ACCEPTED 03-14-00735-CV 4703327 THIRD COURT OF APPEALS AUSTIN, TEXAS 3/31/2015 9:04:27 AM JEFFREY D. KYLE CLERK No. 03-14-00735-CV IN THE FILED IN 3rd COURT OF APPEALS THIRD COURT OF APPEALS AUSTIN, TEXAS AT AUSTIN, TEXAS 3/31/2015 9:04:27 AM JEFFREY D. KYLE Entergy Texas, Inc., et al., Clerk Appellants v. Public Utility Commission of Texas, et al., Appellees Appeal from the 353rd Judicial District Court, Travis County, Texas The Honorable John K. Dietz, Judge Presiding ________________________________________________________________ APPELLANT’S BRIEF OF ENTERGY TEXAS, INC. _________________________________________________________________ John F. Williams State Bar No. 21554100 [email protected] Marnie A. McCormick State Bar No. 00794264 [email protected] DUGGINS WREN MANN & ROMERO, LLP Congress Ave., Ste. 1900 (78701) P. O. Box 1149 Austin, Texas 78767-1149 (512) 744-9300 (512) 744-9399 fax ATTORNEYS FOR APPELLANT ENTERGY TEXAS, INC.

March 2015 ORAL ARGUMENT REQUESTED IDENTITY OF PARTIES AND COUNSEL The following is a list of all parties to the order appealed from and the names and addresses of all trial and appellate counsel: Parties: Attorneys: Entergy Texas, Inc. John F. Williams Plaintiff in District Court Marnie A. McCormick Duggins Wren Mann & Romero, LLP Congress Ave., Ste. 1900 (78701) P. O. Box 1149 Austin, Texas 78767-1149 Counsel in District Court and on Appeal Public Utility Commission of Texas Elizabeth R. B. Sterling Defendant in District Court Assistant Attorney General Environmental Protection Division Office of the Attorney General P.O. Box 12548 Austin TX 78711-2548 Counsel in District Court and on Appeal Office of Public Utility Counsel Sara J. Ferris Plaintiff/Intervenor in District Court Office of Public Utility Counsel 1701 N. Congress Ave., Ste. 9-180 Austin TX 78711-2397 Counsel in District Court and on Appeal Cities of Bridge City, et al. Daniel J. Lawton Plaintiff/Intervenor in District Court Lawton Law Firm PC 12600 Hill Country Blvd., Ste. R275 Austin TX 78738 Counsel in District Court

i State Agencies Susan M. Kelley (retired) Plaintiff/Intervenor in District Court Office of the Attorney General P. O. Box 12548 Austin TX 78711-2548 Counsel in District Court Texas Industrial Energy Consumers Meghan Griffiths Intervenor in District Court Andrews Kurth LLP Congress Ave., Ste. 1700 Austin TX 78701 Counsel in District Court Rex VanMiddlesworth Benjamin Hallmark Thompson Knight LLP San Jacinto Blvd., Ste. 1900 Austin, Texas 78701 Counsel in District Court

ii TABLE OF CONTENTS IDENTITY OF PARTIES AND COUNSEL ............................................................ i TABLE OF CONTENTS ......................................................................................... iii INDEX OF AUTHORITIES.................................................................................... vi STATEMENT OF THE CASE ................................................................................ ix STATEMENT REGARDING ORAL ARGUMENT ............................................. ix ADMINISTRATIVE RECORD .............................................................................. ix ISSUES PRESENTED...............................................................................................x STATEMENT OF FACTS ........................................................................................1 I. Regulatory Framework ....................................................................................1 II. Procedural History ...........................................................................................4 SUMMARY OF THE ARGUMENT ........................................................................5 ARGUMENT AND AUTHORITIES ........................................................................7 I. The Commission erred in disallowing over $11 million associated with ETI’s unrecovered Hurricane Rita reconstruction costs. ........................7 A. Background ...........................................................................................7 B. The Commission erred as a matter of law in concluding that PURA required the insurance proceeds to be trued-up in Docket No. 37744. ...........................................................................................13 C. The Commission also erred in treating the issue as if it had in fact been resolved in Docket No. 37744. ............................................15 D. The Commission’s order contravenes legislative intent. ....................18 II. The Commission erred in refusing to include any of ETI’s adjustments to test-year purchased capacity costs in setting rates. ...................................19 A. Background .........................................................................................19 iii B. The Commission misapplied the standard for adjustments to test-year expenses. ...............................................................................24 1. Adjustments to test-year data are not extraordinary relief........24 2. Adjustments to test-year data need not be proven with absolute certainty. .....................................................................26 C. The Commission’s wholesale disallowance of any adjustment to test-year levels of capacity costs is not supported by substantial evidence.............................................................................27 1. ETI proved that it will incur an annual capacity cost increase of $15.8 million under the Frontier contract...............28 2. ETI proved that it will incur an annual capacity cost increase of $8.1 million under the SRMPA contract. ...............30 3. ETI proved that it will incur an annual capacity cost increase of $14.1 million under the Calpine contract. ..............31 4. The record does not reasonably support the Commission’s other reasons for disallowing 100 percent of these known capacity costs. ..................................................32 a. Load Growth ...................................................................32 b. MSS-1 Costs ...................................................................34 c. MSS-4 Costs ...................................................................36 D. The consequences of the Commission’s decision are extreme and unjust. ...........................................................................................38 III. The Commission erred in setting ETI’s transmission equalization (MSS-2) expense at the test-year level. .........................................................39 A. The Commission erred as a matter of law in applying the standard for adjustments to test-year expenses. ..................................41 B. Additionally, the Commission’s adherence to test-year expense levels is unsupported by substantial evidence.....................................42 CONCLUSION AND PRAYER .............................................................................43 iv CERTIFICATE OF COMPLIANCE .......................................................................44 CERTIFICATE OF SERVICE ................................................................................45 APPENDICES .........................................................................................................47

v INDEX OF AUTHORITIES Cases B.L.M. v. J.H.M., III, No. 03-14-00050-CV, 2014 WL 3562559 *11 (Tex. App. – Austin Jul. 17, 2014, pet. denied) .................................................................................................17 Bluefield Waterworks & Improvement Co. v. Public Serv. Comm’n of State of W.Va., 262 U.S. 679 (1923) ...............................................................................................2 Cameron v. Terrell & Garrett, Inc., 618 S.W.2d 535 (Tex. 1981) ................................................................................33 Cities of Dickinson v. Public Util. Comm’n of Tex., 284 S.W.3d 449 (Tex. App. – Austin 2009, no pet.) ...........................................11 City of Corpus Christi v. Public Util. Comm’n of Tex., 51 S.W.3d 231 (Tex. 2001) ..................................................................................10 City of El Paso v. Public Util. Comm’n of Tex., 344 S.W.3d 609 (Tex. App. – Austin 2011, no pet.) ................................ 3, 19, 20 City of El Paso v. Public Util. Comm’n of Tex., 883 S.W.2d 179 (Tex. 1994) ............................................................... 3, 25, 26, 41 Commint Technical Services, Inc. v. Quickel, 314 S.W.3d 646 (Tex. App. – Houston [14th Dist.] 2010, no pet.) ......................16 Entergy Gulf States, Inc. v. Public Util. Comm’n of Tex., 173 S.W.3d 199 (Tex. App. – Austin 2005, pet. denied) ......................................1 Federal Power Comm’n v. Hope Natural Gas Co., 320 U.S. 591 (1944) ...............................................................................................2 Idaho Power Co. v. Idaho State Tax Comm'n, 109 P.3d 170 (Idaho 2005) ...................................................................................10 Office of Consumer Counsel v. Department of Public Util. Control, 742 A.2d 1257 (Conn. 2000) ................................................................................10 Office of Consumer Counsel v. Department of Public Util. Control, 905 A.2d 1 (Conn. 2006) .....................................................................................10 Office of Public Util. Counsel v. Public Util. Comm’n of Tex., 104 S.W.3d 225 (Tex. App. – Austin 2003, no pet.) .............................................2

vi Starr County v. Starr Industrial Servs., Inc., 584 S.W.2d 352 (Tex. Civ. App. – Austin 1979, writ ref’d n.r.e.) ......................27 State of Texas' Agencies & Institutions of Higher Learning v. Public Util.

Comm’n of Tex., 450 S.W.3d 615 (Tex. App. -- Austin 2014, pet. requested) ........................ 10, 17 Suburban Util. Corp. v. Public Util. Comm’n of Tex., 652 S.W.2d 358 (Tex. 1983) ........................................................................... 3, 26 TXU Elec. Co. v. Public Util. Comm’n of Tex., 51 S.W. 3d 275 (Tex. 2001) (per curiam) ..............................................................8 Woods v. William M. Mercer, Inc., 769 S.W.2d 515 (Tex. 1988) ................................................................................16 Statutes Tex. Gov’t Code Ann. § 2001.174 .............................................................. 19, 39, 43 Tex. Gov’t Code Ann. § 2001.190...........................................................................17 Tex. Util. Code Ann. §§ 11.001, et seq. ....................................................................1 Tex. Util. Code Ann. §§ 36.001, et seq. ..................................................................14 Tex. Util. Code Ann. § 36.003 ...................................................................................2 Tex. Util. Code Ann. § 36.051 .................................................................. 2, 7, 25, 41 Tex. Util. Code Ann. §§ 39.001-.359 ........................................................................2 Tex. Util. Code Ann. § 39.452 ...............................................................................2, 8 Tex. Util. Code Ann. § 39.455 .................................................................................33 Tex. Util. Code Ann. § 39.458 ........................................................................ 7, 8, 18 Tex. Util. Code Ann. §§ 39.458-463 .................................................................. 7, 18 Tex. Util. Code Ann. § 39.459 ............................................................................ 7, 13 Tex. Util. Code Ann. § 39.462 ......................................................................... passim Rules 16 Tex. Admin. Code § 22.222 ................................................................................17 16 Tex. Admin. Code § 25.181 ..................................................................................4 16 Tex. Admin. Code § 25.231 ..................................................................... 3, 24, 41 16 Tex. Admin. Code § 25.234 ..................................................................................3 16 Tex. Admin. Code §§ 25.235-.237 .......................................................................4 vii 16 Tex. Admin. Code § 25.236 ......................................................................... 19, 20 16 Tex. Admin. Code § 25.238 ................................................................................20 Tex. R. Civ. P. 94 .....................................................................................................15 Commission Proceedings Application of Entergy Gulf States, Inc. for Authority to Change Rates and to Reconcile Fuel Costs, Docket No. 34800 ........................................................13 Application of Entergy Gulf States, Inc. for Determination of Hurricane Reconstruction Costs, Docket No. 32907 .................................................... passim Application of Entergy Texas, Inc. for Authority to Change Rates and Reconcile Fuel Costs, Docket No. 37744 ............................................................17

viii STATEMENT OF THE CASE This is a suit for judicial review of the final order of the Public Utility Commission of Texas (the “Commission” or “PUCT”) in its Docket Number 39896, a proceeding initiated by Entergy Texas, Inc. (“ETI” or the “Company”) for authority to change its retail electric rates and reconcile fuel costs. ETI and several other parties to the contested case sought judicial review of the Commission’s order.1 The cases were consolidated.2 The district court, Judge John K. Dietz presiding, reversed the Commission’s order in one respect and summarily affirmed it in all other respects.3 STATEMENT REGARDING ORAL ARGUMENT Cases involving public utility regulation usually involve complex regulatory principles, and this one is no exception. For that reason, the Court’s decisional process would be aided by oral argument.

ADMINISTRATIVE RECORD The Administrative Record (“AR”) comprises Joint Exhibits 4-13 of the Reporter’s Record. Joint Exhibit 13 was sealed per the requirements of Texas Rule of Civil Procedure 76a.4 Joint Exhibits 1-3 are indices to the record.

Clerk’s Record (“CR”) 5. The Clerk’s Record does not yet contain the petitions filed by parties other than ETI.

CR 81.

CR 2118.

CR 2109. ix ISSUES PRESENTED

1. The Commission disallowed over $11 million of costs that ETI incurred to restore its system after Hurricane Rita and that no one disputes ETI is entitled to recover. The Commission decided that ETI should have begun recovering these costs at the end of a previous rate case, Docket No. 37744, based upon a PURA provision and what the Commission characterizes as an ambiguity in the resolution of Docket No. 37744.

a. Did the Commission erroneously interpret PURA as requiring resolution of this issue in Docket No. 37744, when PURA section 39.462(a) says ETI may recover these costs in “any” proceeding authorized by Chapter 36?

b. Did the Commission err by requiring ETI to disprove its opponents’ res judicata theory that the order in Docket No. 37744 bars ETI from seeking recovery of the costs in this case?

c. Does the record reasonably support the Commission’s decision that the order in Docket No. 37744 required ETI to begin recovering these costs, when everyone agrees the Commission’s order said nothing about the issue?

2. The Commission disallowed over $30 million of ETI’s expenses for purchasing capacity from third parties because the amount was not incurred in the test year and because the Commission found there was a possibility that some of the costs might be avoided or offset.

a. Did the Commission err as a matter of law by treating adjustments to test-year levels of expense as “exceptional” and by refusing to make any adjustments for anticipated costs?

b. Is every one of the Commission’s multiple theories about how the costs might be avoided or offset supported by substantial evidence?

x 3. The Commission refused to make any adjustment to ETI’s test-year level of “transmission equalization” expense because the parties disagreed about how big an adjustment was warranted.

a. Did the Commission err as a matter of law by requiring proof of adjustments to test-year expenses with absolute certainty?

b. Is the Commission’s decision to set this expense at the test-year level supported by substantial evidence, when every witness who testified on this issue agreed the test-year level was too low?

xi STATEMENT OF FACTS ETI is an investor-owned electric utility.5 ETI provides bundled generation, transmission, distribution, and customer services to over 400,000 retail customers, primarily in southeastern Texas.6 During the time periods at issue in this case, ETI served both wholesale and retail customers.

I. Regulatory Framework ETI is a subsidiary of Entergy Corporation, which also owns other subsidiaries, or “operating companies,” including electric utilities in Louisiana, Arkansas, and Mississippi.7 The utility subsidiaries each own facilities separately, but they have historically coordinated and shared resources for providing and transmitting energy.8 This coordination across state lines is governed by the “Entergy System Agreement,” a tariff approved by the Federal Energy Regulatory Commission (“FERC”).9 ETI’s wholesale rates are also regulated by the FERC.

See Entergy Gulf States, Inc. v. Public Util. Comm’n of Tex., 173 S.W.3d 199, 207 (Tex. App. – Austin 2005, pet. denied).

The services ETI provides to Texas retail customers are subject to regulation by the PUCT under the Public Utility Regulatory Act (“PURA”).10 The Texas

AR Binder 31, ETI Exh. 4 (Domino Direct at 1 of 38). Id. Id. AR Binder 36, ETI Exh. 39 (Cicio Direct at 6-10 of 75). Id. See Tex. Util. Code Ann. §§ 11.001, et seq. legislature in 1999 ordered electric utilities to “unbundle” their generation, transmission, distribution, and customer service functions as part of an effort to introduce competition into the Texas retail electric industry. See Tex. Util. Code Ann. §§ 39.001-.359. However, in 2009, the legislature amended PURA to require ETI to cease activities relating to the transition to retail competition. See id. § 39.452(i). Accordingly, ETI remains subject to traditional cost-of-service rate regulation. Id. § 39.452(a).

Under traditional regulation, an electric utility provides service, from the acquisition to delivery of power, to all requesting customers in a service area at a Commission-approved “just and reasonable” rate. See Office of Public Util.

Counsel v. Public Util. Comm’n of Tex., 104 S.W.3d 225, 227-28 (Tex. App. – Austin 2003, no pet.); see also Tex. Util. Code Ann. § 36.003(a). Under PURA and applicable constitutional principles, a utility is entitled to rates that afford it a “reasonable opportunity to earn a reasonable return on the utility’s invested capital used and useful in providing service to the public in excess of the utility’s reasonable and necessary operating expenses.” Tex. Util. Code Ann. § 36.051; Federal Power Comm’n v. Hope Natural Gas Co., 320 U.S. 591, 603 (1944); Bluefield Waterworks & Improvement Co. v. Public Serv. Comm’n of State of W.Va., 262 U.S. 679, 692 (1923). To set rates, the Commission determines each of these components, which cumulatively are the utility’s “revenue requirement” or “cost of service.” See, e.g., City of El Paso v. Public Util. Comm’n of Tex., 883 S.W.2d 179, 187 (Tex. 1994); 16 Tex. Admin. Code § 25.231.

The PUCT by rule has adopted a process by which rates are based on a historical “test year,” adjusted for known and measurable changes. See 16 Tex. Admin. Code § 25.231(a). The Commission evaluates the reasonableness of the utility’s expenses, determines the appropriate level of capital investment (or rate base) and a reasonable rate of return on that investment, and then allocates the total revenue requirement among the utility’s various classes of customer. Id. §§ 25.231(b), (c) & .234.

The central goal of this process is to arrive at cost recovery as representative as reasonably possible of the utility’s “cost situation expected in the future.”

Suburban Util. Corp. v. Public Util. Comm’n of Tex., 652 S.W.2d 358, 366 (Tex. 1983). The utility generally bears the risk that its actual operating expenses will exceed the expectations incorporated into the rate, while retail customers bear the converse risk, during the regulatory “lag” between rate cases. City of El Paso v. Public Util. Comm’n of Tex., 344 S.W.3d 609, 613 (Tex. App. – Austin 2011, no pet.).

Exceptions to this general rule of risk exist for certain categories of costs, such as fuel costs and energy efficiency costs. For these types of costs, the utility has a separate rate or “rider” through which it collects its projected costs. The utility later must reconcile those revenues to its actual, reasonable costs so that it recovers no more or less than its actual, reasonable costs for the particular category of expense covered by the rider. See, e.g., 16 Tex. Admin. Code §§ 25.235-.237 & § 25.181.

II. Procedural History The Company initiated the underlying general rate case because the rates in effect did not adequately compensate it for its cost of providing service.11 Among other things, ETI’s third-party purchased power costs were doubling, a study showed that its current depreciation rates were severely understated, and its actual return on equity was some three percentage points lower than its then-authorized return.12 ETI sought a total annual increase of $104.8 million.13 The “test year” for the Company’s application was July 1, 2010 through June 30, 2011.14 Rates were proposed to go into effect in June 2012.15 After an evidentiary hearing, four Administrative Law Judges (“ALJs”) issued a proposal for decision recommending that ETI’s rates be increased by a total of $28.3 million annually.16 The Commission, with a few exceptions, adopted

AR Binder 31, ETI Exh. 4 (Domino Direct at 7 of 38).

Id. at 7-8.

AR Binder 37, ETI Exh. 55 (LeBlanc Rebuttal at 7 of 14).

AR Binder 31, ETI Exh. 4 (Domino Direct at 8 of 38).

AR Binder 43, Vol. K (5/2/12 Tr. at 1540).

See AR Binder 7, Item 244 (Order on Rehearing at 1). the proposal for decision and ordered that ETI’s rates be increased by a total of $27.7 million annually.

ETI appealed several aspects of the final order to the district court.17 Several parties that intervened in the Commission proceeding, including a group of cities (“Cities”), the Office of Public Utility Counsel (“OPUC”), and State Agencies, also appealed.18 The district court sustained one of ETI’s points, reversing the Commission’s decision on that issue.19 The court summarily affirmed the Commission’s order in other respects.20 More detailed facts are explained below in the context of the specific errors ETI brings to this Court.

SUMMARY OF THE ARGUMENT This case is about several multi-million-dollar outlays that ETI made to serve its customers, but that the Commission refused to include in ETI’s rates.

First, ETI spent millions of dollars reconstructing its system after Hurricane Rita. The Commission long ago determined these costs were reasonable and necessary, and that ETI was entitled to recover them. Nevertheless, the Commission has now disallowed over $11 million of these costs on the theory that ETI should have started recovering them after its 2009 rate case. This decision is CR 5.

Though the separate appeals were consolidated, CR 81, the Clerk’s Record does not yet contain the petitions filed by parties other than ETI. In any event, after the cases were consolidated, State Agencies nonsuited their appeal but remained in the case as an intervenor defendant. CR 2084 & 2085.

CR 2118.

Id. based upon an erroneous interpretation of a PURA provision. It is also based upon a legally and factually unsupportable conclusion that ETI should have divined that it was required to begin recovering these costs after the 2009 rate case, even though the order in that case said no such thing.

Second, ETI spent millions of dollars purchasing third-party capacity to serve its customers. Even though the Commission did not find that these purchases were unreasonable or unnecessary, the Commission refused to include the costs in ETI’s rates. The Commission’s decision is based upon an erroneous insistence that test-year data is more important than evidence of what costs the Company expects to bear when the rates go into effect. It is also based upon several fact-findings that ETI might be able to avoid or offset some of these costs. These findings do not support a total disallowance of the purchased capacity costs and are not rationally based upon the record evidence.

Similarly, ETI spent millions of dollars to pay for its share of the multi- jurisdictional transmission network that supports service to its customers, and those costs dramatically increased after the test year. Even though every witness who testified about this issue agreed that the test-year level of this expense was too low, the Commission refused to make any adjustment because the witnesses did not agree on how much of an increase was warranted. This decision is another example of the Commission’s erroneous application of the standard for calculating expenses that should be included in rates. It is also unsupported by substantial evidence.

The effect of all these decisions was that ETI had to bear all these costs at shareholder expense until its next rate case. ETI, therefore, did not have the opportunity to earn the reasonable return on its investment to which it is entitled under PURA. See Tex. Util. Code Ann. § 36.051. Because these decisions were fraught with error, this Court should reverse them.

ARGUMENT AND AUTHORITIES I. The Commission erred in disallowing over $11 million associated with ETI’s unrecovered Hurricane Rita reconstruction costs.

A. Background In 2005, Hurricane Rita struck the upper Texas coast, causing extensive damage to southeastern Texas. The next year, the legislature enacted a set of provisions in PURA that entitles electric utilities like ETI to timely recover reconstruction costs they reasonably and necessarily incurred as a result of the hurricane. See Tex. Util. Code Ann. §§ 39.458-463.

The enactment requires the Commission, upon application by a utility, to determine whether particular hurricane reconstruction costs were reasonably and necessarily incurred and thus eligible for recovery. Id. §§ 39.459(a)(1) & 39.462(b). This determination need not be made in the context of a base-rate proceeding under PURA Chapter 36. Id. § 39.462(e).

If, upon a utility’s application, the Commission determines it would benefit ratepayers for the utility to recover eligible costs through “securitization” financing,21 as opposed to “conventional financing methods,” the Commission must adopt a financing order authorizing the utility to issue bonds. Id. § 39.458.

The bonds are repaid or secured by charges to ratepayers in the utility’s service area. E.g., TXU Elec. Co. v. Public Util. Comm’n of Tex., 51 S.W. 3d 275, 277 (Tex. 2001) (per curiam). Alternatively, a utility is entitled to recover eligible reconstruction costs in a base rate proceeding “or through any other proceeding authorized by Subchapter C, Chapter 36” of PURA. Tex. Util. Code Ann. § 39.462(a).

In December 2006, ETI’s predecessor22 initiated a proceeding to determine whether certain of its Hurricane Rita reconstruction costs were eligible for recovery and securitization.23 The parties to that case reached a settlement and

Securitization is a specialized form of debt financing where repayment of bondholders achieves a high degree of assurance, resulting in very low bond interest rates.

ETI’s predecessor was Entergy Gulf States, Inc. (“EGSI”). EGSI provided retail electric service in both Texas and Louisiana. In 2005, the Texas Legislature enacted legislation providing that EGSI could proceed with and complete jurisdictional separation of its Texas and Louisiana operations to establish two separate, vertically integrated utilities. See Tex. Util. Code Ann. § 39.452(e). By January 1, 2008, EGSI had separated into ETI, a Texas-only utility, and Entergy Gulf States Louisiana, L.L.C., a Louisiana-only utility.

See Application of Entergy Gulf States, Inc. for Determination of Hurricane Reconstruction Costs, Docket No. 32907 (Jul. 5, 2006 Application). Public filings in Docket No. 32907 and other Commission dockets may be accessed at the Commission’s interchange: http://interchange.puc.texas.gov/WebApp/Interchange/application/dbapps/filings/pgSearch.asp by entering the docket number in the “Control Number” field. agreed that $381,236,384 of the expenses at issue were eligible.24 Because ETI expected to receive insurance proceeds of $65,700,000 in the future, the settlement provided that ETI would deduct that amount from its eligible costs.25 The parties agreed that ETI should be allowed to securitize $381,236,384, plus carrying costs, minus the $65.7 million estimated insurance proceeds, plus other qualified costs.26 It was understood that the Company might not receive exactly $65,700,000 in insurance proceeds, so the parties further agreed that after ETI received all of its insurance payments, a true-up would occur to determine the difference between the $65,700,000 estimate and the amount actually received.27 The parties agreed that ETI would accrue interest on the anticipated payments until they were actually paid, either by insurance companies or ratepayers.28 The Commission approved the parties’ agreement.29 The order provided that if ETI received more insurance payments than estimated, the excess would be passed through to ratepayers via a rider.30 But the agreed rider was only for over- recovery. Neither the settlement nor the order specified a method for recovering any insurance under-recovery from ratepayers.

See Docket No. 32907 (Nov. 17, 2006, Settlement Agreement at 2 of 10). Id. at 3 of 10. Id. at 5 of 10. Id. at 3 of 10. Id. See id. (Dec. 1, 2006, Order at 1). Id. at FOF 30.

By 2009, ETI had received only $46,013,904 in insurance proceeds, resulting in a $19,686,096 under-recovery of its actual, eligible hurricane reconstruction costs.31 ETI carried this unrecovered balance on its books, with interest, as a regulatory asset32 because the Commission’s order in Docket No. 32907 expressly contemplated that ETI would be authorized to recover these amounts in the future.33 In 2009, ETI filed a base rate case, Docket No. 37744. By that time, ETI had recovered most of the insurance proceeds it expected to recover, and it sought permission to begin recovering the regulatory asset of $19,686,096, plus interest, on a five-year amortization schedule.34

AR Binder 5, Item 185 (Proposal for Decision at 16).

A “regulatory asset” is a mechanism by which a utility carries a cost on its books as a balance sheet asset based on the expectation that a regulator will allow the utility to recover the cost over a period of years in the future instead of at the time the expenditure is made. E.g. Office of Consumer Counsel v. Department of Public Util. Control, 905 A.2d 1, 7 (Conn. 2006); Idaho Power Co. v. Idaho State Tax Comm'n, 109 P.3d 170, 173 (Idaho 2005); Office of Consumer Counsel v. Department of Public Util. Control, 742 A.2d 1257, 1263 (Conn. 2000); City of Corpus Christi v. Public Util. Comm’n of Tex., 51 S.W.3d 231, 238 (Tex. 2001); State of Texas' Agencies & Institutions of Higher Learning v. Public Util. Comm’n of Tex., 450 S.W.3d 615, 646 (Tex. App. -- Austin 2014, pet. requested). Public utility commissions often permit utilities to recover large capital expenditures on this deferred basis to avoid the “rate shock” that could result if the costs were passed on to ratepayers all at once. E.g., Office of Consumer Counsel, 905 A.2d at 7; Idaho Power Co., 109 P.3d at 173. A regulatory asset is, therefore, a future debt of the ratepayers. Office of Consumer Counsel, 905 A.2d at 7. Regulatory assets are recovered over time from ratepayers on an “amortized” schedule. See Idaho Power Co., 109 P.3d at 173; Office of Consumer Counsel, 742 A.2d at 1263.

Docket 32907 (Dec. 1, 2006, Order at FOF 28) (authorizing ETI to accrue carrying costs on estimated insurance proceeds until paid by insurance companies or until the trued-up amount “is recovered in base rates”); AR Binder 5, Item 185 (Proposal for Decision at 19).

AR Binder 5, Item 185 (Proposal for Decision at 16). Again, as explained above in footnote 32, regulatory assets are traditionally “amortized.” That means they are recovered over a period of time so they are not charged to ratepayers all at once.

Docket No. 37744 was concluded by a “black box” settlement that did not mention the Hurricane Rita regulatory asset.35 Neither the parties’ stipulation nor the PUCT’s order in Docket No. 37744 directed ETI to begin amortizing the regulatory asset or otherwise prescribed a method for recovering it. Neither indicated an intent to alter ETI’s rights under PURA section 39.462 and the Commission’s order in Docket No. 32907.36 ETI, therefore, continued to account for and accrue interest on the unrecovered regulatory asset.

After Docket No. 37744, ETI received an additional $5.7 million in insurance proceeds.37 In its next rate case, the one underlying this appeal, ETI sought permission to begin recovering the updated balance of the reconstruction costs eligible for recovery. With interest, that balance totaled $26,229,627.38 The ALJs recommended ETI recover only $15,175,563.39 The ALJs determined that even though the order in Docket No. 37744 did not say so, ETI should have begun amortizing the regulatory asset on August 15, 2010, the effective date of the rates approved in that docket.40 The ALJs expressed two rationales for their decision. First, they concluded that PURA required any In a “black box” settlement, the parties agree to a total amount that a utility can recover through its rates without specifying any of the individual numbers used to calculate the amount.

See, e.g., Cities of Dickinson, et al. v. Public Util. Comm’n of Tex., 284 S.W.3d 449, 450 (Tex. App. – Austin 2009, no pet.).

Docket No. 32907, supra (Nov. 17, 2006, Settlement Agreement; Dec. 1, 2006, Order).

AR Binder 37, ETI Exh. 46 (Considine Rebuttal at 18).

Id.; AR Binder 5, Item 185 (Proposal for Decision at 16).

AR Binder 5, Item 185 (Proposal for Decision at 23).

Id. at 21-22. true-up of insurance proceeds to occur in the first base rate case after the reconstruction costs were deemed eligible for recovery.41 The ALJs believed that Docket No. 37744 was that case.42 Second, though they characterized the issue as a “close call,”43 the ALJs concluded that the amortization of the unrecovered costs “should be considered as having been approved in Docket No. 37744.”44 They believed the proposed amortization was not disputed in Docket No. 37744, and that ETI therefore had the burden of proving the issue was not resolved in the docket.45 Because they believed ETI did not meet that burden, they treated the issue as if it had already been resolved.46 The ALJs determined that if ETI had begun amortizing the regulatory asset upon the conclusion of Docket No. 37744, only $15,175,563 would be left to deal with in this case.47 The Commission adopted the ALJs’ recommendation.48 This decision must be reversed, because all the rationales for it are flawed.

Id. at 15 & 21-22.

Id. at 16 & 22.

Id. at 20.

Id. at 22.

Id. Id. Id. at 23.

AR Binder 7, Item 244 (Order on Rehearing at 1 & FOFs 19-22).

B. The Commission erred as a matter of law in concluding that PURA required the insurance proceeds to be trued-up in Docket No. 37744.

The ALJs relied upon PURA section 39.459(c) in concluding that the insurance proceeds were required to be trued up in the first base rate case after the reconstruction costs were deemed eligible for recovery.49 Section 39.459(c) reads: To the extent a utility subject to this subchapter receives insurance proceeds, governmental grants, or any other source of funding that compensates it for hurricane reconstruction costs, those amounts shall be used to reduce the utility’s hurricane reconstruction costs recoverable from customers. If the timing of a utility’s receipt of those amounts prevents their inclusion as a reduction to the hurricane reconstruction costs that are securitized, the commission shall take those amounts into account in: (1) the utility’s next base rate proceeding; or (2) any proceeding in which the commission considers hurricane reconstruction costs. Tex. Util. Code Ann. § 39.459 (c) (emphasis added). The Commission, in adopting the ALJs’ construction of this provision, erred as a matter of law.50 PURA section 39.459(c) requires the Commission to remedy a double- recovery if a utility receives insurance or grant money for hurricane reconstruction costs after those same costs have already been securitized. That is the exact

AR Binder 5, Item 185 (Proposal for Decision at 15 & 21-22).

The Commission also erred as a matter of fact in assuming that Docket No. 37744 was ETI’s first base rate case after the reconstruction costs were deemed eligible for recovery in Docket No. 32907. There was another base rate case filed and decided between Docket Nos. 32907 and 37744. See Application of Entergy Gulf States, Inc. for Authority to Change Rates and to Reconcile Fuel Costs, Docket No. 34800. opposite of what happened here. In Docket No. 32907, ETI agreed not to securitize amounts it expected to recover from insurance. Therefore, in the language of the statute, the timing of ETI’s receipt of those amounts did not prevent their inclusion as a reduction to the amounts that were securitized. The Attorney General conceded in the district court that the wording of section 39.459(c) “is not an exact match to the circumstances of this case.”51 Indeed, section 39.459(c) is by its plain terms inapplicable.

Section 39.462(a), on the other hand, speaks directly to this situation. It says: An electric utility subject to this subchapter is entitled to recover hurricane reconstruction costs consistent with the provisions of this subchapter and is entitled to seek recovery of amounts not recovered under this subchapter … in its next base rate proceeding or through any other proceeding authorized by Subchapter C, Chapter 36. Id. § 39.462(a) (emphasis added). There is no question that the proceeding underlying this appeal was authorized by PURA Subchapter C, Chapter 36. See id. § 36.001, et seq. Therefore, the Commission was expressly authorized to address the issue in this case. It certainly was not statutorily required to address the issue in Docket No. 37744 or some other particular case.

CR 698 (PUCT Initial Brief at 14).

C. The Commission also erred in treating the issue as if it had in fact been resolved in Docket No. 37744.

Nothing in the settlement agreement or final order in Docket No. 37744 even mentioned the regulatory asset, much less a method of recovering it. The ALJs acknowledged that.52 They also recognized that utilities are typically not allowed to recover regulatory assets without express approval of the Commission.53 The ALJs nevertheless concluded that the proposed amortization of the regulatory asset should be “considered to have been approved” in Docket No. 37744. They believed that the proposed amortization was not disputed in Docket No. 37744 and that ETI consequently should be required to prove the issue was not resolved in Docket No. 37744.54 Both of these assumptions are incorrect.

First, as a matter of law, ETI did not bear the burden of proving what issues Docket No. 37744 did or did not resolve. The issue of whether Docket No. 37744 bars ETI from seeking particular relief in a subsequent case was a defensive issue raised by intervenors.55 The argument is really that the order in Docket No. 37744 is res judicata of the reconstruction cost recovery issue. Because that is an affirmative defense, intervenors bore the burden of proof on the issue. See, e.g., Tex. R. Civ. P. 94; Woods v. William M. Mercer, Inc., 769 S.W.2d 515, 517 (Tex.

AR Binder 5, Item 185 (Proposal for Decision at 20-21).

Id. at 21.

Id. at 22.

See, e.g., AR Binder 8 (Cities Exh. 2, Garrett Direct at 11).

1988); Commint Technical Services, Inc. v. Quickel, 314 S.W.3d 646, 651 (Tex. App. – Houston [14th Dist.] 2010, no pet.).

There is no reasonable basis in the record upon which to conclude that the parties or the Commission intended ETI to begin amortizing the regulatory asset years ago. The only reason the intervenors gave in support of their argument was their allegation that the issue was “undisputed” in Docket No. 37744. It is true that no party to Docket No. 37744 argued that ETI should not recover the money at all.56 They could not, given that Docket No. 32907 and PURA clearly entitle ETI to recover the full amount of its eligible restoration costs. Regardless, the parties’ litigation positions during the contested phase of a proceeding do not inform what the parties intend when they settle the case, or what the Commission intends in approving the settlement.

Even assuming for the sake of argument that the parties’ litigation positions in Docket No. 37744 were relevant, their positions on whether ETI was entitled to recover the money at all would not be the relevant issue. What would matter is what the parties’ positions were on how and when ETI should recover the money, because that is the issue the Commission says was resolved in Docket No. 37744.

Cities’ witness in Docket No. 37744, Jacob Pous, did dispute ETI’s request to amortize the regulatory asset over a five-year period. He testified that ETI should

See id. at 11. credit the amount to its storm reserve instead.57 The ALJs were mistaken in concluding that this issue was uncontested in Docket No. 37744.58 There certainly is no evidence in this docket that the parties or the Commission intended ETI to begin amortizing the regulatory asset upon the conclusion of Docket No. 37744.

Given that neither the settlement agreement nor the Commission’s order said anything about this issue, and especially since the issue was disputed, ETI would have been unreasonable to “assume” it could begin amortizing the regulatory asset when Docket No. 37744 was over. As this Court recently recognized, the recovery of a regulatory asset is a two-step process. First, the Commission allows creation of the asset, and later, the Commission decides how the utility may recover the asset in rates. State of Texas' Agencies & Institutions of Higher Learning v. Public Util. Comm’n of Tex., 450 S.W.3d 615, 646 (Tex. App. -- Austin 2014, pet requested). Here, the settlement and Commission order in Docket No. 32907 established that the hurricane reconstruction costs were reasonable and necessary and authorized creation of the regulatory asset. But the Company’s proposed See Application of Entergy Texas, Inc. for Authority to Change Rates and Reconcile Fuel Costs, Docket No. 37744 (Pous Direct at 113). Both the Commission and this Court may take notice of the fact this testimony was filed in Docket No. 37744. Tex. Gov’t Code Ann. § 2001.190; 16 Tex. Admin. Code § 22.222(a); B.L.M. v. J.H.M., III, No. 03-14-00050-CV, 2014 WL 3562559 *11 (Tex. App. – Austin Jul. 17, 2014, pet. denied) (not designated for publication).

In contrast, the ALJs correctly observed that another issue – regarding ETI’s storm reserve balance -- was disputed in Docket No. 37744. AR Binder 5, Item 185 (Proposal for Decision at 48). They concluded that issue was not resolved by the black box settlement. Id. Using the ALJs’ own logic, this fact leads to the conclusion that the Hurricane Rita issue was not adjudicated in Docket No. 37744. Resolving two issues differently based on materially similar facts is the essence of arbitrary and capricious action. method of recovering that asset in Docket No. 37744 was a contested issue, and neither the parties’ settlement nor the Commission’s order resolved the issue in favor of one party or another. The only reasonable thing for the Company to do was to maintain the status quo, carrying the balance on its books as a regulatory asset until the Commission affirmatively addresses how the Company may recover it.59 D. The Commission’s order contravenes legislative intent.

The Commission’s decision thwarts the legislature’s purpose in enacting the hurricane reconstruction cost recovery provisions. See Tex. Util. Code Ann. §§ 39.458-.463. The legislature clearly intended to ensure that utilities that incurred reconstruction costs as a result of Hurricane Rita would be able to expeditiously recover those costs in full, with interest. Indeed, the legislature expressly articulated this purpose in PURA. Id. § 39.458. The effect of the Commission’s order here is to disallow over $11 million in unrecovered hurricane reconstruction costs and interest. The order penalizes the utility for, instead of securitizing all of its hurricane reconstruction costs as authorized by the statute, opting not to securitize amounts that it anticipated recovering through insurance.

No one has suggested that ETI was unreasonable in estimating its anticipated

Even Cities opined that the Docket No. 37744 settlement should not be interpreted as changing the status quo unless expressly stated in the settlement agreement or the final order. See AR Binder 5, Item 185 (Proposal for Decision at 17). insurance proceeds when the securitization docket was taking place. The Commission’s reasons for disallowing the amounts that were not ultimately recovered through insurance are not legally or factually sound. The Court should reverse the Commission’s disallowance. See Tex. Gov’t Code Ann. § 2001.174(b)(2).

II. The Commission erred in refusing to include any of ETI’s adjustments to test-year purchased capacity costs in setting rates.

A. Background “Capacity” is the amount of power a utility has available at any given time to serve customers. Utilities are required to have a percentage surplus or “cushion” of capacity available in reserve, in case demand exceeds expectations.

Traditionally regulated utilities supply their need for capacity either by owning generating plants or by buying capacity from someone else.

A utility’s capital investment in building and maintaining its own plant become a part of its invested capital (or “rate base”), and the utility earns a return on that investment. The cost of fueling a power plant and other specified variable “energy” charges incurred to generate power are recoverable dollar-for-dollar as fuel expenses. 16 Tex. Admin. Code § 25.236(a); City of El Paso, 344 S.W.3d at 614.

Purchases of capacity from third parties are, however, treated differently.

They are simply expenses, and earn no return for the utility. Moreover, the fixed costs associated with obtaining capacity from third parties may not, absent special circumstances, be recovered as fuel expenses. 16 Tex. Admin. Code § 25.236(a)(4); City of El Paso, 344 S.W.3d at 614. Instead, they are recovered through base rates. Id.60 Like other base rate expenses, “purchased capacity costs” are quantified during a “test year,” are adjusted for known and measurable changes, and become a component of the utility’s revenue requirement that forms the basis for prospective rates. There is no true-up or reconciliation for the purchased capacity costs recovered through base rates. Combined with the fact that there is no opportunity to earn a return on this type of expense, the adverse financial impact of “regulatory lag” is much more significant for this type of expense than it is for reconcilable fuel costs.

Before 2009, ETI was under a regulatory directive to position itself for retail competition, and that directive necessitated that the Company forego long-term resource procurement. During that time, ETI relied on or “shared” the capacity from Entergy System resources owned by other Entergy operating companies, and relied on short- and limited-term resources to reliably serve its retail customers.61 ETI paid for this Entergy System capacity under Schedule MSS-1 of the Entergy System Agreement. That FERC-approved tariff requires the various Entergy In some circumstances, Commission rules allow utilities to recover purchased capacity costs through a rider. See 16 Tex. Admin. Code § 25.238. ETI does not have such a rider.

See AR Binder 37, ETI Exh. 47 (Cooper Rebuttal at 5-6 of 21); AR Binder 43, Vol. L (5/3/12 Tr. at 1939). operating companies to make and receive payments according to their relative share of total system capacity.62 Some Entergy operating companies own a greater share of Entergy System capacity than they need to serve their own load.63 These entities are considered “long” on capacity.64 Other companies own less than they need, and are “short” on capacity.65 Under Schedule MSS-1, “short” companies pay “long” companies a per-MW rate for the cost of owning these capacity reserves.66 While it was in regulatory limbo, ETI controlled relatively less resources compared to its load than other Entergy companies. It, therefore, made “reserve equalization” payments under Schedule MSS-1.67 In addition to sharing Entergy System capacity under Schedule MSS-1, ETI also purchased power from specific units owned by other Entergy operating companies. Those unit-specific purchases were paid for under contracts with those operating companies under Schedule MSS-4 of the Entergy System Agreement.

Schedule MSS-4 contains a formula that sets the price of power for these purchases based on the actual cost of producing the power.68 After the legislature in 2009 delayed the onset of retail competition in ETI’s service area, ETI found it cost effective to begin to substantially increase its AR Binder 36, ETI Exh. 39 (Cicio Direct at 11-12 of 75).

Id. at 12.

Id. Id. Id. at 13-14.

AR Binder 35, ETI Exh. 34 (Cooper Direct at 22-23 of 25).

AR Binder 36, ETI Exh. 39 (Cicio Direct at 24-26 of 75). reliance upon purchases of capacity from third parties.69 ETI did not buy more third-party capacity simply to serve additional load. Rather, ETI employed the strategy to serve existing load, reduce its reliance on Entergy capacity resources, and render ETI less “short” compared to other Entergy entities.70 The strategy also reduced fuel costs for customers because the third-party resources were by and large more fuel-efficient than the combined Entergy resources and, as explained above, there was no return component included in the cost.71 In this case, ETI asked the Commission to recognize the cost of ETI’s increased reliance on three new third-party purchased capacity contracts. Those contracts cost ETI some $38 million annually. ETI recognized that these contracts would enable ETI annually to avoid about $8 million of the costs it paid to Entergy affiliates for their capacity in the test year. ETI, therefore, asked the Commission to increase its test-year expenses for purchased capacity by the net amount of about $30 million for purposes of setting its annual rates.

No party challenged the wisdom of ETI’s entering into any of the new, third- party contracts or the prices reflected in the contracts. The ALJs, however, included in ETI’s base rates only purchased capacity costs that were incurred

E.g, AR Binder 35, ETI Exh. 34 (Cooper Direct at 23 of 25).

AR Binder 37, ETI Exh. 47 (Cooper Rebuttal at 5 of 21); see also id. at 10-11; AR Binder 37, ETI Exh. 57 (May Rebuttal at 13-15 of 31).

AR Binder 35, ETI Exh. 34 (Cooper Direct at 24 of 25); AR Binder 37, ETI Exh. 47 (Cooper Rebuttal at 7-8 of 21). during ETI’s test year.72 The ALJs disallowed 100 percent of the additional expense associated with the third-party capacity contracts that would be incurred during the first year rates would be in effect (the “rate year”) and thereafter.73 The Commission adopted the ALJs’ proposal for decision on this issue.74 The ALJs concluded that ETI had not proven that the costs it would incur as a result of entering into the third-party purchase capacity contracts were “known and measurable” adjustments to the utility’s test-year expenses.75 The ALJs found that there is “substantial uncertainty” about what ETI will be obligated to pay for the third-party purchased capacity because the third parties might not fully perform their obligations under the contracts.76 The ALJs suggested that the contract costs should not be in rates because they may be offset by increased revenues from load growth.77 The ALJs further found there is “substantial uncertainty” about how much money the third-party purchased power capacity contracts will enable ETI to avoid paying to other Entergy entities under Schedule MSS-1 of the Entergy System Agreement.78 The source of this perceived uncertainty was apparently the ALJs’ view that the net costs were difficult to quantify because the calculations

AR Binder 5, Item 185 (Proposal for Decision at FOF 86).

Id. at FOF 73 & 86.

AR Binder 7, Item 244 (Order on Rehearing at 1 & 7).

AR Binder 5, Item 185 (Proposal for Decision at 108).

Id. at FOFs 77-78.

Id. at 109 & FOFs 84.

Id. at FOFs 75, 76, & 79-82. involve projections and “complex” formulae and “variables.”79 Rather than accepting any of the calculations in evidence or adopting a result within the range of these recommendations, the ALJs simply disallowed the entire adjustment.80 The Commission’s order adopting these recommendations constitutes error of law and is not supported by substantial evidence.

B. The Commission misapplied the standard for adjustments to test-year expenses.

The fundamental error in the Commission’s order is that it misapplies the legal standard for determining what expenses should be included in rates. The order adopts the ALJs’ erroneous view that an adjustment to test-year data is somehow extraordinary or “exceptional” rate relief.81 The ALJs also took the view that to the extent additional costs are based on anticipated changes, they cannot be “known and measurable.”82 These assumptions are wrong as a matter of law.

1. Adjustments to test-year data are not extraordinary relief.

To determine what a utility’s reasonable and necessary expenses are, the Commission determines “the electric utility’s historical test year expenses as adjusted for known and measurable changes.” 16 Tex. Admin. Code § 25.231(b).

Under the rule, known and measurable changes have equal weight with historical Id. at 108.

Id. at 109.

Id. at 108; AR Binder 7, Item 244 (Order on Rehearing at 1).

AR Binder 5, Item 185 (Proposal for Decision at 102). test-year levels. That makes sense, because PURA does not limit a utility’s recoverable expenses to those incurred in a historical test year. Rather, PURA guarantees a utility a reasonable opportunity to earn a reasonable return on its investment over and above its “reasonable and necessary expenses.” Tex. Util.

Code Ann. § 36.051. The goal of ratemaking is to set utility rates that will meet the utility’s and customers’ needs in the future, not the past, as rates are set on a prospective basis.

The Texas Supreme Court has confirmed that making known and measurable adjustments is a critical component of establishing the costs upon which rates are set, and not a rare exception to the use of test-year cost levels. The Court has explained that “changes occurring after the test period, if known, may be taken into consideration by the regulatory agency to help mitigate the effects of inflation and in order to make the test year data as representative as possible of the cost situation that is apt to prevail in the future.” City of El Paso v. Public Util. Comm’n of Tex., 883 S.W.2d 179, 188 (Tex. 1994) (emphasis added).

The recognition of changes to test-year data is especially critical in a case such as this one, where the inability to recover substantial post-test-year expenses inevitably causes ETI to recover an inadequate return, contrary to the requirements of PURA’s fundamental cost-recovery standards. See Tex. Util. Code Ann. § 36.051. The Commission’s conclusion that a utility is somehow less entitled to expenses that occur beyond the test year is contrary to PURA and judicial precedent, and its erroneous application of the known and measurable standard tainted the entirety of its decision on this issue. This is reason enough to reverse the Commission’s decision.

2. Adjustments to test-year data need not be proven with absolute certainty.

The quantum of proof required to establish adjustments to test-year data is not greater than the quantum required to establish the test-year data itself. The Texas Supreme Court has held that known and measurable adjustments should be made if they reflect costs that will be “actually realized,” can be “anticipated with reasonable certainty,” and if they are representative of the costs “apt” to prevail in the future. See City of El Paso, 883 S.W.2d at 188; Suburban Util. Corp., 652 S.W.2d at 362. The standard is not an impossible-to-meet requirement of absolute or virtual certainty. Suburban Util. Corp., 652 S.W.2d at 362. Contrary to its ruling regarding purchased capacity, the Commission in this and other cases has routinely adopted known and measurable adjustments that involve estimates and uncertainty.83 In rejecting ETI’s proposed adjustments to test-year purchased capacity expense, the Commission did not acknowledge or discuss the statute, rule, judicial precedent, or regulatory precedent that guide its inquiry. The decision is

E.g., AR Binder 5, Item 185 (Proposal for Decision at 68 (short-term asset update), 163-64 (payroll adjustments), & 182-86 (ad valorem tax rate update)). contrary to and inconsistent with all those authorities. Under the Commission’s analysis, known and measurable changes routinely adopted by the Commission would never be allowed. The Commission’s ruling is, therefore, arbitrary and capricious. See Starr County v. Starr Industrial Servs., Inc., 584 S.W.2d 352, 355- (Tex. Civ. App. – Austin 1979, writ ref’d n.r.e.). This is another reason the decision must be reversed.

C. The Commission’s wholesale disallowance of any adjustment to test-year levels of capacity costs is not supported by substantial evidence.

The proposed adjustments for third-party purchased capacity expenses are attributable to three contracts the parties call the Frontier, Calpine, and Sam Rayburn Municipal Power Agency (“SRMPA”) contracts. ETI established with reasonable certainty what costs it would incur under each of these contracts while the rates being set in this case would be in effect. The Commission did not discuss the contracts separately, but ruled on them in the aggregate. The Commission said: 77. ETI’s projection of its rate-year third-party capacity contract payments includes numerous assumptions, one of which is that every single third-party supplier will perform at the maximum level under the contract, even though that assumption is inconsistent with ETI’s historical experience.

78. There is substantial uncertainty with regard to ETI’s projection of its rate-year third-party capacity contract payments.84

AR Binder 7, Item 244 (Order on Rehearing at FOFs 77-78); see also AR Binder 5, Item 185 (Proposal for Decision at 108-109).

These findings are not supported by substantial evidence. As discussed below, the adjustments were based on contracts already in place before and during the rate year. The contracts had clearly and specifically ascertainable prices and quantities, which were in evidence. No one disputed that ETI will pay money under these contracts. Rather, some parties speculated that ETI might not have to pay the full amount of these contracts because suppliers might not perform perfectly. Performance under each of the contracts is reasonably assured. There is no reasonable uncertainty regarding the outcome under any of these contracts, certainly none sufficient to support a finding that none of these contract costs are “apt to prevail” in the near future.

1. ETI proved that it will incur an annual capacity cost increase of $15.8 million under the Frontier contract.

There is no reasonable basis in the evidence for the Commission’s finding that the costs of the Frontier contract are uncertain. ETI has had a contract with Frontier for years, leading up to and including the first ten months of the test year.85 In the second-to-last month of the test year, ETI increased the annual amount of power it purchased under the Frontier contract from 150 MW to 300 MW.86 Applying the language of the Texas Supreme Court, the 150 MW increase in capacity and capacity cost was “actually realized” in the test year. But because

AR Binder 43, Vol. L (5/3/12 Tr. at 1938 & 1941). Id. at 1942 & 1959. the step-up happened late in the test year, the test year does not reflect the full amount of expense ETI will incur going forward under the Frontier contract.87 No witness challenged ETI’s quantification of what this contract would cost ETI during the rate year.

On cross-examination at the hearing, ETI’s witness Cooper acknowledged that ETI’s purchased capacity contracts include provisions that authorize ETI to reduce its payments if the counter-party does not perform.88 He explained that ETI did not assume any reduction in future payments for poor performance because in the past, any such adjustments have been “relatively minor.”89 ETI’s witness May, who quantified the increase in annual Frontier costs at $15.8 million, confirmed that ETI has “quite a bit of experiences” with the contract, and a “good understanding of what the costs are today and what the costs will be in the future” under the contract.90 The other parties did not produce evidence to the contrary.

It is simply not reasonable to conclude, based upon this record, that there is “substantial uncertainty” about what ETI’s annual expenses will be in connection with the Frontier increase. The Commission’s findings insofar as they implicate this contract are not supported by substantial evidence.

Id. at 1942.

AR Binder 43, Vol. F (4/26/12 Tr. at 705-06); see also id. at 682.

Id. at 705.

AR Binder 43, Vol. L (5/3/12 Tr. at 1942).

2. ETI proved that it will incur an annual capacity cost increase of $8.1 million under the SRMPA contract.

During the test year, ETI executed a 25-year agreement with SRMPA for MW of capacity.91 Power started flowing under the contract on December 1, 2011, just five months after the end of the test year, well before intervenors filed their testimony in March 2012, and well before the conclusion of the proceeding under review.92 All of the capacity contracted for was allocated to ETI.93 The price of this contract is a “very straightforward $3 per kW a month.”94 It is “very easy to calculate what those known and measurable costs are.”95 $3.00 x 225,000 kW = $675,000 per month. At $675,000 per month, the contract will cost $8.1 million annually. No witness challenged ETI’s quantification of the annual costs of the SRMPA contract. In addition, the SRMPA contract commits “System Capacity,” meaning multiple network resources and substitute resources are designated to supply the capacity. There is no evidence in the record that SRMPA’s entire portfolio of network resources is likely to be simultaneously unavailable.

There is, therefore, no evidence in the record that there is “substantial uncertainty” about whether SRMPA will perform the contract, or what the annual AR Binder 35, ETI Exh. 34 (Cooper Direct at 17 of 25).

See id. Id. at 17 & 19 of 25.

AR Binder 43, Vol. L (5/3/12 Tr. at 1944).

Id. costs of the contract will be. The Commission’s findings insofar as they implicate this contract are not supported by substantial evidence.

3. ETI proved that it will incur an annual capacity cost increase of $14.1 million under the Calpine contract.

ETI purchased capacity from Calpine Energy Services under a one-year contract in effect from June 1, 2008 through May 31, 2009.96 In 2009, ETI entered into a ten-year purchased power agreement with Calpine to purchase 485 MW of capacity from its Carville Energy Center.97 Purchases under this contract were set to begin on June 1, 2012, the beginning of the rate year for this case.98 Fifty percent of the contract was allocated to ETI.99 The resource had been under contract with the Entergy system for some time, and the Entergy companies have significant experience with the pricing and costs under the contract. The most recent contract simply allocated the resource differently to reflect the fact that the “overhang of retail competition” had been lifted for ETI.100 Because of ETI’s experience with Calpine, the capacity costs are “well known.”101 The contract sets out specific capacity quantities and prices, and includes default and other terms to ensure performance. ETI’s historical experience with the Calpine resource establishes that any deviations from the AR Binder 35, ETI Exh. 34 (Cooper Direct at 21-22 of 25).

Id. at 16.

Id. Id. at 19 of 25.

See AR Binder 43, Vol. L (5/3/12 Tr. at 1938).

Id. at 1942. negotiated contract payments will be “very, very small.”102 Both parties to the contract intend and are incentivized to perform such that they will get the full benefits of the capacity and price under the contract.103 ETI projected the annual cost of the Calpine contract will be $14.1 million.104 No witness challenged ETI’s quantification of the costs associated with the Calpine contract. There is no evidence in the record that there is “substantial uncertainty” about whether Calpine will perform the contract, or what the annual costs of the contract will be. The Commission’s findings insofar as they implicate this contract are not supported by substantial evidence.

4. The record does not reasonably support the Commission’s other reasons for disallowing 100 percent of these known capacity costs.

a. Load Growth Intervenors and Commission staff championed multiple theories they alleged would offset ETI’s additional expense under these three contracts. One such theory` was that the cost increase is not known and measurable because it may be offset by load growth that occurs after the test year.105 If it were appropriate to consider future load growth in setting base rates, PURA or the Commission’s rules would say so. Indeed, there are other instances Id. Id. at 1942-43.

AR Binder 8 (Cities Exh. 4B [Highly Sensitive], Goins Direct Exh. DWG-2).

AR Binder 5, Item 185 (Proposal for Decision at 109); AR Binder 7, Item 244 (Order on Rehearing at FOF 84). in which PURA does specify that the utility’s recovery of costs should be subject to an offsetting load growth adjustment. See, e.g., Tex. Util. Code Ann. § 39.455 (utility entitled to recover specified incremental capacity costs “adjusted for load growth”). For base rates, the legislature has left load growth out of the equation, so that it may serve as a source of revenue to address other future cost increases and avoid or defer additional rate increases. The legislature’s inclusion of “load growth” language for specific circumstances but not base rates is evidence the legislature did not intend it to apply generally. Cameron v. Terrell & Garrett, Inc., 618 S.W.2d 535, 540 (Tex. 1981).

Even if load growth could properly be considered, however, it does not support a wholesale disallowance of the increased purchased capacity costs. First, the load growth that intervenors suggested would occur would not fully materialize for at least two years.106 It could not logically offset the third-party capacity cost increases ETI began to experience during or shortly after the test year.

Second, Cities witness Goins is the only intervenor witness who attempted to quantify a load growth adjustment, and he quantified it at $15.8 million – a far cry from the $38 million in increased purchased capacity expense that ETI proved it would incur.107 Moreover, Mr. Goins’s proposal overstated retail load growth

AR Binder 43, Vol. J (5/1/12 Tr. at 1299-1300 [Confidential]).

AR Binder 8 (Cities Exhs. 4 & 4B [Highly Sensitive], Goins Direct at 9 & 16-19). significantly and attempted to predict events beyond the rate year.108 It does not provide a reasonable basis for a known and measurable change at all, much less one that negates all $38 million of ETI’s third-party capacity contract costs.109 The large gap between Mr. Goins’s speculative adjustment and the known costs ETI sought illustrates how far the Commission has strayed from setting rates at a level that will enable ETI to recover the costs it reasonably expects to incur when the rates are in effect. In any event, the Commission’s reliance on the load growth theory to deny ETI any adjustment for its post-test-year increases in third- party purchased capacity costs is not supported by substantial evidence.

b. MSS-1 Costs Another “offset” theory that the Commission adopted concerned the amount of money ETI might save under Schedule MSS-1 as a result of the new third-party purchased capacity contracts. The Commission found that the impact the contracts would have on ETI’s “reserve equalization” payments under Schedule MSS-1 was substantially uncertain, because the calculation of MSS-1 costs depends on “numerous assumptions.”110 The record does not support a wholesale disallowance of ETI’s third-party capacity cost increases on this ground.

Id. at 17-19.

AR Binder 37, ETI Exh. 57 (May Rebuttal at 9-11 of 31); AR Binder 43, Vol. I (5/1/12 Tr. at pp. 1296-1306, 1316-1324 [Confidential]).

AR Binder 5, Item 185 (Proposal for Decision at 108); AR Binder 7, Item 244 (Order on Rehearing at 1 & FOFs 75-76).

Company witness Cooper testified that the MSS-1 cost adjustment is a straightforward calculation.111 While it is true that the MSS-1 amount is dependent on the relative load responsibility of ETI, that relative change in load responsibility was factored into the Company’s calculation.112 Evidence from other parties regarding the MSS-1 costs likewise does not provide substantial evidence justifying a wholesale disallowance of the third-party contract costs. Cities, in fact, adopted ETI’s calculation of MSS-1 impacts.113 And though TIEC argued on one hand that ETI’s MSS-1 expense would increase over test-year levels,114 the evidence, including TIEC’s, is undisputed that MSS-1 costs go down as ETI adds new capacity contracts.115 In fact, the MSS-1 costs decreased during the test year and reached test-year lows during the last two months (when the new Frontier contract was first put in place).116 TIEC’s recommendations regarding MSS-1 costs are contrary to reality and all the record evidence. They certainly do not provide a reasoned basis to reject all of ETI’s proposed increase in third-party purchased capacity costs.

AR Binder 43, Vol. L (5/3/12 Tr. at 1947).

See AR Binder 35, ETI Exh. 34 (Cooper Direct at 20 of 25 & ETI Exh. 34A RRC-1 [Highly Sensitive]).

AR Binder 9, Cities Exh. 6 (Nalepa Direct at 17).

AR Binder 41, TIEC Exh. 1 (Pollock Direct at 26).

AR Binder 41, TIEC Exh. 1D (Pollock Direct at 22, Table 1); AR Binder 9, Cities Exh. 6 (Nalepa Direct Attachment KJN-3 at 2 [Highly Sensitive]).

See AR Binder 9, Cities Exh. 6 (Nalepa Direct Attachment KJN-3 at 2 [Highly Sensitive]). c. MSS-4 Costs The Commission also found that the impact the purchased capacity contracts would have on MSS-4 costs (costs of unit-specific purchases from other Entergy operating companies) was substantially uncertain because the calculation of MSS-4 costs depends on “complex mathematical formulae that utilize numerous variables.”117 However, as shown in the proposal for decision adopted by the Commission, the adjusted MSS-4 costs sought by the Company are lower than the test-year level of MSS-4 costs awarded by the Commission. As the Commission further acknowledged, “while the purchases pursuant to MSS-4 [from test year to rate year] remain fairly stable, the third-party purchases will substantially increase, with a somewhat corresponding decrease for purchases pursuant to MSS-1.”118 In other words, the Commission recognized that the known and measurable adjustment to the test-year amount was driven by third-party purchases, not MSS-4 purchases. The small difference between the test-year and rate-year levels associated with MSS-4 purchases, under the Commission’s own observations, is not material to determining the merits of ETI’s proposed purchased power cost adjustments. In short, alleged uncertainty regarding the rate-year level of MSS-4

AR Binder 7, Item 244 (Order on Rehearing at FOFs 79-82).

AR Binder 5, Item 185 (Proposal for Decision at 100); AR Binder 7, Item 244 (Order on Rehearing at 1, adopting Proposal for Decision). expense is not a reasonable basis for the Commission to reject ETI’s additional third-party purchased power expense.

Even assuming arguendo that the Commission’s rejection of the Company’s adjustment to MSS-4 expense is material to the resolution of this issue, the evidence regarding MSS-4 expense does not support rejection of the entire increase in third-party purchased capacity costs. Similar to ETI, Cities’ and TIEC’s adjustments for MSS-4 costs in all but one respect varied only marginally from the test year. They come nowhere near to offsetting the entire cost of the third-party contracts.119 Cities and TIEC proposed MSS-4 reductions that were materially larger than ETI’s120 only because one of ETI’s Arkansas affiliate contracts (the “WBL” contract) was set to terminate after the test year. Intervenors’ argument was based on the flawed assumption that ETI would take no action to replace the WBL contract. To the contrary, the evidence was undisputed that ETI was short of capacity and in fact extended the very contract in question.121 The dispute over how much ETI might save in MSS-4 costs does not rationally support a disallowance of the entire increase for the new purchased capacity contracts

AR Binder 41, TIEC Exh. 1 (Pollock Direct at Exh. JP-1) (Line 4 shows $1.4 million reduction to test year amount of affiliate contracts)); AR Binder 8, Cities Exh. 4B (Goins Errata Exh. DWG-2 [Highly Sensitive]) (less than $3 million reduction to test-year costs for affiliate contracts excluding WBL). $12.7 million and $11.1 million, respectively.

AR Binder 43, Vol. E (4/26/12 Tr. at 687-88 & 696); AR Binder 37, ETI Exh. 47 (Cooper Rebuttal at 5 of 21); AR Binder 43, Vol. L (5/3/12 Tr. at 1946).

D. The consequences of the Commission’s decision are extreme and unjust.

The three new third-party purchased power contracts that drive ETI’s requested adjustment to test-year capacity costs benefit customers tremendously.

They increase the capacity of ETI resources by 618 MW (150 by the Frontier contract, 225 by the SRMPA contract, and 243 by the half of the Calpine contract allocated to ETI). They result in substantial fuel savings for customers because of their diverse fuel resources and efficient heat rates.122 Customers will benefit from those savings on a dollar-for-dollar basis in fuel reconciliations. While the third- party owners of the capacity resources profit from the capacity payments ETI must make, and the retail customers of ETI benefit from the superior heat rates and resulting fuel savings, the Commission’s order forces the middleman – ETI –to pay for the capacity with shareholder funds.

The Commission’s draconian adherence to the test-year data and incorrect application of the standard for making adjustments to that data are reasons alone to reverse the decision, because they taint every one of the Commission’s findings discussed above. Even disregarding those errors, none of the Commission’s findings rationally justifies the disallowance of 100 percent of the cost increase resulting from the three new contracts. Because the Commission did not quantify

AR Binder 35, ETI Exh. 34 (Cooper Direct at 24 of 25); AR Binder 37, ETI Exh. 47 (Cooper Rebuttal at 7-8 of 21). how much of a disallowance it made upon each individual theory, if this Court finds any of the findings are unsupported by substantial evidence, it must reverse the whole disallowance and remand to the Commission for further consideration.

This Court may not decide fact issues the Commission did not. Tex. Gov’t Code Ann. § 2001.174(1).

III. The Commission erred in setting ETI’s transmission equalization (MSS- 2) expense at the test-year level.

The Commission also erred in refusing to make any adjustment for another known and measurable increase in ETI’s expenses after the test year. The Entergy system transmission grid is a large network, the various pieces of which are owned by individual Entergy operating companies. The network, however, is integrated and operated for the mutual benefit of all of the Entergy operating companies.123 In any given month, some of the operating companies may be “long” on the amount of transmission capacity they own. That is, they own a portion of the transmission capacity that is greater than their share of the overall load placed on the transmission system. Other operating companies may be “short” on capacity.

The Entergy System Agreement includes a FERC-approved Schedule MSS-2 that equalizes the ownership costs of certain high-voltage transmission facilities among the operating companies. The long operating companies receive MSS-2 payments

AR Binder 36, ETI Exh. 39 (Cicio Direct at 15 of 75); AR Binder 43, Vol. C (4/25/12 Tr. at 450); AR Binder 43, Vol. F (4/27/12 Tr. at 793). from the short operating companies for the use of their transmission facilities so that each pays its fair share of the total ownership costs of the shared system on a monthly basis.124 Over the course of the test year, ETI was short, so it paid a total of $1,753,797 in MSS-2 payments to various other operating companies.125 But ETI’s MSS-2 expenses increased at the end of the test year and continued to increase after the test year.126 ETI anticipated these costs would increase even more by the rate year because of transmission projects that were planned to go into service by the rate year.127 ETI calculated that its MSS-2 expenses would be $10.7 million annually by the rate year.128 ETI sought to include that level of its expense in its rates.

The ALJs recommended that the Commission disallow any increase in MSS- expense over the test-year level. They found that the increased expenses were not “known and measurable,” again because the MSS-2 calculation depends on variables and projections, and because not all the projects ETI included in its

AR Binder 36, ETI Exh. 39 (Cicio Direct at 15 of 75); AR Binder 43, Vol. F (4/27/12 Tr. at & 735-36).

AR Binder 43, Vol. F (4/27/12 Tr. at 724 & 737); AR Binder 9, Cities Exh. 28.

AR Binder 9, Cities Exh. 29.

AR Binder 43, Vol. F (4/27/12 Tr. at 761); AR Binder 37, ETI Exh. 59 (McCulla Rebuttal at 2-3 of 12).

AR Binder 43, Vol. C (4/25/12 Tr. at 452-53); AR Binder 43, Vol. F (4/27/12 Tr. at 738 & 760). calculation were in service during the test year.129 The Commission adopted the ALJs’ recommendation that only the test-year level of MSS-2 expense should be included in ETI’s rates.130 A. The Commission erred as a matter of law in applying the standard for adjustments to test-year expenses.

The Commission’s decision is flawed as a matter of law for the same reason its decision about purchased capacity costs is flawed. That is, the goal of ratemaking is to give the utility a reasonable opportunity to earn a reasonable return on its investment over and above its reasonable and necessary expenses. Tex. Util. Code Ann. § 36.051. Commission Rule 25.231 mirrors this principle.

None of the opposing parties’ witnesses refuted that the projects underlying ETI’s proposed MSS-2 adjustment were already approved and in process, or that

AR Binder 5, Item 185 (Proposal for Decision at 116 & FOFs 87-93).

AR Binder 7, Item 244 (Order on Rehearing at 1 & FOFs 87-94). they will be completed. No intervenor or Staff witness offered any testimony or evidence casting doubt on the reasonableness of the construction cost estimates.

Their position was simply that if there is any possibility of uncertainty or variability in the elements of an adjustment to test-year data, it must be denied.

The Commission erred as a matter of law in adopting that standard.

B. Additionally, the Commission’s adherence to test-year expense levels is unsupported by substantial evidence.

It is undisputed that ETI’s test-year level of MSS-2 expense was too low.

Every witness testifying on the issue recognized that the test-year amount is too small and should be updated based on more recent, actual payment information.

ETI proffered evidence that by the time of the hearing, its annualized MSS-2 expenses based upon actual, known, historical investment exceeded test-year levels by about $6.7 million, and its rate-year MSS-2 expenses would exceed test- year levels by almost $9 million.131 TIEC witness Pollock annualized the last six months of the test-year expense, increasing it by a million dollars.132 Cities witness Goins also rejected the test-year expense level and instead used a more recent 12-month period of actual payments, including six months that occurred after the test year. He recommended the Commission include an annual expense of

AR Binder 43, Vol. C (4/25/12 Tr. at 452-53); AR Binder 43, Vol. F (4/27/12 Tr. at 738, 760, 763, 780, & 783-84).

AR Binder 41, TIEC Exh. 1 (Pollock Direct at 32-33). $4.1 million in ETI’s rates, exceeding the test year by almost $2.5 million.133 Indeed, Cities Exhibit 29 includes the MSS-2 payment for every month from January 2010 to February 2012. It shows that MSS-2 costs have steadily increased every month from the last month of the test year, and in fact have doubled since the last month of the test year.134 No witness testified that the test year was representative of the expense ETI would bear during the rate year. The Commission’s decision that the test-year level of MSS-2 expense is sufficient is simply not supported by any evidence in the record.

Viewing the evidence as a whole, there is no reasonable basis for a conclusion that the test-year level of $1.7 million is representative of costs apt to prevail in the future. The Commission’s ruling is, therefore, unsupported by substantial evidence and must be reversed. Tex. Gov’t Code Ann. § 2001.174(b)(2).

CONCLUSION AND PRAYER For all these reasons, Entergy Texas, Inc. respectfully requests this Court reverse the district court’s judgment insofar as it affirms the Public Utility Commission’s order in the respects discussed above. ETI requests the Court remand the case to the Commission for further proceedings consistent with the

AR Binder 8, Cities Exh. 4 (Goins Direct at 21-22).

AR Binder 9, Cities Exh. 29 (Response of ETI to Cities RFI 5-1).

Court’s decision. Entergy Texas, Inc. further requests its costs of court and any other relief to which it may show itself justly entitled.

Respectfully submitted,

/s/ Marnie A. McCormick John F. Williams State Bar No. 21554100 Marnie A. McCormick State Bar No. 00794264 [email protected] DUGGINS WREN MANN & ROMERO, LLP P. O. Box 1149 Austin, Texas 78767-1149 (512) 744-9300 (512) 744-9399 fax ATTORNEYS FOR APPELLANT ENTERGY TEXAS, INC.

CERTIFICATE OF COMPLIANCE I certify that this document contains 10,765 words in the portions of the document that are subject to the word limits of Texas Rule of Appellate Procedure 9.4(i), as measured by the undersigned’s word-processing software.

/s/ Marnie A. McCormick Marnie A. McCormick

CERTIFICATE OF SERVICE The undersigned counsel certifies that the foregoing document was electronically filed with the Clerk of the Court using the electronic case filing system of the Court, and that a true and correct copy was served on the following lead counsel for all parties via electronic service on the 31st day of March, 2015: Elizabeth R. B. Sterling Environmental Protection Division Office of the Attorney General P. O. Box 12548 (MC 066) Austin TX 78711-2548 Counsel for Appellee Public Utility Commission of Texas Rex D. VanMiddlesworth Benjamin Hallmark Thompson Knight LLP San Jacinto Blvd., Ste. 1900 Austin TX 78701 Counsel for Intervenor Texas Industrial Energy Consumers Susan M. Kelley (retired)135 Administrative Law Division Office of the Attorney General P. O. Box 12548 Austin TX 78711-2548 Counsel for Intervenor State Agencies Sara Ferris Office of Public Utility Counsel 1701 N. Congress Ave., Ste. 9-180 P. O. Box 12397 Austin TX 78711-2397 Counsel for Intervenor Office of Public Utility Counsel

State Agencies have not yet appeared or designated a new lead counsel in this appeal.

Daniel J. Lawton LAWTON LAW FIRM PC 12600 Hill Country Blvd., Ste. R-275 Austin TX 78738 Counsel for Cities of Anahuac, et al.

/s/ Marnie A. McCormick Marnie A. McCormick

APPENDICES A. ALJs’ Proposal for Decision in Docket No. 39896 B. Commission's Order on Rehearing in Docket No. 39896 C. District Court's Final Judgment D. Commission’s Final Order in Docket No. 37744

APPENDIX A ALJ's Proposal for Decision in Docket No. 39896 SOAH DOCKET NO. XXX-XX-XXXX PUC DOCKET NO. 39896 APPLICATION OF ENTERGY TEXAS, § BEFORE THE STATE OFFICE INC. FOR AUTHORITY TO CHANGE § RATES, RECONCILE FUEL COSTS, § OF AND OBTAIN DEFERRED § ACCOUNTING TREATMENT § ADMINISTRATIVE HEARINGS PROPOSAL FOR DECISION TABLE OF CONTENTS

I. INTRODUCTION [Germane to Preliminary Order Issue Nos. 1 and 4]........ 1 II. JURISDICTION AND NOTICE ......................................................................... 2 III. PROCEDURAL HISTORY ................................................................................. 2 IV. EXECUTIVE SUMMARY .................................................................................. 4 A. Rate Base................................................................................................................ 4 1. Capital Investment .................................................................................... 4 2. Hurricane Rita Regulatory Asset ............................................................ 4 3. Prepaid Pension Asset Balance ................................................................ 5 4. FIN 48 Tax Adjustment ............................................................................ 5 5. Cash Working Capital .............................................................................. 5 6. Self-Insurance Storm Reserve ................................................................. 5 7. Coal Inventory........................................................................................... 5 8. Spindletop Gas Storage Facility .............................................................. 5 9. Short Term Assets ..................................................................................... 6 10. Acquisition Adjustment ............................................................................ 6 11. Capitalized Incentive Compensation ...................................................... 6 B. Rate of Return and Capital Structure ................................................................ 6 C. Cost of Service ....................................................................................................... 7 1. Purchased Power Capacity Expense ....................................................... 7 2. Transmission Equalization (MSS-2) Expense ........................................ 7 3. Depreciation Expense ............................................................................... 7 4. Labor Costs................................................................................................ 7 SOAH DOCKET NO. XXX-XX-XXXX TABLE OF CONTENTS PAGE II PUC DOCKET NO. 39896

5. Interest on Customer Deposits................................................................. 8 6. Property (Ad Valorem) Tax Expense ...................................................... 9 7. Advertising, Dues, and Contributions..................................................... 9 8. Other Revenue Related Adjustments ...................................................... 9 9. Federal Income Tax .................................................................................. 9 10. River Bend Decommissioning Expense ................................................... 9 11. Self-Insurance Storm Reserve Expense .................................................. 9 12. Spindletop Gas Storage Facility ............................................................ 10 D. Affiliate Transactions ......................................................................................... 10 E. Jurisdictional Cost Allocation............................................................................ 10 F. Class Cost Allocation .......................................................................................... 11 1. Renewable Energy Credit Rider............................................................ 11 2. Class Cost Allocation .............................................................................. 11 3. Revenue Allocation ................................................................................. 12 4. Rate Design .............................................................................................. 12 G. MISO Transition ................................................................................................. 14 V. RATE BASE [Germane to Preliminary Order Issue Nos. 4, 10, and 16] ...... 14 A. Capital Investment [Germane to Preliminary Order Issue No. 17] ............... 14 B. Hurricane Rita Regulatory Asset ...................................................................... 15 C. Prepaid Pension Asset Balance .......................................................................... 23 D. FIN 48 Tax Adjustment ...................................................................................... 26 E. Cash Working Capital ........................................................................................ 30 1. The Revenue Lag Component of the Lead-Lag Study ........................ 31 2. The Expense Lead Component of the Lead-Lag Study ....................... 39 F. Self-Insurance Storm Reserve [Germane to Preliminary Order Issue No. 5] .................................................................................................................... 45 1. The Effect of Prior Settled Cases........................................................... 46 2. OPC’s Proposed Adjustment ................................................................. 49 3. 1997 Ice Storm ......................................................................................... 54 4. Jurisdictional Separation Plan Allocation ............................................ 57 5. $50,000 Reserve Threshold .................................................................... 58 6. Hurricane Rita Regulatory Asset .......................................................... 60 SOAH DOCKET NO. XXX-XX-XXXX TABLE OF CONTENTS PAGE III PUC DOCKET NO. 39896

7. Conclusion ............................................................................................... 60 G. Coal Inventory..................................................................................................... 61 H. Spindletop Gas Storage Facility ........................................................................ 63 I. Short Term Assets ............................................................................................... 68 J. Acquisition Adjustment ...................................................................................... 69 K. Capitalized Incentive Compensation ................................................................ 71 VI. RATE OF RETURN [Germane to Preliminary Order Issue Nos. 4 and 11] ......................................................................................................................... 73 A. Capital Structure ................................................................................................ 73 B. Return on Equity................................................................................................. 73 1. Proxy Group ............................................................................................ 74 2. DCF Analysis ........................................................................................... 76 3. Risk Premium Analysis .......................................................................... 83 4. Comparable Earnings............................................................................. 88 5. CAPM Analysis ....................................................................................... 90 6. ALJs’ Analysis......................................................................................... 93 C. Cost of Debt ......................................................................................................... 95 D. Overall Rate of Return ....................................................................................... 95 VII. OPERATING EXPENSES [Germane to Preliminary Order Issue Nos. 2, 3, 4, and 16] .......................................................................................................... 95 A. Purchased Power Capacity Expense [Germane to Supplemental Preliminary Order Issue No. 1] ......................................................................... 95 1. The Sources of ETI’s Purchased Power................................................ 95 2. ETI’s Request Regarding PPCCs .......................................................... 99 3. Staff and Intervenors’ Opposition to ETI’s PPCCs Proposal .......... 101 4. The Intervenors’ Recommendations Regarding PPCCs ................... 106 5. The ALJs’ Analysis Regarding PPCCs ............................................... 108 B. Transmission Equalization (MSS-2) Expense ................................................ 110 C. Depreciation Expense [Germane to Preliminary Order Issue No. 12] ........ 117 1. Terminology and Methodology............................................................ 118 2. Production Plant ................................................................................... 125 3. Transmission Plant ............................................................................... 132 SOAH DOCKET NO. XXX-XX-XXXX TABLE OF CONTENTS PAGE IV PUC DOCKET NO. 39896

4. Distribution Plant ................................................................................. 140 5. General Plant......................................................................................... 154 6. Fully Accrued Depreciation ................................................................. 160 7. Other Depreciation Issues – Accumulated Provision for Depreciation .......................................................................................... 161 D. Labor Costs........................................................................................................ 163 1. Payroll and Related Adjustments ........................................................ 163 2. Incentive Compensation ....................................................................... 165 3. Compensation and Benefits Levels ...................................................... 175 4. Non-Qualified Executive Retirement Benefits ................................... 177 5. Employee Relocation Costs .................................................................. 179 6. Executive Perquisites ............................................................................ 180 E. Interest on Customer Deposits......................................................................... 181 F. Property (Ad Valorem) Tax Expense .............................................................. 181 G. Advertising, Dues, and Contributions............................................................. 185 H. Other Revenue-Related Adjustments ............................................................. 185 I. Federal Income Tax .......................................................................................... 185 J. River Bend Decommissioning Expense ........................................................... 186 K. Self-Insurance Storm Reserve Expense [Germane to Preliminary Order Issue No. 5]......................................................................................................... 188 L. Spindletop Gas Storage Facility ...................................................................... 193 VIII. AFFILIATE TRANSACTIONS [Germane to Preliminary Order Issue No. 3] .................................................................................................................. 194 A. Large Industrial & Commercial Sales Reallocation ...................................... 199 B. Administration Costs ........................................................................................ 201 C. Customer Service Operations Class ................................................................ 202 1. Projects F3PCR29324 (Revenue Assurance - Adm.), F3PCR53095 (Headquarter’s Credit & Collect), F3PCR73380 (Credit Systems), and F3PCR73458 (Credit Call Outsourcing) .................... 202 2. Projects F3PCR73381 (Customer Svc Cntr Credit Desk), F3PCR73390 (Customer Svs Ctl - Entergy Bus), and F3PCR73403 (Customer Issue Resolution – ES) ............................... 203 D. Distribution Operations Class ......................................................................... 203 1. Project F5PCDW0200 (Lineman’s Rodeo Expenses) ........................ 204 SOAH DOCKET NO. XXX-XX-XXXX TABLE OF CONTENTS PAGE V PUC DOCKET NO. 39896

2. Projects F3PCTJGUSE (Joint Use With Third Party – E) and F3PCTJTUSE (Joint Use With Third Parties – A)............................ 204 E. Energy and Fuel Management Class .............................................................. 205 1. Project F3PCWE0140 (EMO Regulatory Affairs) ............................ 205 2. Projects F3PPSPE003 (SPO Summer 2009 RFP Expense), F3PPSPE003 (SPO Summer 2009 RFP Expense), F3PPSPE004 (SPO Summer09RFP IM & Propslsubmt), and F3PPWET303 (SPO2008 Winter Westn RegionRFP-IM) ......................................... 206 3. Project F3PCCSPSYS (System Planning and Strategic) .................. 207 F. Environmental Service Class ........................................................................... 207 G. Federal PRG Affairs Class ............................................................................... 209 1. Project F5PPSPE044 (PMO Support Initiative-System) .................. 209 2. Project F3PPUTLDER (Utility Derivatives Compliance) ................. 210 3. Project F3PCSYSRAF (System Regulatory Affairs-Federal) .......... 211 H. Financial Services Class ................................................................................... 214 1. Projects F3PCF05700 (Corporate Planning & Analysis), F3PCF21600 (Corp Rptg Analysis & Policy), F3PCFF1000 (Financial Forecasting), F3PPADSENT (Analytic/Decision Support-Entergy), and F3PPSPSENT (Strategic Planning Svcs- Entergy) ................................................................................................. 214 2. Projects F3PCF20990 (Operations Exec VP & CFO) and F3PCFF1001 (OCE Support)............................................................... 215 3. Project F3PCR73345 (Quick Payment Center, Adm) ....................... 216 4. Project F3PCF23936 (Manage Cash) .................................................. 217 I. Human Resources Class ................................................................................... 218 1. Project F3PCHRCCSM (HR Competitive Compensation) .............. 218 2. Projects (Non-Qualified Post-Retirement) and F5PPZNQBDU (Non-Qual Pension/Benf-Dom Utl)...................................................... 219 J. Information Technology Class ......................................................................... 219 1. (Evaluated Receipts Settlement) ......................................................... 220 2. Project F3PCFX3555 (BOD/Executive Support) ............................... 220 K. Internal and External Communications Class ............................................... 221 L. Legal Services Class .......................................................................................... 222 1. Project F3PPCASHCT (Contractual Alternative/Cashpo) .............. 223 SOAH DOCKET NO. XXX-XX-XXXX TABLE OF CONTENTS PAGE VI PUC DOCKET NO. 39896

2. Project F5PCZLDEPT (Supervision & Support – Legal)................. 223 3. Project F3PCF99180 (Corp. Compliance Tracking Sys) .................. 223 4. Projects F3PPINVDOJ (DOJ Anti Trust Investigation) and F3PPTDHY19 (Dept. of Justice Investigation) .................................. 224 5. Project F3PCE01601 (Ferc - Access Transmission) ......................... 226 6. Project F3PCERAKTL (RAKTL Patent Matter) ............................. 227 7. Project F3PPEASTIN (Willard Eastin et al.) ..................................... 228 8. Project F3PPTCGS11 (TX Docket Competitive Generation) .......... 229 9. Project F5PCE13759 (Jenkins Class Action Suit) ............................. 230 10. Project F3PCSYSAGR (System Agreement-2001) ............................ 231 11. Project F3PCCDVDAT (Corporate Development Data Room) ....... 232 12. Project F3PPWET302 (SPO 2008 Winter Western Region) ............ 233 13. Project F3PPWET308 (SPO Calpine PPA/Project Houston) ........... 234 M. Other Expenses Class ....................................................................................... 235 1. Projects F3PCSPETEI (Entergy-Tulane Energy Institute) and F5PPKATRPT (Storm Cost Processing & Review) .......................... 235 2. Project F3PCC08500 (Executive VP, Operations)............................. 236 3. Projects F3PPBFMESI (ESI Function Migration Relocation), F3PPBFRESI (ESI Business Function ), F3PPDRPESI (ESI Disaster Recovery Plan Charge), F5PPBFMREL (Business Function Migration Employee), F5PPBFRREL (Business Function Relocation), F5PPBFRSEV (Business Function Relocation Severance), F5PPDRPREL (Disaster Recovery Plan Relocation), and F5PPETXRFI (2009 Texas Ike Recovery Filing) .. 236 N. Regulatory Services Class ................................................................................ 238 O. Retail Operations Class .................................................................................... 239 1. Project F5PPICCIMG (ICC – “Image” Message) ............................. 240 2. Projects F3PPR56640 (Wholesale - EGS-TX) and F3PPR56920 (Wholesale - All Jurisdictions) ............................................................. 240 P. Supply Chain Class ........................................................................................... 241 Q. Transmission and Distribution Support Class ............................................... 242 R. Tax Services Class ............................................................................................. 244 S. Transmission Operations Class ....................................................................... 245 T. Treasury Operations Class .............................................................................. 246 SOAH DOCKET NO. XXX-XX-XXXX TABLE OF CONTENTS PAGE VII PUC DOCKET NO. 39896

U. Utility and Executive Management Class ....................................................... 249 IX. JURISDICTIONAL COST ALLOCATION [Germane to Preliminary Order Issue No. 13] ........................................................................................... 250 A. A&E 4CP ........................................................................................................... 251 B. 12CP ................................................................................................................... 252 X. CLASS COST ALLOCATION AND RATE DESIGN [Germane to Preliminary Order Issue No. 1] ....................................................................... 255 A. Renewable Energy Credit Rider [Germane to Preliminary Order Issue No. 19] ................................................................................................................ 255 1. ETI’s Proposed Cost Recovery ............................................................ 255 2. Opposition to ETI’s Proposal .............................................................. 256 3. ETI’s Response ...................................................................................... 260 4. ALJs’ Analysis....................................................................................... 261 B. Class Cost Allocation [Germane to Preliminary Order Issue No. 14] ......... 262 1. Municipal Franchise Fees .................................................................... 262 2. Miscellaneous Gross Receipts Taxes ................................................... 267 3. Capacity-Related Production Costs .................................................... 268 4. Transmission Costs ............................................................................... 273 C. Revenue Allocation ........................................................................................... 274 1. Argument for Moving Rates to Cost ................................................... 275 2. Argument for Gradualism ................................................................... 278 3. ALJs’ Recommendation ....................................................................... 281 D. Rate Design [Germane to Preliminary Order Issue Nos. 15, 18, and 20] .... 282 1. Lighting and Traffic Signal Schedules ................................................ 283 2. Demand Ratchet .................................................................................... 287 3. Large Industrial Power Service (LIPS) .............................................. 295 4. Schedulable Intermittent Pumping Service (SIPS)............................ 299 5. Standby Maintenance Service (SMS) .................................................. 303 6. Additional Facilities Charge (AFC) .................................................... 310 7. Large General Service (LGS) .............................................................. 313 8. General Service (GS) ............................................................................ 315 9. Residential Service (RS) ....................................................................... 315 SOAH DOCKET NO. XXX-XX-XXXX TABLE OF CONTENTS PAGE VIII PUC DOCKET NO. 39896

XI. FUEL RECONCILIATION [Germane to Preliminary Order Issue Nos. 21-31] ......................................................................................................... 319 A. Spindletop Gas Storage Facility ...................................................................... 324 B. Use of Current Line Losses for Fuel Cost Allocation .................................... 325 C. ETI’s Special Circumstances Request ............................................................ 326 XII. OTHER ISSUES ............................................................................................... 327 A. MISO Transition Expenses [Germane to Preliminary Order Issue Nos. 6-8 and Docket No. 39741 Preliminary Order Issue Nos. 1-9] ............. 327 1. Deferred Accounting............................................................................. 329 2. Base Rate Recovery............................................................................... 336 B. TCRF Baseline [Germane to Supplemental Preliminary Order Issue No. 2] .................................................................................................................. 338 C. DCRF Baseline [Germane to Supplemental Preliminary Order Issue No. 2] .................................................................................................................. 338 D. Purchased Power Capacity Cost Baseline [Germane to Supplemental Preliminary Order Issue No. 1] ....................................................................... 339 XIII. CONCLUSION ................................................................................................. 341 XIV. PROPOSED FINDINGS OF FACT, CONCLUSIONS OF LAW, AND ORDERING PARAGRAPHS .......................................................................... 341 A. Findings of Fact ................................................................................................. 341 B. Conclusions of Law ........................................................................................... 364 C. Proposed Ordering Paragraphs ...................................................................... 366 List of Acronyms and Defined Terms Attachment A List of Acronyms and Defined Terms TERM DEFINITION 12CP 12 Coincident Peak A&E 4CP Average and Excess, 4 Coincident Peak A&P Average and Single Coincident Peak ADFIT Accumulated Deferred Federal Income Tax AFC Additional Facilities Charge AFUDC Allowance for Funds Used During Construction ALJs Administrative Law Judges BCII/U3 Big Cajun II, Unit 3 Brazos Brazos Electric Cooperative, Inc. Calpine Calpine Energy Services Contract for the purchase of 485 MW of capacity from Carville Contract Calpine’s Carville Energy Center CAPM Capital Asset Pricing Model CenterPoint CenterPoint Energy Houston Electric, LLC CGS Competitive Generation Service CI Conformance Index Anahuac, Beaumont, Bridge City, Cleveland, Conroe, Dayton, Groves, Houston, Huntsville, Montgomery, Navasota, Nederland, Oak Ridge North, Orange, Pine Forest, Rose City, Pinehurst, Port Arthur, Port Neches, Shenandoah, Silsbee, Sour Lake, Splendora, Vidor, and Cities West Orange, Texas Commission Public Utility Commission of Texas Company Entergy Texas, Inc. CP Coincident Peak CWIP Construction Work in Progress DCF Discounted Cash Flow DCRF Distribution Cost Recovery Factor DOE United States Department of Energy DOJ United States Department of Justice EAI Entergy Arkansas, Inc. EA WBL 2009 Contract between ETI and EAI for Wholesale Base Contract Load Resources EGSI Entergy Gulf States, Inc., predecessor to ETI EGSL Entergy Gulf States Louisiana, LLC ELL Entergy Louisiana, Inc. EMI Entergy Mississippi, Inc. Enbridge Long-term Gas Supply Contract between ETI and Enbridge Contract Pipeline, L.P. ENOI Entergy New Orleans, Inc. Entergy Entergy Corporation TERM DEFINITION ESI Entergy Services, Inc. ETEC East Texas Electric Cooperative, Inc. ETI Entergy Texas, Inc. FAS 106 FASB Statement No. 106 FASB Financial Accounting Standards Board FERC Federal Energy Regulatory Commission FIN 48 Financial Interpretation Number 48 GAAP Generally Accepted Accounting Principles GDP Gross Domestic Product GS General Service GSU Gulf States Utilities Company Iowa Curves Various Known Patterns of Industrial Asset Mortality Rates IRS Internal Revenue Service ISB Intra-System Bill Class action lawsuit filed in Texas district court in 2003 on Jenkins Class behalf of all Texas retail customers served by ETI’s Action predecessor-in-interest, EGSI Kroger The Kroger Co. kW Kilowatt kWh Kilowatt-hour LED Light Emitting Diode LGS Large General Service LIPS Large Industrial Power Service MFF Municipal Franchise Fees MGRT Miscellaneous Gross Receipts Tax MISO Midwest Independent Transmission System Operator, Inc. MSS-2 Schedule MSS-2 of the Entergy System Agreement MW Megawatt Moody’s Moody’s Investors Service MWh Megawatt-hour NARUC National Association of Regulatory Utility Commissioners Nelson Nelson 6, a 550 MW Unit located in Westlake, Louisiana O&M Operations and Maintenance OATT Open Access Transmission Tariff OPC Office of Public Utility Counsel PFD Proposal for Decision PPCCs Purchased Power Capacity Costs PPR Purchased Power Rider PUC Public Utility Commission of Texas PURA Public Utility Regulatory Act Rate Year June 1, 2012, through May 31, 2013 Reconciliation Period July 1, 2009, through June 30, 2011 TERM DEFINITION RECs Renewable Energy Credits Reserve Strategic Petroleum Reserve River Bend River Bend Nuclear Generating Station Unit No. 1 ROE Return on Equity RRC Railroad Commission of Texas RS Residential Service RTO Regional Transmission Organization S&P Standard & Poor’s SFAS Statement of Financial Accounting Standards SIPS Schedulable Intermittent Pumping Service SMS Standby Maintenance Service SOAH State Office of Administrative Hearings Spindletop Facility Spindletop Gas Storage Facility SRMPA Sam Rayburn Municipal Power Agency Staff Staff of the Public Utility Commission of Texas State Agencies State of Texas State Agencies T&D Transmission and Distribution TCRF Transmission Cost Recovery Factor Test Year July 1, 2010, through June 30, 2011 TIEC Texas Industrial Energy Consumers Value Line Value Line Investment Survey Wal-Mart Wal-Mart Stores, LLC, and Sam’s East, Inc. Zacks Zacks Investment Service SOAH DOCKET NO. XXX-XX-XXXX PUC DOCKET NO. 39896 APPLICATION OF ENTERGY TEXAS, § BEFORE THE STATE OFFICE INC. FOR AUTHORITY TO CHANGE § RATES, RECONCILE FUEL COSTS, § OF AND OBTAIN DEFERRED § ACCOUNTING TREATMENT § ADMINISTRATIVE HEARINGS

PROPOSAL FOR DECISION I. INTRODUCTION [Germane to Preliminary Order Issue Nos. 1 and 4] Entergy Texas, Inc. (ETI or the Company) is an investor-owned electric utility with a retail service area located in southeastern Texas. ETI serves retail and wholesale electric customers in Texas. As of June 30, 2011, ETI served approximately 412,000 Texas retail customers. The Federal Energy Regulatory Commission (FERC) regulates ETI’s wholesale electric operations.

On November 28, 2011, ETI filed an application requesting approval of: (1) a proposed increase in annual base rate revenues of approximately $111.8 million over adjusted revenues for the period beginning July 1, 2010, and ending June 30, 2011 (Test Year); (2) a set of proposed tariff schedules presented in the Electric Utility Rate Filing Package for Generating Utilities accompanying ETI’s application and including new riders for recovery of costs related to purchased power capacity and renewable energy credit requirements; (3) a request for final reconciliation of ETI’s fuel and purchased power costs for the reconciliation period from July 1, 2009, to June 30, 2011 (Reconciliation Period); and (4) certain waivers to the instructions in Rate Filing Package Schedule V accompanying ETI’s application. The rate year for ETI’s proposed changes is June 1, 2012, through May 31, 2013 (Rate Year).1 On April 13, 2012, adjusted its request for a proposed increase in annual base rate revenues to approximately $104.8 million over adjusted Test Year revenues.

During the hearing the parties used the term “Rate Year” to refer to the period June 2012 through May 2013. This was intended to represent the first 12 months of the rates adopted in this case. However, the rates in this case will not go into effect (as temporary rates) until at least June 30, 2012. Nevertheless, for purposes of this PFD, Rate Year will refer to the period June 2012 through May 2013.

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II. JURISDICTION AND NOTICE The Public Utility Commission of Texas (Commission or PUC) has jurisdiction over ETI and this rate case application pursuant to Public Utility Regulatory Act (PURA) §§ 14.001, 32.001, 33.002, and 35.004. The State Office of Administrative Hearings (SOAH) has jurisdiction over the contested case hearing, including the preparation of the proposal for decision (PFD) pursuant to PURA § 14.053 and Tex. Gov’t Code § 2003.049(b). Those municipalities in ETI’s service area that have not surrendered jurisdiction to the Commission continue to have exclusive original jurisdiction over ETI’s rates, operations, and services in their respective municipalities pursuant to PURA § 33.001. When ETI filed its application with the Commission, it also filed the application with its original jurisdiction cities. Pursuant to PURA §§ 32.001(b), 33.051, and 33.053, ETI appealed the actions of the original jurisdiction cities to the Commission and had those appeals consolidated with this docket.

ETI’s notice of its application and notice of the hearing were not contested and, therefore, do not require further discussion but will be addressed in the proposed findings of fact and conclusions of law.

III. PROCEDURAL HISTORY As noted above, ETI filed its application and rate filing package on November 28, 2011. On November 29, 2011, the Commission referred this proceeding to SOAH. On December 19, 2011, the Commission issued its Preliminary Order setting forth 31 issues to be addressed in this proceeding. On January 19, 2012, the Commission issued a Supplemental Preliminary Order listing two additional issues to be considered and stating that ETI’s request for a purchased power cost recovery rider should not be addressed in this docket.

On September 2, 2011, ETI filed an application requesting authority to defer accounting related to its proposed transition to membership in the Midwest Independent Transmission System Operator, Inc. (MISO). This proceeding was docketed as Docket No. 39741. On November 22, 2011, the Commission issued its Preliminary Order in Docket No. 39741 addressing certain SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 3 PUC DOCKET NO. 39896

threshold legal/policy questions and setting forth nine issues to be addressed in the proceeding. On December 20, 2011, Docket No. 39741 was consolidated into this docket for all purposes.

The following entities were granted intervenor status in this case: Texas Industrial Energy Consumers (TIEC); State of Texas State Agencies (State Agencies); Office of Public Utility Counsel (OPC); the Cities of Anahuac, Beaumont, Bridge City, Cleveland, Conroe, Dayton, Groves, Houston, Huntsville, Montgomery, Navasota, Nederland, Oak Ridge North, Orange, Pine Forest, Rose City, Pinehurst, Port Arthur, Port Neches, Shenandoah, Silsbee, Sour Lake, Splendora, Vidor, and West Orange (Cities); The Kroger Co. (Kroger); Wal-Mart Stores, LLC, and Sam’s East, Inc. (Wal-Mart); East Texas Electric Cooperative, Inc. (ETEC); and the United States Department of Energy (DOE).

The hearing on the merits convened before SOAH Administrative Law Judges (ALJs) Thomas H. Walston, Steven D. Arnold, and Hunter Burkhalter on April 24, 2012, and continued through May 4, 2012. The record remained open for the filing of post-hearing briefs and proposed finds of fact and conclusions of law. On June 8, 2012, the parties filed proposed finds of fact and conclusions of law and the record closed. As permitted by P.U.C. PROC. R. 22.261(a), ALJ Lilo D.

Pomerleau read the record and joined in writing the PFD. Number running began on June 26, 2012, and Staff returned the final numbers to the ALJs on July 3, 2012. The parties requested that the ALJs submit their PFD so the Commission could consider the matter at its July 27, 2012, open meeting.

The following is a list of the parties who participated in the hearing and their counsel:

PARTIES REPRESENTATIVES ETI Steven H. Neinast, Casey Wren, and John F. Williams2 Cities Daniel J. Lawton, Stephen Mack, and Molly Mayhall TIEC Rex. D. VanMiddlesworth, Meghan Griffiths, and James Nortey State of Texas Susan Kelley OPC Sara J. Ferris DOE Steven A. Porter Several other attorneys appeared on behalf of ETI. The ALJs listed only the three attorneys who appeared throughout the hearing.

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PARTIES REPRESENTATIVES Kroger Kurt J. Boehm Wal-Mart Rick D. Chamberlain Staff Scott Smyth, Joseph Younger, Jacob J. Lawler, and Jason Haas

IV. EXECUTIVE SUMMARY ETI proposed an overall increase of approximately $104.8 million. The ALJs recommend an overall rate increase for ETI of $16.4 million, as shown on the schedules attached to this PFD. With respect to ETI’s request to reconcile fuel and purchased power costs during the Reconciliation Period, the ALJs recommend approval without change. Attachment A contains the schedules provided by Commission Staff reflecting the ALJs’ recommendations. On issues of particular significance, the ALJs’ recommendations are set forth below.

A. Rate Base 1. Capital Investment ETI’s capital additions closed to plant in service between July 1, 2009, and June 30, 2011, were prudently incurred and are used and useful in providing service to ETI’s customers.

2. Hurricane Rita Regulatory Asset The appropriate calculation of the Hurricane Rita regulatory asset should begin with the amount claimed by ETI in Docket No. 37744,3 less amortization accruals to the end of the Test Year in the present case, and less the amount of additional insurance proceeds received by ETI after the conclusion of Docket No. 37744. This produces a remaining balance of $15,175,563, which should remain in rate base as a regulatory asset, applying a five-year amortization rate that commenced August 15, 2010. Further, the Hurricane Rita regulatory asset should not be moved to the storm insurance reserve.

Application of Entergy Texas, Inc. for Authority to Change Rates and Reconcile Fuel Costs, Docket SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 5 PUC DOCKET NO. 39896

3. Prepaid Pension Asset Balance The construction work in progress (CWIP)-related portion of ETI’s pension asset ($25,311,236 out of the total asset) should be excluded from the asset, but accrue allowance for funds used during construction.

4. FIN 48 Tax Adjustment The Commission should find that $4,621,778 (representing ETI’s full FIN 48 Liability of $5,916,461 less the $1,294,683 cash deposit ETI has made with the Internal Revenue Service (IRS) for the FIN 48 Liability) should be added to ETI’s ADFIT and thus be used to reduce ETI’s rate base.

5. Cash Working Capital The ALJs recommend no changes to ETI’s cash working capital.

6. Self-Insurance Storm Reserve The Commission should approve ETI’s Test Year-end storm reserve balance of negative $59,799,744.

7. Coal Inventory The full value of ETI’s coal inventory was reasonable and should be included in rate base.

8. Spindletop Gas Storage Facility The Spindletop Gas Storage Facility (Spindletop Facility) is a used and useful facility providing reliability and swing flexibility to ETI’s customers at a reasonable price and should be included in rate base.

No. 37744 (Dec. 13, 2010).

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9. Short Term Assets The ALJs recommend Staff’s proposal to include the following amounts in rate base: prepayments at $8,134,351 ($916,313 more than ETI’s request); materials and supplies at $29,285,421 ($32,847 more than ETI’s request); and fuel inventory at $52,693,485 ($1,066,490 less than ETI’s request).

10. Acquisition Adjustment The $1,127,778 incurred by ETI in internal acquisition costs associated with the purchase of the Spindletop Facility was reasonable, necessary, properly incurred, and should be included in rate base.

11. Capitalized Incentive Compensation The Test Year for ETI’s prior ratemaking proceeding ended on June 30, 2009. The reasonableness of ETI’s capital costs (including capitalized incentive compensation) was dealt with by the Commission in that proceeding and is not at issue here. Thus, exclusion of capitalized incentive compensation that is financially-based can only be made for incentive costs that ETI capitalized during the period from July 1, 2009 (the end of the prior Test Year) through June 30, 2010 (the commencement of the current Test Year).

B. Rate of Return and Capital Structure The ALJs recommend a return on equity (ROE) of 9.80 percent; a cost of debt of 6.74 percent; a capital structure comprised of 50.08 percent debt and 49.92 percent common equity; and an overall rate of return of 8.27 percent. This is a downward adjustment to ETI’s request for a 10.60 percent ROE, and no change to ETI’s 6.74 percent cost of debt and 50.08/49.92 capital structure. It compares to Staff’s proposed 9.60 percent ROE; OPC’s proposed 9.30 percent ROE; TIEC’s proposed 9.50 percent ROE; Cities’ proposed 9.50 percent ROE; and State Agencies’ proposed 9.30 percent ROE. No party opposed ETI’s proposed 6.74 percent cost of debt or its proposed 50.08/49.92 capital structure.

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C. Cost of Service 1. Purchased Power Capacity Expense ETI’s purchased power capacity costs should be set at the amount of the Company’s Test Year level, which is $245,432,884.

2. Transmission Equalization (MSS-2) Expense ETI should recover only the amount of expenses under Schedule MSS-2 of the Entergy System Agreement it paid in the Test Year, $1,753,797.

3. Depreciation Expense The interim retirements methodology should not be adopted. The values proposed by ETI should be adopted except for the following:

Service Lives: Account 364-40 R1.

Account 368-33 L0.5.

Net Salvage: Production Plant- negative 5 percent.

Account 354-negative 5 percent Account 361-negative 5 percent.

Account 362-negative 10 percent.

Account 368-negative 5 percent.

Account 369.1-negative 10 percent.

Account 369.2-negative 10 percent.

4. Labor Costs ¾ Payroll and Related Adjustments The Commission should accept: (1) the payroll adjustments proposed in the ETI application; and (2) the further payroll adjustments proposed by Staff as corrected by ETI.

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¾ Incentive Compensation ETI should not be entitled to recover its financially based incentive compensation costs.

Thus, the ALJs recommend removing $6,196,037 from ETI’s requested operation and maintenance (O&M) expenses. Additionally, an additional reduction should be made to account for the FICA taxes that ETI would have paid as a result of those costs.

¾ Compensation and Benefit Levels ETI met its burden to prove the reasonableness of its base pay and incentive package costs.

It is reasonable to view market price for these categories of costs as lying within a range of +/- percent of median, rather than being a single point along a spectrum. As to both base pay and the incentive package, ETI has proven that its costs fall within such an acceptable range. Accordingly, the ALJs recommend rejecting the adjustments sought by Cities.

¾ Nonqualified Executive Retirement Benefits The ALJs recommend an adjustment to remove $2,114,931, representing the full costs associated with ETI’s non-qualified executive retirement benefits.

¾ Employee Relocation Costs The Commission should allow ETI’s relocation expenses.

¾ Executive Perquisites The ALJs recommend an adjustment to remove $40,620, representing the full cost of ETI’s executive perquisite costs.

5. Interest on Customer Deposits The ALJs recommend using the active customer deposits amount of $35,872,476 and the 2012 interest rate, which produces a recommended interest expense of $43,047 ($35,872,476 multiplied by .12 percent).

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6. Property (Ad Valorem) Tax Expense ETI’s property tax burden should be adjusted upward by applying the effective tax rate of 0.007435784 for the calendar year 2011 to the final, adopted Test Year-end plant in service value for ETI.

7. Advertising, Dues, and Contributions The ALJs recommend an adjustment to remove $12,800 from ETI’s costs of advertising, dues and contributions.

8. Other Revenue Related Adjustments These amounts were determined through number running and are reflected in Attachment A.

9. Federal Income Tax The Commission should adopt ETI’s proposal on federal income taxes.

10. River Bend Decommissioning Expense ETI’s annual decommissioning revenue requirement should reflect the most current calculation of $1,126,000. Therefore, an adjustment of $893,000 to the pro forma cost of service is needed to reflect the difference between the requested level for decommissioning costs of $2,019,000 and the recommended level of $1,126,000.

11. Self-Insurance Storm Reserve Expense The Commission should approve a total annual accrual of $8,270,000, comprised of an annual accrual of $4,400,000 to provide for average annual expected storm losses, plus an annual accrual of $3,870,000 for 20 years to restore the reserve from its current deficit. The ALJs recommend approval of ETI’s proposed target reserve of $17,595,000. The Commission should require ETI to continue recording its annual accrual until modified by future Commission orders.

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12. Spindletop Gas Storage Facility The ALJs recommend inclusion of the costs of operating the Spindletop Facility as requested by ETI.

D. Affiliate Transactions ETI agreed to remove the following affiliate transactions from its request, which the ALJs recommend be approved: (1) Project F3PPCASHCT (Contractual Alternative/Cashpo) in the amount of $2,553; (2) Project F3PCSPETEI (Entergy-Tulane Energy Institute) in the amount of $14,288; and (3) Project F5PPKATRPT (Storm Cost Processing & Review) in the amount of $929.

Except as noted below, all remaining affiliate transactions should be approved. The ALJs recommend that the following affiliate transactions not be included:

¾ $356,151 (which figure includes the $112,531 agreed to by ETI) of costs associated with Projects F5PCZUBENQ (Non-Qualified Post Retirement) and F5PPZNQBDU (Non Qual Pension/Benf Dom Utl); ¾ $10,279 of costs associated with Project F3PPFXERSP (Evaluated Receipts Settlement); ¾ $19,714 of costs associated with Project F3PPEASTIN (Willard Eastin et al); and ¾ $171,032 of costs associated with Project F3PPE9981S (Integrated Energy Management for ESI).

E. Jurisdictional Cost Allocation The ALJs recommend the use of 12 Coincident Peak (12CP) to allocate capacity-related production costs between the retail and wholesale jurisdictions.

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F. Class Cost Allocation 1. Renewable Energy Credit Rider The Commission should deny ETI’s request to institute a renewable energy credit rider, and the Test Year expense of $623,303 should be used for setting rates in this case. Finally, the Renewable Portfolio Standard Calculation Opt-Out Credit Rider should be maintained, with an adjustment to the credit rates to reflect the Test Year data used to set ETI’s base rates.

2. Class Cost Allocation The parties generally agreed that ETI’s cost-of-service study comported with accepted industry practices, but some parties had issues with specific items discussed below.

(a) Municipal Franchise Fees Municipal franchise fees should be allocated on the basis of in-city kilowatt-hour (kWh) sales, without an adjustment for the municipal franchise fee rate in the municipality in which a given kWh sale occurred. The ALJs recommend adoption of ETI’s proposal to collect costs from all customers taking service from the system.

(b) Miscellaneous Gross Receipts Tax Similar to municipal franchise fees, miscellaneous gross receipts taxes should be allocated to the rate classes according to ETI’s cost of service study.

(c) Capacity-Related Production Costs The ALJs recommend the use of Average and Excess 4 Coincident Peak (A&E 4CP) to allocate capacity-related production costs, as proposed by ETI. The ALJs do not find sufficient support to allocate the reserve equalization payments differently than other capacity-related production costs.

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(d) Transmission Costs ETI’s proposed methodology for allocation of transmission costs should be approved. A&E 4CP is a well-accepted method for allocating such costs.

3. Revenue Allocation Revenue allocation in this case should be based on each class’s cost of service and consistent with the ALJs’ recommendations in the PFD that impact revenue allocation.

4. Rate Design (a) Lighting and Traffic Signal Schedules ETI should be directed to perform a light emitting diode (LED) lighting cost study before significant changes are made to its lighting rates. The ALJs further recommend that ETI conduct this study before filing its next rate case and provide the results of any completed study to Cities and interested parties. The study should include detailed information regarding differences in the cost of serving LED and non-LED lighting customers, if ETI currently has LED lighting customers taking service. ETI should modify the applicable tariffs to eliminate its fee for any replacement of a functioning light with a lower-wattage bulb.

(b) Demand Ratchet ETI’s proposed Large Industrial Power Service (LIPS) tariff should be amended to include the language proposed by DOE witness Etheridge.

(c) Large Industrial Power Service The ALJs recommend the adoption of a $630 customer charge for this customer class, a slight decrease in the LIPS energy charges, and an increase in the demand charges from current rates for this class, as proposed by Staff witness Abbott.

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(d) Schedulable Intermittent Pumping Service The Commission should adopt the Schedulable Intermittent Pumping Service rider proposed by DOE witness Etheridge.

(e) Standby Maintenance Service The Commission should adopt the changes to Schedule SMS recommended by TIEC, with the exception of a $6,000 customer charge. Consistent with the ALJs’ recommendation that a new LIPS charge of $630 is reasonable, the Standby Maintenance Service (SMS) charge should be limited to $630 and not apply if a Schedule SMS customer also purchased supplementary power under another applicable rate.

(f) Additional Facilities Charge Schedule AFC should be changed in accordance with TIEC’s recommendations and those recommended numbers should be reduced in proportion to any authorized reduction in ETI’s proposed rate of return, O&M expense, and property tax expense.

(g) Large General Service Schedule LGS should be amended as proposed by Kroger. Schedule LGS also has a demand ratchet, and the ALJs’ recommendation for the elimination of ETI’s LIPS demand ratchet is applicable to this class

(h) General Service The Commission should adopt the decrease in the Schedule GS customer charge to $39.91 from the current (and Company proposed) rate of $41.09, as well as Staff’s recommended decrease in energy charges. Schedule GS also has a demand ratchet, and the ALJs’ recommendation for the elimination of ETI’s LIPS demand ratchet is applicable to this class.

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(i) Residential Service ETI’s declining block winter rates provide a disincentive to energy efficiency. The ALJs recommend an initial 20 percent reduction, followed by 20 percent subsequent reductions of the differential in the next three rate cases unless ETI provides sufficient evidence that such changes are unjust and unreasonable.

G. MISO Transition The Commission should deny ETI’s request for deferred accounting of its MISO transition expenses to be incurred on or after January 1, 2011. However, the Commission should authorize ETI to include $2.4 million of MISO transition expense in base rates set in the present case, based on a five-year amortization of $12 million in total projected expenses. Further, the Commission should authorize ETI to include in base rates $52,800 in MISO transition expenses for the 2010 portion of the Test Year expenses, plus $2.4 million for the post Test Year adjustment, for a total of $2,452,800.

V. RATE BASE [Germane to Preliminary Order Issue Nos. 4, 10, and 16] A. Capital Investment [Germane to Preliminary Order Issue No. 17] ETI presented for review $408,078,600 in capital additions closed to plant in service between July 1, 2009, and June 30, 2011; that is, from the end of the test year in the Company’s last base rate case, which was Docket No. 37744, through the Test Year presented in this case. The capital additions were detailed in the testimony and exhibits of the following Company witnesses: Garrison (Generation), McCulla (Transmission), Corkran (Distribution), Stokes (Customer Service), Brown (Information Technology), Plauche (Administrative), Cicio (System Planning and Operations), Hunter (Supply Chain), May (Regulatory), and Sloan (Legal).4 The evidence shows that these

ETI Ex. 27 (Garrison Direct) at 20-28 and WWG-4; ETI Ex. 32 (McCulla Direct) at 64-92 and MFM-16; ETI Ex. 25 (Corkran Direct) at 78-108 and SBC-3; ETI Ex. 37A (Roman Direct, adopted by Stokes) at 121- and AFR-5; ETI Ex. 24 (Brown Direct) at 29-37 and JFB-3; ETI Ex. 20 (Plauche Direct) at 37-44 and TCP-11; ETI Ex. 39 (Cicio Direct) at 71-75 and PJC-6; ETI Ex. 16 (Hunter Direct) at 34-38 and JMH-7; ETI Ex. 7 (May Direct) at 53-54 and PRM-3; and ETI Ex. 38 (Sloan Direct) at 37-43 and RDS-4.

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capital additions were prudently incurred and are used and useful in providing service to ETI’s customers. No party challenged any of the capital additions or the costs thereof, and the ALJs find no reason to do so either.

B. Hurricane Rita Regulatory Asset Hurricane Rita struck the upper Texas coast in September 2005, causing extensive property damage. In 2006, the Texas Legislature enacted PURA Chapter 39 to authorize electric utilities such as ETI to securitize the recovery of their reconstruction costs incurred as a result of Hurricane Rita.

Under the statute, the amount of reconstruction costs to be securitized had to be reduced by the insurance proceeds and government grants received by a utility. If additional insurance or grant proceeds were received after the securitization order was approved, the Commission was required to take those amounts into account in the utility’s next base rate case. This was provided in Section 39.459(c) of PURA:

To the extent a utility subject to this subchapter receives insurance proceeds, governmental grants, or any other source of funding that compensates it for hurricane reconstruction costs, those amounts shall be used to reduce the utility’s hurricane reconstruction costs recoverable from customers. If the timing of a utility’s receipt of those amounts prevents their inclusion as a reduction to the hurricane reconstruction costs that are securitized, the commission shall take those amounts into account in: (1) the utility’s next base rate proceeding; or (2) any proceeding in which the commission considers hurricane reconstruction costs.

Docket No. 32907 was the proceeding for ETI to determine the amount of Hurricane Rita reconstruction costs that it could securitize, net of any proceeds received from insurance or government grants.5 In that case, ETI asserted that it incurred $393,236,384 in Hurricane Rita reconstruction costs for its Texas Retail jurisdiction. The parties reached a settlement in that case, which set ETI’s hurricane reconstruction expenses eligible for securitization at $381,236,384. In

Application of Entergy Gulf States, Inc. for Determination of Hurricane Reconstruction Costs, Docket No. 32907 (Dec. 1, 2006).

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addition, ETI estimated that it would receive $65,700,000 in future insurance proceeds that, pursuant to the settlement, was deducted from the amount to be securitized. The parties also agreed that after ETI received all of its insurance payments, a true-up would occur to reflect the difference between the $65,700,000 credited and the amount actually received. The settlement agreement provided that if ETI received more insurance payments than estimated, the excess payments would be passed through to ratepayers in the form of a rider; however, the agreement did not address how an under- recovery by ETI would be handled. It turned out that ETI received only $46,013,904 in insurance proceeds,6 leaving a $19,686,096 under-recovery by ETI, which the parties refer to as Overestimated Insurance Proceeds.7

Docket No. 37744 was ETI’s next base rate case after Docket No. 32907. In Docket No. 37744, ETI requested recovery of the Overestimated Insurance Proceeds by establishing a regulatory asset of $19,686,096, plus accrued carrying costs, to be amortized over five years.8 Docket No. 37744 also concluded by a black-box settlement, and neither the Stipulation and Settlement Agreement nor the Order entered by the Commission specifically addressed the proposed regulatory asset or any other recovery for Overestimated Insurance Proceeds.

In the present case, ETI has again sought approval of a regulatory asset to recover $26,229,627, for the balance of Overestimated Insurance Proceeds, plus carrying costs through June 30, 2011.9 Cities objected to the amount of ETI’s request. They argue that this issue was resolved in Docket No. 37744 and that ETI should have been amortizing the asset since the conclusion of that case. Staff also argues that the issue was resolved in Docket No. 37744 and requested that ETI’s request be denied entirely; or, alternatively, that it should be considered partially amortized and accordingly reduced. ETI argues that the issue was not resolved in Docket No. 37744 and that it should be allowed a full recovery in the present case. Alternatively, ETI argues that Cities’ proposed reduction was not calculated correctly.

See Docket No. 32907, Final Order at FoF 27. Cities Ex. 2 (Garrett Direct) at Exhibit MG2.3. $19,686,096 = 65,700,000 - $46,013,904.

Cities Ex. 2 (Garrett Direct) at 11.

Schedule P Cost of Service Workpapers, Vol. 2, ETI Ex. 3 at AJ 15, page 15.3.

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Cities’ expert accounting witness, Mark Garrett, testified that ETI should have been amortizing the balance of Overestimated Insurance Proceeds since the effective date of rates set in Docket No. 37744. In addition, he argues that ETI should not have continued to accrue interest on the balance that was added into rate base in that docket, because it would have then earned a rate of return. Therefore, Mr. Garrett’s adjustment started with the balance of $25,278,210 that ETI requested in Docket No. 37744. He reduced that balance by $9,479,329 for amortization between the date rates went into effect in Docket No. 37744 and the date that rates will go into effect in the current case (22.5 months). Mr. Garrett further reduced the remaining balance by $5,678,960 to account for additional insurance proceeds received by ETI after Docket No. 37744. By Mr. Garrett’s calculations, this left a remaining balance of Overestimated Insurance Proceeds of $11,071,338.10 Both Mr. Garrett and Cities witness Jacob Pous also recommended that this remaining balance not be carried as a regulatory asset but, instead, be moved to the storm insurance reserve for recovery.11 In their view, this would ensure that the remaining balance would be properly recovered.

In response to ETI’s argument that the Hurricane Rita Regulatory Asset was not resolved in Docket No. 37744, Cities stress that Docket No. 37744 settled as a “black box settlement.” In Cities’ opinion, such a settlement should not be interpreted as changing the status quo unless expressly stated in the settlement agreement or final order. Cities contend that the status quo in Docket No. 37744 was that ETI was authorized to recover its Over Estimated Insurance Proceeds, because recovery was authorized by PURA § 39.459(c); recovery had been previously approved in Docket No. 32907; and no party objected to its recovery in Docket No. 37744. Therefore, Cities state, the final order in Docket No. 37744 should be interpreted as authorizing ETI’s requested recovery of the Hurricane Rita Regulatory asset in the rates set in that docket.12

Cities also disagree with ETI’s alternative argument that Mr. Garrett improperly calculated the remaining balance of the asset by deducting an amount for insurance proceeds ETI received after Cities Ex. 2 (Garrett Direct) at Exhibit MG2.3.

Id. (Garrett Direct) at 12; Cities Ex. 5 (Pous Direct) at 64.

Cities Reply Brief at 10-14.

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Docket No. 37744 concluded. Cities state that Mr. Garrett’s adjustment was correct because it began with the balance requested in Docket No. 37744, before the additional insurance proceeds were received. In other words, Mr. Garret did not start with the balance claimed by ETI in the present case,13 so he correctly applied the amount received after Docket No. 37744 to reduce the balance claimed in that docket.14 According to Cities, Mr. Garrett began with the prior balance to properly reflect that no carrying charges would accrue on the balance after it was included in rate base and recovered a return through rates.15 Cities also dispute ETI’s argument that Mr. Garrett should not have accounted for amortization occurring between the Test Year and the Rate Year as an “invalid post-test year adjustment.”16 In Cities’ view, this was a valid known and measureable change that should be taken into account.17

Staff recommends that the Hurricane Rita Regulatory Asset be removed from rate base entirely. Staff witness Anna Givens stated that it is reasonable to assume that this asset was included as part of the settlement in Docket No. 37744. Accordingly, she stated that it is not appropriate for ETI to request recovery of the same asset in the present docket. Therefore, Ms. Givens recommended removal of the entire requested $26,229,627 Hurricane Rita regulatory asset from ETI’s rate base.18

Alternatively, Ms. Givens proposed that the Commission allow ETI a regulatory asset of $17,486,418, to be amortized over 40 months. Ms. Givens noted that higher rates from Docket No. 37744 first went into effect on August 15, 2010;19 therefore, at least one-third of the regulatory asset should have been amortized by the conclusion of the present case. Using ETI’s updated hurricane regulatory asset request of $26,229,627, Ms. Givens recommended a decrease of one-third

Cities Initial Brief at 8.

Cities Ex. 2B (Garrett Direct), Exhibit MG-2.3.

Docket No. 32907, Final Order at FoF 28.

ETI’s Initial Brief at 7.

Cities’ Reply Brief at 10-14.

Staff Ex. 1 (Givens Direct) at 32-34.

Docket No. 37744, Order, FoF 16 (Dec. 13, 2010).

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to ETI’s request. This would equal an $8,743,209 reduction, resulting in her recommended regulatory asset of $17,486,418 ($26,229,627 - $8,743,209). Ms. Givens also recommended that the amortization period be decreased from 60 months to 40 months, which is the time remaining on ETI’s original Docket No. 37744 request.20

ETI disagrees with Cities and Staff, and it argues that its total requested Hurricane Rita regulatory asset should be included in rate base in this case. First, it notes that no instruction in the Stipulation and Settlement Agreement filed in Docket No. 37744 required ETI to begin amortizing the asset or otherwise directed the treatment of the asset. Likewise, no Finding of Fact or Conclusion of Law in the agreed order entered in Docket No. 37744 authorized the proposed treatment of the asset. In contrast, ETI notes, the settlement in Docket No. 32907 does specifically address the treatment of this asset, and it argues that its request to include the full Hurricane Rita regulatory asset in rate base in the present case is consistent with that settlement. In ETI’s opinion, it has not previously been authorized to establish the regulatory asset, it has not amortized it, and the full amount should be included in rate base in this case.21

Alternatively, if Cities’ proposed amortization is accepted, ETI argues that Mr. Garrett’s calculations were wrong. First, ETI states, Mr. Garrett incorrectly assumed that the $26,229,627 Hurricane Rita regulatory asset requested in this case did not account for the $5,678,960 of insurance proceeds that ETI received after Docket No. 37744. According to ETI, the $5,678,960 was accounted for, as shown on WP/P AJ 15.3. Therefore, ETI states, Mr. Garrett’s adjustment for this $5.6 million would remove this amount from the asset a second time.22 Second, ETI argues that Mr. Garrett erred by amortizing the asset by 22.5 months. Mr. Garrett calculated the amortization period from the time rates went into effect after Docket No. 37744 (August 15, 2010) through the time revised rates would go into effect in this docket (June 30, 2012). ETI states that Mr. Garrett Staff Ex. 1 (Givens Direct) at 34. Ms. Givens noted that amount recommended in Docket No. 37744 was $25,278,000, which is $951,627 less than the amount requested in the current proceeding. However, she stated that this does not affect her recommendation, because by the time the hearing on the merits concluded, at least another two months of amortization expense under the existing rates would be collected by the ETI and should adequately compensate it for the difference. Staff Ex. 1 (Givens Direct) at 35.

ETI Ex. 46 (Considine Rebuttal) at 19-24; ETI Initial Brief at 5-6.

ETI Ex. 46 (Considine Rebuttal) at 21-22; ETI Initial Brief at 7.

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made an invalid post-test year adjustment because post-test year adjustments for rate base items are limited to plant additions recorded in FERC Accounts 101 or 102. In contrast, regulatory assets, like the Hurricane Rita regulatory asset, are recorded in Account 182.3. Therefore, in ETI’s opinion, if it was required to amortize this regulatory asset, it would be appropriate to amortize it for only 10.5 months, to the end of the Test Year (August 15, 2010, through June 30, 2011). These two corrections would adjust Mr. Garrett’s proposed asset balance from $10,714,557 to $21,805,940.23

ETI also disagrees with Mr. Pous’ recommendation that the regulatory asset be removed from rate base and placed in the storm reserve, to be amortized over 20 years. In ETI’s opinion, this approach would defeat the purpose of securitization, which is to provide ETI with cost recovery in an expedited manner.24

Finally, ETI argues that Ms. Givens’ analysis was flawed. It reiterated that no provision in the Stipulation and Settlement Agreement or the final order filed in Docket No. 37744 directed the treatment of the regulatory asset or stated that ETI would begin amortizing the asset. Further, ETI stresses that it never sought recovery of the entire asset all at once in Docket No. 37744. Instead, ETI requests recovery over a period of years through amortization. Thus, according to ETI, even if Ms. Givens’ argument were accepted, the entire asset should not be disallowed.25

This issue is a close call because the black-box settlement agreement and final order in Docket No. 37744 did not expressly state how the Hurricane Rita regulatory asset issue was resolved. The following factors support finding that the Hurricane Rita regulatory asset issue was resolved in Docket No. 37744:

x the settlement agreement and final order in Docket No. 32907 expressly provided that the difference between the amount of ETI’s estimated insurance proceeds and the amount actually received by ETI would be trued up after ETI received the proceeds;

ETI Ex. 46 (Considine Rebuttal) at 22; ETI Initial Brief at 7-8.

ETI Initial Brief at 8.

ETI Ex. 46 (Considine Rebuttal) at 21; Id. at 8-9.

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x PURA § 39.459(c) provides that if the timing of a utility’s receipt of insurance proceeds prevented their inclusion as a reduction to the securitized costs, the Commission “shall take those amounts into account . . . in the utility’s next base rate proceeding;” x Docket No. 37744 was ETI’s next base rate proceeding; x in Docket No. 37744, ETI requested a true-up concerning the insurance proceeds, and it requested that a regulatory asset be established for the deficit and amortized over five years; x in Docket No. 37744, no party objected to ETI’s proposed regulatory asset or amortization; x the stipulation and settlement agreement entered by the parties in Docket No. 37744 stated that the parties resolved all issues, except for ETI’s Competitive Generation Service (CGS) proposal; and x neither the stipulation and settlement agreement nor the Order entered in Docket No. 37744 specifically disapproved, excluded, or deferred consideration ETI’s proposed regulatory asset, although they did specifically exclude or disapprove other items, such as ETI’s CGS proposal and various proposed riders.

On the other hand, some factors support a finding that the Hurricane Rita regulatory asset issue was not resolved in Docket No. 37744. The stipulation and settlement agreement and the Order entered in Docket No. 37744 did not expressly approve ETI’s proposed regulatory asset, although certain other items were expressly approved, such as River Bend Nuclear Generating Station Unit No. 1 (River Bend) decommissioning costs, depreciation rates, and other items. Also, utilities are typically not allowed to create regulatory assets without express approval of the Commission.

Thus, the difficulty with this issue is the nature of the black-box settlement of Docket No. 37744. In the settlement, the parties agreed to an increase in base rate revenues of $59 million effective August 15, 2010, with an additional increase in base rate revenues effective May 2, 2011.

However, there was no explanation on how this increase was determined, and there was no specific agreement or finding on the amount of ETI’s rate base or its reasonable and necessary cost of service. In that case, there was no objection to ETI’s proposed Hurricane Rita regulatory asset, it was authorized by the prior settlement in Docket No. 32907, and the Commission was directed by SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 22 PUC DOCKET NO. 39896

PURA § 39.459(c) to take into account ETI’s insurance proceeds related to the Hurricane Rita securitized costs in ETI’s next rate case, which was Docket No. 37744. Moreover, when there is uncertainty whether an undisputed issue was deferred for future consideration or was included within the rates set in a black-box settlement, the burden should be on the utility to establish that the issue was deferred for future consideration. When all the evidence and factors are considered, the ALJs find that that ETI’s proposed Hurricane Rita regulatory asset should be considered as having been approved in Docket No. 37744, and ETI should have amortized the asset since August 15, 2010, the effective date of rates approved in that docket.

The ALJs also find that none of the amortization calculations proposed by the parties were entirely correct. ETI’s proposal to start with its requested $26,229,627 was flawed because it included carrying costs from August 15, 2010, when the asset should have been included in rate base, to June 30, 2011, the end of the Test Year in the present case. During that period, the asset would have earned a rate of return as part of rate base, and accrual of carrying costs should have ceased. Therefore, it would be more accurate to begin amortizing the Hurricane Rita regulatory asset by using the balance requested by ETI in Docket No. 37744. That amount, according to Mr. Garrett, was $25,278,210. However, the amortization calculation should not extend beyond the end of the Test Year in the present case (June 30, 2011), as proposed by Cities and Staff. P.U.C. SUBST.

R. 25.231(c)(2)(F)(ii) provides for post-test-year reductions to rate base, and the recommendation for a post-test-year adjustment to the Hurricane Rita regulatory asset does not fall within the scope of that rule. The balance remaining after amortization to the end of the Test Year should be further reduced by $5,678,960 to account for additional insurance proceeds received by ETI after Docket No. 37744 concluded but before the end of the Test Year in the present case. ETI argues that this reduction was already included in its request. However, as discussed above, the appropriate calculation should begin with the balance of the asset at the conclusion of Docket No. 37744, not the balance requested by ETI in the present case. The balance of the asset at the conclusion of Docket No. 37744 did not account for the additional insurance proceeds paid to ETI afterwards, so it should be deducted now. In summary, the ALJs find that the appropriate amount of the Hurricane Rita regulatory asset to be included in rate base in this case should be calculated as follows: SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 23 PUC DOCKET NO. 39896

Beginning balance at conclusion of Docket No. 37744 (original balance + carrying charges) $25,278,210 Less amortization for period 8/15/10 to 6/30/11 = 10.5 months / 60 months = 17.5% - $4,423,687 Less additional insurance proceeds received - $5,678,960 Remaining balance of Hurricane Rita regulatory asset $15,175,563

Finally, the ALJs recommend that the Commission not adopt the recommendation of Cities to move the Hurricane Rita regulatory asset to the storm insurance reserve for recovery. As noted by ETI, one purpose of enactment of PURA Chapter 39 was to allow expedited recovery of costs resulting from Hurricane Rita storm damage. Moving the regulatory asset to the storm insurance reserve would defeat that purpose and negate the five-year amortization plan the parties agreed to in Docket No. 37744.

In summary, the ALJs find that ETI’s proposed Hurricane Rita regulatory asset was an issue resolved by the black-box settlement in Docket No. 37744. Therefore, ETI should have included the asset in rate base at the conclusion of that docket and should have begun amortizing it over a period of five years. The accrual of carrying charges should have ceased when Docket No. 37744 concluded, because the asset would have then begun earning a rate of return as part of rate base. The appropriate calculation of the asset should begin with the amount claimed by ETI in Docket No. 37744, less amortization accruals to the end of the Test Year in the present case, and less the amount of additional insurance proceeds received by ETI after the conclusion of Docket No. 37744.

This produces a remaining balance of $15,175,563, which should remain in rate base as a regulatory asset, applying a five-year amortization rate that commenced August 15, 2010. Further, the Hurricane Rita regulatory asset should not be moved to the storm insurance reserve.

C. Prepaid Pension Asset Balance ETI included in rate base an item titled Unfunded Pension in the amount of $55,973,545.26 The amount requested in this account represents the accumulated difference between the Statement of Financial Accounting Standards (SFAS) No. 87 calculated pension costs each year and the actual ETI Ex. 3, Sched. B-1, Line 10.

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contributions made by the Company to the pension fund.27 It is a debit balance, meaning that the Company has contributed roughly $56 million more to its pension fund than the minimum required by SFAS 87.28 Other than Cities, no party opposes ETI’s request to include this item in rate base.

Cities argue that ETI ought not be entitled to include this amount in rate base because it represents amounts the ETI overpaid to its pension, resulting in little to no benefit to ratepayers.

Cities witness Mark Garrett pointed out that ETI earned only 1.37 percent on its pension assets over the past five years, while it is seeking a rate of return of more than 11 percent. Thus, he argues, if the asset were included in rate base, ratepayers would pay a substantial premium for the slight pension cost savings ETI’s excess contributions may have achieved.29

Cities argue that the entire prepaid pension asset should be removed from rate base because ETI has not justified its inclusion. This would reduce pro forma rate base by $36,382,803, which is the net amount of the prepaid balance less accumulated deferred income tax ($55,973,545 – $19,590,740 = $36,382,803). At the same time, Cities would increase operating expense by $498,284, to provide a 1.37 percent return on the net balance of ETI’s prepaid pension asset balance.30

Alternatively, Cities contend that the Commission should treat the pension assets in the same manner as the approach adopted by the Commission in Docket No. 33309.31 In that docket, the Commission allowed a pension prepayment asset, less accrued deferred federal income taxes (ADFIT) and less the portion of the asset that is capitalized to CWIP, to be included in rate base. As to the excluded portion, the Commission allowed the accrual of an allowance for funds used during construction (AFUDC). Thus, Cities contend, if the Commission opts for this approach, it should allow ETI’s pension prepayment asset, less ADFIT, to be included in rate base, but excluding Cities Ex. 2 (Garrett Direct) at 7.

ETI Initial Brief at 10; Cities Ex. 2 (Garrett Direct) at 8.

Cities Ex. 2 (Garrett Direct) at 8-9.

Id. at 10, MG-2.2; Cities Initial Brief at 10.

Remand of Docket No. 33309 (Application of AEP Texas Central Company for Authority to Change Rates), Docket No. 38772, Order on Remand at FoF 15A (Jan. 30, 2011).

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$25,311,236 for the portion of the prepaid pension balance associated with CWIP, and allow AFUDC to accrue on the excluded balance.32

ETI responds first by disputing Mr. Garrett’s contention that it has unreasonably overpaid into its pension fund. It contends it has made contributions to the pension fund in accordance with contribution guidelines established by the Employee Retirement Income Security Act of 1974 and the Internal Revenue Code of 1986, and that the contributions were within the allowable range of contributions deductible for tax purposes. ETI also was guided in its required pension contributions by the Pension Protection Act of 2006 rules, effective beginning with the 2008 plan year.33

ETI next disputes Cities’ contention that the earnings associated with ETI’s pension contributions provide insufficient benefits to justify inclusion of the asset in rate base. ETI points out that ratepayer benefits are not just limited to the level provided by the actual pension fund earnings on investment. Rather, under FAS 87, pension costs included in the cost of service for ratemaking purposes are intended to include the expected rate of return on assets. Thus, ETI argues that the expected long-term rate of return on ETI’s assets is 8.5 percent, not the actual earnings as suggested by Mr. Garrett.34

On behalf of ETI, Mr. Considine testified that the pension balance is no different than any other prepayments made by the Company, which are included in rate base and earn a full return on rate base. Furthermore, the Company would be allowed to earn a full return on rate base had the Company invested these same dollars in Plant in Service, but the Company in this case used funds to contribute to a still under-funded pension plan and at the same time provided a timely reduction to formerly FAS 87 annual pension cost, thereby immediately benefitting ratepayers.35 Therefore, ETI argues it is clearly investor-supplied capital and accordingly should earn the Company’s requested return on rate base.

Cities Initial Brief at 8-9; Cities Ex. 2 (Garret Direct) at 12.

ETI Ex. 46 (Considine Rebuttal) at 22.

Id. Id. at 23-24.

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ETI acknowledged the approach to this issue taken by the Commission in Docket No. 33309, but failed to explain why it is distinguishable from the present case.36

The ALJs conclude that the approach taken by the Commission in Docket No. 33309 was sound and should be applied in the present case. Neither party adequately explained why the circumstances of the present case are distinguishable. Thus, the ALJs recommend that the CWIP-related portion of ETI’s pension asset ($25,311,236 out of the total asset) should be excluded from the asset, but accrue allowance for funds used during construction.

D. FIN 48 Tax Adjustment The Financial Accounting Standards Board (FASB) is the body that establishes the rules that constitute generally accepted accounting principles (GAAP). FASB’s Interpretation No. 48 (FIN 48) prescribes the way in which a company must analyze, quantify, and disclose the potential consequences of tax positions that the company has taken which are legally “uncertain.” Pursuant to FIN 48, ETI and its independent auditors are required to evaluate each of its uncertain tax positions to determine, under the most objective, reasonable standards, which portion of each position will most likely ultimately have to be paid to taxing authorities if challenged by the authorities. FIN 48 requires that this portion be excluded from ADFIT for financial reporting purposes and accrue interest and, in some cases, penalties.37

ETI and its auditors periodically perform the FIN 48 analysis. In so doing, they have concluded that the Company has taken a number of uncertain tax positions that the Company expects to lose if challenged by the IRS. ETI concluded that these uncertain tax positions result in a total of $5,916,461 in tax dollars that the Company expects it will ultimately have to pay, with interest, to the IRS. As required by FIN 48, this amount is recorded on ETI’s balance sheet as a tax liability.38 In other words, ETI has, thus far, avoided paying to the IRS $5,916,461 in tax dollars (ETI’s FIN 48

ETI Initial Brief at 10-11.

ETI Ex. 70 (Warren Rebuttal) at 9-12.

ETI Ex. 64 (Roberts Rebuttal) at 4-7.

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Liability) in reliance upon tax positions that the Company believes will not prevail in the event the positions are challenged, via an audit, by the IRS.

In preparing its application in this proceeding, ETI made an accounting adjustment to its Test Year numbers by not including the $5,916,461 in its ADFIT balance. This had the effect of reducing the Company’s Test Year deferred tax balance and, therefore, increasing its rate base.39

Cities witness Mark Garrrett asserted that the deduction of $5,916,461 – representing ETI’s FIN 48 Liability – should be added to ETI’s ADFIT balance and thus be used to reduce the Company’s rate base. Mr. Garrett pointed out that the Commission first considered this issue in a recent Oncor docket.40 In that docket, the Commission decided to include FIN 48 liabilities in ADFIT because of the low likelihood that the IRS would actually audit and review the issue.41 Mr. Garrett testified that this is a fair result because: (1) a utility with FIN 48 liabilities might never have its underlying uncertain tax positions audited by the IRS; and (2) even if the uncertain positions are audited by the IRS, the utility might prevail on them. In either case, the utility would never have to pay those tax amounts. Moreover, during the time when the uncertainty exists, the utility enjoys the use of cost-free capital (from the deferred taxes associated with the deductions) at its disposal.42 Thus, Mr. Garrett recommends that ETI’s ADFIT balance be increased by $5,916,461 to reinstate the FIN 48 Liability removed by the Company.43

ETI witnesses Rory Roberts and James Warren stated that the $5,916,461 should not be included in the Company’s ADFIT balance. Mr. Roberts explained that, because the Company expects to lose on its uncertain tax positions, it expects that it will ultimately have to pay $5,916,461 in taxes to the IRS, plus interest. Accordingly, Mr. Garrett testified that the amount does not

Id. at 4.

Cities Ex. 2 (Garrett Direct) at 5-7. See also Application of Oncor Electric Delivery Company LLC for Authority to Change Rates, Docket No. 35717, Order on Reh’g (Nov. 30, 2009).

Id. at 18 FOF 59 (“The IRS may not audit or reverse Oncor’s position as to the tax deductions identified as FIN 48 deductions and moved into the FIN 48 reserve.”).

Cities Ex. 2 (Garrett Direct) at 5-6.

Id. at 7.

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represent cost-free funds available to the Company and, as such, should not be included in the Company’s ADFIT balance.44

Both the Cities and ETI agree that ETI’s rate base “should reflect the actual amount of cost free capital in the ADFIT accounts at Test Year end.”45 However, ETI witness Mr. Warren testified that the FIN 48 Liability is not cost-free capital to the Company because the best available expert opinion in the record of this case is that ETI will “most likely” ultimately have to pay the money to the IRS, with interest.46

Moreover, Mr. Warren pointed out that, beginning with 2010 tax returns, a corporate taxpayer is required to complete and file a Schedule UTP, on which the taxpayer must specifically identify and describe its FIN 48 positions. Mr. Warren contended that, because ETI must now annually file a Schedule UTP, it is more likely that the IRS will audit the Company, thereby forcing it to pay the FIN 48 Liabilities, with interest.47 This constitutes additional support for the notion that the FIN 48 Liability is not cost-free capital for the Company. Mr. Warren correctly points out that, in a recent CenterPoint Energy Houston Electric, LLC, (CenterPoint) rate case, the Commission specifically acknowledged that filing of a Schedule UTP makes it more likely that a company will be audited. In that case, the ALJs recommended that CenterPoint’s FIN 48 Liability, totaling some $164 million, be added to CenterPoint’s ADFIT, thereby reducing its rate base. The Commission adopted the recommendation. However, in light of its conclusion that the filing of a Schedule UTP increases the likelihood of an audit, the Commission authorized CenterPoint to establish a deferred tax account rider to enable it to recover any portion of its FIN 48 Liability that it might ultimately be forced to pay to the IRS, plus interest.48 ETI does not necessarily oppose the use of a rider in this

ETI Ex. 64 (Roberts Rebuttal) at 7.

Cities Ex. 2 (Garrett Direct) at 6; see also ETI Ex. 70 (Warren Rebuttal) at 6-7.

ETI Ex. 70 (Warren Rebuttal) at 17.

Id. at 14, 20-21.

ETI Ex. 70 (Warren Rebuttal) at 19-20. See also Application of CenterPoint Electric Delivery Company, LLC, for Authority to Change Rates, Docket No. 38339, Order on Reh’g at 3-4 (June 23, 2011).

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case, but contends that it would be preferable to simply exclude ETI’s FIN 48 Liability from its ADFIT balance, thereby increasing its rate base.49

In the alternative that the Commission rejects ETI’s request to exclude the full amount of the FIN 48 Liability from the Company’s ADFIT balance, ETI contends that at least any amount of cash deposit the Company has made with the IRS that is attributable to the FIN 48 Liability should be removed from the Company’s ADFIT balance.50 The Cities’ witness, Mr. Garrett, agrees.51 Staff also agrees, arguing that ETI should be required to increase its ADFIT balance by the amount of its FIN 48 Liability less the amount of any cash deposit attributable to the liability that ETI has made with the IRS.52 ETI has made a cash deposit with the IRS in the amount of $1,294,683. This amount is associated with the Company’s FIN 48 Liability.53

Consistent with prior Commission precedent from the Oncor and CenterPoint proceedings, the ALJs conclude that ETI’s FIN 48 Liability should be included in the Company’s ADFIT balance.

There is, however, one caveat to this conclusion. The amount of the cash deposit made by ETI to the IRS which is attributable to the Company’s FIN 48 Liability should not be included in the ADFIT balance. Therefore, the ALJs recommend that the Commission find that $4,621,778 (representing ETI’s full FIN 48 Liability of $5,916,461 less the $1,294,683 cash deposit ETI has made with the IRS) should be added to ETI’s ADFIT and thus be used to reduce ETI’s rate base. No party expressly advocated the addition of a deferred tax account rider,54 and the ALJs do not recommend one in this case.

ETI Initial Brief at 13; ETI Ex. 70 (Warren Rebuttal) at 20.

ETI Ex. 64 (Roberts Rebuttal) at 8-9.

Cities Ex. 2 (Garrett Direct) at 7 n. 4.

Staff’s Initial Brief at 11-12.

ETI Ex. 64 (Roberts Rebuttal) at 8.

Cities and Staff both point out that there is much less need for a deferred tax account rider in the present case than there was in the CenterPoint case, where CenterPoint had $164 million in FIN 48 liabilities. Cities Reply Brief at 18; Staff Reply Brief at 10.

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E. Cash Working Capital Rate base includes a reasonable allowance for cash working capital. Cash working capital represents the average amount of investor capital used to bridge the gap in time between when expenditures are made by ETI to provide services and when the corresponding revenues are received by ETI.55 Generally, an increase in revenue lag days and/or a decrease in expense lead days will result in an increase to the amount of cash working capital included in the rate base. Conversely, a decrease in revenue lag days and/or an increase in expense lead days will reduce the cash working capital included in rate base. A properly prepared lead-lag study can result in either a positive cash working capital amount (and therefore an increase to the rate base) or a negative cash working capital amount (and a corresponding decrease to the rate base).

Pursuant to P.U.C. SUBST. R. 25.231(c)(2)(B)(iii)(IV), ETI calculated its cash working capital allowance by performing a lead-lag study. ETI witness Jay Joyce prepared the lead-lag study for the Company. Based upon the study, ETI requests a cash working capital addition to its rate base of negative $2,013,921.56

Only Staff and Cities submitted evidence and argument relevant to the cash working capital requirement. Staff does not challenge the accuracy of the lead and lag days determined in Mr. Joyce’s study. Instead, Staff witness Anna Givens recommends that the cash working capital calculation be updated to reflect the impacts of Staff’s recommended adjustments to ETI’s O&M costs and taxes.57 ETI agrees that the final cash working capital amount should be updated to reflect the actual revenue requirements approved by the Commission in this case.58

Cities witness Jacob Pous asserts that Mr. Joyce’s lead-lag study contains a number of errors which understate the negative cash working capital requirements of the Company. Mr. Pous asserts that the correct cash working capital amount for inclusion in ETI’s rate base is negative $24,000,000 ETI Ex. 17 (Joyce Direct) at 4.

Id. at 20 and JJJ-3.

Staff Ex. 1 (Givens Direct) at 30-31.

ETI Ex. 54 (Joyce Rebuttal) at 37; ETI Initial Brief at 14.

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(more than an order of magnitude increase of the negative amount).59 Each of the major components of the lead-lag study, and Cities’ criticisms of same, will be discussed in turn.

1. The Revenue Lag Component of the Lead-Lag Study Mr. Pous raises a number of criticisms about the revenue lag component of Mr. Joyce’s lead lag study. There are four parts to the revenue lag component: (1) the “service period lag,” which consists of the roughly 15 days from the mid-point of the month in which service is provided to the end of that month; (2) the “billing lag,” which represents the time between the date a customer’s meter is read and the date a bill is issued to the customer; (3) the “collection lag,” which represents the time between the issuance of the bill and the date the customer’s payment is received; and (4) ”receipt of funds lag,” which measures the delay between ETI’s receipt of payment and the bank’s clearance of the payment.60 When the four parts were combined together, Mr. Joyce identified ETI’s revenue lag as 43.86 days.61

(a) Billing Lag Mr. Joyce identified the billing lags (i.e., the delay between when meters are read and bills are sent to customers) as ranging from 5.4 to 5.65 days, depending upon the customer class.62 On behalf of the Cities, Mr. Pous asserted that this duration is too long. Mr. Pous complained that the billing lag in ETI’s lead-lag study is longer than in studies from previous ratemaking proceedings involving ETI’s predecessor, despite the fact that, in the interim between studies, ETI has invested substantially in electronic meter reading devices and computer systems that ought to shorten the lag time. According to Mr. Pous, in a previous proceeding, ETI’s predecessor identified its billing lag as only 3.61 days.63 Mr. Pous also pointed out that the Railroad Commission of Texas (RRC), recently adopted a 1-day billing lag for a large gas utility, Atmos Mid-Tex, due to the utility’s use of

Cities Ex. 5 (Pous Direct) at 72.

ETI Ex. 17 (Joyce Direct) at 8-10.

Id. at JJJ-3.

Cities Ex. 5 (Pous Direct) at 74.

Id. SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 32 PUC DOCKET NO. 39896

modern electronic meter reading devices (the Atmos Mid-Tex RRC proceeding). Mr. Pous stated that the billing lag identified by ETI would unjustly reward the Company for being inefficient in sending out its bills because customers should not be punished if the utility decides to manage its billing processing and payment system less efficiently. Thus, Mr. Pous recommended a schedule of different billing lags for different customer classes. For residential and commercial customers, Mr. Pous recommended a 1.46 day billing lag, based since ETI’s predecessor claimed such a lag in a prior PUC docket (Docket No. 12852). For large industrial, public authority, and street lighting customers, Mr. Pous recommends a billing lag of 3.72 days. He calculated that the combined impact of these adjustments would result in a 41.10-day total revenue lag (as compared to Mr. Joyce’s figure of 43.86 days). Mr. Pous then calculates that this shorter lag period results in an additional negative cash working capital of $11.4 million.64

ETI responds by pointing out that the 1.46-day billing lag suggested by Mr. Pous for residential and commercial customers was derived from a rate case by ETI’s predecessor from 1993, whereas Mr. Joyce more properly relied on actual Test Year data. Mr. Joyce asserted that Mr. Pous, in effect, “cherry picked” the 1.46-day figure from one page of a 47-page study associated with the 1993 rate case, and that the remaining pages of the study have not been located and, therefore, cannot be evaluated. Thus, Mr. Joyce testified, “[i]t is unfair and unreasonable to use such an old document to attempt to support a position when reasonable, contemporaneous evidence exists.”65

ETI argues that it is more appropriate in this case to rely upon ETI’s actual residential and commercial billing practices, rather than to substitute artificial and arbitrary 1.46-day and 3.72-day periods derived from other sources. According to Mr. Joyce, it is unavoidably necessary, when conducting a lead-lag study, to take into account the actual amount of time employed by ETI in performing all of the activities in its billing-cycle-based meter reading and billing processes.

Mr. Joyce complains that Mr. Pous’ approach would jettison this actual data and analysis derived

Id. at 75-77.

ETI Ex. 54 (Joyce Rebuttal) at 11.

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from the Test Year and improperly substitute arbitrary numbers based upon a prior, dated, rate proceeding.66

Mr. Joyce acknowledged that the RRC recently adopted a 1-day billing lag in the Atmos Mid-Tex RRC proceeding. He pointed out, however, that the RRC did so simply because Atmos Mid-Tex failed to present evidence supporting a longer billing lag. Additionally, Mr. Joyce pointed out that the RRC promptly reversed itself in Atmos Mid-Tex’s next rate case, adopting a longer billing lag after the company provided sufficient evidence to support the longer period.67

ETI also provided extensive evidence regarding the details of its meter reading and billing process.68 ETI witness Dolores Stokes explained that the meter reading and billing cycle includes time for extensive quality assurance activities to ensure accurate billing, thereby preventing unnecessary frustration for the customer and additional costs to the Company that would be required for customer service, rebilling, and account corrections.69

Cities questioned Mr. Joyce at the hearing about the billing lag period in this case compared to ETI’s last rate case. Mr. Joyce explained that the total period from meter reading to collection of billing revenues had not changed appreciably between the two cases, but due to a difference in lead- lag methodology, the date that divides the two components of that lag – metering to billing and billing to collection – had changed.70 As a result, the first period – billing lag – was longer than in the previous case but the second period – collection lag – was shorter.71 ETI introduced into evidence a response to a Cities RFI that discussed this difference in more detail.72 After explaining

Id. at 5-7.

Id.at 8-9.

ETI Ex. 54 (Joyce Rebuttal); ETI Ex. 66 (Stokes Rebuttal).

ETI Ex. 66 (Stokes Rebuttal) at 18.

Tr. at 499-500, 502.

Tr. at 499-502.

ETI Ex. 73.

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the change in lead-lag methodology, the RFI response concluded that “the combined billing and collection lags are substantially similar from the prior case to this current case.”73

The ALJs conclude that ETI has met its burden to show that the billing lag it utilized in the lead-lag study is reasonable and appropriate. Absent his own opinion, Mr. Pous does not offer meaningful evidence to support his assertion that the Company’s billing lag is too long or that the Company’s billing practices are inefficient. For example, he offered no criticism of any specific billing practice of the Company. The only support for his charge of inefficiency is that the billing lag in a previous ETI rate case was shorter. Mr. Joyce convincingly explained that this was merely an artifact of changes in the methodology of the lead-lag study – the billing lag became longer, but the collection lag became shorter.

Mr. Pous’ reliance upon an example from the RRC is unconvincing. Similarly, his reliance upon data from a previous rate case is unpersuasive, especially because only a very limited snippet of data from that case is available, the case occurred roughly 20 years ago, and it involved a different company. It is not possible, from the evidence in the record, to know how different or similar ETI’s current billing practices are to those used in the previous case.

In this case, ETI has thoroughly explained its metering and billing processes and established that those processes are reasonable. The Company is therefore entitled to establish rates based on the actual cash working capital necessary to facilitate those policies. The ALJs recommend rejecting Cities’ request to shorten the billing lag time identified in ETI’s lead-lag study

(b) Collection Lag In his lead-lag study, Mr. Joyce identified various collection lags (i.e., the delay between the issuance of an electric bill and the date the customer’s payment is received) for different classes of customers. As to third-party customers, the collection lag was determined using a random sample of invoices from residential, commercial, industrial, public authority, and street light customer billings during the Test Year, measuring the time between when the bills were mailed and the payment ETI Ex. 73 at 2.

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receipt date. The collection lag for MSS-4 and Intra-System Bill (ISB) revenues was based on the actual payment dates for each of the affiliate revenue types.74

¾ Collection Lag for Residential Customers As to the residential class, Mr. Joyce determined that the collection lag was 23.73 days. On behalf of the Cities, Mr. Pous disputed the accuracy of that estimate, complaining that it is substantially longer than the lag identified for commercial customers. Mr. Pous contended that Mr. Joyce determined the collection lag for residential customers by relying on a sample size that was too small. Mr. Pous examined the month-end accounts receivable data for ETI’s entire residential class for the entire Test Year, and concluded that the collection lag for the class is actually 22.07 days (as compared to Mr. Joyce’s figure of 23.73 days). Mr. Pous then calculated that this shorter lag period results in an additional negative cash working capital of $2.4 million.75

Mr. Joyce made several points in response. First, he noted that, although Mr. Pous is advocating reliance upon month-end accounts receivable data to calculate the collection lag in this case, he has testified in another proceeding that such data is unusable and unreliable. For example, in the Atmos Mid-Tex RRC proceeding, Mr. Pous argued in favor of measuring actual bill payment practices of actual customers (i.e., the approach taken by Mr. Joyce in the present case) and against analyzing the monthly accounts receivable balances for each month of the Test Year (i.e., the approach now being advocated for by Mr. Pous).76 Next, Mr. Joyce disputed Mr. Pous’ assertion that the sample size used by Mr. Joyce was too limited. According to Mr. Joyce, his sample of 100 residential customers is comparable to all of the residential collection lag calculations he has performed during his 15 years of performing lead-lag studies.77 Mr. Joyce also accused Mr. Pous of

ETI Ex. 17 (Joyce Direct) at 10.

Cities Ex. 5 (Pous Direct) at 77-79.

ETI Ex. 54 (Joyce Rebuttal) at 13-15.

Id. at 15-17.

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inexplicably picking out a few data points, rather than relying upon the entirety of the sampling data, in order to derive his collection lag estimate.78

The ALJs are unpersuaded by Mr. Pous’ criticisms and conclude that ETI has met its burden to show that the collection lag it utilized in the lead-lag study for residential customers is reasonable and appropriate.

¾ Collection Lag for MSS-4 and ISB Affiliate Rate Classes As to MSS-4 and ISB rate classes, Mr. Joyce determined that the collection lags were 46.19 and 15.61 days, respectively.79 Mr. Pous again disputed the accuracy of these estimates. Mr. Pous pointed out that the underlying data reveals that the majority of the MSS-4 revenue lag days range from 43 to 46 days, with only two values equaling or exceeding 50 days. Mr. Pous testified that the two values equaling or exceeding 50 days should be deemed unrepresentative and, therefore, excluded from the calculations for determining the average lag. Similarly, the majority of ISB revenue lag days range from 15 to 16 days, with only a few lags running as long as 22 days. Again, Mr. Pous contended that the longer revenue lag days should be deemed unrepresentative and excluded from the calculations for the average. Mr. Pous also complained that the payment deadlines for these affiliate transactions are stipulated in the Entergy System Agreement. Thus, it is Mr. Pous’ opinion that ETI unreasonably contractually agreed to “excessively long” revenue lag days associated with the MSS-4 and ISB rate classes. Mr. Pous concluded that if what he considers to be the unrepresentative lag days are excluded from the calculations, then the collection lag would change for the MSS-4 class from 46.19 days to 45.14 days, and for the ISB class from 15.61 days to 14.77 days. Collectively, the lag for the two classes would be .77 days shorter, resulting in an additional negative cash working capital of $3.2 million.80

Mr. Joyce first responded by disputing Mr. Pous’ contention that there are unusual outliers in the MSS-4 and ISB payment data. He noted that the lag days for MSS-4 payments ranged from 43 Id. at 17.

Id. at 18.

Cities Ex. 5 (Pous Direct) at 79-81; ETI Ex. 54 (Joyce Rebuttal) at 18.

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to 54 days. He described this as a “relatively tight payment range and certainly within the expected range of reasonableness.”81 Next, Mr. Joyce described Mr. Pous’ assertion that outlier numbers should not be considered in the data as nonsensical. Mr. Joyce agreed that, in cases where sampling is used (such as was done for the residential customer class), it is appropriate to exclude data points that are unrepresentative of the population as a whole. In the case of the MSS-4 and ISB classes, however, Mr. Joyce determined the collection lag by reviewing the entire class populations.

According to Mr. Joyce, it is inappropriate to eliminate data points when reviewing an entire population, unless it is necessary to make a known and measurable change.82

The ALJs are again unpersuaded by Mr. Pous’ criticisms. The ALJs conclude that ETI has met its burden as to show that the collection lag it utilized in the lead-lag study is reasonable and appropriate.

(c) Receipt of Funds Lag In the lead-lag study, Mr. Joyce identified the receipt of funds lag (i.e., the delay between the date the funds are received from the customers and the date the funds clear the bank and are available to ETI). As required by P.U.C. SUBST. R. 25.231(c)(2)(B)(iii)(IV)(-d-), Mr. Joyce assumed that one business day is needed to clear any payments by methods other than electronic transfer, while electronic payments are available to ETI on the date received. Because 53.39 percent of customer payments were made by methods other than electronic transfer, Mr. Joyce calculated the receipt of funds lag to be .77 days.83

Mr. Pous again contended that this duration is too long. He acknowledges that P.U.C.

SUBST. R. 25.231(c)(2)(B)(iii)(IV)(-d-) mandates the assumption that funds paid by check will be available “no later than” the following business day. However, he stated that this is merely the maximum possible duration, and ETI should take into account that fact that many checks are cleared ETI Ex. 54 (Joyce Rebuttal) at 19.

Id. at 19.

ETI Ex. 17 (Joyce Direct) at 10. The receipt of funds lag is also sometimes referred to by the witnesses as the “cash receipts float.”

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(and therefore the funds are available) sooner than one day later. Therefore, the funds from all checks received on any day other than Saturday should be assumed to be available on the date of receipt, while the funds from checks received on Saturday should be assumed to be available two days later. Mr. Pous was also critical of the fact that Mr. Joyce treated the funds from all “walk-in” payments made by customers to be available the next day. Funds from walk-in payments ought to be deemed available on the date they are received. If these two changes are adopted, Mr. Pous contended that receipt of funds lag would be shortened from .77 days to .15 days, resulting in an additional negative cash working capital of $2.1 million.84

Mr. Joyce first responded by pointing out that Mr. Pous’ contention that all funds are immediately available except for checks received on Saturdays is simply not accurate. Mr. Joyce cited from a 2007 Report to Congress made by the Board of Governors of the Federal Reserve System which supports the conclusion that most funds paid by check in this country are not available on the day they are received (and a significant portion are still not available the next business day).85 Mr. Joyce also disagreed with Mr. Pous’ contention that all walk-in payments should be considered immediately available. According to Mr. Joyce, walk-in payments are made at third-party vendor locations, such as grocery stores and check-cashing stores. Based upon his own investigation, Mr. Joyce determined that walk-in payments are actually available to ETI two days after receipt.

Thus, his one-day assumption for walk-in payments is conservative.86

The ALJs conclude that ETI has met its burden as to show that the receipt of funds lag it utilized in the lead-lag study is reasonable and appropriate. The positions taken by Mr. Pous on this issue were unreasonable and counter to the requirements of P.U.C. SUBST.

R. 25.231(c)(2)(B)(iii)(IV)(-d-).

Cities Ex. 5 (Pous Direct) at 81-82; Cities Ex. 5A (Errata No. 1).

ETI Ex. 54 (Joyce Rebuttal) at 21-23.

ETI Ex. 54 (Joyce Rebuttal) at 23-24.

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2. The Expense Lead Component of the Lead-Lag Study For the expense lead portion of his lead-lag study, Mr. Joyce calculated different expense lead days for numerous different categories of expenses. Each category will be discussed in turn.

(a) Expense Lead – Operations and Maintenance Expense Mr. Joyce separated O&M expenses into two groups – energy costs and “other O&M” expenses. Each of those two groups was further divided into subgroups.87

¾ Energy Costs Fuel. Mr. Joyce explains that, during the Test Year, ETI purchased two kinds of fuel: (1) coal and oil; and (2) natural gas. He concluded that there were 44.27 expense lead days for coal and oil, based upon the time between the service periods and payment dates or payment due dates for all coal and oil invoices from the Test Year. As to natural gas, he determined that there were 40.63 expense lead days, based upon a comparison of the service period and payment due dates and the payment dates from a random sample of gas invoices.88 No party challenged this approach, and the ALJs find no reason to do so either.

Purchased Power. Mr. Joyce explained that there were two components to ETI’s purchased power energy costs in the Test Year: (1) MSS-4 Purchases; and (2) Other Purchased Power (consisting of Joint Account Purchases, MSS-3 Purchases, Reserve Equalization, Cogeneration Purchases, Renewable Energy Credits, and Toledo Bend Purchases). Relying upon either the entire population or a sample from the Test Year (depending upon the category), Mr. Joyce concluded that there were 58.76 expense lead days for MSS-4, and 35.79 expense lead days for Other Purchased Power.89

ETI Ex. 17 (Joyce Direct) at 11.

Id. at 11 and JJJ-3.

ETI Ex. 17 (Joyce Direct) at 12 and JJJ-3.

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No party challenged the 35.79 day estimate for Other Purchased Power. However, on behalf of the Cities, Mr. Pous testified that the expense lead days for MSS-4 should be lengthened from 58.76 days to 60.65 days. According to Mr. Pous, Mr. Joyce made several errors in calculating the expense lead days for MSS-4 expenses. First, Mr. Joyce inadvertently placed the service period month after the billing month for two MSS-4 invoices. Mr. Pous based this conclusion on the fact that the expense leads for these two invoices are roughly 30 days shorter than the “vast majority” of the other invoices.90 In response, Mr. Joyce denied that he erroneously placed the service period month after the billing month, and pointed out that Mr. Pous lacks any evidence to support his assertion. Instead, Mr. Joyce considered the entire population of MSS-4 invoices for the Test Year.

Those invoices show payment lead days ranging from 30 to 120 days, with most points being near 30, 60, or 70 payment lead days. According to Mr. Joyce, this is reasonable and well within the range he has experienced in other rate cases.91

Mr. Pous testified that Mr. Joyce erred in calculating the expense lead days for MSS-4 expenses by considering only the payment due dates specified in the Entergy System Agreement, rather than also considering the actual payment dates. According to Mr. Pous, in four instances during the Test Year, extensions were granted to ETI to allow it to make MSS-4 payments after the deadline specified in the Entergy System Agreement. Therefore, Mr. Pous stated that the expense lead days for MSS-4 payments should have been calculated using the later of the actual payment date or the allowable payment period.92 Mr. Joyce largely agreed with Mr. Pous on this point. That is, he agreed that the payment lead days should be based on the later of the paid date or the due date.

However, he disagreed with some of Mr. Pous’ calculations on this issue because Mr. Pous wrongly designated several due dates of Saturday or Sunday, when he should have selected Fridays as the due date.93

Cities Ex. 5 (Pous Direct) at 83-84.

ETI Ex. 54 (Joyce Rebuttal) at 26-28.

Cities Ex. 5 (Pous Direct) at 84.

ETI Ex. 54 (Joyce Rebuttal) at 28-29.

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Next, Mr. Pous testified that Mr. Joyce erred in calculating the expense lead days for MSS-4 expenses by erroneously concluding that one invoice had been paid on the first of the month when, in fact, it had been paid on the 18th of the month.94 Mr. Joyce agreed with the change.95 Mr. Joyce then recalculated the expense lead days for MSS-4 and revised the number of lead days from 58.76 to 59.81.96

The ALJs conclude that ETI has met its burden as to show that there were 59.81 expense lead days for MSS-4, and 35.79 expense lead days for Other Purchased Power.

¾ Other O&M Expenses This category of expenses was broken down in the lead-lag study into four groups – regular payroll costs, incentive payroll costs, affiliate service company costs, and all other O&M costs (such as materials, services, and so on).

Regular Payroll Costs. The lead days for regular payroll costs were computed by determining the average days of service being reimbursed and adding the days between the end of each service period and the payments to employees. This amount was then adjusted to incorporate the effects of vacation pay based upon actual ETI data. By this method, Mr. Joyce determined the expense lead for regular payroll costs to be 20.68 days.97 No party challenged this approach, and the ALJs agree.

Incentive Pay Costs. ETI has an annual employee incentive program in place. Incentive payments for the year 2010 were made in the first quarter of 2011. The lead days for incentive pay costs were based on the weighted days between the midpoint of the service period (i.e., July 1, 2010) and the date the incentives were paid (March 10, 2011). By this method, Mr. Joyce determined the

Cities Ex. 5 (Pous Direct) at 84.

ETI Ex. 54 (Joyce Rebuttal) at 29.

ETI Ex. 54 (Joyce Rebuttal) at JJJ-R-2.

ETI Ex. 17 (Joyce Direct) at 13 and JJJ-3.

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expense lead for incentive pay costs to be 251.77 days.98 No party challenged this approach, and the ALJs agree.

Affiliate Service Company Costs and Other O&M Costs. Charges from Entergy Services, Inc. (ESI) are paid in the month following the month in which the charges were incurred. The lead days for affiliate service company costs were based on the number of days from the mid-month to the later of the contractual due date or the actual settlement date in the following month. By this method, Mr. Joyce determined the expense lead for affiliate service company costs to be 39.64 days.99

The lead days for other O&M costs were based on a random sampling from the Test Year.

Mr. Joyce originally determined the expense lead for other O&M costs to be 47.46 days.100 However, to correct an error on his part, Mr. Joyce subsequently revised the expense lead time for other O&M costs down to 43.89 days.101

Mr. Pous testified that ETI’s “FAS 106-related expenses” were wrongly included in either the affiliate service company costs or the other O&M costs. FASB is the body that establishes the rules that constitute GAAP. FASB’s Statement Number 106 (FAS 106) establishes the standards for an employer’s treatment of the non-cash retirement benefits it gives its employees. Based on the action taken by the Commission in Docket No. 16705,102 Mr. Pous believes that ETI’s FAS 106 costs should have been separately identified and accounted for in the lead-lag study. He contended

Id. at 14 and JJJ-3.

ETI Ex. 17 (Joyce Direct) at 15, and JJJ-3.

Id. at 15-17, and JJJ-3.

ETI Ex. 54 (Joyce Rebuttal) at JJJ-R-2.

Application of Entergy Gulf States, Inc. for Approval of Its Transition to Competition Plan and the Tariffs Implementing the Plan, and for the Authority to Reconcile Fuel Costs, to Set Revised Fuel Factors, and to Recover a Surcharge for Underrecovered Fuel Costs, Docket No. 16705, (Oct. 13, 1998).

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that, when those costs are properly accounted for, it results in an additional negative cash working capital of $3.8 million.103

Mr. Joyce contended that the prior Commission decision upon which Mr. Pous relies, Docket No. 16705, dates from 1996, is inapplicable to the facts in the present case, is outdated, and has been superseded by subsequent Commission decisions. Mr. Pous advocated a 312.55-day expense lead for FAS 106 expenses. However, Mr. Joyce pointed out that, during the Test Year, ETI made its FAS 106 payments to a trust at the end of each month, resulting in a one-half month payment lead (15.25 days). Mr. Joyce testified that his treatment of FAS 106 expenses in his lead-lag study is consistent with the approach that was approved by the Commission in a recent Oncor ratemaking case, Docket No. 35717.104

The ALJs conclude that ETI met its burden to show that there were 39.64 expense lead days for Affiliate Service Company Costs and 43.89 expense lead days for Other O&M Costs.

(b) Expense Lead – Current Federal Income Tax Expense As required by P.U.C. SUBST. R. 25.231(c)(2)(B)(iii)(IV)(-f-), Mr. Joyce calculated the lead days for federal income taxes by measuring the days between the midpoints of the annual calendar year service periods and the actual dates on which ETI made its estimated quarterly tax payments.

By this method, Mr. Joyce determined the expense lead for current federal income tax costs to be days. He then determined that this resulted in a $1.6 million cash working capital requirement associated with the Company’s Federal Income Tax Expenses.105

Mr. Pous testified that the Company’s cash working capital requirement for Federal Income Tax Expenses ought to be a negative number or, at most, zero. He bases this argument on his assertion that, during the past five years, the Company “has received in excess of a net $90 million of refunds” on its federal income taxes. In other words, because “refunds produce cash” for the Cities Ex. 5 (Pous Direct) at 85-88.

ETI Ex. 54 (Joyce Rebuttal) at 29-32.

ETI Ex. 17 (Joyce Direct) at 17, and JJJ-3.

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Company, Mr. Pous contends that the Company is seeking a positive cash working capital requirement for cash transactions “that have not been made and are not being made.”106

Mr. Joyce responds by disputing Mr. Pous’ contention that “refunds produce cash.”

Mr. Joyce points out that any refund from the IRS merely represents a return of the Company’s own cash for payments previously made. Moreover, Mr. Joyce stresses that his approach for calculating the expense lead for current federal income taxes is perfectly consistent with: (1) the requirements of P.U.C. SUBST. R. 25.231(c)(2)(B)(iii)(IV)(-f-); (2) current IRS guidelines found at IRS Publication 542; and (3) Commission precedent. Mr. Joyce further points out that, by contrast, Mr. Pous’ approach has been consistently rejected by the RRC.107 The ALJs find Mr. Joyce’s arguments to be more persuasive on this point and conclude that ETI has met its burden as to show that the expense lead for current federal income tax costs it utilized in the lead-lag study is reasonable and appropriate.

The ALJs conclude that ETI met its burden to show that there were 39.64 expense lead days for Affiliate Service Company Costs and 43.89 expense lead days for Other O&M Costs.

(c) Expense Lead and Lag – Taxes Other than Income Taxes This group of taxes consists of: (1) payroll-related taxes; (2) ad valorem taxes; (3) Texas state gross receipts taxes; (4) the PUC assessment tax; and (5) Texas state franchise taxes.

Calculating from the midpoints of the work periods to the respective payment dates of the taxes, Mr. Joyce determined that the payroll taxes had an expense lead time of 16.45 days. As to the franchise taxes, Mr. Joyce concluded that the Company had a collection lag of 46.42 days because the Company was required to pay the taxes in May 2010. As to the other non-payroll-related taxes, Mr. Joyce calculated from the midpoint of the period for which the tax was assessed to the payment date, resulting in the following expense lead days: 213.51 days for ad valorem taxes; 74.28 days for

Cities Ex. 5 (Pous Direct) at 88-89.

ETI Ex. 54 (Joyce Rebuttal) at 33-36, JJJ-R-1.

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Texas state gross receipts taxes; and 225.50 days for the PUC tax.108 No party challenged this approach, and the ALJs agree.

F. Self-Insurance Storm Reserve [Germane to Preliminary Order Issue No. 5] In Docket Nos. 16705 and 37744, the Commission authorized ETI to maintain a reasonable and necessary storm damage reserve account of $15,572,000.109 As of June 30, 1996, ETI had a positive reserve balance of $12,074,581, constituting a reduction to rate base. Over the next years, ETI charged $101,670,803 to the reserve related to more than 200 storms (excluding securitized events), but it accrued only $29,796,478 through base rates. Thus, ETI’s end-of-test-year balance for its storm damage reserve in the present case was a negative $59,799,744.110 This negative balance is an addition to rate base.111

OPC and Cities argue that ETI’s current storm damage reserve negative balance should be adjusted. OPC contends that ETI failed to prove that its storm damage expenses booked since 1996 were reasonable and prudently incurred, so it recommends disallowing all of those charges and refunding to customers the resulting positive balance that exceeds the authorized balance.

Alternatively, OPC suggests that ETI’s negative balance be reset to its currently authorized balance, with no refund to customers. Cities contend that ETI’s current negative storm damage reserve balance should be reduced because it includes: unreasonable expenditures associated with a 1997 ice storm; expenses associated with former assets in Louisiana; and amounts that Cities claim should have been treated as insurance deductibles. Cities also recommend transferring ETI’s Hurricane Rita Regulatory Asset to the storm damage reserve. The parties’ recommendations are summarized as follows:

ETI Ex. 17 (Joyce Direct) at 18-19, and JJJ-3.

Staff Ex. 4 (Roelse Direct) at 8. $12,074,581 + $29,796,478 – $101,670,803 = ($59,799,744).

P.U.C. SUBST. R. 25.231(c)(2)(E).

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Party Reserve Balance ETI ($59,800,000) Cities ($34,051,597) OPC-1 $41,871,059 OPC-2 $15,572,000

1. The Effect of Prior Settled Cases As with the Hurricane Rita Regulatory Asset (Section V.B.), the effect of the black-box settlements in Docket Nos. 34800 and 37744 is a significant issue concerning the storm damage reserve. However, the parties’ positions are generally reversed from the positions taken on the Hurricane Rita Regulatory Asset. That is, ETI now argues that its storm reserve negative balance was resolved and approved in those settled dockets, while Cities and OPC argue that it was not.

ETI notes that the final orders in Docket Nos. 34800 and 37744 contained “stipulated and agreed upon” conclusions of law stating that overall total invested capital through the end of the test year in those cases met the requirements of PURA § 36.053(a) that electric utility rates be based on the original cost, less depreciation, of property used by and useful to the utility in providing service.112 Then ETI cites language in P.U.C. SUBST. R. 25.231(c)(2)(E), which provides that any deficit in a self-insurance plan will be considered an increase to rate base, or invested capital. As a result, ETI argues, the Commission could not make a determination that a rate base expense item was included in rate base as used and useful without also determining that the rate base expense was prudently and reasonably incurred.113 Thus, ETI asserts, a Commission conclusion of law that approved invested capital as meeting the requirements of PURA § 36.053(a) necessarily also determined that an expense included in rate base was prudently and reasonably incurred. In other words, ETI states, the “prudent and reasonable” standard is incorporated into the “used and useful” PURA § 36.053(a) provides: “Electric utility rates shall be based on the original cost, less depreciation, of property used by and useful to the utility in providing service.”

ETI cited: City of Alvin v. Public Util. Comm’n of Texas, 876 S.W.2d 346, 353-354 (Tex. App.—Austin, 1993, no pet.); see also Application of Gulf States Utilities Company for Authority to Change Rates, Docket Nos. 7195 and 6755, 14 P.U.C. BULL. 1943 at 1969 (May 16, 1998) (“dishonest or obviously wasteful or imprudent expenditures constitutionally can be excluded from a utility’s rate base. Such costs clearly are not used and useful in providing serviced to the public.”).

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standard in PURA § 36.053(a).114 Therefore, ETI argues that by issuing a final orders in Docket Nos. 34800 and 37744 with conclusions of law that ETI’s overall total invested capital met the requirements of PURA § 36.053(a), the Commission implicitly approved the negative balances of its insurance reserve in both prior dockets; consequently, those orders preclude litigation in the present case of whether those expenses were prudently and reasonably incurred.115

Cities reject ETI’s contention that the storm damage reserve balance was approved in Docket Nos. 34800 and 37744. Cities point out that in order to comply with PURA, all final orders in rate cases must include a conclusion of law stating that the overall total invested capital through the end of the test year meets the requirements of PURA § 36.053(a). However, Cities contend, pursuant to the parties’ agreements in Docket Nos. 37744 and 34800, no determination was made as to what was included in ETI’s total invested capital in those cases. Cities explain that in Docket Nos. 37744 and 34800 Cities claimed that certain expenses were not properly included in the storm reserve balance, while ETI argues that they were. However, neither Cities nor ETI’s recommendation was specifically approved as part of the base rate settlement and neither of their recommended balances may be considered as the basis for setting rates in those dockets.116 Thus, Cities argues, in such “black box” settlements no specific storm reserve balance is approved unless expressly stated.

Cities also argues that the final orders in Docket Nos. 37744 and 34800 could just as logically be interpreted as denying ETI’s request to include objectionable expenses in the storm damage reserve, because both orders specified that the revenue requirement approved in those cases did not include any prohibited expenses. Finally, Cities states that adoption of ETI’s arguments would make black- box settlements impossible in the future.117

ETI cited Docket No. 7195, 14 P.U.C. BULL. at 1969 (“the prudent investment test is embodied in traditional ratemaking principles as expressed through PURA Sections … 41.”). PURA Section 41(a) is the predecessor to current Section 36.053.

ETI Initial Brief at 20-22; ETI Reply Brief at 17.

Docket No. 37744, Final Order at Ordering Paragraph 14; Application of Entergy Gulf States, Inc. for Authority to Change Rates and to Reconcile Fuel Costs, Docket No. 34800 at Ordering Paragraph 12.

Cities Reply Brief at 22-26.

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OPC makes arguments similar to Cities, and notes that no storm damage reserve amount was either agreed to by the parties or approved by the orders in either Docket No. 34800 or Docket No. 37744.118

The ALJs find that the Commission did not implicitly approved all of ETI’s storm damage expenses and its storm damage reserve balances in the final orders in Docket Nos. 34800 and 37744.

Although the orders in those settled cases contained conclusions of law the that overall total invested capital through the end of the test year met the requirements of PURA § 36.053(a), the orders made no findings of what the total invested capital included, and specifically there were no findings or conclusions approving the amount of the storm damage reserve. As pointed out by Cities, in those dockets the intervenors disputed various items in ETI’s requested storm damage reserve, but the “black box” settlement did not specifically address those issues; consequently, it is as logical to conclude that objectionable expenses were excluded from the storm damage reserve and from the total invested capital as it is to conclude that the objectionable expenses were included. In Section V.B., the ALJs conclude that ETI’s Hurricane Rita regulatory asset should be considered as being included in the black-box settlement and final order in Docket No. 37744, even though the settlement and order did not expressly state how the Hurricane Rita regulatory asset issue was resolved. However, that issue involved unique circumstances and is distinguishable because PURA § 39.459(c) required the Commission to consider the insurance payments for the Hurricane Rita restoration expenses in ETI’s next rate case, which was Docket No. 37744; ETI requested a true-up in that docket of the insurance proceeds it received concerning the regulatory asset; and no party objected to ETI’s proposed regulatory asset or its proposed amortization. In contrast, intervenors in Docket Nos. 34800 and 37744 did object to ETI’s proposed storm damage reserve and, under those circumstances, it is not possible to determine how the issues concerning the storm damage reserve were resolved by the black-box settlement. Therefore, the ALJs find that the black-box settlements and final orders in Docket Nos. 34800 and 37744 neither approved nor disapproved the reasonableness and necessity of ETI’s storm damage expenses incurred since 1996 or ETI’s current storm damage reserve negative balance.

OPC Reply Brief at 7-8.

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2. OPC’s Proposed Adjustment OPC witness Nathan Benedict testified that ETI failed to prove that any of its $101,670,803 in storm damage expense booked since 1996 was prudently incurred, so he recommended disallowing all of those charges and refunding to customers the resulting positive balance that exceeds the authorized balance. Removing those charges would leave ETI with a current positive storm reserve balance of $41,871,059 (beginning balance of $12,074,581 + accruals of $29,796,478). This balance exceeds the currently approved storm reserve balance of $15,572,000 by $26,299,059, and Mr. Benedict proposed that this surplus be refunded to rate payers at a rate of $1,314,953 per year for 20 years. Mr. Benedict acknowledged that some storm damage expenses incurred by ETI since 1996 likely were reasonable and necessary. Therefore, as an alternative proposal, Mr. Benedict suggested that ETI’s current storm balance reserve be set at the last approved amount of $15,572,000 (i.e., without any surplus or deficit). This proposal would result in a $75,363,744 reduction to ETI’s current storm damage reserve negative balance and rate base.119

As discussed above, OPC disagrees with ETI’s argument that the Commission implicitly approved these expenses in the final orders in Docket Nos. 34800 and 37744.120 Therefore, OPC argues that ETI had to prove in the present case that the expenses were prudently incurred.

Concerning ETI’s burden of proof, OPC acknowledges that, although a utility has the ultimate burden to prove that its proposed rates are just and reasonable, once the utility establishes a prima facie case of prudence of a rate change, the burden shifts to the other parties to produce evidence to rebut that presumption. Then, if the other parties rebut the presumption, the burden shifts back to the utility to prove by a preponderance of the evidence that the challenged expenditures were prudent. However, OPC notes, if the utility fails to establish a prima facie case, the burden of going forward with evidence never shifts to the other parties.121 In OPC’s opinion, ETI never established a prima facie case because ETI’s spreadsheet of storm damage expenses was excluded from evidence

OPC Ex. 6 (Benedict Direct) at 6-16; OPC Initial Brief at 19.

OPC Reply Brief at 7-8.

OPC Reply Brief at 2-3, citing, Entergy Gulf States, Inc. v. Public Utility Comm’n, 112 S.W.3d 208 (Tex. App. – 2003, pet. denied).

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and ETI witness Greg Wilson acknowledged on cross examination that he made no analysis of whether ETI’s storm damage costs were reasonable and necessary.122

ETI complains that Mr. Benedict simply sought a global rejection of more than $100 million of expenses without any evidence to support his position, and it stressed that even Mr. Benedict acknowledged that some of ETI’s expenses were prudently incurred. ETI also states that, in any event, it met its burden of proof with regard to expenses booked to the storm damage reserve.

Concerning its proof, ETI states that its burden was to make a prima facie case supporting the prudence of its invested capital,123 and once it made that showing, the burden shifted to the opposing parties to overcome the presumption of prudence by presenting evidence that reasonably challenged the expenditures.124 This is the same position as OPC. ETI argues that it met its burden to prove a prima facie case.125 ETI notes that it provided storm cost data accompanied by narrative testimony that supported the reasonableness of ETI’s self-insurance plan; storm preparedness and response; service quality; and cost of labor, materials, and services used to carry out distribution activities (including system restoration). For instance, ETI states, it presented its proposed storm reserve balance through the direct testimony of Mr. Greg Wilson126 and in the Commission’s rate filing package.127 Mr. Wilson also explained the function of ETI’s self-insurance program, described the $50,000 threshold to exclude minor weather events, and provided work papers detailing the nominal and trended losses for each storm booked to the reserve since 1986, as well as annual and total loss levels.128

OPC Reply Brief at 1-5.

ETI Initial Brief at 22, citing, Application of Texas Utilities Electric Company for Authority to Change Rates, Docket No. 9300, 17 P.U.C. BULL. 2057, 2148, Order on Rehearing (Sept. 27, 1991).

Docket No. 9300, 17 P.U.C. BULL. at 2148.

Although ETI contended that the storm damage reserve has been approved in prior dockets, it argued that its evidence also supported storm damage charges going back to July 1, 1996. ETI Initial Brief at 23, n. 147.

ETI Ex. 14 (Wilson Direct) at 11.

ETI Ex. 3 (Schedules) at Schedule B-1, line 7; Schedule WP_B-1, page 7.

ETI Ex. 14 (Wilson Direct) at 5-7; WP GSW-3_1.

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Further, ETI witness Shawn Corkran presented testimony regarding subject matters that directly support the ability of the system to withstand storms, and ETI’s ability to reasonably and efficiently respond to storm events, thereby supporting the conclusion that reasonable and necessary costs are booked to the storm reserve balance. This evidence included ETI’s distribution operations, industry-recognized comprehensive storm plans, annual storm drills, storm response and restoration processes, distribution maintenance and asset improvement processes, service quality and continuous improvement programs, and vegetation management practices. ETI points out that Mr. Corkran also described how it prepares for emergency situations,129 and Mr. Corkran explained how charges to the storm reserve are captured and recorded.130 Mr. Corkran also noted that ETI has received either the Edison Electric Institute’s Emergency Assistance Award or Emergency Response Award every year since 1998, which recognize ETI’s exemplary storm restoration response.131 Likewise, Mr. Corkran discussed ETI’s reliability statistics since 2000, which demonstrated a high quality of service,132 and he provided four exhibits demonstrating that, on both per-kilowatt-hour (kWh) and per-customer bases, ETI’s distribution O&M costs compared favorably to the costs of other utilities.133 In ETI’s opinion, because it carried out its distribution activities in the same efficient and cost-effective manner while performing routine activities as during storm restoration, those metrics and reliability statistics support the reasonableness of costs booked to the reserve.134

ETI also argues that it supported the reasonableness of the costs booked to its storm reserve through the direct testimony of its supply chain witness, Mr. Joseph Hunter. Mr. Hunter explained that ETI’s procurement policies and procedures are designed to streamline the acquisition of materials and services through the use of strategic supply networks in order to achieve the lowest reasonable cost.135 Mr. Hunter also described how the centralization of the supply chain function on Id. at 28.

Id. at 93.

Id. at 29.

Id. at 12-29.

Id., Exhibits SBC-2A, SBC-2B, SBC-2C, and SBC-2D.

ETI Initial Brief at 22-24.

ETI Ex. 16 (Hunter Direct) at 5, 9-10, and Exhibits JMH-1(Entergy Companies’ Procurement Policy) and JMH-3 (Entergy Companies’ Approval Authority Policy).

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a system-wide basis provides greater leverage and buying power in the procurement of materials and, thus, lower costs than could be achieved by ETI alone.136 Furthermore, Mr. Hunter specifically noted that the standardization of supply chain activities “makes possible a smoother day-to-day operation as well as rapid response to major storms or emergencies.”137

Finally, ETI stated that it provided an extensive amount of storm reserve data through the discovery process, which provided a basis for any interested party to investigate the reasonableness of any particular storm response or expenditure booked to the reserve. It stressed that OPC witness Benedict acknowledged that ETI provided 420 pages and over 22,220 lines of detail reflecting every charge to the storm reserve over the last 15 years,138 which specified the month, year, state, project code, work order type, function, storm name, account number, resource code, resource code description, and amount.139 Therefore, ETI argues that it made a prima facie case regarding its storm reserve through the presentation of narrative testimony, schedules, work papers, and expense detail and, accordingly, the burden shifted to parties seeking to disallow the expenses allocated to the storm damage reserve to present evidence that reasonably challenges their prudence.140 Yet, ETI contends, OPC did not challenge any specific expenditure booked to the reserve other than the 1997 ice storm expenses discussed later. Therefore, ETI argues that it met its prima facie burden and OPC’s proposed disallowance of either $101,670,803 or $75,363,744 should be denied.141

Although it is a close call, the ALJs find that ETI established a prima facie case that its storm damage expenses incurred since June 30, 1996, were prudently incurred. A prima facie case is a low burden. It is not the same as a preponderance of the evidence. Rather, as stated in Town of Fairveiw v. City of McKinney, prima facie evidence “is merely that which suffices for the proof of a particular

ETI Ex. 16 (Hunter Direct) at 17.

Id. at 18 (emphasis added).

Tr. at 1703.

Tr. at 1704.

Docket No. 9300, 17 P.U.C. BULL. at 2147.

ETI Initial Brief at 22-26; ETI Reply Brief at 16-19.

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fact until contradicted and overcome by other evidence.”142 Similarly, Black’s Law Dictionary defines a prima facie case as sufficient evidence “to allow the fact-trier to infer the fact at issue and rule in the party’s favor.”143

Except for expenses incurred with the 1997 ice storm, ETI did not present any testimony that explicitly stated that the expenses included in its storm damage reserve were prudently incurred.

However, ETI did present sufficient other evidence that at least allows the ALJs to infer that the expenses were prudently incurred. As noted above, a reasonable inference from the evidence presented is sufficient to establish a prima facie case. ETI witness Gregory Wilson presented testimony about the background of the storm damage reserve and about ETI’s yearly major storm damage losses, although OPC is correct that he did not explicitly evaluate or determine whether ETI’s expenses were reasonable and necessary.144 In addition, OPC witness Benedict provided testimony that ETI has booked $101,670,908 to the storm damage reserve since 1996,145 and that ETI’s $50,000 threshold is a means of excluding from the reserve small storm-related expenses that ETI could anticipate as routine O&M expense and which should be excluded from the storm damage reserve.146 ETI presented testimony that it had not recorded storm damage expense to both the storm damage reserve and to O&M expense,147 and Mr. Benedict agreed that he had no information to contradict this148 or that any securitized costs were charged to the storm damage reserve.149 Although the document itself was excluded from evidence, Mr. Benedict testified that ETI provided him with a 420-page spreadsheet covering all of ETI’s storm damage expenses back to 1996, including the month, year, state, project code, project name, work order type, function, storm name, account number, resource code, resource code description, and amount.150 In addition, ETI provided 271 S.W.3d 461, 467 (Tex. App. – Dallas 2008 pet. denied).

Black’s Law Dictionary, 8th Ed. (2004).

ETI Ex. 14 (Wilson Direct) at Ex. GSW-3.

OPC Ex. 6 (Benedict Direct) at 7-8.

Tr. at 1694.

ETI Ex. 72 (Wilson Rebuttal) at 2-3.

Tr. at 1695-1696.

Tr. at 1698.

Tr. at 1704.

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other testimony described previously concerning its distribution operations, storm plans, storm response operations, purchasing procedures, and the like.

ETI did not present a witness who specifically testified that all of its storm damage expenses booked to the storm damage reserve were prudently incurred, except for expenses related to the 1997 ice storm. Such testimony would have been more helpful than the evidence ETI relied upon.

Nevertheless, the burden of establishing a prima facie case does not require such direct testimony, if a fact can be reasonably inferred from other evidence presented. The ALJs reiterate that it is a close call, but they find that ETI did present sufficient evidence to infer that the expenses charged to the storm damage reserve were prudently incurred. At that point, the burden shifted to OPC to produce evidence to challenge specific expense items included in the storm damage reserve, but OPC did not present any such evidence except for the items discussed below. Therefore, the ALJs recommend that the Commission not adopt either of OPC’s recommended denials of expenses contained in ETI’s storm damage reserve.

3. 1997 Ice Storm ETI’s proposed negative storm reserve balance includes $13,014,379 in expenditures associated with a 1997 ice storm. Cities and OPC contend that this expense should be excluded from the storm balance reserve.

Cities witness Pous explained that ETI first requested to include the 1997 ice storm expense in the storm damage reserve as a post test year adjustment in its 1995-1996 test-year rate case, Docket No. 16705. The Commission denied the requested post test year adjustment and stated that the expense should be considered in ETI’s next rate case. Thereafter, ETI had a series of rate cases (Docket No. 20150 – 1998 rate case; Docket No. 30123 – 2004 rate case; Docket No. 34800 – 2007 rate case; Docket No. 37744 – 2009 rate case) in which intervenors challenged the 1997 ice storm expenses, but those cases all settled or were otherwise concluded without any express decision concerning the prudence of ETI’s 1997 ice storm expenses.151 Mr. Pous testified that these expenses

Cities Ex. 5 (Pous Direct) at 49-55.

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are now appropriately at issue in the present case, and he recommended that the entire balance be excluded from the storm damage reserve. He pointed out that in Docket No. 18249, the Commission found that ETI’s poor quality of service exacerbated the extent of damage caused by the storm, and it found that the response efforts were uneven and delayed and could have been more effective if ETI had a better communication and management program in place.152 Mr. Pous also contended that in the present case ETI failed to prove that any portion of the 1997 Ice Storm expenses were reasonable.153

Thus, Cities argue that the Commission has already determined that ETI’s negligence was a major factor in the extent and duration of the outages,154 so no expenses associated with the 1997 ice storm should be eligible for recovery from customers through the storm damage reserve. In response to ETI’s argument that it was already penalized for these issues in Docket No. 18249 through a reduction to the allowed ROE, Cities argue that the Commission did not absolve ETI from responsibility for damage caused by ETI’s poor service quality, and ETI’s customers should not be ordered to pay for expenses that were caused by ETI’s negligence.155

OPC makes the same arguments as Cities concerning the 1997 ice storm expenses.156

ETI argues that, due to quality of service issues related to the 1997 ice storm, the Commission reduced Entergy Gulf States, Inc.’s (EGSI) ROE by 60 basis points in Docket No. 18249 and subjected EGSI to significant spending requirements and quantified performance guarantees. In ETI’s opinion, it would be inequitable to now penalize ETI a second time for the same issues. Moreover, ETI argues that it established that its expenses were reasonable and necessary. ETI witness Shawn Corkran testified that the 1997 ice storm was the most destructive

Entergy Gulf States, Inc. Service Quality Issues Severed From Docket No. 16705, Docket No. 18249, Final Order at FoF 97, 98, & 102 (Apr. 21, 1998).

Cities Ex. 5 (Pous Direct) at 56-59; see Cities Initial Brief at 18-19.

Cities Initial Brief at 18 (“The Company’s failure to clear the limbs before the storm was a major factor in the number and duration of outages experienced by customers.”).

Cities Reply Brief at 28-30.

OPC Ex. 6 (Benedict Direct) at 12; OPC Initial Brief at 16; OPC Reply Brief at 7-10.

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winter storm ever to hit the EGSI/ETI system, with about 3,400 miles of distribution lines and miles of transmission lines de-energized during the storm’s peak. A large part of the restoration effort involved clearing broken and fallen trees and tree limbs from lines. Mr. Corkran reviewed all of the costs incurred in response to the 1997 ice storm and stated that they were reasonable and necessary to reliably restore service to customers as quickly as possible after the storm. He provided an exhibit with a detailed breakdown of labor, materials, transportation, lodging, and other expenses incurred. In his opinion, all of these costs charged to the storm damage reserve, totaling $13,014,379, were reasonable, necessary, and prudently incurred.157

The ALJs recommend that the Commission authorize ETI to include in the storm damage reserve its $13,014,379 in expenditures associated with the 1997 ice storm. ETI established that those expenses were reasonable and necessary to repair the damage and restore power to its customers. ETI witness Mr. Corkran provided detailed testimony concerning the seriousness of the storm and the resulting expenses incurred for repair work and restoration of power to customers.158

In contrast, Cities and OPC did not challenge any specific item in these restoration expenses.

Instead, they relied upon the Commission’s findings in Docket No. 18249 that ETI’s deficient maintenance exacerbated the amount of damage caused by the storm. However, in that docket the Commission also reduced ETI’s ROE by 60 basis points due to poor service issues, including deficient preventative maintenance. The Commission made the reduction in ROE retroactive and required ETI to make refunds to customers. Likewise, in that docket the Commission found that the ice storm was severe and that significant damage would have occurred even with exemplary vegetation management and other preventative measures. It is not feasible to accurately determine now what portion of ice storm damage that occurred 15 years ago was caused by preventative maintenance issues.

The ALJs conclude, however, that the Commission’s retroactive reduction of ETI’s ROE in Docket No. 18249 in part compensated ratepayers for the poor service issues that exacerbated the ETI Ex. 48 (Corkran Rebuttal) at 2-12.

ETI Ex. 48 (Corkran Rebuttal) at 2-12 and Ex. SBC-R-1.

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storm damage. Nevertheless, once the ice storm occurred, ETI had to take appropriate action to repair the damage and restore service. ETI has established the expenses incurred in those efforts were reasonable and necessary, and the ALJs find that they should be included in the storm damage reserve. Therefore, the ALJs recommend that the Commission deny Cities and OPC’s proposed adjustment.

4. Jurisdictional Separation Plan Allocation Cities complained that ETI’s storm damage reserve deficit includes $12,498,325 in costs that belong to Louisiana jurisdiction customers but were incorrectly transferred to Texas customers during implementation of the Jurisdiction Separation Plan. Cities explain that before the jurisdictional separation of EGSI into ETI and Entergy Gulf States Louisiana, LLC (EGSL), the transmission investment and expense associated with maintaining the transmission system, including storm restoration costs, was allocated between the Texas and Louisiana retail jurisdictions. In the jurisdictional separation of EGSI into ETI and EGSL, the transmission system investment was split between each company based upon a situs basis. The transmission facilities in Texas were transferred to ETI and the transmission facilities in Louisiana were transferred to EGSL. After the jurisdictional separation, ETI and EGSL were each responsible for future O&M expense, including storm restoration expense, associated with their respective transmission investments.

Cities claim that in the present case ETI has attempted to reverse the allocation of expenses incurred on behalf of Louisiana customers before the jurisdictional separation and to charge those expenses to Texas customers through the storm damage reserve. In Cities’ opinion, any expense that was allocated to Louisiana customers prior to the jurisdictional separation was properly charged to Louisiana customers. Cities argue that ETI may not now reverse expenses allocated to Louisiana customers and charge them to Texas customers solely on the basis that ETI acquired the transmission investment located in Texas.159

Cities Ex. 5 (Pous Direct) at 59-60; Cities Initial Brief at 19-20.

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In response, ETI witness Considine explained that an analysis of storm reserve charges was preformed prior to the jurisdictional separation to determine if storm charges were incurred for Texas or Louisiana property. The reclassification of certain charges was made as a result of that analysis, which is in evidence, to properly reflect the state in which the storm charges were incurred.

The largest charge assigned to ETI through this analysis was a $10,652,130 charge related to project “E2PPSJ8291 Trans EGSI-TX Hurricane Rita 9-24-05,” which expressly related to damages to the Texas portion of the former EGSI transmission system. Similarly, costs were assigned from ETI to EGSL for projects such as “E2PPSJ8296 Trans. Hurricane Katrina - EGSI-La” and “E2PPSJ8302 Trans EGSI-LA Hurricane Rita 9-24-05,” that clearly related to assets located in Louisiana. In other words, prior to the separation, the Texas portion of the storm damage reserve could include charges for restoration work performed on assets located in Louisiana, and vice versa. The analysis conducted pursuant to the separation re-aligned the charges to the jurisdiction where the assets are located. In that way, ETI argues, neither jurisdiction has charges in its storm reserve balance for assets located in the other jurisdiction. In short, ETI argues that the assets and liabilities following the separation have been properly assigned and no improper cost shifting occurred.160

The ALJs recommend that the Commission deny Cities’ proposed adjustment. ETI offered evidence to explain how its reclassification study reassigned various costs from the Texas jurisdiction to Louisiana, as well as from the Louisiana jurisdiction to Texas. This study resulted in more expenses from Louisiana being reassigned to the Texas jurisdiction than from Texas to Louisiana, but Cities offered no evidence to explain why the study was flawed or why the reassignments were in error. The ALJs found ETI’s evidence to be credible and that it supported the jurisdictional allocation of these expenses as proposed by ETI.

5. $50,000 Reserve Threshold Cities witness Pous also proposed a $10,950,000 reduction to ETI’s negative storm damage reserve balance due to ETI including in the reserve the first $50,000 of expense for each separate storm event. Mr. Pous asserted that this amount is equivalent to a deductible for insurance purposes ETI Ex. 46 (Considine Rebuttal) at 25 and Ex. MPC-R-3 at 25; ETI Initial Brief at 19-36; ETI Reply Brief at 20-21.

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and should have not been charged to the reserve. Cities note that P.U.C. SUBST. R. 25.231(b)(1)(G) requires that a storm reserve only collect for “property and liability losses which occur, and which could not have been reasonably anticipated and included in operating and maintenance expenses.”

Because of ETI’s low $50,000 threshold, Cities contend, ETI has recorded to the storm reserve expenses associated with 219 different weather events in the past 15 years. This equates to approximately 14.6 weather events per year, or 1.2 weather events per month, on average. In Cities’ view, ETI’s booking to the storm damage reserve of all expenses associated with a weather event exceeding $50,000 – including the first $50,000 – is inconsistent with P.U.C. SUBST.

R. 25.231(b)(1)(G). Cities argue that ETI may not reasonably claim that such a recurring expense is “not reasonably anticipated” to qualify it for the storm reserve. Cities proposed adjustment is based on $50,000 for each of the 219 storm events, for a total of $10,950,000. In addition, based on the nature of ETI’s recurring storm expense, Cities also recommend that the deductible amount be increased to $500,000, which Cities stated is consistent with the storm reserve treatment afforded to other utilities in Texas.161

ETI witness Gregory Wilson testified that Mr. Pous misconstrued the $50,000 trigger when he treated it as a deductible. Mr. Wilson explained that if a storm causes $50,000 or less in damage, the expenses are not charged to the storm damage reserve. However, if a storm causes more than $50,000 in damage, all of the expenses are charged to the reserve. He noted that if the $50,000 were treated as a deductible, then that amount would still be charged to O&M whenever storm damage exceeded the $50,000 threshold. But, under the current arrangement, when storm damage exceeds $50,000 all of the expenses are charged to the storm damage reserve, and the first $50,000 is not charged to O&M. Therefore, no double recovery occurs. Moreover, ETI argues that Cities’ proposed retroactive removal of these amounts from the reserve would constitute a disallowance of costs without any finding of imprudence, as well as impermissible retroactive ratemaking. ETI also contends that even if the Commission were to implement Mr. Pous’s recommendation prospectively, it would require a corresponding increase in ETI’s O&M costs. Therefore, ETI disagreed with

Cities Ex. 5 (Pous Direct) at 61-63; Cities Initial Brief at 20-21.

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Cities’ recommendation to reduce the current balance of the storm damage reserve by $10,950,000 or to change the current level of the threshold.162

The ALJs find that Cities’ proposed adjustment to ETI’s storm damage reserve is not warranted. ETI explained that the $50,000 threshold amount was included in the storm damage reserve whenever storm restoration expenses exceeded the threshold, but that amount was not included in O&M expense. Accordingly, no double recovery has occurred, and Cities presented no other valid reason to disallow the allocation of these expenses to the storm damage reserve.

Therefore, the ALJs recommend that the Commission deny Cities’ proposed $10,950,000 adjustment to ETI’s current storm damage reserve balance. As a policy matter, the Commission may choose to increase ETI’s threshold on a prospective basis to some higher amount, as recommended by Cities, but the evidence presented by the Cities on this issue was not sufficient for the ALJs to make such a recommendation.

6. Hurricane Rita Regulatory Asset As discussed in Section V.B., Cities recommend an adjustment to the Hurricane Rita regulatory asset, and they recommended the adjusted balance be moved to the storm damage reserve.

For the reasons stated in Section V.B., the ALJs recommend that the Commission not adopt Cities’ proposal to move the Hurricane Rita regulatory asset to the storm damage reserve.

7. Conclusion In conclusion, the ALJs find that ETI’s storm damage expenses since 1996 and its storm damage reserve balance were not approved by the Commission as a result of the black-box settlements in Docket Nos. 34800 and 37744. The ALJs also find that ETI established a prima facie case concerning the prudence of its storm damage expenses incurred since 1996 and that intervenors’ proposed adjustments should be denied. Therefore, the ALJs recommend that the Commission approve ETI’s test-year-end storm reserve balance of negative $59,799,744.

ETI Ex. 72 (Wilson Rebuttal) at 2-3; EIT’s Initial Brief at 27-28; ETI Reply Brief at 21-22.

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G. Coal Inventory ETI is the partial owner of two coal-fired power generating facilities. It owns a 29.75 percent interest in Nelson 6, a 550 megawatt (MW) unit located in Westlake, Louisiana (Nelson), and a 17.85 percent interest in Big Cajun II, Unit 3, a 588 MW unit located in New Roads, Louisiana (BCII/U3). EGSL is the majority owner and operator of Nelson and is responsible for the supply and delivery of coal to that facility. A third party, LaGen, is a co-owner of BCII/U3, and is the operator of the plant. Pursuant to a joint operating agreement between the co-owners, LaGen is responsible for the acquisition and delivery of coal to BCII/U3. The coal for both units comes, via train, from minefields in Wyoming.163

Entergy has adopted a “Coal Inventory Policy” at Nelson to ensure that a sufficient coal inventory is always maintained on-site to help mitigate transportation and unit operating risks. The policy calls for, among other things, a 12-month average inventory target of a 43-day supply of coal.

Because Entergy is not the operator of BCII/U3, it does not have ultimate control over the coal inventories at that unit. Pursuant to the joint operating agreement for that unit, however, each year ETI nominates for the next calendar year the level of coal to be delivered for its account at BCII/U3.

ETI’s nomination process is targeted to ensure an end-of-year inventory target of a 43-day supply of coal.164

In its application, ETI includes a coal inventory amount in its rate base that is based upon the average inventories at Nelson and BCII/U3 for the 13 months ending in June 2011.165 The average coal inventory at Nelson was 384,860 tons, representing approximately 48 days of inventory, assuming an average daily burn rate of 8,000 tons. The total proposed dollar amount for the coal inventories at both facilities is $9,846,037. Of that total, the Nelson portion is $6,040,926, and the

ETI Ex. 33 (Trushenski Direct) at 3-4.

ETI Ex. 33 (Trushenski Direct) at 30-31.

ETI Ex. 68 (Trushenski Rebuttal) at 2. Notably, the amount ETI is seeking in its Rate Base is calculated upon a 13-month average ending June 2011 (the last month of the Test Year), even though that amount is slightly less than the 12-month average for the Test Year.

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BCII/U3 portion is $3,805,111.166 ETI witness Ryan Trushenski, the Manager of the Solid Fuel Supply Group for ESI, testified that the coal inventory levels that were maintained at Nelson and BCII/U3 during the test year were reasonable and the costs incurred to maintain those levels were reasonable.167

Cities do not challenge the reasonableness of the Company’s 43-day inventory targets.

Rather, Cities point out that the size of the actual inventory that was maintained on-site at Nelson during the Test Year exceeded the Company’s inventory target level. Therefore, Cities contend that customers should not be forced to pay for inventory levels exceeding a 43-day supply (the amount that the Company determined, through its Coal Inventory Policy, to be a reasonable and necessary inventory to maintain on-site). According to Cities’ witness, Karl Nalepa, a 43-day inventory of coal at Nelson would equate to 340,000 tons. He recommends that the value of a 43-day supply of coal be included in the rate base, but that $1,451,415 be excluded from the rate base to account for inventory at Nelson that was in excess of the 43-day supply.168

The evidence shows that the Company’s inventory “target” was a 43-day supply, while actual inventories during the Test Year averaged around a 48-day supply. Mr. Trushenski pointed out, and the ALJs concur, that the 43-day “target” was never intended to represent a hard and fast figure from which no deviations could be allowed. Rather, the target merely represents an operational planning tool. Moreover, there are many real-world factors – such as train cycle times, coal burn rates, and so on – that can cause the actual coal inventory to fluctuate over time.169 The ALJs conclude that the 48-day coal inventory was acceptably close to the 43-day target and was not unreasonable. The total proposed dollar amount for this coal inventory is $9,846,037. The ALJs conclude that the full value of the coal inventory was reasonable and should be included in rate base.

ETI Ex. 68 (Trushenski Rebuttal) at 2, and 3 at WP/P RB 4.2.

ETI Ex. 33 (Trushenski Direct) at 30-31.

Cities Ex. 6 (Nalepa Direct) at 28-29, 6C and 6E.

ETI Ex. 68 (Trushenski Rebuttal) at 4.

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H. Spindletop Gas Storage Facility ETI relies upon a variety of fuel types to generate electricity. A major fuel component is natural gas. However, energy generated from natural gas typically has the highest marginal cost and, therefore, it is most often the last resource deployed to generate electricity. The fluctuation of natural gas demand resulting from the changes in instantaneous demand is known as “swing.”

Although a portion of the system’s base load requirement is met with natural gas, the primary role of natural gas is as a swing fuel on the system.170

Since 2004, ETI has owned and used the Spindletop Facility. ETI, through a third-party operator, uses the Spindletop Facility to maintain a natural gas inventory that can be used to supply ETI’s Sabine Station and Lewis Creek power generating facilities. Spindletop consists of two salt-dome storage caverns (and associated equipment) located near Sabine Station.171 The Spindletop Facility serves a function similar to that of a city water tower – it enables ETI to buy natural gas at one point in time, store it, and use it at some future point when supplies are not available elsewhere or when peak needs cannot otherwise be met. ETI maintains that the primary benefit of the Spindletop Facility is that it provides: (1) supply reliability; and (2) swing flexibility.

“Supply reliability” means that the facility can provide a reliable supply of gas for Sabine Station and Lewis Creek during potential gas supply curtailments, such as can occur during hurricanes, freezes, or other unusual events. In a worst-case scenario, the Spindletop Facility is capable of providing 100 percent of the fuel requirements for all five units at Sabine Station and one Lewis Creek unit for four days at 70 percent of capacity. The Spindletop Facility also allows the Company to avoid almost all intra-day gas purchases for Sabine Station. This is important because intra-day purchases tend to be more expensive than longer-term purchases.172

Because major supply disruptions are more likely to occur during hurricane season and during the winter, ETI manages its gas inventories conservatively during the period from June through March in order to ensure that it can provide a reliable supply of fuel to meet peak generation

ETI Ex. 28 (McIlvoy Direct) at 7.

Id. at 31.

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loads for four consecutive days. During the remainder of the year, ETI will consider withdrawing gas from the Spindletop Facility when the current day spot market price is higher than the replacement cost for the gas, as determined by future market indicators. Conversely, ETI injects gas into the Spindletop Facility when the cost of gas in the current market is less than the price of gas in the futures market.173 For these various reasons, ETI witness Karen McIlvoy, who is employed as the manager of ESI’s Gas & Oil Supply Group, testified that that Spindletop Facility is used and useful for providing reliable, economical service to ETI’s customers.174 ETI witness Devon Jaycox, who is employed as the manager of ESI’s Operations and Planning Group, testified that the Company is always evaluating how much reliability the Spindletop Facility can provide as compared to other options. He explained that, at Sabine Station, there is no other option that can provide ETI with the same level of reliability and flexible swing service that the Spindletop Facility provides.175

Cities are critical of the Spindletop Facility, contending that the costs of operating it outweigh the benefits gained from it. No other party challenged ETI’s use of the Spindletop Facility. Cities’ witness Karl Nalepa testified that it costs ETI $13,219,097 per year to operate the gas storage facility, whereas the Company could achieve the same supply reliability and swing flexibility benefits it gets from the Spindletop Facility through other gas supply options at a cost of only $1,724,659, thereby saving its customers $11,494,438. Thus, Mr. Nalepa stated that it is imprudent for ETI to continue operating the Spindletop Facility.176

Mr. Nalepa testified that no other Entergy operating company owns or leases its own gas storage facility, yet those other companies are able to satisfy their needs for supply reliability and swing flexibility through other methods, such as existing gas supply and transportation contracts, at much lower costs. According to Mr. Nalepa, those other companies obtain supply reliability and swing flexibility through the use of monthly, daily, and intra-day natural gas supply contracts. In

ETI Ex. 28 (McIlvoy Direct) at 32-33; ETI Initial Brief at 39, n. 264.

ETI Ex. 28 (McIlvoy Direct) at 33-34.

Id. at 37.

Tr. at 966.

Cities Ex. 6 (Nalepa Direct) at 18-20; Cities Ex. 6B (Errata No. 2).

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support of this claim, he pointed to one of the operating companies, EGSL, as an example. He pointed out that EGSL has no firm transportation contracts, no firm supply contracts, and no fuel oil back-up at its generating plants. Thus, Mr. Nalepa stated that the only cost incurred by EGSL for reliability and flexibility is the commodity cost of the natural gas it purchases. Mr. Nalepa testified that EGSL achieves the same level of service as ETI without incurring the large cost of the Spindletop Facility.177

Mr. Nalepa asserted that the long-term gas supply contract that ETI recently entered into with Enbridge Pipeline, L.P. (the Enbridge Contract) will help provide the Company with increased supply reliability because the gas supplied by Enbridge will come from production areas that are less susceptible to hurricane-related disruptions. Mr. Nalepa also noted that ETI could meet its swing flexibility requirements through use of spot gas purchases, its operational balancing agreement with the TETCO pipeline, and other pipeline companies, such as the Copano Pipeline that serves Lewis Creek.178

Mr. Nalepa also disputed ETI’s contention that the Spindletop Facility serves as a valuable protection against extreme events such as hurricanes, by noting that the Spindletop Facility was out of service for almost two weeks in 2005 following Hurricane Rita.179

As noted above, Mr. Nalepa testified that it cost ETI $13,219,097 to operate the Spindletop Facility in the Test Year. Mr. Nalepa estimated that the sum of the Test Year withdrawals of gas from the Spindletop Facility equaled 8,560,604 MMBtu. He then divided his total estimated cost of the facility ($13,219,097) by his total estimated withdrawals of gas (8,560,604 MMBtu) to calculate an “all-in per unit rate” of $1.54 per MMBtu. He asserted that, by contrast, transportation costs on various gas pipelines connected to Sabine and Lewis Creek ranged from $0.025 to $0.22 per MMBtu. Mr. Nalepa estimated $0.18 per MMBtu as the average replacement cost that ETI would incur in transportation contracts if it were to stop using the Spindletop Facility and achieve the same

Cities Ex. 6 (Nalepa Direct) at 22-23.

Cities Ex. 6 (Nalepa Direct) at 25.

Id. at 23-24.

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level of supply reliability and swing flexibility through the use of gas supply contracts. By multiplying $0.18 times 8,560,604 MMBtu, he estimated that the benefits of the Spindletop Facility could have been achieved through other means at a cost of only $1,724,659. Thus, Mr. Nalepa recommended that $7,794,202 should be removed from ETI’s base rate, and $5,424,895 should be excluded as an eligible fuel expense.180

ETI disagrees with essentially all of Mr. Nalepa’s points and responds to his testimony on a number of fronts. Perhaps foremost, ETI points out that Mr. Nalepa’s main premise – that ETI’s customers pay all the costs of the Spindletop Facility while the other Entergy operating customers avoid those costs – is simply incorrect. According to ETI witnesses, 57.50 percent of the costs associated with the Spindletop Facility are billed to EGSL as part of the MSS-4 billing process between ETI and EGSL for its “legacy plants,”181 and another 2.4 percent of the costs are passed on to other Entergy operating companies through the MSS-3 agreement. Only 40.1 percent of the Spindletop Facility costs are borne by ETI customers.182 Thus, Mr. Nalepa’s calculations greatly overstate the costs of the Spindletop Facility that are borne by ETI customers and greatly understate the costs that are borne by EGSL customers. ETI witness Considine also pointed out that the Commission has consistently and repeatedly concluded that the Spindletop Facility is used and useful and, therefore, has allowed ETI and its predecessors to recover the costs associated with the Spindletop Facility.183

Ms. McIlvoy also testified that, contrary to Mr. Nalepa’s testimony, the conditions under which the other Entergy operating companies operate are so different from the conditions under which ETI operates that it makes no sense to assume they have similar supply reliability and swing flexibility needs. For example, EGSL and ETI both own roughly the same generating capacity from

Id. at 24-27; Cities Ex. 6B (Errata No. 2).

The legacy plants are the four power generating plants that were owned by Entergy Gulf States, Inc. – Lewis Creek, Sabine Station, Nelson, and Willow Glen. When EGSI was broken into ETI and EGSL in 2007, ETI became the owner of Lewis Creek and Sabine Station, while EGSL became the owner of Nelson and Willow Glen. ETI Ex. 60 (McIlvoy Rebuttal) at 5-6; ETI Ex. 46 (Considine Rebuttal) at 3.

ETI Ex. 46 (Considine Rebuttal) at 3-4; ETI Ex. 60 (McIlvoy Rebuttal) at 18-19.

ETI Ex. 46 (Considine Rebuttal) at 3-4.

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gas-powered plants – 2,378 MW for EGSL versus 2,295 MW for ETI. However, the ETI plants are operated at a much higher capacity than the EGSL plants. During the Reconciliation Period, EGSL burned much less natural gas than did ETI – 63,420,554 MMBtu burned at the EGSL plants versus 144,538,535 MMBtu burned at the ETI plants. Moreover, EGSL has four gas-powered plants while ETI has only two. Of EGSL’s four plants, two (Calcasieu and Ouachita) use combined cycle gas turbine technology. This gives them a quick-start and shut-down capability, allowing them to be operated primarily only at peak demand times. Thus, according to Ms. McIlvoy, Mr. Nalepa’s premise – that because EGSL is able to reliably operate its gas-fired facilities without gas storage, ETI should be able to do so as well – makes no sense. Because ETI burns a vastly larger amount of natural gas than EGSL, its need for supply reliability and swing flexibility is much greater.184

Ms. McIlvoy also disputed Mr. Nalepa’s assertion that ETI could use the Enbridge Contract and call options to provide the Company with sufficient supply reliability. She noted that the maximum amount of gas deliverable under the Enbridge Contract is insufficient to run the ETI plants even at minimum load. By contrast, the Spindletop Facility is capable of supplying all Sabine Station units and one unit at Lewis Creek for four days at 70 percent capacity. Moreover, the Enbridge Contract will expire, whereas the Spindletop Facility can be operated indefinitely.

Ms. McIlvoy explains that the use of call options is not viable because a call option must be delivered “ratably,” meaning the gas must be delivered at a constant, even rate throughout the delivery period. In order to have gas available to meet peak needs in the absence of the Spindletop Facility, ETI would have to exercise call options for a maximum delivery, but it would not need all of the gas delivered at off-peak times of the day.185

ETI witness Jaycox disputed Mr. Nalepa’s premise that ETI could use call options to ensure reliability. According to Mr. Jaycox, “call options are cheaper than storage, but there’s no comparison” between the amount of reliability that they provide as compared to the Spindletop Facility.186 Mr. Jaycox also explained that, due to their geographic location and the limited import ETI Ex. 60 (McIlvoy Rebuttal) at 3-8.

ETI Ex. 60 (McIlvoy Rebuttal) at 8-12.

Tr. at 969.

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capability to the ETI service area, Sabine Station and Lewis Creek are considered particularly critical, thereby increasing the need for reliability at those plants.187

When Mr. Nalepa calculated ETI’s cost of achieving supply reliability and swing flexibility without the use of the Spindletop Facility, he estimated it would cost only $1,724,659. He did so, in part, by assuming that a five-day 35,000 MMBtu/day call option would cost ETI $26,250.

Ms. McIlvoy asserted that it is not reasonable to assume that all options would cost as little as $26,250. Based upon her calculations, ETI would have to purchase 14 five-day 35,000 MMBtu/day call options per month to achieve supply reliability. She posited that, based upon the laws of supply and demand, the more call options ETI has to purchase, the higher the cost of those options would be. She also pointed out that Mr. Nalepa’s proposed use of call options would require ETI to spend hundreds of thousands of dollars each month to purchase call options that it would never exercise.

According to Ms. McIlvoy, it is unclear from Commission precedents whether ETI would be entitled to recover the costs of these un-exercised options.188

The evidence establishes that the Spindletop Facility is critical to providing reliability and swing flexibility to ETI’s Texas plants. The ALJs conclude that the Spindletop Facility is a used and useful facility providing reliability and swing flexibility to ETI’s customers at a reasonable price, and Cities’ arguments to the contrary lack merit.

I. Short Term Assets In its application ETI requested that, as short term assets, the following amounts be included in the rate base: prepayments in the amount of $7,218,037; materials and supplies in the amount of $29,252,574; and fuel inventory in the amount of $53,759,975. These amounts were derived using 13-month averages ending June 2011.189 Staff witness Anna Givens agrees with the approach of using 13-month averages to determine the appropriate amounts for short term assets. However, she recommends using the 13-month period ending December 2011, because it is the most recent Tr. at 975, 986-87.

ETI Ex. 60 (McIlvoy Rebuttal) at 12-15.

ETI Ex. 3 at Sched. B-1.

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information available. Using this approach, Ms. Givens recommends that, as short term assets, the following amounts be included in the rate base: prepayments at $8,134,351 ($916,313 more than ETI’s request); materials and supplies at $29,285,421 ($32,847 more than ETI’s request); and fuel inventory at $52,693,485 ($1,066,490 less than ETI’s request).190 ETI does not oppose Staff’s recommendation on this issue. No party has a criticism of Staff’s estimates as to prepayment, materials and supplies, and fuel inventory, nor do the ALJs. Accordingly, the ALJs recommend adopting the numbers proposed by Staff.

J. Acquisition Adjustment In its application, ETI included an adjustment of $1,127,778 for an “electric plant acquisition.”191 The proposed adjustment, which relates to costs incurred by ETI when it acquired the Spindletop Facility, consists of closing costs of $211,209 and legal and internal costs of $916,568.192 ETI witness Considine explained that, prior to December 2009, the same amounts were included in the Electric Plant in Service (FERC Account 101). On January 11, 2010, FERC issued Opinion No. 505 in FERC Docket No. ER07-956-00 and ordered the Company to transfer the amounts above from Account 101 to FERC Account 114, Electric Plant Acquisition Adjustments.

He also pointed out that the costs were included in ETI’s filed rate base amounts in Docket Nos. 34800 and 37744.193 Mr. Considine contended that these amounts should remain in rate base because they represent costs incurred by ETI for the purchase of a viable asset that benefits its retail customers. He pointed out that the amounts have previously been included in the Company’s rate base, but the only thing that has changed is that the amounts were previously allocated to a different account. ETI argues that the fact that the costs were approved as part of rate base in two previous ETI dockets verifies that they were “reasonable, prudently incurred, and properly capitalized.”194

Staff Ex. 1 (Givens Direct) at 31-32.

ETI Ex. 3 at Sched. C-1.

ETI Ex. 46 (Considine Rebuttal) at 4.

Id. at 4-5.

ETI Initial Brief at 43.

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Thus, ETI contends it would be inappropriate to penalize it because of an accounting technicality imposed upon it by FERC.195

Staff advocates the removal of the entire electric plant acquisition adjustment from rate base, contending that, “[a]s a rule, the rate base component for plant in service includes only the original cost, net of accumulated depreciation.”196 Cities similarly contend, without citing to any legal authority, that acquisition adjustments are not legally permitted as an addition to rate base for ratemaking purposes or as a depreciable asset for regulatory ratemaking purposes.197 Staff disputes ETI’s contention that the fact that the costs were approved as part of rate base in two previous ETI dockets proves that they were reasonable, prudently incurred, and properly capitalized. Staff points out that those two prior dockets were settled rate cases and, therefore, “provide no illumination on this issue.”198 Finally, Staff argues that ETI failed to prove either element of the Commission’s two- part Hooks test for the determination of whether the acquisition adjustment should be included in rate base. Pursuant to the Hooks test, in determining whether an acquisition adjustment should be included in rate base, “the Commission should consider whether or not the purchase price was excessive and whether or not specific and offsetting benefits have accrued to ratepayers.”199 According to Staff, ETI’s acquisition adjustment should be disallowed because the Company failed to meet it burden of proof on these two issues.200

The ALJs are unpersuaded by the arguments of Staff and Cities. Their primary argument (i.e., that acquisition adjustments are simply not allowed as an addition to rate base for ratemaking purposes) is incorrect. Indeed, the Hooks decision, the precedent on which Staff relies for its fallback argument, suggests that, more often than not, acquisition adjustments should be included in

ETI Ex. 46 (Considine Rebuttal) at 5.

Staff Ex. 1 (Givens Direct) at 35.

Cities Initial Brief at 26.

Staff Initial Brief at 11.

Application of Hooks Telephone Company for a Rate Increase within Bowie County, Docket No. 2150, Examiner’s Report at 2 (Mar. 28, 1980)(Hooks).

Staff Reply Brief at 12.

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rate base: “Amortization of an acquisition adjustment need not be allowed as an expense in all cases.”201

Moreover, the evidence demonstrates that ETI met is burden under the Hooks test. As discussed more fully in Section V.H. of this PFD, above, there is ample evidence in the record to demonstrate that the Spindletop Facility is used and useful and provides specific and offsetting benefits to ratepayers in a cost-effective manner. The evidence further shows that the acquisition adjustment represents costs that were actually incurred by ETI in the furtherance of acquiring the Spindletop Facility, and not a mere mark-up in original cost. For these reasons, the ALJs conclude that the $1,127,778 incurred by ETI in internal acquisition costs associated with the purchase of the Spindletop Facility was reasonable, necessary, and properly incurred. Accordingly, the ALJs agree that it should be included in ETI’s rate base.

K. Capitalized Incentive Compensation In the application, some of the incentive payments ETI made to its employees were capitalized into plant in service accounts and ETI asks to include those amounts in rate base.202 A portion of those capitalized accounts represents payments made by ETI for incentive compensation tied to financial goals (financially-based incentive compensation). Cities contend that, consistent with Commission precedent, ETI ought not be allowed to include in rate base the portion of its capitalized incentive compensation that is attributable to financially-based incentive compensation.203 The issue of whether financially-based incentive compensation is recoverable as a portion of Operating Expenses is discussed at length in Section VII.D.2. of this PFD. ETI makes the same arguments in favor of recoverability in that section that it makes here as to the inclusion of financially-based incentive compensation in rate base. The discussion of that issue need not be repeated here, but the analysis is the same. In summary, the ALJs conclude that ETI should not be entitled to recover its financially-based incentive compensation costs. Thus, for the same reasons discussed in Section VII.D.2, the ALJs agree with Cities’ contention that the portion of ETI’s

Hooks (emphasis added).

Cities Ex. 2 (Garrett Direct) at 52.

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incentive payments that are capitalized and that are financially-based should be excluded from ETI’s rate base.

On the other hand, the ALJs disagree with Cities as to the amount of that exclusion. Cities argue that $9,835,111 (Cities’ estimate of ETI’s financially-based incentive payments that are capitalized each year into plant in service) should be removed from rate base.204 Broadly speaking, ETI has two categories of incentive compensation programs – annual incentive programs, and long- term incentive programs. To arrive at the figure of $9,835,111, Cities’ witness Garrett assumed that: (1) 100 percent of the costs of the long-term incentive programs were financially-based and, therefore, should be excluded from rate base; and (2) his calculated percentage of the annual incentive programs were financially-based and, therefore, should be excluded from rate base. He then applied those percentages to the incentive costs that ETI capitalized in 2008, 2009, and the portion of 2010 prior to the Test Year.205

As explained in Section VII.D.2., the ALJs agree that Mr. Garrett was correct to recommend removing 100 percent of the cost of ETI’s long-term incentive programs. However, as to the annual incentive programs, he defined what qualifies as “financially based” much too broadly, and therefore wrongly assumed that his calculated percentage of the costs of those programs should be excluded.

Instead, the ALJs conclude that the actual percentages should be used to determine the amount that is financially based.206

Finally, ETI challenges Mr. Garrett’s attempt to disallow capitalized incentive costs from 2008 through June 30, 2009.

Much of the rate base that Mr. Garrett seeks to disallow (namely, costs from 2007 through June 30, 2009) is not presented for review in this rate case. Rather those costs were presented for review in the Company’s last rate case, Docket No. 37744, Id. at 52-53.

Id. at 52-53; Cities Initial Brief at 27.

Cities Ex. 2 (Garrett Direct) at 53 and MG-2.10.

See discussion in Section VII.D.2.

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in which the Company presented capital additions for the period of April 1, 2007, through June 30, 2009. . . . Even though Docket No. 37744 was a settled case, the final order concluded that ‘[b]ased on the evidence in this docket, the overall total invested capital through the end of the test year meets the requirements in PURA § 36.053(a) that electric utility rates be based on original cost, less depreciation of property used and useful to the utility in providing service.’ This conclusion goes beyond merely settling issues without deciding anything and should be construed as to be conclusive as to the reasonableness of capital costs at issue in that prior case.207 The ALJs agree. The Test Year for ETI’s prior ratemaking proceeding ended on June 30, 2009. The reasonableness of ETI’s capital costs (including capitalized incentive compensation) was dealt with by the Commission in that proceeding and is not at issue here. Thus, the ALJs conclude that exclusion of capitalized incentive compensation that is financially-based can only be made for incentive costs that ETI capitalized during the period from July 1, 2009 (the end of the prior Test Year) through June 30, 2010 (the commencement of the current Test Year). The amount of the exclusion is not specifically known at this time.

VI. RATE OF RETURN [Germane to Preliminary Order Issue Nos. 4 and 11] A. Capital Structure ETI’s capital structure is 50.08 percent debt and 49.92 percent equity. No party has taken issue with ETI’s capital structure. Therefore, the ALJs recommend that the Commission enter an order finding that the appropriate capital structure for ETI is 50.08 percent debt and 49.92 percent equity.

B. Return on Equity The United States Supreme Court has set forth a minimum constitutional standard governing equity returns for utility investors:

From the investor or company point of view it is important that there be enough revenue not only for operating expenses but also for the capital costs of the business.

These include service on the debt and dividends on the stock. By that standard the ETI Initial Brief at 44, quoting Docket No. 37744, Order at CoL 10 (Dec. 13, 2010).

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return to the equity owner should be commensurate with returns on investments in other enterprises having comparable risks. That return, moreover, should be sufficient to assure confidence in the financial integrity of the enterprise, so as to maintain its credit and to attract capital.208 Thus, a utility must have a reasonable opportunity to earn a return that is: (1) commensurate with returns on equity investments in enterprises having comparable risks; (2) sufficient to ensure the financial soundness of the utility’s operations; and (3) adequate to attract capital at reasonable rates, thereby enabling it to provide safe, reliable service. The allowed ROE should enable the utility to finance capital expenditures at reasonable rates and to maintain its financial flexibility during the period in which the rates are expected to remain in effect.

1. Proxy Group Because ETI is not a publicly traded company, it is necessary to establish a group of companies that are publicly traded and that are comparable to ETI in certain fundamental business and financial respects to serve as its “proxy” in the ROE estimation process. Both financial theory and legal precedent support the use of comparable companies within a proxy group to determine a utility’s ROE, and all of the ROE witnesses in this case have relied on proxy groups to estimate a required ROE for ETI.

ETI witness Hadaway started with all the vertically integrated electric utilities that are included in the Value Line Investment Survey (Value Line). To improve the group’s comparability with ETI, which has a senior secured bond ratings of BBB+ (Outlook Negative) from Standard &

Federal Power Comm’n v. Hope Natural Gas Co., 320 U.S. 591, 603, 64 S. Ct. 281, 288 (1944); see also Bluefield Waterworks & Improvement Co. v. Public Serv. Comm’n of W. Va., 262 U.S. 679, 692-93, 43 S. Ct. 675, 679 (1923) (“A public utility is entitled to such rates as will permit it to earn a return on the value of the property which it employs for the convenience of the public equal to that generally being made at the same time and in the same general part of the country on investments in other business undertakings which are attended by corresponding risks and uncertainties; but it has no constitutional right to profits such as are realized or anticipated in highly profitable enterprises or speculative ventures. The return should be reasonably sufficient to assure confidence in the financial soundness of the utility and should be adequate, under efficient and economical management, to maintain and support its credit and enable it to raise the money necessary for the proper discharge of its public duties.”).

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Poor’s (S&P) and Baa2 (stable) rating from Moody’s Investors Service (Moody’s), Dr. Hadaway imposed the following restrictions:

x comparable companies had to have senior secured bond ratings of at least BBB by S&P or Baa by Moody’s; x comparable companies had to derive at least 70 percent of revenues from regulated utility sales; x comparable companies had to have consistent financial records not affected by recent mergers or restructuring; and x comparable companies had to have a consistent dividend record with no dividend cuts or resumptions during the past two years.

Those selection criteria resulted in a 23-utility proxy group.

State Agencies witness Miravete excluded Entergy from his proxy group, but otherwise his proxy group was identical to ETI’s. Cities witness Parcell ran his calculations using both Dr. Hadaway’s 23-utility proxy group and another 8-utility proxy group, but they produced similar ROE results. TIEC witness Gorman used the same 23 utility proxy group as ETI witness Hadaway used.

Staff witness Cutter was the only witness to use a different proxy group. He used a 13 utility proxy group for his discounted cash-flow (DCF) analysis. To arrive at this proxy group, Mr. Cutter started with all of the domestic electric-utility companies tracked by Value Line because Value Line is the most widely used, independent investment service in the world. Then he eliminated the utilities that did not meet the following criteria:

x Value Line Financial Strength ratings of A+, A or B++; x A capital structure including less than 45 percent, or more than 55 percent, debt; x Total capitalization in excess of five billion dollars; x No recent dividend cuts or omissions; SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 76 PUC DOCKET NO. 39896

x No recent or potential merger activities or other major capital expansion; and x No Value Line appraisal of being outside the norm.

On his final analysis, Mr. Cutter eliminated three of his 13 utility proxy group, referring to those he eliminated as “outliers.” ETI points out, however, that one of the remaining ten companies, Con Ed, is not comparable to ETI because it is a delivery company as opposed to a vertically integrated utility. ETI’s essential criticism of Mr. Cutter’s proxy group analysis is that he should have used a larger proxy group and that he admitted a better comparison to ETI could be obtained from using a larger proxy group.

2. DCF Analysis To analyze ETI’s cost of equity capital, all of the testifying experts first performed a DCF analysis. The DCF approach is based on the theory that a stock’s current price represents the present value of all expected future cash flows. In its most general form, the DCF model is expressed as follows:

Where P0 represents the current stock price, D1 . . . . D∞ are all expected future dividends, and k is the expected discount rate, or required ROE. That equation can be simplified and rearranged to ascertain the required ROE:

Where P0 represents the current stock price, D is expected future dividends, g is the growth rate, and k is the expected discount rate, or required ROE.

This is commonly referred to as the “Constant Growth DCF” model in which the first term is the expected dividend yield and the second term is the expected long-term growth rate. The SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 77 PUC DOCKET NO. 39896

Constant Growth DCF model requires assumptions of: (1) a constant growth rate for earnings and dividends; (2) a stable dividend payout ratio; (3) a constant price-to-earnings multiple; and (4) a discount rate greater than the expected growth rate.

ETI witness Hadaway’s DCF analysis was based on three versions of the DCF model. In the first version of the DCF model, he used the constant growth format with long-term expected growth based on analysts’ estimates of five-year utility earnings growth. In the second version of the DCF model, for the estimated growth rate, Dr. Hadaway used only the long-term estimated gross domestic product (GDP) growth rate. In the third version of the DCF model, Dr. Hadaway used a two-stage growth approach, with stage one based on Value Line’s three-to-five-year dividend projections and stage two based on long-term projected growth in GDP. The dividend yields in all three of the annual models are from Value Line’s projections of dividends for the coming year and stock prices are from the three-month average for the months that correspond to the Value Line editions from which the underlying financial data are taken.209

The DCF results for Dr. Hadaway’s comparable company group using the traditional constant growth model indicated an ROE of 9.90 percent to 10.00 percent. Dr. Hadaway then recalculated the constant growth results with the growth rate based on long-term forecasted growth in GDP. With the GDP growth rate, the constant growth model indicates an ROE range of 10.40 percent to 10.70 percent. Although the GDP growth rate is higher than the average of analysts’ growth rates, Dr. Hadaway testified that his GDP estimate is within the analysts’ range and slightly below the 6.00 percent 3-to-5 year average growth rate projection from Value Line. Finally, Dr. Hadaway’s multistage DCF model indicated an ROE range of 10.20 percent to 10.30 percent.

The results from the DCF model, therefore, indicate an ROE range of 9.90 percent to 10.70 percent.210 In his rebuttal, Dr. Hadaway updated his ROE analysis using current market conditions but employing the same methodologies that he used in his previous analysis. After

ETI Ex. 6 (Hadaway Direct) at 33-44.

Id. at 44, Exhibit SCH-4.

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making adjustments to the proxy group to stay consistent with his selection criteria, Dr. Hadaway’s indicated DCF range was 10.00 percent to 10.20 percent.211

The principal argument against Dr. Hadaway’s analyses is that he used unsupported and excessive growth rates. According to the intervenors, these excessive growth rates exaggerate future cash flows, which results in an inflated ROE.

Intervenors argue that Dr. Hadaway’s Analysts’ Constant Growth DCF model produces excessive return estimates.212 In rebuttal, Dr. Hadaway’s analysts’ growth model produced a 10.1 percent group average ROE and a 10.0 percent group median ROE.213 The intervenors contend that the group average long-term growth rate on which his DCF study was based was 5.62 percent, which is far too high to be sustainable in the long-term (as required as an input in the Constant Growth DCF model).214 According to intervenors, the excessive level of his growth rate is apparent by comparison to current analysts’ projected growth for U.S. GDP, which range from 4.5 percent to 5.0 percent.215 Dr. Hadaway’s growth rate is more than 60 basis points above the most generous expected growth of the U.S. economy. Intervenors contend that that nominal GDP should be the ceiling of a reliable proxy for a utility dividend growth rate. Because the evidence shows that nominal GDP as projected by consensus analysts, the Executive Branch, and the Congressional Budget Office is 5 percent, Dr. Hadaway’s 5.62 percent growth rate is excessive and undermines the reasonableness of his models.

Intervenors criticize Dr. Hadaway’s decision on rebuttal to exclude Edison International in his proxy group.216 Dr. Hadaway did so because Edison International’s ROE of 5.2 percent was below a 5.07 percent cost of debt based on an average of Triple B utility rates for the time period Id. at 44.

TIEC Ex. 2 (Gorman Direct) at 39.

ETI Ex. 52 (Hadaway Rebuttal) at Ex. SCH-R-6.

Id. at Ex. SCH-R-6; TIEC Ex. 2 (Gorman Direct) at 39; Cities Ex. 3 (Parcell Direct) at 36-37; OPC Ex. 1 (Szerszen Direct) at 23-24.

TIEC Ex. 2 (Gorman Direct) at 19; Cities Ex. 3 (Parcell Direct) at 37.

ETI Ex. 51 (Hadaway Rebuttal) at Ex. SCH-R-6.

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January 12-March 12, plus 100 basis points.217 Intervenors contend that this rationale is tenuous, and that had Dr. Hadaway included Edison International (or even excluded Hawaiian Electric, the utility in his proxy group that had the highest ROE) his own analysis (even with its excessive growth rates) would have resulted in a 9.85 percent average ROE.

Finally, Dr. Hadaway conceded that he used the same methodology for calculating GDP in this case as he did in the Oncor rate case.218 Intervenors contend that Dr. Hadaway’s GDP projections are not credible proxies for investor’s expected dividend growth rates because they are not based on published analysts’ or government GDP forecasts. Rather, Dr. Hadaway forecasts future GDP growth using his own personal calculation that forecasts GDP by examining historic GDP growth over the last 10, 20, 30, 40, 50, and 60-year periods and weighting those averages.219 Intervenors note that this approach was rejected by the Commission in the Oncor rate case.220

Staff witness Cutter used the DCF model to project ETI’s cost of equity. Under Mr. Cutter’s view, the theory underlying the DCF model is that the price of a share is equal to the present value of all future earnings. Unless the stock is sold for a profit (or loss) from the price it was originally purchased, the only way to determine earnings on a share is to determine its future dividends. This requires, in Mr. Cutter’s opinion, an understanding of investors’ current expectations of growth of those dividends. The issue is the growth expectation that investors have embodied in the current price of the stock. According to Mr. Cutter, the best way to arrive at a reliable growth estimate of those dividends is to use the growth estimates of investment advisory firms rather than the estimates of a single, independent analyst.221

Mr. Cutter used both Value Line and Zacks Investment Service (Zacks) in ascertaining long-term earnings growth rates. He used Value Line because it is the most widely used Id. Tr. at 227-228.

ETI Ex. 6 (Hadaway Direct) at Ex. SCH-3; Tr. at 218.

Application of Oncor Electric Delivery Company, LLC, for Authority to Change Rates, Docket No. 35717, PFD at 72-73.

Staff Ex. 6 (Cutter Direct) at 10-15.

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independent investment service in the world and Zacks because it compiles consensus earnings forecasts from groups of professional security analysts.222

Mr. Cutter’s DCF analysis resulted in range from 7.46 percent to 10.71 percent, with a point estimate for cost of equity being 9.3 percent.

TIEC witness Gorman’s first DCF model was a constant growth model using consensus analysts’ growth rates that resulted in an average constant growth DCF of 9.32 percent and a median constant growth DCF of 9.84 percent. The average analysts’ growth rate was 4.94 percent.223 According to TIEC, ETI does not claim that a constant growth model using analysts’ growth rates is inappropriate and argues that Dr. Hadaway failed to offer any rebuttal testimony criticizing Mr. Gorman’s Analysts’ Growth DCF model.

Mr. Gorman also performed a constant growth DCF model using sustainable growth rates.

His average sustainable growth rate for the proxy group was 4.54 percent and produced a proxy group average and median DCF result of 8.91 percent and 8.9 percent, respectively.224 According to TIEC, a sustainable growth rate is based on the percentage of a utility’s earnings that are retained and reinvested in utility plant and equipment.225

Mr. Gorman also performed a multi-stage DCF model to reflect changing growth expectations that would reflect the possibility of non-constant growth for a company over time.

Mr. Gorman’s multi-stage model reflected three growth periods: (1) a short-term growth period of five years; (2) a transition period for years six through ten; and (3) a long-term growth period, starting in year 11 through perpetuity. For the short-term period, Mr. Gorman relied on the consensus analysts’ growth projections from his constant growth DCF model (i.e., 4.94 percent).

For the second stage (i.e., the transition period), growth rates are reduced or increased by an equal

Staff Ex. 6 (Cutter Direct) at 13.

TIEC Ex. 2 (Gorman Direct) at Ex. MPG-4.

TIEC Ex. 2 (Gorman Direct) at 18.

TIEC Ex. 2 (Gorman Direct) at 17.

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factor, which reflect the difference between the analysts’ growth rates and the GDP growth rate. For the long-term period, he assumed the maximum sustainable growth rate for a utility company as proxied by the consensus analysts’ projected growth rate for the U.S. GDP (i.e., 5.0 percent). The result of his multi-stage growth DCF model was an average ROE of 9.37 percent and a median of 9.48 percent.226

Cities witness Parcell calculated the DCF results for each company in his proxy group by using and considering five indicators of growth expectations consisting of: (i) 2007 – 2011 earnings retention; (ii) five-year historical average earnings per share, dividends per share, and book value per share; (iii) projected earnings retention; (iv) projected EPS, DPS, BVPS; and (v) projected EPS as reported by Yahoo Finance. Using this in his DCF model resulted in an ROE of 9.0 percent to 9.5 percent.227

OPC witness Szerszen’s DCF analysis used the same group of 23 comparable companies included in Dr. Hadaway’s DCF analysis. Dr. Szerszen’s DCF analysis was framed with consideration of ETI’s financial integrity as discussed by the major bond rating agencies, the current and projected interest rate environment, and investment analyst views of the regulated utility sector.228 Interest rates are currently very low, as reflected in the yields to maturity and interest rates on various fixed income investments. OPC contends, in contrast to Dr. Hadaway, that utility stocks have been less volatile than the stock market in general.229 This is confirmed by Value Line’s December 23, 2011, observation that “electric utility stocks have long been viewed as a safe haven in volatile markets, due in large part to their generous dividend yields.”230 Dr. Szerszen also took exception to Moody’s characterization of ETI as having above average business and regulatory risk.

Moody’s assessment is primarily based on the lack of pass-through regulatory lag-reducing cost recovery mechanisms in Texas compared to Entergy’s Louisiana and Mississippi jurisdictions. Dr.

TIEC Ex. 2 (Gorman Direct) at 19, Ex. MPG-9.

Cities Ex. 3 (Parcell Direct) at 24, 33.

OPC Ex. 1 (Szerszen Direct) at 8-17.

Id. at 15.

Id. SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 82 PUC DOCKET NO. 39896

Szerszen testified that ETI may not have a formula rate plan similar to the Louisiana and Mississippi Entergy operating companies, but it does have a Distribution Cost Recovery Factor (DCRF) and Transmission Cost Recovery Factor (TCRF) available that “will allow ETI to charge ratepayers for additional distribution and transmission investments outside of a traditional rate request filing.”231 None of Entergy’s other operating companies have TCRF and DCRF riders. OPC notes that Cities witness Parcell agrees that the availability of such recovery mechanisms affects ETI’s level of risk; he testified that a combination of ETI’s fuel factor rider, TTC rider, energy efficiency rider, hurricane cost recovery rider, rate case expense rider, proposed increased customer service charge, and DCRF and TCRF riders results in about 30 percent of ETI’s total overall requested revenue requirement being subject to revenue risk and regulatory lag.232

Dr. Szerszen incorporated two different dividend yield calculations in her DCF model. The first calculation estimated a dividend yield using 2011 average stock prices and 2012 projected dividend rates for each company, and the second calculation incorporated more recent March 5, 2012, closing prices for the comparables. The average dividend yield using 2011 average stock prices was 4.66 percent and, using March 5, 2012, closing prices, was 4.32 percent.233

Dr. Szerszen provided some practical examples of how blind reliance on analyst earnings growth projections can lead to questionable DCF growth rates. At least five of the comparable utility companies had five-year earnings growth rate projections that ranged from 8.5 percent to percent. Dr. Szerszen stated that she was unaware of any regulated utility company that has consistently achieved such high earnings growth rate over the past 28 years, and that it is reasonable to assume such performance is unlikely in the longer term future. Dr. Szerszen’s review of the comparable company past and projected growth rates resulted in a reasonable dividend growth rate expectation of 3.9 percent to 5 percent. Depending on whether 2011 average stock prices are used or

Id at 11-13.

Cities Ex. 3 (Parcell Direct) at 16-18.

OPC Ex. 1 (Szerszen Direct) at 17.

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the updated 2012 stock prices are used, Dr. Szerszen’s DCF analysis resulted in an ROE ranging from 8.32 percent to 9.32 percent.234

State Agencies’ witness Miravete’s DCF analysis used calculations for three averaging periods, 30, 90 (the reference period), and 180 days ending on March 2, 2012, respectively. For the commonly used 90 day averaging period, the capitalization-weighted average ROE is 9.23 percent.

Evaluating the averaging period at either 30 or 180 days produces ROE estimates of 9.24 percent and 9.34 percent, respectively. Dr. Miravete weighed the computations by the capitalization of each firm to correct the effect of each variable according to the relative market value of the corresponding utility. According to Dr. Miravete, this approach avoids the distortion caused by adding numerous, but possibly irrelevant, firms that may produce biased estimates. Dr. Miravete conceded that the effect of ignoring differences in scale of utilities in the determination of the ROE is substantial. He acknowledged that if he had ignored the differences in size of these electric utilities, his DCF ROE estimate would have been 9.68 percent.235

3. Risk Premium Analysis Dr. Hadaway’s risk premium studies are divided into two parts. First, he compared electric utility authorized ROEs for the period 1980-2010 to contemporaneous long-term utility interest rates. The differences between the average authorized ROEs and the average interest rate for the year is the indicated equity risk premium. He then added the indicated equity risk premium to the forecasted and current triple-B utility bond interest rate to estimate ROE.236

In calculating the equity risk premium, Dr. Hadaway adjusted for the inverse relationship between equity risk premiums and interest rates (when interest rates are high, risk premiums are low and vice versa). Dr. Hadaway provided regression analyses of the allowed annual equity risk premiums relative to interest rate levels. The negative regression coefficients confirm the inverse relationship between equity risk premiums and interest rates according to ETI. Dr. Hadaway used Id. at 22.

State Agencies Ex. 1 (Miravete Direct) at 12-13.

ETI Ex. 6 (Hadaway Direct) at 36-38, 45.

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that negative interest rate change coefficient in conjunction with current and forecasted interest rates to establish the appropriate ROE.237 Staff witness Cutter agreed that the risk premium analysis needs to reflect this adjustment.238

The results of Dr. Hadaway’s initial equity risk premium studies indicate an ROE range of 10.00 percent to 10.01 percent. ETI states that these results reflect the sharp drop in interest rates that have occurred for high quality borrowers. The Federal Reserve System’s continuing “easy money” policies have provided renewed liquidity in the credit markets that is reflected in these lower yields. These models, however, cannot capture the current equity volatility or the increased level of risk aversion for equity investors. These circumstances indicate that the cost of equity has not declined to the extent that interest rates on utility debt have dropped. Thus, Dr. Hadaway testified that the results of the risk premium analysis must be discounted and more emphasis placed on the DCF analysis.239

In his rebuttal, Dr. Hadaway updated his ROE analysis using current market conditions but employing the same methodologies that he used in his previous analysis.240 His updated risk premium analysis was an ROE of 10.38 percent using projected triple-B utility interest rates and 9.96 percent using current triple-B utility interest rates.241

TIEC contends that Dr. Hadaway’s utility risk premium analysis is flawed for two primary reasons. First, Dr. Hadaway developed a forward-looking risk premium model that relied on forecasted interest rates and volatile utility spreads that are uncertain and produce inaccurate results.

As Mr. Gorman testified, it is more reasonable at this time to rely on current observable interest rates rather than forecasted projections. Over the last several years, forecasted yield projections have proven to be overstated because, even though interest rates have been projected to increase,

ETI Ex. 6 (Hadaway Direct) at 45-46, Ex. SCH-5; ETI Ex. 52 (Hadaway Rebuttal) at 32.

Staff Ex. 6 (Cutter Direct) at 20.

ETI Ex. 6 (Hadaway Direct) at 10-23, 45; Tr. at 233-235.

ETI Ex. 52 (Hadaway Rebuttal) at 44.

Id. at 45.

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those projections have consistently been proven wrong.242 Accordingly, Dr. Hadaway’s forecasted utility bond yield of 5.17 percent is overstated.

Second, TIEC argues that Dr. Hadaway’s risk premium model is flawed because he improperly inflates his actual risk premium of 3.28 percent with an adjustment of 1.56 percent that he asserts reflects the inverse relationship between interest rates and utility risk premiums.243 TIEC argues that Dr. Hadaway’s use of this adjustment is improper and not supported by academic research. Mr. Gorman testified that “a relative investment risk differential cannot be measured simply by observing nominal interest rates.”244 He noted:

While academic studies have shown that, in the past, there has been an inverse relationship with these variables, researchers have found that the relationship changes over time and is influenced by changes in perception of the risk of bond investments relative to equity investments, and not simply changes to interest rates.245 As described in Mr. Gorman’s testimony, correcting Dr. Hadaway’s models for the elimination of this inverse relationship adjustment puts Dr. Hadaway’s risk premium in the range of 8.5 percent to 10 percent, with a midpoint of 9.3 percent.246

Staff witness Cutter’s “conventional risk premium estimate” estimated the cost of ETI’s equity by comparing the costs of equity authorized for utilities across the United States to the yields of large-company corporate bonds that are rated Baa by Moody’s within the timeframe of 1980 through 2011. This risk premium approach relies on the historical relationship between two indices

TIEC Ex. 2 (Gorman Direct) at 42-43; OPC Ex. 1(Szerszen Direct) at 27-28.

TIEC Ex. 2 (Gorman Direct) at 42-43; see also ETI Ex. 6 (Hadaway Direct) at Ex. SCH-5 at 1.

TIEC Ex. 2 (Gorman Direct) at 44.

TIEC Ex. 2 (Gorman Direct) at 44 (citing “The Market Risk Premium: Expectational Estimates Using Analysts’ Forecasts,” Robert S. Harris and Felicia C. Marston, Journal of Applied Finance, Volume 11, No. 1, 2001 and “The Risk Premium Approach to Measuring a Utility’s Cost of Equity,” Eugene F. Brigham, Dilip K. Shome, and Steve R. Vinson, Financial Management, Spring 1985).

TIEC Ex. 2 (Gorman Direct) at 45.

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to forecast a value for one of the indices in a period for which it is unknown by using the known value of the other one during that same period.247

To account for the relationship between the authorized costs of equity and the bond yields required to quantify ETI’s cost of equity, Mr. Cutter subtracted the bond yields from the authorized costs of equity to determine a risk premium for the riskier equity. He tested the data by performing a regression analysis, which showed with high confidence that there is a trend in the relationship. It is an inverse trend, in which the risk premiums increase as bond yields decrease. On average, from 1980 to 2011, risk premiums increased 0.4207 percent for every 1.00 percent that bond yields decreased.248

The calculation of the adjustment to the risk premium that the regression analysis indicated was incorporated in Staff’s analysis. The results of this risk premium analysis produced a cost of equity of 9.81 percent.249

Mr. Gorman’s risk premium analysis produced an ROE estimate in the range of 9.2 percent to 9.4 percent, with a midpoint estimate of approximately 9.3 percent. His risk premium model was based on two estimates of an equity risk premium. First, he estimated the difference between the required return on utility common equity investments and U.S. Treasury bonds for the period 1986 through 2011, which produced an equity risk premium of 5.23 percent. The second equity risk premium estimate was based on the difference between regulatory commission-authorized returns on common equity and contemporary “A” rated utility bond yields for the period 1986 through 2011, which produced an equity risk premium of 3.8 percent. Mr. Gorman testified that “[t]he equity risk premium should reflect the relative market perception of risk in the utility industry today.”250

Staff Ex. 6 (Cutter Direct) at 10, 19.

Staff Ex. 6 (Cutter Direct) at 20.

Id. at 20, Attachment SC-6.

TIEC Ex. 2 Gorman Direct) at 26.

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Accordingly, to gauge investor expectations he examined the yield spread between utility bonds and Treasury bonds over the last 32 years.251

According to TIEC, this analysis showed that the current utility bond yield spreads over Treasury bond yields are lower than the 32-year average spreads, which is evidence that “the market considers the utility industry to be a relatively low risk investment and demonstrates that utilities continue to have strong access to capital.”252 Mr. Gorman then added a projected long-term Treasury bond yield to his estimated equity risk premium over Treasury yields, which produced a common equity in the range of 8.2 percent to 9.95 percent. Due to unusually large yield spreads between Treasury bond and “Baa” utility bond yields, Mr. Gorman gave two-thirds weight to his high end risk premium of 9.95 percent and one-third weight to his low-end risk premium of 8.2 percent, which produced an equity risk premium of 9.4 percent. He also added his equity risk premium over utility bond yields to the current 13-week average yield on “Baa” rated utility bonds for the period ending March 2, 2012, of 5.05 percent. Adding his equity risk premium of 3.03 percent to 4.62 percent to the bond yield of 5.05 percent, produced an ROE in the range of 8.08 percent to 9.67 percent, which he then weighted more heavily on the high end estimate to produce a recommendation of 9.2 percent.253

The primary criticism that Dr. Hadaway lodged against Mr. Gorman’s risk premium analysis was that Mr. Gorman did not adjust his analysis upward to reflect a purported inverse relationship between equity risk premiums and interest rates.254 For example, Dr. Hadaway’s risk premium analysis adjusted his risk premium results by 1.56 percent to account for this relationship.255

OPC witness Szerszen also performed a risk premium analysis, using Dr. Hadaway’s study of historical authorized electric company allowed returns on equity and average bond yields. The

Id. at 25-28.

Id. at 27.

TIEC Ex. 2 (Gorman Direct) at 26-28.

ETI Ex. 52 (Hadaway Rebuttal) at 32.

ETI Ex. 6 (Hadaway Direct) at Ex. SCH-5.

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average risk premium from Dr. Hadaway’s 1980-2010 study was 328 basis points.256 Adding this historical risk premium to current triple B bond yield (4.67 percent) results in a 7.95 percent risk-premium derived DCF rate, and using Dr. Hadaway’s 5.17 percent projected bond yield results in a risk premium derived rate of 8.45 percent. Giving more weight to the 2001-2010 risk premiums shown in Dr. Hadaway’s exhibit results in an average risk premium of 4.21 percent. This yields an 8.88 percent to 9.38 percent risk premium derived cost of equity based on the current 4.67 percent and projected 5.17 percent bond yields, according to Dr. Szerszen’s analysis.257

4. Comparable Earnings Cities witness Parcell also performed a Comparable Earnings analysis. According to Mr. Parcell, the Comparable Earnings method is derived from the “corresponding risk” standard of the Bluefield and Hope cases. This method is thus based upon the economic concept of opportunity cost. The cost of capital is an opportunity cost: the prospective return available to investors from alternative investments of similar risk.258

The Comparable Earnings method is designed to measure the returns expected to be earned on the original cost book value of similar risk enterprises. Thus, according to Mr. Parcell, this method provides a direct measure of the fair return, because the Comparable Earnings method translates into practice the competitive principle upon which regulation is based.259

The Comparable Earnings method normally examines the experienced and/or projected returns on book common equity. The logic for examining returns on book equity follows from the use of original-cost, rate-base regulation for public utilities, which uses a utility’s book common equity to determine the cost of capital. This cost of capital is, in turn, used as the fair rate of return which is then applied (multiplied) to the book value of rate base to establish the dollar level of

ETI Ex. No. 6 (Hadaway Direct) at Ex. SCH-5.

OPC Ex. 1 (Szerszen Direct) at 29-30.

Cities Ex. 3 (Parcell Direct) at 28.

Id. at 29.

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capital costs to be recovered by the utility. Mr. Parcell stated that this technique is thus consistent with the rate base methodology used to set utility rates.260

Mr. Parcell conducted the Comparable Earnings methodology by examining realized returns on equity for several groups of companies and evaluating the investor acceptance of these returns by reference to the resulting market-to-book ratios. He testified that in this manner it is possible to assess the degree to which a given level of return equates to the cost of capital.

Mr. Parcell’s Comparable Earnings analysis is based on market data (through the use of market-to-book ratios) and is thus essentially a market test. As a result, he testified that his analysis is not subject to the criticisms occasionally made by some who maintain that past earned returns do not represent the cost of capital. In addition, he stated that his analysis uses prospective returns and thus is not confined to historical data.261

Mr. Parcell’s Comparable Earnings analysis considered the experienced equity returns of the proxy groups of utilities for the period 1992-2011 (i.e., the last twenty years). His Comparable Earnings analysis required an examination of a relatively long period of time to determine trends in earnings over at least a full business cycle. Further, in estimating a fair level of return for a future period, it is important to examine earnings over a diverse period of time to avoid any undue influence from unusual conditions that may occur in a single year or shorter period. Therefore, in forming his judgment of the current cost of equity he focused on two periods: 2002-2011 (the recent business cycle) and 1992-2001 (the prior business cycle).262

Based on the recent earnings and market-to-book ratios, Mr. Parcell’s Comparable Earnings analysis indicated that the cost of equity for the proxy utilities is no more than 9.5 percent to 10.0 percent (9.75 percent mid-point). Recent returns of 10.0 percent to 12.1 percent have resulted in market-to-book ratios of 143 and greater. Prospective returns of 9.5 percent to 10.3 percent result

Id. Cities Ex. 3 (Parcell Direct) at 29.

Id. at 30.

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in anticipated market-to-book ratios of over 125. As a result, it is apparent that returns below this level would result in market-to-book ratios of well above 100. According to Mr. Parcell, an ROE of 9.5 percent to 10.0 percent should thus result in a market-to-book ratio of well over 100 .263

5. CAPM Analysis The Capital Asset Pricing Model (CAPM) is a risk premium approach that estimates the ROE for a given security as a function of a risk-free return plus a risk premium to compensate investors for the non-diversifiable, or systematic, risk of that security. The CAPM formula is as follows:

Ke = rf + β(rm – rf) Where Ke equals the required market ROE; β equals the Beta of an individual security; rf equals the risk free rate of return; and rm equals the required return on the market as a whole. In this equation, (rm – rf) represents the market risk premium. According to the theory underlying the CAPM, because diversifiable risk can be diversified away, investors should be concerned only with non-diversifiable risk, which is measured by Beta. In effect, Beta represents the risk of the particular security relative to the market as a whole.

Only Staff witness Cutter, Cities witness Parcell, and State Agencies witness Miravete used the CAPM methodology to estimate ETI’s ROE.

Mr. Cutter used CAPM in the qualitative analysis of ETI’s cost of equity. He did not directly use the CAPM in the determination of ETI’s cost of equity because it yielded a cost of equity that was over 200 basis points lower than the lower of the other two estimates, while those other two estimates were less than half a percent apart from each other.264 The CAPM provides an additional indication that a significant drop to the estimated costs of equity that Staff made in prior dockets is

Cities Ex. 3 (Parcell Direct) at 31-32.

Staff Ex. 6 (Cutter Direct) at 21.

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appropriate because the CAPM estimate is lower than either of the two other approaches even when adjusted for the current low yield on Treasury Bonds.265

Mr. Cutter testified that the CAPM is one of the cornerstones of financial theory.266 In its simplest sense, the model describes the relationship between the risk of an asset and its expected return, and assumes that investors will not hold a risky asset unless they are adequately compensated for the risk.267

In this case, without any adjustment to the way it has been used in recent rate cases at the Commission, the CAPM yielded a cost of equity for ETI of 6.93 percent. Mr. Cutter testified that aspects of the capital markets today were likely causing the CAPM’s cost of equity estimate to be low. Specifically, the Federal Reserve System is following an aggressive policy designed to keep the yields of both short-term and long-term Treasury bonds low. This policy influences two of the three variables used in the CAPM formula to be lower, which, in turn, makes the CAPM’s final estimate of ETI’s cost of equity lower.268

To account for the impact of this aggressive Federal Reserve System policy, Mr. Cutter made two adjustments to his CAPM analysis. First, Mr. Cutter adjusted the risk-free rate variable in the CAPM because it is most influenced by current Federal Reserve System policy. By changing this variable to 3.7 percent (which is the average yield from 1926 through 2010 of the risk-free rate’s proxy security, U.S. Treasury Bills), the CAPM’s estimate of ETI’s cost of equity increased from 6.93 percent to 7.92 percent, or by 99 basis points.269

The second adjustment to the CAPM result that Mr. Cutter made to account for the current aggressive Federal Reserve System policy was to the risk premium, which is also particularly sensitive to Federal Reserve System policy. By using the difference between the averages of the Id. Id. Id. Staff Ex. 6 (Cutter Direct) at 21-24.

Id. at 24.

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yield of long-term government bonds and the yield of large company stocks between 1926 and 2010, the effect of Federal Reserve System policy on the risk premium was significantly diluted.

Mr. Cutter found that because the CAPM estimate of ETI’s cost of equity was excessively low, even with adjustments for Federal Reserve System policy, it would be appropriate to further adjust it by multiplying the unadjusted estimate plus two times the effect of adjusting the risk-free rate, or: 6.93 percent + (2 * 0.99 percent) = 8.91 percent.270 It is important to note, however, that Mr. Cutter used the CAPM analysis only as a qualitative check on its DCF and risk premium analyses, not as an independent source of analysis.

Although Cities witness Parcell did perform a CAPM analysis, he does not employ the CAPM results in arriving at his 9.0 percent to 10.0 percent range of results.271

State Agencies witness Miravete used the daily average of the yield of the ten-year Treasury bond between December 1, 2011, and March 2, 2012, as reported by the Board of Governors of the Federal Reserve System, as his risk-free return in his CAPM model. He used Value Line’s most recent betas for the regulated utilities included in the proxy group. Dr. Miravete corrected the betas by substituting an average between their value and 1.0 to recognize that markets trend towards long-term equilibrium because these regulated utilities were able to attract investors during the most troubled times, which indicates that the perceived market risk of these utilities is lower than for other firms. Dr. Miravete’s capitalization-weighted average CAPM ROE is 7.64 percent on a 90 days averaging period, with a range between 7.64 percent (30 days) and 8.28 percent (180 days).

Dr. Miravete characterizes these estimates as low relative to those of the DCF model because of the low yields of Treasury bonds after the implementation of the quantitative easing monetary policy over the past two years.272

Id. at 21, 24-25.

Cities Ex. 3 (Parcell Direct) at 3, 25-28.

State Agencies Ex. 1 (Miravete Direct) at 19-21.

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6. ALJs’ Analysis Given the detail, time, and effort that went into the various experts’ testimony on this issue, one might easily conclude that the development of an estimated ROE is a precise science. But, as acknowledged by virtually all experts on the subject, estimating the cost of equity is not an exact science but rather a result of informed judgment.

The first question that must be addressed is the appropriate proxy group. There were essentially only two competing views on this issue – one presented by Dr. Hadaway and the other by Mr. Cutter. The ALJs have reviewed the evidence and the arguments of both sides with respect to the composition of the proxy group. Although Staff’s proxy group could, in some respects, be considered more comparable to ETI than Dr. Hadaway’s larger group, the ALJs do not believe that this overcomes the flaws inherent in such a small group. In the end, a group of nine companies, while comparable, simply does not provide a robust enough sample to create a valid group for comparison. The ALJs therefore find that the 23 utility group selected by ETI witness Hadaway is the appropriate proxy group.

The next issue is the core issue to be decided: the appropriate ROE for ETI. The experts in this case testified to the following ROE ranges or estimates, depending on the calculation methodology employed:

Witness/Analysis Range Ultimate Recommendation Hadaway - DCF 9.9 – 10.7 10.6 Hadaway – Risk Premium 9.96 – 10.38 Cutter – DCF 7.46 – 10.71 9.6 Cutter – Risk Premium 9.81 Cutter – CAPM 8.91 Gorman –DCF 9.3 – 9.7 9.5 Gorman – Risk Premium 9.2 – 9.4 Parcell – DCF 9.0 – 9.5 9.5 Parcell – Comparable Earnings 9.5 – 10.0 SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 94 PUC DOCKET NO. 39896

Witness/Analysis Range Ultimate Recommendation Szerszen – DCF 8.32 – 9.32 9.3 Szerszen – Risk Premium 9.3 Miravete – DCF 9.23 – 9.34 9.3 Miravete – CAPM 7.64 – 8.28 Just focusing on the ultimate ROE recommendations, it is clear that there is a fairly tightly grouped range when considering Staff and the intervenors. This ranges from a low of 9.3 percent to a high of 9.6 percent. The range expands when it is considered that Staff witness Cutter did not contest ETI’s assertion that Staff’s DCF recommended ROE would be 10.0 percent if he had used the same proxy group as the other witnesses.273 The ALJs believe that the criticisms leveled at Dr. Hadaway’s ROE recommendation are generally correct, certainly to the point that the ultimate recommendation is so high as to be an outlier. The ALJs conclude that the proper range of acceptable ROEs would be from 9.3 percent to 10.0 percent. This is actually confirmed by ETI’s own witness, Mr. Barrileaux, who testified that, from a cash flow metric standpoint, an ROE of 9.99 percent would provide “a reasonable outcome that balances debt and equity financing.”274

The mid-point of the range discussed above is 9.65 percent. There has been a tremendous amount of testimony about the unsettled economic conditions facing utilities and the effect of those conditions on the appropriate ROE. The ALJs believe that this is an effect that must be taken into account, and that the effect would be to move the ultimate ROE towards the upper limits of the range determined to be reasonable. In this case, the ALJs find that the reasonable adjustment would be basis points, moving the reasonable ROE to 9.80 percent. Accordingly, the ALJs recommend that the Commission find that 9.80 percent is the appropriate ROE for ETI.

Tr. at 1795.

ETI Ex. 44 (Barrileaux Rebuttal) at 5, Ex. CEB-R-1.

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C. Cost of Debt ETI’s weighted average cost of debt at the end of the test year was 6.74 percent.275 No party has taken issue with that cost of debt. Therefore, the ALJs recommend that the Commission enter an order finding that the appropriate cost of debt for ETI is 6.74 percent.

D. Overall Rate of Return The overall rate of return is a product of the capital structure, ROE, and cost of debt. Based on the discussions set forth above, the ALJs recommend that the Commission adopt the following overall rate of return for ETI:

Weighted Component Cost Weighting Cost Debt 6.74 50.08% 3.38 Equity 9.80 49.92% 4.89 Overall 8.27 VII. OPERATING EXPENSES [Germane to Preliminary Order Issue Nos. 2, 3, 4, and 16] A. Purchased Power Capacity Expense [Germane to Supplemental Preliminary Order Issue No. 1] One of the most hotly contested issues in this case concerned the appropriate size of ETI’s purchased power capacity costs (PPCCs). In order to understand this issue, it is necessary to understand some background relative to how ETI obtains and uses power generation capacity.

1. The Sources of ETI’s Purchased Power The Entergy System Agreement is a FERC-approved tariff that mandates that the Operating Companies operate as a single, integrated system.276 The System Agreement’s essential function is to provide the contractual basis for the planning, construction, and operation of generation and ETI Ex. 5 (Barrilleaux Direct) at 37.

ETI Ex. 30 (Jaycox Direct) at 5-6; ETI Ex. 39 (Cicio Direct) at 6-10.

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transmission resources in an economic and reliable manner. By jointly planning and operating their electric systems, the Operating Companies believe they are able to aggregate their loads and jointly dispatch their resources to serve that load using the lowest cost resources available from all of the Operating Companies, resulting in lower total costs than the total cost of each Operating Company planning and operating separately. Another function of the Entergy System Agreement is to provide a basis for the equalization among the Operating Companies of any imbalances of costs arising from the construction, ownership, or operation of facilities that are used for the collective benefit of all Entergy Operating Companies.277

To provide reliable service, ETI must have sufficient generation capacity to meet the maximum demands imposed on its system. Some of this generation capacity (approximately 1,200 MW) is generating plants owned and operated by ETI.278 The remainder of ETI’s capacity comes from four types of purchased capacity: (1) capacity purchases from third parties; (2) capacity purchases from other Entergy affiliates through “legacy affiliate contracts” under MSS-4; (3) capacity purchases from other Entergy affiliates through “other affiliate contracts” under MSS-4; and (4) capacity purchases from the Entergy system through reserve equalization payments under MSS-1.279 MSS-1 and MSS-4 are schedules included in the Entergy System Agreement which set out complex mathematical formulas whereby the various Operating Companies can equalize and share the costs of power capacity among themselves.280 These four sources of purchased capacity are inversely related to one another: the more ETI purchases from one source, the less it needs to purchase from the others.281 ¾ Capacity Purchases from Third Parties Third-party capacity contracts are contracts that the system has allocated in whole or part to ETI. ETI has contracted to purchase capacity from a number of third parties, including

ETI Ex. 39 (Cicio Direct) at 6, 8-10, 11-30.

Tr. at 1539-40.

ETI Ex. 34 (Cooper Direct) at 20-21; Tr. at 1901; ETI Initial Brief at 71.

ETI Ex. 39 (Cicio Direct) at PJC-1, pp. 30 and 62.

Tr. at 1946-47.

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ConocoPhillips-SRW, Dow Pipeline, Frontier, Calpine-Carville, and Sam Rayburn Municipal Power Agency (SRMPA). Since 2009, ETI has been in the process of substantially increasing its reliance upon third party purchases of capacity. During the Rate Year, it plans to more than double the amount of capacity it purchases from third parties as compared to the amount it purchased during the Test Year.282

Since the Test Year, Entergy has been engaged in an effort to increase ETI’s long-term power capacity through dealing with third parties. It has entered into a number of agreements in that regard:

x In 2009, it entered into a ten-year purchased power agreement with Calpine Energy Services (Calpine) to purchase 485 MW of capacity from Calpine’s Carville Energy Center (Carville Contract). Purchases pursuant to the Carville Contract will commence during the Rate Year, on June 1, 2012, and 50 percent of this contract is allocated to ETI.283 x During the Period from July 2009 through June 2011, the Company executed an agreement with NRG for a 75 MW one-year call option, with a delivery period that began on March 1, 2011, and percent of this contract is allocated to ETI.284 x During the Period from July 2009 through June 2011, the Company executed a three-year agreement with Dow Pipeline for 100 MW capacity, with a delivery period that began on April 1, 2011, and 100 percent of this contract is allocated to ETI.285 x During the Period from July 2009 through June 2011, the Company executed a 25-year agreement with SRMPA for 225 MW, with a delivery period beginning on December 1, 2011, and 100 percent of this contract is allocated to ETI. ETI contends that the SRMPA contract will be beneficial because it provides “much-needed long-term base load capacity at an economically attractive price.”286

ETI Ex. 34 (Cooper Direct) at 23; see also ETI Init. Br. at 75-76.

ETI Ex. 34 (Cooper Direct) at 16, 19.

ETI Ex. 34 (Cooper Direct) at 16, 19.

Id. at 17, 19.

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x An additional contract, the Frontier contract, was in place during the Test Year, and saw a MW increase in contract capacity during the Test Year.287 ETI argues that its growing reliance on third-party purchases will diversify its energy portfolio and help the Company meet its reliability needs at a lower cost.288 The new purchased power contracts will also reduce ETI’s fuel costs and dependence upon aging, higher heat rate generation units within the Entergy system.289

¾ Capacity Purchases from Other Entergy Affiliates Through “Legacy” Affiliate Contracts Under MSS-4 The term “legacy affiliate contracts” refers to those contracts resulting from the December 31, 2007, jurisdictional separation of EGSI into ETI and EGSL, pursuant to which ETI purchases its allocated share of power from plants such as the River Bend nuclear plant, located in Louisiana and owned by EGSL as a result of the separation. The legacy affiliate purchases are made under MSS-4.290

¾ Capacity Purchases from Other Entergy Affiliates Through “Other” Affiliate Contracts Under MSS-4 “Other affiliate contracts” refers to all affiliate contracts other than legacy contracts whereby ETI purchases capacity and associated energy from other Operating Companies.291 The other affiliate purchases are also made under MSS-4.292 Among others, in 2009 ETI entered into a new affiliate contract with Entergy Arkansas, Inc. (EAI) for wholesale base load resources (the EA WBL Contract), whereby ETI was allocated 31.7 percent of 336 MW capacity.293

Tr. 1937-38.

ETI Ex. 34 (Cooper Direct) at 24.

Tr. at 1112-13, 1940-41.

ETI Ex. 39 (Cicio Direct) at 24-26.

ETI Ex. 34 (Cooper Direct) at 21.

ETI Ex. 39 (Cicio Direct) at 24-26.

Cities Ex. 6 (Nalepa Direct) at 13-14.

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¾ Capacity Purchases from the Entergy System Through Reserve Equalization Payments Under MSS-1 Reserve Equalization payments are made under MSS-1. In any given month, some of the Operating Companies might be “long” on the amount of generating capacity they own (meaning that they own more capacity than they need) while others might be “short” on capacity (meaning they own less capacity than they need). In such a month, the long Operating Companies would receive MSS-1 payments from the short Operating Companies for use of their capacity.294

2. ETI’s Request Regarding PPCCs During the Test Year, ETI had total PPCCs of $245,432,884.295 In the application, however, ETI is not seeking to recover its Test Year expenses. Rather, it is asking to recover roughly $276 million, which represents the Company’s anticipated PPCCs in the Rate Year.296 In other words, ETI is seeking roughly $31 million more than its actual Test Year expenses. ETI derived this estimate based largely upon what it believes will the purchased power agreements in place during the Rate Year.297

As the following tables illustrate, ETI projects that, during the Rate Year, the total quantity, and the relative quantities purchased from each source, will differ substantially from its Test Year purchases.

Test Year vs. Rate Year Power Capacity Quantities (MW-Months)298 Purchase Test Year Rate Year Third Party Purchases 5,884 12,834

ETI Ex. 39 (Cicio Direct) at 11-13; Cities Ex. 4 (Goins Direct) at 13.

TIEC Ex. 1 (Pollack Direct) at Ex. JP-1; Tr. at 652-53.

TIEC Ex. 1 (Pollack Direct) at JP-1; ETI Ex. 34 (Cooper Direct) at 20; ETI Ex. 34A (Errata to Cooper Direct).

TIEC Ex. 1 (Pollack Direct) at 22.

TIEC Ex. 1 (Pollack Direct) at 22, Table 1 (Errata).

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Test Year vs. Rate Year Power Capacity Quantities (MW-Months)298 Purchase Test Year Rate Year Affiliate Purchases (both 21,670 21,711 Legacy and Other) Under MSS-4 Reserve Equalization 8,309 5,262 Under MSS-1 Total 35,863 39,807

Test Year vs. Rate Year Power Capacity Costs299 Purchase Test Year Rate Year Third Party Purchases $32,094,893 $69,061,200 Affiliate Purchases (both $189,032,442 $188,430,917 Legacy and Other) Under MSS-4 Reserve Equalization $25,461,353 $18,317,367 Under MSS-1 Total $246,588,688300 $275,809,484 This indicates ETI will purchase roughly 11 percent more power in the Rate Year than it did in the Test Year. Moreover, while the purchases pursuant to MSS-4 will remain fairly stable, the third-party purchases will substantially increase, with a somewhat corresponding decrease for purchases pursuant to MSS-1. In other word, ETI’s plan is to become “less short” (on capacity) relative to the other Operating Companies in the Rate Year than it was in the Test Year.

ETI contends that the shift toward more third party purchases is part of its effort to develop a more diverse, modern, and efficient portfolio of generation supply resources, both to serve current customer needs and to serve anticipated load growth. This, in turn, will lower energy costs and result in savings for customers.301

ETI’s initial request in this case was for a Purchased Power Rider (PPR) that would allow the Company to recover $276 million, but would be subject to future reconciliation based on actual Cities Ex. 12.

Cities now agree that the correct amount for the Test Year is $245,432,884. See TIEC Reply Brief at 18.

ETI Ex. 47 (Cooper Rebuttal) at 7-8.

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expenses and revenues, much like a fuel factor.302 The intervenors point out that the PPR proposal, while unprecedented, would have at least matched any post-Test Year increases in total purchased capacity costs with corresponding increases in sales, and would also have allowed for a prudence review of any post-Test Year purchased power capacity expenses in a future reconciliation proceeding.303 The Commission, however, rejected the PPR proposal in its Supplemental Preliminary Order.304 In lieu of the PPR proposal, ETI now proposes to simply recover the $276 million as part of its base rates.

3. Staff and Intervenors’ Opposition to ETI’s PPCCs Proposal Staff and all of the actively-engaged intervenors oppose ETI’s proposed adjustment to its Test Year PPCCs. They make a number of arguments against ETI’s proposal.

(a) The PPCCs Requested by ETI Are Not Known and Measurable First, they contend that ETI’s Rate Year forecast cannot be considered known or measurable.

Staff points out that the four305 components from which ETI purchases power are interrelated, such that, “when ETI adds capacity under one element, such as through third party contracts, the other components, such as ETI’s MSS-1 payments, will decrease.”306 Staff describes each of the components comprising ETI’s PPCC Rate Year forecast as being “infected” with numerous assumptions.307 For example, ETI necessarily made projections, rather than relying upon actual payments, when it estimated what it will pay for third-party contracts in the Rate Year.308 Many of the third party contracts that will be in effect in the Rate Year do not contain fixed price terms.

Rather, the amounts ETI will pay will fluctuate based upon factors such as required availability and Tr. at 1954; Cities Ex. 4 (Goins Direct) at 14.

TIEC Init. Br. at 25-26; Tr. at 1954; Cities Init. Br. at 37; Cities Ex. 6 (Nalepa Direct) at 8.

Supplemental Preliminary Order at 2 (Jan. 9, 2012).

Staff (and some of the intervenors) describe them as three components, by combining affiliate purchases under legacy contracts and affiliate purchases under other contracts into one component.

Staff Initial Brief at 25 (citing Tr. at 1946).

Staff Initial Brief at 26.

Tr. at 704.

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performance. Nevertheless, ETI simply assumed it would pay the maximum amount possible under each of its third party contracts, and disregarded any of the contractual factors that might reduce its Rate Year payments.309 Thus, the intervenors contend that ETI’s cost estimates for third party purchased power are merely projections, as opposed to known and measurable changes.310

Similarly, ETI’s contractual agreements with its affiliate Operating Companies require ETI to make assumptions about their future costs. The contracts do not definitively fix prices or quantities. Rather, prices and quantities under the contracts will fluctuate based on the specific operational conditions actually experienced by the various Operating Companies during the Rate Year.311 The ultimate determination of payments made in the Rate Year will be calculated based upon the complex mathematical formula set out in schedule MSS-4. That formula contains a great number of variables. ETI had to make assumptions about each one of those variables in order to estimate its Rate Year costs.312 The intervenors point to ETI’s new contract with EAI (the EA WBL Contract) as evidence of the “inherently speculative nature” of ETI’s PPCCs request. According to the intervenors: x the EA WBL Contract was signed on April 11, 2012 (only days before the hearing in this matter commenced); purchases will not commence under the contract until January 1, 2013; x pricing under the contract will be determined in 2013 pursuant to the complex formula contained in MSS-4; x the quantity of capacity ETI ultimately purchases under the contract will be based on a yet-to-be- determined allocation percentage between ETI and the other Operating Companies; x the contract itself may never go into effect because it is contingent upon ETI receiving all necessary “regulatory approvals” before August 1, 2012; and x if it does go into effect, it will still be subject to at least two further revisions before any power is received by ETI under the contract.313 Tr. at 704-05.

TIEC Initial Brief at 29-30; Staff Initial Brief at 26.

Tr. at 606.

See Staff Initial Brief at 27; Tr. 606.

ETI Ex. 47 (Cooper Rebuttal) at RRC-R-1, and Tr. at 628-9.

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The EA WBL Contract accounts for more than one-third of ETI’s upward adjustment to its Test Year PPCCs. The intervenors contend that, in order for ETI to arrive at its forecasted PPCCs for the Rate Year, it had to make myriad assumptions as to the future values of the many variables in the EA WBL Contract (and the other affiliate contracts).314 Therefore, the intervenors argue that ETI’s cost estimates for its contractual agreements with its affiliate Operating Companies are merely projections, as opposed to known and measurable changes.315

ETI’s estimated costs for its MSS-1 payments also require assumptions about the future. In order to calculate its future reserve equalization responsibilities using the complex formula set out in MSS-1, ETI had to forecast its own future loads, along with the future loads of all the other Operating Companies. If those assumptions prove to be wrong, then ETI’s actual MSS-1 costs will be different than as projected in the application.316 It is noteworthy, according to the intervenors, that ETI projected the future load growths of all the Operating Companies when it calculated its projected Rate Year MSS-1 costs because, elsewhere in ETI’s evidence, the Company has taken the position that future projected loads should not be considered known and measurable.317 Staff argues:

ETI cannot have it both ways. It cannot claim load growth to be speculative in one context, and then claim that it can forecast with absolute certainty the respective load growths for each EOC on the Entergy System.318 TIEC points out that ETI’s estimated MSS-1 payments “were still changing on the eve of the hearing.”319 In the following exchange, even ETI witness Phillip May, one of the Company’s

Staff Initial Brief at 27-28. Staff makes the further point that, because the EA WBL Contract was executed only days before the hearing, Staff has been unable to determine whether the contract is even a prudent one.

TIEC Initial Brief at 30-32; Staff Initial Brief at 27-28.

Tr. at 651-52.

Tr. at 1907; see also Staff Initial Brief at 28; TIEC Initial Brief at 27-28.

Staff Initial Brief at 29; see also TIEC Initial Brief at 37.

TIEC Initial Brief at 28.

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primary witnesses regarding its PPCCs, seems to have conceded that the Company’s MSS-1 projections are not known and measurable:

Q: Do you think that the projection . . . of rate year sales that is implicit in the calculation of MSS-1 costs . . . is a known and measurable change?

A: I think that there is some uncertainty with regard to that projection, yes, sir.320 In sum, the intervenors contend that ETI’s cost estimates for all components of purchased power in the Rate Year are merely projections, as opposed to known and measurable changes.321

(b) The PPCCs Requested by ETI Violate the Matching Principle Second, the intervenors acknowledge the principle that Test Year expenses may be adjusted for known and measurable changes. However, they contend that such adjustments can only be made where the attendant impacts on all aspects of a utility’s operations (including revenue, expenses, and invested capital) can with reasonable certainty be identified, quantified, and matched.322 They assert that ETI’s proposed adjustment does not satisfy this matching principle. The intervenors complain that ETI is improperly attempting to “compare apples to oranges” by mixing a forecast of future Rate Year PPCCs with actual Test Year billing determinants. As explained by Cities witness Nalepa, “[u]nder the company’s approach of mixing estimated rate year costs with test year billing units, there is a failure to recognize customer growth and increased sales revenue – thus overstating the revenue requirement.”323 The argument, essentially, is that the various new or expanded contracts that ETI has entered into were executed so that, in whole or in part, ETI would be able to meet future demand, but that ETI is seeking to recover the costs of those new contracts from its existing customers.324

Tr. at 1918-19.

TIEC Initial Brief at 27-28; Staff Initial Brief at 29.

Cities Ex. 6 (Nalepa Direct) at 12, citing P.U.C. SUBST. R. 25.231(c)(2)(F).

Cities Ex. 6 (Nalepa Direct) at 8; Cities Ex. 4 (Goins Direct) at 14-15.

Cities Ex. 6 (Nalepa Direct) at 11; see also Cities Initial Brief at 38, Staff’s Initial Brief at 30, TIEC Initial SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 105 PUC DOCKET NO. 39896

The intervenors offer various examples, of which the following is typical, to illustrate why it was inappropriate for ETI to fail to take load growth into account when it calculated its Rate Year PPCCs. Assume that, during the Test Year, Utility X had 100 billing units and $500 of PPCCs. Also assume that, during the Rate Year, Utility X had 200 billing units and $1,000 of PPCCs. If Utility X were limited to setting its rates based solely on its Test Year numbers, then it would recover precisely the right amount to cover its PPCCs in both the Test Year (100 billing units x $5 per unit = $500 of PPCCs) and in the Rate Year (200 billing units x $5 per unit = $1,000 of PPCCs). If, on the other hand, Utility X were allowed to set its rates based upon it billing units from the Test Year (100) and its PPCCs from the Rate Year ($1,000), then Utility X would unfairly recover twice the amount needed to cover its actual PPCCs in the Rate Year (200 billing units x $10 per unit = $2,000).325 Thus, intervenors contend that ETI’s load growth must be taken into account if PPCCs are to be based on Rate Year projections.326 They point out that ETI itself expects steady load growth in the next few years,327 and experienced “good” growth over the two years preceding the Test Year.328

For its part, ETI denies that its increased capacity has been obtained in order to meet load growth. Rather, it contends that it has added capacity in order to be “less short” in comparison to the other Operating Companies.329 Moreover, ETI contends that the load growth adjustments proposed by intervenors are “uncertain and unnecessary.”330

(c) ETI’s Proposal Would Preclude Prudence Review Third, TIEC contends that ETI’s future Rate Year proposal would set rates based on projections without any effective Commission review of: (1) what the actual expenditures under

Brief at 35-39.

Cities Ex. 4 (Goins Direct) at 16-17.

Cities Ex. 4 (Goins Direct) at 17; see also TIEC Ex. 23.

Cities Ex. 4 (Goins Direct) at 17; Tr. at 706.

Tr. at 130.

ETI Initial Brief at 68-69.

Id. at 69.

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purchased capacity contracts turn out to be; (2) whether those expenditures turn out to be reasonable; and (3) whether the future contracts were prudent.331

4. The Intervenors’ Recommendations Regarding PPCCs The intervenors agree that the amount requested by ETI is unreasonable, excessive, and should be rejected. They do not universally agree, however, about what the proper number for PPCCs should be. Staff, TIEC, and State Agencies argue that ETI’s PPCCs should be set at the amount of the Company’s Test Year PPCCs: $245.4 million. This position is best summarized by Staff:

Staff recommends that the Commission adhere to traditional ratemaking principles and set the amount of ETI’s purchased power expenses based on what the Company actually experienced during its test year. During its test year, ETI had total purchased power capacity expenses of $245.4 million. This amount is not in dispute.

This amount is known. This amount is measurable. The Commission should utilize this amount to set just and reasonable rates for ETI and its ratepayers.332 Rather than recommending Test Year PPCCs, Cities offer two alternatives – one recommended by its witness Dr. Dennis Goins, and another recommended by its witness Mr. Nalepa.333 Dr. Goins recommends that ETI be allowed to recover PPCCs of roughly $242.9 million.334 This amount is roughly $33 million less than ETI’s requested amount and $3 million less than ETI’s actual Test Year costs. To arrive at this amount, Dr. Goins made several calculations. First, he adjusted the average per kW cost of ETI’s legacy and other affiliate purchases using cost data from November 2010 through October 2011, which is slightly more current data than that relied upon by ETI.335 Second, as to MSS-4 costs, because the EA WBL contract is set to expire sooner than the three years he assumed ETI’s new rates will be in effect, Dr. Goins “normalized” the

TIEC Initial Brief at 33-35.

Staff Initial Brief at 29.

Cities Initial Brief at 40.

Cities Ex. 6 (Nalepa Direct) at 17, and Errata No. 3.

Cities Ex. 4 (Goins Direct) at 17-18.

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costs of the EA WBL contract over the three year period.336 Finally, he adjusted the Rate Year total PPCCs estimate to reflect the effects of load growth, based upon ETI forecasts.337

Mr. Nalepa took a slightly different approach. He recommended that ETI be allowed to recover PPCCs of $236,838,634, or roughly $39 million less than ETI’s requested amount and $8 million less than ETI’s Test Year costs.338 To arrive at this amount, Mr. Nalepa first calculated the per kW cost of ETI’s third party Rate Year capacity and applied it to ETI’s Test Year-end capacity. In this way, “the increased cost of the new resources is recognized, but current demand is better matched to current resources.”339 Second, he made the same adjustment as Dr. Goins as to MSS-4 costs due to the EA WBL contract.340

TIEC explains it is reluctant to “descend into the rabbit hole and engage in ratemaking based on prognostications, estimates, projections, and assumptions about what may happen in the future.”341 If the Commission were to do so, however, TIEC argues that the final result would be lower than the Test Year PPCCs, not higher. TIEC’s witness Jeffry Pollock calculated the impact of projected unit prices based upon ETI’s projections, and he eliminated the expiring EA WBL Contract. His result, which TIEC is not advocating, would allow ETI to recover PPCCs of $238.8 million, roughly $7 million less than its Test Year costs.342

ETI describes the proposals made by TIEC and Cities as “extreme” and contrary to common sense.343 For example, Mr. Pollock’s calculations indicate that ETI’s MSS-1 costs would increase by roughly $5 million, while its third-party and affiliate contracts would slightly decrease. ETI argues that this is the opposite of reality. By adding capacity through third party contracts, its Cities Ex. 4 (Goins Direct) at 18; Cities Ex. 6 (Nalepa Direct) at 15-16.

Cities Ex. 4 (Goins Direct) at 18-19.

Cities Ex. 6 (Nalepa Direct) at 17.

Cities Ex. 6 (Nalepa Direct) at 12-13.

Id. at 15-16.

TIEC Initial Brief at 41.

TIEC Ex. 1 (Pollack Direct) at 25-27; TIEC Initial Brief at 41-42.

ETI Initial Brief at 83.

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reliance upon the other purchased power components, especially MSS-1, will necessarily decline, not increase.344 ETI also argues that load growth is inherently uncertain and should not be taken into account.345

5. The ALJs’ Analysis Regarding PPCCs The ALJs conclude that ETI failed to meet its burden to prove that the adjustment it seeks to its Test Year PPCCs is known and measurable. The known and measurable standard is an exception to the actual data contained in the Test Year. The point of a historical Test Year is to review actual costs, which include the ups and downs of what actually occurred. As to a forecast of the Rate Year, by contrast, the evidence demonstrates that the costs attributable to a particular contract to purchase capacity cannot currently be known because there are so many variables that will play into the amount ETI ultimately pays. As stated above, ETI’s third party contracts lack fixed prices and the amounts ETI will pay could fluctuate based upon factors such as required availability and performance. ETI simply assumed it would pay the maximum amounts under those contracts, and disregarded the contractual factors that could lower the payment amounts. Yet this assumption runs counter to ETI’s historical experience with its contracts.346 Similarly, ETI’s affiliate contracts do not fix prices or quantities, and the amount ETI ultimately pays will fluctuate based upon operational conditions experienced by all of the Operating Companies during the Rate Year. Those operational conditions obviously cannot be known at this time. Both the affiliate contracts under MSS-4 and the equalization payments under MSS-1 are based upon highly complex mathematical formulae that utilize numerous variables. Any of the variables could change during the Rate Year, thereby altering the amounts paid by ETI under affiliate contracts or MSS-1. As a result, the evidence demonstrates that there could be a substantial difference between ETI’s projected Rate Year costs and what actually ends up occurring. ETI asks the Commission to trust it that these differences would be “small,”347 but provides no evidence as to what small means.

Id. 83.

Id. 84.

Tr. at 705.

ETI Initial Brief at 81.

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The efforts made by ETI, Cities, and TIEC to forecast Rate Year PPCCs further illustrate the difficulty of deviating from actual Test Year data in an area that involves so many future contingencies and unknowns. Those forecasts swung wildly – ETI estimated Rate Year PPCCs that were $31 million more than the Test Year, while the Cities’ and TIEC’s estimates came in at $3 million, $8 million, and $7 million less than the Test Year, respectively. Indeed, even Cities’ own witnesses disagreed substantially among themselves as to what the proper amount should be.

Moreover, arguably ETI could not even agree with itself regarding the proper amount because, in its Initial Brief, it suggested that a reduction of roughly $4.5 million might be warranted to account for its latest projection of its MSS-1 costs in the Rate Year.348

The ALJs are similarly convinced that ETI’s request violated the matching principle by mixing its forecast of future Rate Year PPCCs with Test Year billing determinants. It is logically inconsistent for ETI to have, on the one hand, based its estimate of Rate Year MSS-1 costs on its projections of the load growths of ETI and all the other Operating Companies and, on the other hand, argue that load growth cannot be considered known and measurable when calculating its overall PPCCs. This argument does not withstand scrutiny, especially in light of the fact that ETI clearly believes its load will be larger in the Rate Year than it was in the Test Year and it has, in fact, contracted for six percent more load in the Rate Year.349

Simply put, the intervenors presented substantial evidence that all of the components of ETI’s purchased power capacity contain significant variability and uncertainty in costs, thereby leading to the conclusion that estimates of Rate Year PPCCs cannot be considered known and measurable. For this reason, the ALJs recommend that ETI’s PPCCs request be rejected. In its place, the ALJs recommend that ETI be allowed to recover its Test Year PPCCs of $245,432,884.

ETI Initial Brief at 77 (citing Tr. at 684, 1945).

ETI Ex. 47 (Cooper Rebuttal) at 4; Tr. at 667-68.

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B. Transmission Equalization (MSS-2) Expense The Entergy system transmission grid is a large, integrated transmission network that is operated for the mutual benefit of all of the Entergy Operating Companies.350 Service Schedule MSS-2 is a FERC jurisdictional tariff that equalizes the ownership costs of certain high voltage transmission facilities among ETI and the other Operating Companies, so that each Operating Company pays its just and reasonable share of those costs. Accordingly, those costs are referred to as “transmission equalization” payments.351 MSS-2 generally applies to equalization of transmission costs for transmission assets of 230 kV and larger.352

In any given month, some of the Operating Companies might be “long” on the amount of transmission capacity they own (meaning that they own more capacity than they need) while others might be “short” on capacity (meaning they own less capacity than they need). In such a month, the long Operating Companies would receive MSS-2 payments from the short Operating Companies for use of their transmission facilities.353 Over the course of the Test Year, ETI was short, meaning that it paid a total of $1,753,797 in MSS-2 payments to various other Operating Companies.354

In the application, rather than seeking to recover only the $1.7 million in Test Year MSS-2 costs, ETI is seeking to recover roughly $10.7 million, which represents its anticipated MSS-2 expenses in the Rate Year.355 The additional $9 million that ETI seeks is based on the Company’s estimates of transmission construction projects that are expected to have been completed by or during the Rate Year which will result in changes to the relative transmission line ownership ratios between the Operating Companies. In other words, ETI expects that, by or during the Rate Year, its ownership share under the MSS-2 will decrease relative to the other Operating Companies (as the

Tr. at 450, 793.

Tr. at 724; ETI Ex. 39 (Cicio Direct) at 15-17 and PJC-1 at 38.

Tr. at 450-51, 731.

Tr. at 731, 735.

Tr. at 723-24, 737; Cities Ex. 28.

Tr. at 452-53, 738, 760.

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transmission capacity owned by the other Operating Companies increases), thereby driving the amount of ETI’s MSS-2 payments upward.356

The increase is driven by ETI’s prediction that $184.9 million in additional transmission capacity will be built by other Operating Companies by the end of the Rate Year. ETI identified six construction projects that are either underway or approved for construction and which, collectively, will account for roughly $141 million of the predicted $184.9 million in additional transmission capacity. Of those six projects, one was completed and went into service on December 16, 2011, after the end of the Test Year. The other five are either under construction or still in the planning phase and are currently scheduled to go into service on dates ranging from June 29, 2012, to December 31, 2012.357 According to ETI, the remaining $43.9 million of the $184.9 million in additional transmission capacity is derived from “an estimate of the capital investment necessary to maintain equalizable [i.e. MSS-2 qualifying] transmission investments across the Entergy Transmission System.”358 The estimate is based upon the Operating Company’s projected budgets and historical spending patterns for maintenance of transmission facilities.359

Staff, State Agencies, TIEC, and Cities all oppose ETI’s effort to recover $10.7 million in MSS-2 expenses. The parties make a number of arguments. First, they point out that MSS-2 utilizes a complex mathematical formula to calculate each Operating Company’s liability (or credit) under the equalization process. There are a great number of variables that are used in the formula, such as the amount of investments made by each Operating Company in transmission facilities, the costs of capital for each Operating Company, the size of the load demanded by each Operating Company, and the amount of state and federal taxes paid by each Operating Company. Changes to any of these variables can change the amount ETI owes (or is due) pursuant to MSS-2.360 Moreover, these variables relate not only to ETI, but to all of the Operating Companies. Indeed, Cities calculate that,

Tr. at 775-77.

ETI Ex. 59 (McCulla Rebuttal) at 2 and MFM-R-1; Tr. at 456-58.

ETI Ex. 59 (McCulla Rebuttal) at 3.

Id. ETI Ex. 39 (Cicio Direct) at PJC-1 at 38-43; Tr. at 454-55.

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to perform the MSS-2 calculation, at least 360 “mini-forecasts” must be made, only 60 of which relate to ETI.361 As explained by TIEC witness Pollock, any effort to estimate future amounts of these many variables “is susceptible to a host of uncertainties.”362 The intervenors argue that for ETI to arrive at its estimate of $10.7 in MSS-2 costs during the Rate Year, the Company had to speculate as to what the many MSS-2 variables would be in the Rate Year. In other words, they contend that ETI’s estimate of its future MSS-2 costs cannot possibly be considered “known and measurable” and, therefore, is not recoverable.363 State Agencies and Staff liken ETI’s attempt to obtain an MSS-2 adjustment for not-yet-complete construction projects to an impermissible request to recover the costs of CWIP without having to meet PURA’s burden of proving that recovery is necessary to protect the utilities financial integrity.364

Second, the parties oppose ETI’s effort to recover its predicted MSS-2 expense in the Rate Year point out that the primary driver of the increased costs over the Test Year comes from a number of transmission projects that have not yet come into service, and are still in the planning or construction phase. ETI concedes that if the projects do not actually come into service at the currently estimated times, then the Company’s estimates of its MSS-2 costs during the Rate Year will be inaccurate.365 Thus, Staff contends that ETI’s projections about future MSS-2 costs cannot be considered known and measurable.366 Moreover, TIEC and Staff contend that ETI is effectively seeking higher rates based upon expenses associated with projects that are not yet completed and, therefore, the projects cannot be considered “used and useful.”367 As explained by TIEC:

It would be bad public policy for the Commission to rely on speculative construction end dates to form the basis of a known and measurable change to test year costs.

Cities Reply Br. at 68-69.

TIEC Ex. 1 (Pollock Direct) at 29.

Staff Initial Brief at 31; State Agencies Initial Brief at 11-13; TIEC Initial Brief at 44-45; Cities Initial Brief at 44.

State Agencies Initial Brief at 12 (citing PURA § 36.054; P.U.C. SUBST. R. 25.231(c)(2)(D)); Staff Reply Brief at 20.

Tr. at 800-801 Staff Initial Brief at 32.

TIEC Initial Brief at 47; Staff Initial Brief at 19-20.

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ETI’s own witness Mr. Cicio admitted that in-service dates can be uncertain. . . .

Similarly, costs can change upward or downward. For this reason, the Commission has typically followed the policy that proper ratemaking requires that a utility actually build the transmission infrastructure suggested by its projections, and then seek to account for that investment on a historical basis in a future rate case. In Docket No. 28906, for example, the Commission held that LCRA’s projections of future transmission investment did not support a finding that its projected capital needs satisfied the known and measurable test. It is similarly unreasonable for ETI to make a post-test year adjustment associated with transmission projects that are not serving any of its customers and that may or may not impact ETI’s transmission equalization expense, depending on when the projects are finally completed.368 Third, in addition to the six transmission projects that are under development, another driver of the increased costs over the Test Year comes from ETI’s estimate that $43.9 million will be spent to maintain transmission investments across the Entergy Transmission System. The intervenors contend that ETI has provided little to no evidentiary support for this estimate. State Agencies and Cities also point out the unfairness of allowing ETI to begin recovering $10.7 million per year in its rates immediately based upon new transmission facilities, even though many of those new facilities will not come into service (and ETI will therefore not incur higher MSS-2 payments for those facilities) for many months.369

Fourth, Cities points out that Entergy and the various Operating Companies have announced a plan to sell all of their transmission assets to a third party. That process is currently underway.

The evidence suggests that, if and when that transaction is complete, ETI’s MSS-2 expenses will disappear.370

Finally, TIEC argues that there is no need to grant ETI’s request for a pro forma adjustment to its test year MSS-2 expenses because the Company can avail itself of a TCRF if its Rate Year costs deviate substantially from its Test Year costs. Thus, if it turns out that ETI experiences an

TIEC Initial Brief at 47 (citing Docket No. 28906, Order at 6).

State Agencies Initial Brief at 12; Cities Initial Brief at 45.

Cities Reply Brief at 67-68; Tr. at 113-14; Cities Ex. 4 (Goins Direct) at 20-21. Admittedly, if these expenses disappear, ETI will still have to bear transmission expenses. However, it is impossible to know, at this time, what those expenses would be.

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increase in its MSS-2 expenses during the Rate Year, the utility has cost recovery mechanisms at its disposal that could make it whole in a timely manner.

Staff and State Agencies argue that only $1.7 million (representing ETI’s actual Test Year expenses) should be approved in this proceeding. TIEC witness Pollock recommends approving a slight upward adjustment to account for the fact that ETI’s MSS-2 expenses were substantially higher in the second six months of the Test Year than they were in the first six months. Mr. Pollock and TIEC recommend a pro forma adjustment equal to twice the amount of MSS-2 payments incurred by ETI in the second six months of the Test Year, or $2.7 million.371

Cities’ witness Goins presented yet another alternative. Dr. Goins proposes to adjust the projected Rate Year costs for known expenses incurred after the Test Year. He proposed reducing the adjusted Rate Year MSS-2 expense to a Test Year level by applying a load growth adjustment using ETI’s own projected load growth as a benchmark indicator of the reasonable anticipated level of growth. (Cities invoke essentially the same “matching principle” argument regarding load growth that they raised with respect to PPCCs). The result of Dr. Goins’ adjustment would be to would allow ETI to recover $4,103,850 in MSS-2 expenses.372

ETI responds to these arguments on a number of fronts. It contends that the main driver of changes in MSS-2 expenses is the relative amount of equalizable transmission investment in the transmission system by ETI and the other Operating Companies, compared to their proportionate responsibility for that investment, based on each company’s responsibility ratio.373 ETI argues that the other elements of the formula are relatively stable, and do not vary significantly from year to year.374 ETI contends its requested level of MSS-2 expense is based on a known and measurable

TIEC Ex. 1 (Pollack Direct) at 32-33.

Cities Ex. 4 (Goins Direct) at 20-21.

ETI Ex. 45 (Cicio Rebuttal) at 3-4. Responsibility Ratio is an allocator that reflects the relative contribution of each Operating Company to the System’s coincident peak load – in other words, an Operating Company’s coincident peak load divided by the System peak load, calculated on a rolling twelve-month average. ETI Ex. 39 (Cicio Direct) at 12.

Tr. at 763 and 780.

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change because it is based on the $184.9 million in additional transmission investment for all of the Operating Companies that ETI knows will occur and can reasonably measure. ETI points out that “the vast majority” of the planned transmission projects have received full funding approval and have been constructed or are on schedule to be completed before the end of the Rate Year, while the remaining amount is reasonably quantified and measured based on the budget and historical spending for maintenance of equalizable transmission facilities.375

ETI also argues that its actual MSS-2 expenses have steadily trended upward since the Test Year. ETI explains as follows:

[I]n the last month of the test year (June 2011), ETI’s payments began to increase significantly, as the balance of relative equalizable investment levels shifted among the Operating Companies. ETI’s actual monthly payments have climbed steadily ever since, reaching $698,289 in the most recent actual month’s bill (February 2012).

Annualization of this most recent actual data yields an annual MSS-2 amount of $8.4 million, almost five times the test year level. In light of this trend in actual historical data, the notion of basing the MSS-2 expense in rates on the test year level is unreasonable on its face.376 Thus, ETI contends its requested expense level is “consistent” with actual recent historical levels of MSS-2 expense.377

ETI describes Cities’ concern regarding load growth as a “red herring.” ETI contends that load growth is not the cause of changes in MSS-2 costs. Instead, its MSS-2 increases are driven by the other Operating Companies’ transmission investments, “separate and apart from, and unaffected by,” any increase in ETI’s load.378 Moreover, ETI contends that load growth adjustments are not

ETI Ex. 59 (McCulla Rebuttal) at 2-3; ETI Initial Brief at 88-89.

ETI Initial Brief at 90-91; Tr. at 784.

ETI Initial Brief at 91.

ETI Ex. 45 (Cicio Rebuttal) at 4-5; ETI Initial Brief at 93.

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known and measurable and are not the proper subject of a post-test year adjustment for ordinary expenses such as MSS-2 costs.379

Finally, if the Commission rejects its request for $10.7 million in MSS-2 costs, ETI suggests annualizing the most recent period of its actual MSS-2 costs, by multiplying its February 2012 MSS- bill times 12, resulting in an amount of $8,379,480. ETI contends this would be more representative of expected Rate Year MSS-2 costs than the amounts proposed by the intervenors.380

For largely the same reasons as were discussed relative to PPCCs, the ALJs conclude that ETI failed to meet its burden to prove that its proposed Rate Year MSS-2 costs are known and measurable. The MSS-2 formula requires assumptions about a great number of variables. Changes to any of the variables could occur during the Rate Year, thereby altering the amount paid by (or received by) ETI during the Rate Year. The projects that underlie ETI’s Rate Year request are largely not yet built, and might never be built. Additionally, much like with the PPCCs estimates, there is a wide gulf between the competing estimates by ETI, Cities, and TIEC of forecast Rate Year MSS-2 costs, illustrating the problem of deviating from actual Test Year data in an area that involves so many future contingencies and unknowns.

The ALJs are equally unconvinced by ETI’s alternative proposal to multiply its February 2012 MSS-2 bill times 12, resulting in an amount of $8,379,480. ETI offered no evidence to establish that a single month’s costs can serve as a reasonable representation of what ETI’s future Rate Year MSS-2 costs will be. Moreover, February 2012 is outside of the Test Year.

The intervenors presented substantial evidence to demonstrate that ETI’s estimate of its Rate Year MSS-2 costs cannot be considered known and measurable. For this reason, the ALJs recommend that ETI’s MSS-2 request be rejected. In its place, the ALJs recommend that ETI be allowed to recover its Test Year MSS-2 costs of $1,753,797.

ETI Ex. 57 (May Rebuttal) at 12; ETI Initial Brief at 93.

ETI Ex. 46 (Considine Rebuttal) at 37; ETI Initial Brief at 32.

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C. Depreciation Expense [Germane to Preliminary Order Issue No. 12] ETI currently has an annual depreciation expense of approximately $72.1 million. This expense is based on the previously approved depreciation rates.381 ETI now requests depreciation rates that would result in an annual depreciation expense of approximately $86 million. This requested amount represents an increase in the annual depreciation expense of approximately $13.9 million - almost 20 percent - from the current annual depreciation expense.382 The depreciation expense ultimately included in retail rates, however, will be derived by applying the Commission approved rates to the test year end plant balances as of June 30, 2011.

The other parties have accepted the vast majority of ETI’s recommendations, but take issue with the Company on a few issues related to generation, transmission, distribution, and general plant accounts. Staff recommends an annual depreciation expense of approximately $78.2 million, an increase of approximately $6.1 million from the current annual depreciation expense.383 Cities recommend an annual depreciation expense of approximately $67.6 million.384

The identical positions of ETI, Staff, and Cities on depreciation issues are set forth in the following table:385

Plant Group Approved ETI Proposal Staff Proposal Cities Proposal Hydro $7,137 $245 $245 n/a Production Regional Trans. $685,351 $685,351 $685,351 n/a & Market Operations General $4,175,311 $5,946,949 $5,946,949 n/a Amortized Plant

ETI Ex. 13 (Watson Direct) Attachment DAW-1. Appendix B at 3.

ETI Ex. 13 (Watson Direct) at 7.

Staff Ex. 2 (Mathis Direct) at 8.

Cities Ex. 5C (Pous Depreciation Study) at 2.

ETI Ex. 13 (Watson Direct) at 7; Staff Ex. 2 (Mathis Direct) at 7-8; Cities Ex. 5C (Pous Depreciation Study) at 7, 8, and 34.

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The differing positions of ETI, Staff, and Cities on depreciation issues are set forth in the following table:386

Plant Group Approved ETI Proposal Staff Proposal Cities Proposal Steam $17,497,781 $18,660,946 $14,709,942 n/a Production Transmission $13,679,827 $16,493,761 $16,417,727 $13,451,479 Plant Distribution $32,110,774 $40,493,392 $38,806,863 $33,186,546 Plant General Plant $3,943,450 $1,604,644 $1,604,644 $973,519 General Plant $0 $2,134,924 $0 n/a Reserve Deficiency TOTAL $72,099,631 $86,020,212 $78,171,721 n/a387 The competing positions of ETI, Staff, and Cities reflected in the table above are primarily the result of different: (1) net salvage rates for certain accounts; (2) remaining life parameters for certain accounts; and (3) treatment of a potential general plant reserve deficiency. Cities witness Pous also questions the reliability of the data employed by ETI witness Watson in the performance of his study.

An analysis of the competing net salvage rates and life parameters for each account is presented in detail below, organized by plant and account group.

1. Terminology and Methodology Depreciation is a method of allocating the loss of the service value, not restored by current maintenance, over the useful life of an asset. This loss may be caused by wear and tear, decay, obsolescence, or changes in demand.388

ETI Ex. 13 (Watson Direct) at 7; Staff Ex. 2 (Mathis Direct) at 7-8; Cities Ex. 5C (Pous Depreciation Study) at 7, 8, and 34.

A total value of Cities’ adjustments in this format would be out of context and is therefore not provided in this table.

Staff Ex. 2 (Mathis Direct) at 8.

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Within the context of a rate case, the purpose of depreciation is to allow a company to recover the cost of an asset over the asset’s useful life. Ideally, the cost of the asset is spread out evenly across the years the asset is in service, thus recovering the cost of the asset from the customers who receive the benefit of the asset.389

Both ETI and Staff use the remaining-life technique, average life group procedure, and straight-line method to calculate the depreciation rate.390 The basic formula for the remaining life technique is presented below.

For example, if an asset has a book reserve ratio of 0.5 (i.e., 50 percent of the asset’s value has already been recovered through prior depreciation expense), a net salvage ratio of zero (i.e., the asset will cost nothing to retire, or all retiring costs will be recovered through its subsequent sale), and the composite remaining life is ten years (i.e., the asset is expected to remain in service for another ten years), then the depreciation rate will be 5 percent (i.e., {[(1 - 0.5 - 0) / 10 ] *100}).

By operation of the remaining-life formula, a greater net salvage value will reduce the numerator and result in a lower depreciation rate and a lower depreciation expense. Likewise, a lower net salvage value will increase the numerator and result in a higher depreciation rate and a higher depreciation expense. Similarly, a longer remaining-life will result in a lower depreciation rate and lower depreciation expense, and a shorter remaining-life will result in a higher depreciation rate and a higher depreciation expense.

Because net salvage and remaining-life values are the two contested variables in the remaining-life formula, a clear explanation of net salvage and remaining-life will be helpful.

Staff Ex. 1 (Mathis Direct) at 8-9.

ETI Ex. 13 (Watson Direct) at 15; Staff Ex. 2 (Mathis Direct) at 10-11.

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Net Salvage Value. Net salvage is calculated by taking the amount received for an asset as a result of its sale, reuse, or reimbursement, and subtracting that amount from the cost associated with retiring the asset. This figure is then divided by the original cost of the asset to determine the net salvage ratio. For example, if an asset with an original cost of $200 is resold for $20, but it costs the owner $10 to ship the asset to the purchaser, then the net salvage value of that asset would be $10 ($20 - $10), and the net salvage ratio of that asset would be 5 percent ($10/$200).

ETI witness Watson and Staff witness Mathis used different methods of calculating a net salvage rate.391 Mr. Watson took the average (mean) of recorded net salvage values for groups of successive years (rolling bands), and then selected the net salvage rate from among these averages.392 Ms. Mathis also used rolling band averages (means), but then took the median from a representative group of rolling bands when the historical salvage data would have otherwise produced what Mr. Watson considers skewed results.393

Ms. Mathis’ method of calculating net salvage rates follows recent Commission precedent.394 As Mr. Watson explained at the hearing, it is appropriate to infer acceptance of a methodology by looking at whether the Commission adopted the conclusions that the methodology produced.395 In other words, if the Commission adopts the conclusions, then by inference the Commission has adopted the methodology used to derive those conclusions. Thus, it is necessary to examine recent litigated rate cases to ascertain Commission precedent.

In the most recent fully-litigated rate case, Docket No. 38339,396 Staff disagreed with CenterPoint’s depreciation witness, Mr. Watson, concerning the net salvage rates for five

Tr. at 415-416.

ETI Ex. 13 (Watson Direct) at 20-21.

Id. at 22-23, 32-33.

Tr. at 1766; Staff Ex. 9 (Docket No. 38339 Final Order) at FoF 126, 128, 130, and 131.

Tr. at 397.

Application of CenterPoint Energy Houston Electric, LLC, for Authority to Change Rates, Docket No. 38339 (June 23, 2011).

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accounts.397 In its order, the Commission adopted Staff’s recommended net salvage rates for four out of those five accounts for which Staff disagreed with Mr. Watson.398 Staff’s method for calculating net salvage rates is the same in the present case as it was in the CenterPoint rate case.399

ETI argues that the use of a median, as employed by Ms. Mathis, is not a sufficiently rigorous or expansive approach to depreciation analysis. According to ETI, depreciation training and texts, as well as authoritative statistical texts, favor the average, or mean, not the median, as the best indicator of the central tendency of a data set. ETI argues that this is particularly the case because depreciation analysis requires careful consideration of trends over time.400 ETI then offers the following comments:

[Ms. Mathis] agreed in response to a hypothetical that the median value of an initial period of ten years of +5% net salvage, followed by one year of 0% salvage, followed by the most recent period of ten years of -5% salvage, would be 0%. This hypothetical plainly illustrates how reliance on the median can overlook data trends.

In the hypothetical, if the depreciation analyst would otherwise wish to give more weight to the most recent historical period as indicative of conditions going forward, the use of the median would obscure that important trend information.401 A close examination of the hypothetical shows that in the case posited by ETI, however, the median and the mean are identical: both are zero. While the use of the median would produce a result that ignores the trend that ETI says should be taken into account, the mean produces the same result.

Changing the hypothetical produces no more clarity. If the examination was of a period that had ten years of positive five percent salvage value, followed by one year of zero percent net salvage value, followed by the most recent 10-year period, which had negative 10 percent net salvage value, the median would still be zero but the mean would be negative 2.38 percent. This appears to support the trending argument advanced by ETI. If the analysis then focuses on a different hypothetical, one with ten years of positive 10 percent net salvage value followed by one year of zero percent net Tr. at 401-402.

See Staff Ex. 9 (Docket No. 38339 Final Order); Tr. at 402.

Tr. at 415-416.

ETI Initial Brief at 105.

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salvage value, with the most recent ten-year period having negative five percent net salvage value, the results are more perplexing. The median is still zero, but the mean, which ETI contends will recognize the trending, is 2.38. Although this does in some respects recognize the trend to a negative salvage value, it does not recognize it as well as the median.

Principles and Procedures of Statistics, by Steel and Torrie, states: “Certain types of data show a tendency to have a pronounced tail to the right or the left. Such distributions are said to be skewed, and the arithmetic mean may not be the most informative central value.” Where the average of the incomes of a group of individuals is required, and most of those incomes are low, the mean income could be considerably larger than the median. In Docket No. 38339, Staff posed the following example, which the ALJs found both informative and persuasive: Suppose a sample of incomes from professional baseball players was taken that happened to include the salary of two of the most highly compensated players in the league today. As a result, the mean of the salaries would likely be far greater than the median salary, because the use of the median would be skewed by the very high salaries. The median would likely provide a more accurate measure of the central tendency of the salaries. Such circumstances are found where using the median to find the central tendency prevents outliers in data that “skews” or shows extreme variations rather than showing more symmetrical variations. The ALJs believe this is as accurate today as it was during the Docket No. 38339 timeframe. They therefore find that the use of the median is the more appropriate methodology for determining net salvage value.

Remaining Life. Composite remaining life is the weighted average remaining life of the property account for a group of all vintages. The average remaining life represents the future years of service expected for the surviving property.

There are numerous ways to calculate the remaining life (life parameter) of a group of assets in a depreciation study. Examples include the interim retirement rate method and the retirement (actuarial) rate method. The interim retirement rate method uses interim retirement curves to model (predict) the retirement of individual assets within plant accounts. Alternatively, the retirement (actuarial) rate method uses historical mortality data for a group of assets and compares that data to various known patterns of industrial asset mortality rates (Iowa Curves). If the historical data SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 123 PUC DOCKET NO. 39896

creates a pattern of mortality that closely follows one of the Iowa Curves, then that Iowa Curve may be used to approximate the remaining lives of that given group of assets in the future. Whether the historical mortality data creates a pattern that closely follows a given Iowa Curve is determined through plotting both sets of data (the historical mortality data and the Iowa Curve) on a graph and quantifying the closeness of fit through statistical analysis and visual examination.

Mr. Watson used multiple methods to calculate the remaining lives of assets, depending on the asset. Generally, he used the retirement rate (actuarial) method.402 However, to calculate the remaining life of production plant accounts, he used the interim retirement rate method.403 Ms. Mathis disagreed with the use of the interim retirement rate method because the Commission has rejected the application of interim retirement rates of production plant, as they are based on future projection of retirements, for ETI and Central Power and Light Company in Docket Nos. 16705404 and 14965,405 respectively.

ETI argues that the life span procedure, without the use of interim retirement curves, is unrealistic in its assumption that all production plant assets are “depreciated (straight-line) for the same number of periods and retire at the same time (the terminal retirement date).” Use of interim retirements is an important refinement that adds accuracy to the determination of the depreciation rates according to ETI. Mr. Watson offered the following explanation:

Adding interim retirement curves to the procedure reflects the fact that some of the assets at a power plant will not survive to the end of the life of the facility and should be depreciated (straight-line) more quickly and retired earlier than the terminal life of the facility.406

ETI Ex. 13 (Watson Direct) at 16.

Staff Ex. 2 (Mathis Direct) at 14.

Application of Entergy Gulf States, Inc., for Approval of its Transition to Competition to Competition Plan and the Tariffs Implementing the Plan, and for the Authority to Reconcile Fuel Costs, to Set Revised Fuel Factors, and to Recover a Surcharge for Under-recovered Fuel Costs, Docket No. 16705 (Oct. 14, 1998).

Application of Central Power & Light Company for Authority to Change Rates, Docket No. 14965 (Oct. 16, 1997).

ETI Ex. 13 (Watson Direct) at Ex. DAW-1, at 7-8.

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ETI contends that this issue presents a unique situation where all the experts agree with the theoretical soundness of Mr. Watson’s approach, but Mr. Pous and Ms. Mathis recommend its rejection due to the existence of contrary Commission precedent. The impact of their position is a $1,558,081 reduction to depreciation expense, based on December 31, 2010, plant balances.

Mr. Pous generally supports the use of interim retirements because “I think it’s right,”407 and he uses the method in other jurisdictions, where it is a prevalent practice. Ms. Mathis “also appears to recognize the theoretical soundness of utilizing interim retirements.”408 Even in Docket No. 16705, the precedent cited by Mr. Pous and Ms. Mathis, the Staff depreciation witness agreed that the use of interim retirements was appropriate, though not blessed by the Commission. ETI argues that use of interim retirements reflects the undisputable fact that “generating units will have retirements of depreciable property before the end of their lives.”409

ETI is correct that neither Ms. Mathis nor Mr. Pous provide any reasoning behind the prior Commission precedent. Moreover, it is also true that the Commission precedent is relatively old at this point (dating back to the mid-1990s) and apparently has not been revisited in any recent cases.

ETI argues that the Commission has in at least one other case used interim retirements (Docket No. 15195410), but provides little more than that comment to support the concept. It is true that in concept, interim retirements are determined in much the same fashion as other elements of depreciation analysis. Primarily based on historical accounting data, the analyst identifies characteristics in the history of the data upon which to base a reasoned assessment of retirements going forward, which is similar to what occurs in determining asset lives or net salvage. Interim retirement determinations are supported by their own Iowa Curves, just as is the analysis of plant lives.

Although the ALJs are persuaded by ETI’s arguments that the use of interim retirements may be the more theoretically correct methodology to employ, Commission precedent clearly disfavors ETI Ex. 71 (Watson Rebuttal) at 71, citing Pous Deposition at 49, 51.

Staff Ex. 2 (Mathis Direct) at 12-13.

ETI Ex. 13 (Watson Direct) at Ex. DAW-1, p. 8.

Application of Texas Utilities Electric Company for the Reconciliation of Fuel Costs, Docket No. 15195 (Aug. 26, 1997).

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the use of interim retirements and the ALJs are reluctant to rule contrary to Commission precedent.

Accordingly, the ALJs find that the retirement (actuarial) rate method, rather than the interim retirement method, should be used.

2. Production Plant (a) Lives Mr. Watson primarily used the life span method to calculate remaining lives of the production plant accounts.411 The life span method estimates a production plant’s life based on consultation with utility management, financial, and engineering staff.412 However, he used interim retirement methodology to reduce the remaining lives determined by the life span method. Staff does not dispute the remaining lives determined by the life span methodology, but does dispute the use of interim retirements. For the reasons discussed in Section VII.C.1, ETI should not be allowed to use the interim retirement methodology to adjust downward the remaining lives of its production plant accounts.

Cities witness Pous disputed only the remaining life determination for ETI’s Sabine Power Plant Units 4 and 5, ETI’s largest and newest gas fired generating units. Mr. Pous recommended a life span for Sabine Units 4 and 5 of 64 years based on assessment of the units, comparison to the estimated life span of similar units owned by ETI as well as other gas fired generating units across the country. ETI proposes a 60-year life for the two units. Mr. Pous noted that a “64-year life span recommended for Sabine Units 4 and 5 is consistent with the life span proposed by the Company for its Lewis Creek 1 generating unit. Lewis Creek Unit 1 is an older, smaller, and generally less efficient generating unit than Sabine Units 4 and 5. Cities contend that there is no basis or logic for assigning a shorter life span for a more capital-intensive asset that is newer, larger, and generally more efficient.”413

ETI Ex. 13 (Watson Direct) at 16.

Staff Ex. 2 (Mathis Direct) at 14.

Cities Ex. 5C (Pous Depreciation Study) at 9.

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ETI witness Watson explained that he primarily relied on the determination of Company personnel to arrive at the 60-year life for the Sabine Units. Although Cities attempted to cast doubt on Mr. Watson’s determinations regarding the life of these units, it is clear that his determinations are based on conversations with ETI various generation personnel and that those conversations confirmed that based on evaluation of a variety of considerations, including age, operational role, level of funding, unit condition, and operational risk, 60 years constitutes a reasonable threshold for the expected life of Sabine Units 4 and 5. It is also clear that comparisons to Lewis Creek Unit 1 are not appropriate. Lewis Creek Unit 1 has significant differences, which explain its longer life-span.

Unlike the Sabine Units, ETI is planning to spend in excess of $100 million to refurbish the Lewis Creek critical equipment over the next three years to sustain operating reliability. ETI is not performing similar refurbishment activities at Sabine.414

The Sabine Units are projected to be “must-run” units. This means that these units are, for the most part, deployed to operate whenever they are available for service. Mr. Pous compared these units to EAI’s Lake Catherine Units 1 & 2,415 but ETI contends this is not a reasonable comparison.

EAI’s Lake Catherine Units 1 & 2 are not “must-run” units. They experience very infrequent operation and are not projected to run much in the future. Other things being equal, according to ETI, this would justify the longer 67-year life span assigned to these Arkansas units, because they would not be experiencing the wear and tear of daily operation.416

The explanations offered by ETI for the 60-year life of the Sabine Units 4 and 5 generating facilities are convincing. It appears that Mr. Watson engaged knowledgeable people within ETI to gather pertinent information and applied that information appropriately. The comparison to Lake Creek units is not appropriate given the planned refurbishment of those units. Similarly, the comparison to the Lake Catherine units also fails. A unit that does not carry the “must-run” designation can easily be expected to perform longer than a unit, such as the Sabine Units, that

ETI Ex. 51 (Garrison Rebuttal) at 3.

Cities Ex. 5 (Pous Direct) at 7-8.

ETI Ex. 51 (Garrison Rebuttal) at 3.

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carries the “must-run” designation. Accordingly, the ALJs find that ETI’s choice of a 60-year life for the Sabine Units 4 and 5 is reasonable.

(b) Net Salvage Value In determining the net salvage attributable to production plant, ETI witness Watson started with the negative 5 percent net salvage factor approved most recently for ETI in PUC Docket No. 16705. This is a net salvage value that the Commission has adopted in a number of cases for production plant.417 Mr. Watson testified that the net salvage calculation must reflect known changes in the cost of retiring production plant since the net salvage factor was last set.

Accordingly, Mr. Watson’s study used the Handy-Whitman labor index to calculate the change in labor costs applicable to removal activity for the years 1997 to 2010. Consideration of the increases in labor costs over this 13-year period resulted in an increase in the cost of removal, and a corresponding increase in the level of negative net salvage, from negative five percent to negative 8.5 percent.418

Both Staff witness Mathis and Cities witness Pous disagreed with ETI’s proposal for production plant net salvage. Ms. Mathis proposed that the existing negative 5 percent net salvage factor be retained. Ms. Mathis stated that Mr. Watson’s analysis is flawed for three reasons:

x First, Mr. Watson did not calculate a gross salvage value for each plant. This is a necessary element of the fundamental net salvage rate calculation.419 x Second, Mr. Watson unreasonably assumed that all steam production plants would be demolished at the end of their estimated remaining lives without any consideration of reuse of the unit after refurbishment, or mothballing the unit or selling the unit in the event of deregulation of the generating function of the utility.420

Staff Ex. 2 (Mathis Direct) at 17.

ETI Ex. 13 (Watson Direct) at Ex. DAW-1, at 64.

Staff Ex. 2 (Mathis Direct) at 16-17.

Id. at 17.

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x Third, Mr. Watson did not provide detailed plans for the actual demolition of each of its power plants. The Commission has consistently approved negative five percent net salvage rates for production plants if detailed plant-specific and reasonable demolition cost studies were not filed by the utility.421 ETI responds that Staff’s recommendation fails to account for the fact that the negative 5 percent benchmark is stale, having been established in a Commission proceeding 35 years ago. Since that time, “labor costs have escalated by 267 percent with the rational expectation that they will continue to increase at least with inflation.”422

Cities witness Pous recommended moving from the current negative five percent net salvage to a positive 5 percent net salvage; i.e., that it should be determined that the gross salvage from the power plants will exceed the removal cost. Mr. Pous stated that he bases this claim on the ETI’s actual experience over the past 45 years as well as current trends within the industry in the last years. According to Mr. Pous, ETI has retired many units since 1965 and demolished or sold the units and achieved a range of net salvage values from zero percent net salvage to positive 180 percent.423 Other utilities in Texas and elsewhere have also experienced positive net salvage levels.424 Mr. Pous testified that since 1998 over 1,000 generating units have been sold, and in all instances resulted in positive net salvage.425 He also claims that his positive five percent production net salvage is consistent with the Commission’s decision in the most recent SPS case, Docket No. 32766, where Mr. Watson was hired by SPS as a depreciation witness and the Commission ultimately approved a positive five percent net salvage.426 As ETI notes, however, the SPS rate case was the result of settlement427 and is of little precedential value.

Id. ETI Ex. 71 (Watson Rebuttal) at 17, 19.

Cities Ex. 5 (Pous Direct) at 15.

Cities Ex. 5C (Pous Depreciation Study) at 11; Cities Ex. 5 (Pous Direct) at 15-16.

Cities Ex. 5C (Pous Depreciation Study) at 11.

Cities Ex. 5 (Pous Direct) at 17.

See ETI Ex. 71 (Watson Rebuttal) at 6.

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ETI argues that Cities witness Pous appears to primarily base this claim on the fact that the sale of utility plants in circumstances bearing no relationship to depreciation analysis has yielded gains that Mr. Pous characterizes as “positive net salvage.” He uses as examples sales that form a part of the restructuring of the Texas utility business to introduce retail competition. Ms. Mathis also concluded, without elaboration, that ETI’s production plant net salvage analysis is flawed because it does not consider the possibility that the unit could be sold as a consequence of deregulation. Neither Ms. Mathis nor Mr. Pous, however, pointed to any instance in which the Commission has adopted such an approach to determining net salvage.

ETI contends that this argument should be rejected for a number of reasons. It argues that although there is no precedent supporting Ms. Mathis’ and Mr. Pous’ approach, there is clear recent precedent rejecting the inclusion of sales in depreciation analysis.428 The sales referenced by these witnesses are unique and unpredictable events, as should be evident from the use of the restructuring of the utility industry as an example of this type of activity. Indeed, at this time the Texas Legislature has halted for the foreseeable future any ETI move to competition. For purposes of depreciation analysis, net salvage is aimed at determining the salvage received at the end of the plants’ useful lives. Mr. Pous’ analysis necessarily assumed that, due to the sale, the life of the plants will be truncated. Yet he made no adjustment to production plant lives to account for the effect of theoretical sales.429

ETI also contends that Mr. Pous’ other examples of positive net salvage are equally unavailing. Mr. Pous points to ETI’s retirement of Neches Station as an example of positive salvage,430 but fails to mention that: (1) this outcome was uniquely the result of insurance proceeds received by ETI after a boiler explosion; and (2) the proceeds flowed back to customers via means other than depreciation rates.431 ETI contends that Mr. Pous’ claim that a contractor paid $1 million See Application of AEP Texas Central Co. for Authority to Change Rates, Docket No. 33309, FoF 107, 108, 112 (Mar. 4, 2008) (proceeds from sale of building properly removed from depreciation analysis as non-recurring item).

ETI Ex. 71 (Watson Rebuttal) at 5-7.

Cities Ex. 5 (Pous Direct) at 14.

ETI Ex. 46 (Considine Rebuttal) at 49-50.

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for the right to demolish a power plant, apparently based on unrecorded hearsay conversations, and without any information from Mr. Pous regarding the facts and circumstances surrounding the transaction, proves nothing.

Finally, Mr. Pous stated that Mr. Watson’s adjustment to the net salvage rates is flawed because it does not adequately reflect the increase in scrap metal prices in recent years. ETI responds that although scrap metal prices have gone up recently, it is unknown what the prices will be in the future, and these commodity prices have proven to be quite volatile and unpredictable.432 According to ETI, it is not reasonable to assume, as does Mr. Pous, that prices will stay indefinitely at what is their historically highest level. ETI argues that Mr. Pous’ method is based on speculation and broad, conclusory opinions regarding economic trends, as to which he makes no attempt to actually arrive at a quantifiable analysis that yields his unprecedented positive net salvage recommendation.433

Mr. Pous’ testimony that net salvage value should be revised to reflect a value of positive 5 percent is seriously flawed. First, pointing to a settled case as precedent carries no weight.

Second, attempting to draw conclusions from sales that were forced to comply with the regulatory framework and apply those conclusions to an entity that is not subject to the same regulatory framework is equally flawed. Finally, Mr. Pous attempted to use ETI’s own experience to support his position ignores the fact that ETI’s experiences were driven by factors that were unique to ETI at the time and circumstances involved; they do not support the more universal application urged by Mr. Pous.

Ms. Mathis’ analysis, in some respects, suffers from the same flaws as Mr. Pous’.

Nevertheless, some of her points carry more weight. The ALJs believe that Mr. Watson is correct that labor costs have increased since the negative five percent net salvage value was first established by the Commission. However, that is not the end of the story. Are there other factors that also have changed in the corresponding time period? There is no evidence on this point, and that is the crux of ETI Ex. 71 (Watson Rebuttal) at 17-18.

ETI Initial Brief at 103.

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the matter. As Ms. Mathis argues, there is only one way that all the changing values can be evaluated; through the introduction of plant-specific demolition cost studies. Had studies of that nature been provided, the parties would have been able to evaluate them and provide a supportable, fully-vetted recommendation. The ALJs recommend that the Commission find that a negative 5 percent net salvage value for production plant is appropriate.

(c) Depreciation Reserve TIEC argues that $1.1 million of ETI’s requested $13 million increase in depreciation expenses is related to ETI’s production plant assets.434 ETI has a $92,537,000 surplus in production plant assets. A surplus depreciation reserve occurs when the theoretical reserve (the reserve that would exist if the current proposed rates had been in place in the past) exceeds the per book depreciation reserve. According to TIEC, this indicates that ETI customers have overpaid the value of production plant assets.435 Since ETI has already over-recovered the value of the production plant assets, there is no valid reason to seek any additional recovery. TIEC contends that ETI has not shown why it needs to increase production depreciation rates at this time given that the production depreciation reserve has a considerable surplus. Therefore, it argues, $1.1 million of the proposed increase should be rejected.

ETI rejects TIEC’s recommendation because it is clearly contrary to Commission policy and precedent. According to ETI, the Commission has consistently adopted the remaining life, straight- line method for determining depreciation rates.436 This method requires that the remaining life of the asset be determined, and depreciation rates established to recover the asset’s remaining cost in equal installments over that life. In this way, by the end of the life, the costs will be recovered.

Mr. Pollock’s approach ignores these principles, and seeks to look back in time to compare how the ETI Ex. 13A (Watson Workpapers) at Appendix B. This figure is derived by subtracting the expenses from the existing production plant account from the proposed production plant account.

TIEC Ex. 1 (Pollock Direct) at 36-37, Ex. JP-5.

See Application of AEP Texas Central Co. for Authority to Change Rates, Docket No. 33309, PFD at 127-128 (Mar. 4, 2008); Application of CenterPoint Electric Delivery Company for Authority to Change Rates; Docket No. 39339, PFD at 86 (Dec. 3, 2010); Application of Oncor Electric Delivery Company, LLC, for Authority to Change Rates, Docket No. 35717, PFD at 153-154 (June 2, 2009).

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depreciation rates now proposed would have affected the recovery in the past. Those past depreciation rates, however, were authorized for use by the Commission. ETI argues that depreciation rates are at all times estimates, subject to adjustment using updated studies, and there is no reason for adoption of Mr. Pollock’s alternative. Finally, the Commission expressly rejected adjustment to the outcome of remaining life depreciation determinations based on differences between theoretical and book depreciation reserves in CenterPoint Docket No. 38339.437

The ALJs agree with TIEC that the Commission’s decision in Docket No. 38339 is not four-square on point with this case. That is not sufficient, however, to overcome the arguments advanced by ETI in favor of its position in the current case. The Commission has consistently used the remaining life, straight-line methodology for determining depreciation rates, and that methodology requires that the remaining life of the asset be determined, and depreciation rates established to recover the asset’s remaining cost in equal installments over that life. Mr. Pollock’s proposal ignores that consistently applied methodology. The ALJs recommend that the Commission approve ETI’s recommended treatment of the production plant depreciation reserve.

3. Transmission Plant (a) Lives Mr. Watson’s study presents ETI’s life proposal for transmission Accounts 350.2 to 359, a total of eight accounts.438 Neither Staff witness Mathis nor Cities witness Pous took issue with any of the recommended lives for transmission plant accounts.439 Accordingly, the ALJs recommend that the Commission adopt ETI’s proposed lives for these accounts.

ETI Ex. 71 (Watson Rebuttal) at 75-77 (citing CenterPoint Docket No. 38839 PFD).

ETI Ex. 13 (Watson Direct) at Ex. DAW-1 at 30-36.

Staff Ex. 2A (Mathis Direct) at 21; Cities Ex. 5 (Pous Direct) at 28.

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(b) Net Salvage Value Staff disagrees with Mr. Watson’s recommendations for two of the eight transmission accounts, and Mr. Pous disagrees regarding three of the accounts. The parties’ positions on transmission net salvage values in dispute are set out below:

Transmission Account Net Salvage Account Current ETI Staff Cities Net Salvage Proposal Proposal Proposal Value 352-Structures & Improvements -5% -10% -5% -10% 353-Station Equipment +5% -20% -20% 0% 354-Towers & Fixtures -5% -20% -5% -20% 355-Poles and Fixtures -25% -30% -30% -15% 356-Overhead Conductors & -20% -30% -30% -10% Devices (i) Account 352-Structures & Improvements Mr. Watson’s analysis of this account, and for all the accounts in his study, included the examination of trends and bands for numerous years. For Account 352, he found the five-year and ten-year moving averages for the years 2008-2010 particularly telling.440 A moving average is a rolling average that updates each year to include the additional year as part of the average for the longer period under study. Mr. Watson testified that his recommendation of negative 10 percent net salvage is consistent (albeit less negative) with the five-year and ten-year moving averages for 2008, which range from negative 16.31 percent to negative 16.80 percent. Although the moving averages for 2009 and 2010 appear more positive, this was the result of a large, atypical gross salvage in 2009.441 Cities propose no change to Mr. Watson’s recommendation.

Staff witness Mathis recommended a net salvage rate of negative five percent for Account 352. This recommendation is based on analysis of historical salvage data for the period of ETI Ex. 71 (Watson Rebuttal) at 56.

ETI Ex. 13 (Watson Direct) at Ex. DAW-1 at 65. The atypical gross salvage resulted from the sale of a spare transformer, an asset whose cost is booked to an entirely different account. ETI Ex. 71 (Watson Rebuttal) at 57. The atypical amount is shown at Appendix E-2 at 1 of Mr. Watson’s depreciation study.

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1984 through 2010. Specifically, the three-year moving average for the same period produces a net salvage rate of negative 5.53 percent, which is very close to the currently approved net salvage rate for this account. Moreover, an examination of the mean and median rolling band averages for Account 352 shows a range of net salvage rates between positive 0.08 percent and negative 6.83 percent.442 Thus, according to Ms. Mathis, the net salvage rate of negative 5 percent is a reasonable estimate based on the available historical data.

In response to Mr. Watson’s contention that the 2008 moving average is the most important, Ms. Mathis pointed out that the 2009 five-year and ten-year moving averages feature positive 16.66 percent and positive 4.45 percent net salvage rates, respectively. Moreover, the 2010 five-year and ten-year moving averages feature positive 25.13 percent and positive 6.75 percent net salvage rates, respectively.443 Ms. Mathis stated that if it is a sound depreciation methodology to select a net salvage rate based on recent five-year and ten-year moving averages, then the rate for this account should be significantly greater than either Ms. Mathis’ or Mr. Watson’s recommendation.444

Although the moving averages cited by Ms. Mathis for 2009 and 2010 appear to belie the arguments raised by Ms. Watson, the ALJs are persuaded that those are significantly influenced by the atypical gross salvage resulting from the 2009 sale of a spare transformer, an asset whose cost is booked to an entirely different account. If, as claimed by Mr. Watson, the sale was sufficiently atypical, it would influence both 2009 and 2010 moving averages, making them unreliable.

Accordingly, the ALJs recommend that the Commission adopt ETI’s negative 10 percent net salvage value for Account 352.

Staff Ex. 2 (Mathis Direct) at 22, Appendix C at 1.

Id. According to Ms. Mathis, if 2009’s moving averages are adopted, the net salvage ratio should be around positive 4.45 percent or positive 16.66 percent. If 2010’s moving averages are adopted, the net salvage ratio should be around positive 6.75 percent or positive 25.13 percent.

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(ii) Account 353-Station Equipment Similar to Account 352, a large atypical positive salvage amount in this account makes the most recent moving average appear more positive than the history would otherwise suggest.445 Mr. Watson recommended setting net salvage at negative 20 percent, which he contended is a reasonable middle ground between the values suggested by the five-year and ten-year moving averages for transaction year 2010 (which show net salvage of negative 14.42 percent and negative 20 percent, respectively).446 Ms. Mathis agreed with the Company’s proposal on this account.

Although Mr. Pous acknowledged that retention of the current Commission-approved positive five percent net salvage is supported by ETI’s experience, he ultimately opted for a recommendation that the net salvage value be reduced to zero percent. Mr. Pous noted that the actual per book data for a five-year band and a ten-year band are a positive 117.04 percent and a positive 31.95 percent, respectively.447 Mr. Pous stated that his analysis does not ignore the positive net salvage recorded by ETI because of the sale of transmission investment, rather he testified that:

the Company has reported five separate sales during the past 22 years, or about once every four years. Such activity cannot be considered an ‘unusual circumstance’ or an outlier, and should be taken into consideration as an event that may continue to occur in the future. In a proper evaluation phase of a depreciation study, recognition of some level of future sales is appropriate.448 Mr. Pous’ analysis also reflected that transformers, which contain large quantities of copper and produce gross salvage when retired, comprise a significant level of investment in this account, but were underreported in the five-year and ten-year band analyses.449 Mr. Pous stated that, given the significant increase in the value of copper, the future proportionate retirement of transformers will result in future net salvage values being less negative or more positive than the historical data.

The atypical amount is shown at Appendix E-2, p. 1 of 10 of Mr. Watson’s depreciation study.

ETI Ex. 13 (Watson Direct) at Ex. DAW-1 at 65.

Cities Ex. 5C (Pous Depreciation Study) at 21, 23.

Id. SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 136 PUC DOCKET NO. 39896

ETI responds that Cities’ criticism that the per book data in Mr. Watson’s workpapers show a large positive net salvage value for the five-year and ten-year bands is unfounded. According to ETI, Mr. Watson’s workpapers clearly indicate that adjustments were required and made to the per book data for unique transactions involving sales and storm activity. As to sales, the workpapers450 show that in the 26 years of data for Account 353, there were three occasions with very large sales proceeds for the sale of substations. As to storm activities, the same workpapers show only one occasion in 26 years where gross salvage amounts were recorded. ETI contends that these unique events are properly excluded from net salvage analysis and Mr. Pous’ reliance on the per book data to establish positive net salvage is erroneous. With respect to Mr. Pous’ concern’s relating to the price of copper, ETI responds that Mr. Pous’ reliance on copper’s scrap value is pure speculation, unsupported by any ETI-specific data regarding the amount of copper at issue, or any consideration of the offsetting significant and increasing labor costs involved in the removal of large station transformers.

As explained by Mr. Watson, it appears to the ALJs that the adjustments made were, indeed, required because of the unique nature of the events they reflected. The ALJs also find that Mr. Pous’ concerns relating to the price of copper are speculative. Coupled with the fact that Staff supports ETI’s proposed net salvage value, the ALJs recommend that the Commission approve ETI’s recommended negative 20 percent net salvage value.

(iii) Account 354-Towers and Fixtures Although there is limited experience available for this account, the five-year and ten-year moving averages for transaction year 2010 show a substantial level of negative net salvage (negative 299 percent and negative 233 percent, respectively). Taking into account the low level of

Id. at 22.

ETI Ex. 13A (Watson Direct) Workpaper on CD, “Entergy Net Salvage Transmission Distribution General” Spreadsheet, “Data Adjustments” Tab, Account 353.

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retirement experience, Mr. Watson stated that he moderated the outcome by recommending moving to negative 20 percent net salvage.451 Mr. Pous concurred in this recommendation.

Ms. Mathis recommended a net salvage rate of negative 5 percent for Account 354.452 This recommendation is based on Commission precedent due to the absence of reliable historical salvage data.453 Although historical salvage data is available for the period of 1984 through 2010, this account had a low level of retirement during this period.454 Because of the limited retirement activity, Ms. Mathis stated that a reasonable net salvage rate cannot be calculated from the historical salvage data.455 For example, annual net salvage rates range from approximately negative 6,000 percent to approximately positive 31,253,400 percent.456 According to Ms. Mathis, such divergent numbers are indicative of the low retirement activity within this account.

The negative five percent net salvage value recommended by Ms. Mathis is the current Commission-approved number. The ALJs find it difficult to draw any conclusions from the paucity of historical data. Had there been additional historical data, it might have been possible to reach the conclusion urged by Mr. Watson; however, there was not. The ALJs recommend that the Commission adopt the negative five percent net salvage value recommended by Staff.

(iv) Account 355-Poles and Fixtures The Commission approved net salvage value for this account is a negative 25 percent.457 This account has shown negative salvage since the 1990s, and the most recent ten-year moving averages show negative 33.84 percent net salvage. Although years 2009-2010 reflect positive salvage values, Mr. Watson determined that these values were the product of differences in the ETI Ex. 13 (Watson Direct) at Ex. DAW-1 at 66.

Staff Ex. 2 (Mathis Direct) at 23.

Id. at 23.

ETI Ex. 13 (Watson Direct) at DAW-1 at 66.

Staff Ex. 2 (Mathis Direct) at 23.

Id. at Appendix C at 2.

Cities Ex. 5C (Pous Depreciation Study) at 23.

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timing of the recording of the various transactions associated with the asset retirement, rather than reflecting an actual positive salvage amount.458 For example, Mr. Watson’s net salvage workpapers show a significant level of positive salvage only for the years 2009-2010 in Account 355.459 This is at odds with the remainder of the net salvage data shown in the workpapers, which is almost exclusively negative net salvage.460 Accordingly, Mr. Watson gave less weight to the 2009 and 2010 values, but moderated his recommendation compared to the ten-year moving averages, resulting in a recommended net salvage of negative 30 percent. Ms. Mathis concurred.

Cities witness Pous disagreed with Mr. Watson’s analysis, claiming: (1) per book data from the five-year and ten-year moving averages show positive net salvage amounts; (2) authoritative depreciation treatises do not support Mr. Watson’s decision to adjust relocation-related transactions out of the analysis;461 (3) no portion of relocation-related costs can be treated as removal unless that treatment is prescribed by contract with the third-party; and (4) after the correction to his analysis, Mr. Watson changed his methodology to arrive at a negative net salvage recommendation. Mr. Pous recommended an increase in the net salvage values to a negative 15 percent based on the actual historical data of ETI. Cities contend that Mr. Pous was conservative in his recommendation given the trend in the data. The most recent five-year band of actual data yields a positive two percent net salvage.462

The ALJs agree that the debate regarding this account essentially boils down to whether Mr. Watson’s adjustment to remove relocation expense associated with third-party reimbursement from the analysis is appropriate. Although Mr. Pous claims that Mr. Watson’s approach is contrary ETI Ex. 13 (Watson Direct) at Ex. DAW-1, p. 66.

ETI Ex. 13A (Watson Workpapers CD), Adjusted Data Net Salvage Tab, account 355, lines 130-131, columns I – S.

ETI Ex. 13A (Watson Workpapers CD), Adjusted Data Net Salvage Tab, account 355, at lines 105 – 129, columns I – AC. The 2005-2006 data in this workpaper show an obvious example of an accounting adjustment timing difference, wherein the year 2005 shows a $1,867,532 removal cost (row 126, column G), while the immediately following year 2006 shows a large negative removal adjustment of ($1,059,096), (row 127, column G).

Relocations involve the situation where the Company is reimbursed by a third party who desires the relocation or replacement of the facilities in question.

Cities Ex. 5C (Pous Depreciation Study) at 22-25.

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to authoritative guidance, ETI contends that he arrives at that conclusion only by disregarding the guidance in question, as well as Commission precedent. ETI argues that the depreciation text in question squarely supports Mr. Watson’s approach:

A reimbursed retirement is one for which the company is fully compensated at the time of retirement …. Usually reimbursed retirements should not be included in analysis of property whose investment is recovered through depreciation accruals.463 Mr. Watson explained at hearing that, in his experience, adjustments to remove relocation expense are standard in depreciation analysis, and to do otherwise would result in a disproportionate impact on reasonably expected ongoing net salvage, caused by a transaction (the relocation) that constitutes a very small portion of the overall assets in question.464

Mr. Pous stated that all third-party reimbursements for facility relocation performed by the Company have to be deemed as salvage (thereby inflating the salvage portion of the net between removal costs and salvage proceeds) unless a contract between ETI and a third-party explicitly says otherwise. Mr. Watson’s approach, however, is squarely supported the Commission’s decision in the recent Oncor case, Docket No. 35717, where it was held that these third-party “reimbursements are prepayments for new property being installed.”465 The ALJs find that Mr. Pous’ argument is not credible in light of Mr. Watson’s treatment of relocations in general. Since Mr. Watson properly removed such relocation expense from the depreciation analysis altogether, those amounts correctly have no impact on depreciation rates, regardless of how they are allocated between gross salvage proceeds and the cost of installing new facilities.

ETI’s evidence and argument support its request. Accordingly, the ALJs recommend that the Commission approve a net salvage of negative 30 percent as proposed by Mr. Watson.

ETI Ex. 71 (Watson Rebuttal) at 63 (quoting Depreciation Systems, Iowa State Press, 1994, at 16-17).

Tr. at 405.

ETI Ex. 71 (Watson Rebuttal) at 63.

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(v) 356-Overhead Conductors and Devices The Commission approved net salvage value for this account is a negative 20 percent.466 Much as was the case with Account 355, ETI argues that timing differences in reflecting accounting adjustments made the more recent shorter data bands less representative of reasonably expected future net salvage. Mr. Watson’s study determined that the longer ten-year moving average for transaction year 2010 showed salvage of negative 33 percent, so Mr. Watson recommended moving to negative 30 percent net salvage for this account.467 Staff witness Mathis adopted the same negative net salvage value.

Cities’ witness Pous recommended an increase to the net salvage value to a negative 10 percent based on a review of the actual historical data. The actual five-year and ten-year bands yield a positive one percent and a negative 31 percent. Mr. Pous argues that the trend in the data could justify even a less negative value.

As with Account 355, the ALJs find that ETI’s evidence and arguments support its request.

Accordingly, the ALJs recommend that the Commission approve a net salvage of negative 30 percent as proposed by Mr. Watson.

4. Distribution Plant (a) Lives An asset’s useful life is used to determine the remaining life over which the cost will be spread for recovery through depreciation expense.468 The Company’s depreciation study addresses distribution accounts included between Accounts 360.2 and 373.2. According to ETI, the life parameters in Mr. Watson’s study reflect standard depreciation analysis procedures, including comparison to standard Iowa curves and actuarial analysis, along with the exercise of informed

Cities Ex. 5C (Pous Depreciation Study) at 25.

ETI Ex. 13 (Watson Direct) at Ex. DAW-1 at 66-67.

Id. at 16.

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judgment.469 Multiple bands and trends were reviewed and, in general, Mr. Watson’s study explained that the dispersion curve chosen for each account is based on examination of the various “placement and experience bands”470 and the characteristics of the underlying asset in each account.

The dispersion curve is then chosen that best matches the actual data.471 Staff disagrees with Mr. Watson’s life parameters for three accounts; Cities with five accounts. The parties’ various recommendations on the accounts in dispute are shown below:

Depreciation Plant Lives Account Approved Life ETI Proposal Staff Proposal Cities Proposal 361 45 yrs. S2 65 yrs. R3 70 yrs. R3 65 yrs. R3 364 44 yrs. S1 38 yrs. R1.5 40 yrs. R1 44 yrs. L1 365 44 yrs. S1 39 yrs. R0.5 40 yrs. R0.5 42 yrs. S-0.5 367 40 yrs. S1 35 yrs. R1.5 35 yrs. R1.5 45 yrs. S-0.5 368 39 yrs. S0 29 yrs. L1 29 yrs. L1 33 yrs. L0.5 369.1 36 yrs. S4 26 yrs. L4 26 yrs. L4 33 yrs. R4 (i) Account 361 – Structures and Improvements Mr. Watson’s study depicts the fit between the actual data in the account and the 65 R3 life parameter that he proposed for this account.472 Mr. Pous agreed with this recommendation.

Ms. Mathis stated, however, that a life parameter of 70 R3 is a better visual fit for the 1960-2010 experience band.473 Considering all the historical mortality data available for this account (the overall experience band), the selected Iowa Curve produces a conformance index (CI) of 37.53.474 The CI is a measure

Id. at Ex. DAW-1 at 37-54.

Placement bands look at assets installed in various years and reveal the types of assets in the account over time. Experience bands show accounting transactions associated with the assets over time and reveal trends associated with operational changes and other events.

ETI Ex. 13 (Watson Direct) at Ex. DAW-1 at 37-54.

Id. at Ex. DAW-1 at 37.

Staff Ex. 2 (Mathis Direct) at 25-26.

Id. at 26, Table-5.

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of closeness of fit, and a higher CI value indicates a closer fit between the two sets of data that are being compared.475 Mr. Watson recommended a life parameter of 65 years based on comparing various slices (bands) of this account’s mortality data to the 65 R3 Iowa Curve.476 However, Staff argues that Mr. Watson’s recommended life parameter and Iowa Curve of 65-R3 produces a CI of only 23.61 when measured against the overall (1960 – 2010) experience band.477 ETI responds that the flaw in Ms. Mathis’ position is that she only looks at one band. As the average age of the investment is only 19.22 years, it is inadequate to look at only one band that examines a 50-year period. When shorter bands are also factored in (1970-2010 and 1990-2010), the Company’s proposal shows a significantly higher CI, which is indicative of a better fit to the actual data.478 The ALJs are persuaded that, in this instance, Ms. Mathis erred by limiting her review to a single band, especially when that band is significantly longer than the average age of the investment at issue. In this case, looking at multiple, shorter bands will give a clearer picture of the average life of the investment at issue. Therefore, the ALJs recommend the Commission approve the 65 R3 life parameter Mr. Watson proposes for this account.

(ii) Account 364 – Poles, Towers, and Fixtures Mr. Watson’s study results in his proposing a life parameter of 38 R1.5.479 He stated that the current plant in service reflects a life (13.97 years on average) that is substantially shorter than his recommendation, and all the bands examined reflect a shorter life than the currently approved years. Mr. Watson testified that his recommendation balances these facts with the additional fact

ETI Ex. 71 (Watson Rebuttal) at 24.

ETI Ex. 13 (Watson Direct) at 18, Figure 1.

Staff Ex. 2 (Mathis Direct) at 26, Table-5.

ETI Ex. 71 (Watson Rebuttal) at 24.

ETI Ex. 13 (Watson Direct) at Ex. DAW-1 at 41.

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that ETI is currently using Penta and CCA-treated poles (as opposed to creosote treated poles), for which a longer life is expected.

Ms. Mathis (40 R1) and Mr. Pous (44 L1) both proposed different life parameters than Mr. Watson. Ms. Mathis stated that her proposed life parameter is a better visual and mathematical fit for the single experience band (1959-2010) she considered.480 Mr. Watson responded to this argument, stating that the mathematical computer fitting emphasized by Ms. Mathis is too limited an approach, because there is too little information provided at the tail of the curve to rely on computer fitting in this instance. Mr. Watson indicated that his proposed life parameter shows a better fit over the full range of placement and experience bands applicable to this account.481

Mr. Pous recommended that the expected service life remain at 44 years based on actuarial analysis and advances made by the industry and ETI in treating and preserving poles.482 Mr. Pous also noted that “absent identifiable and supportable specific problems, the industry is not experiencing shorter lives for poles and neither should ETI.”483 He stated that selection of different types of poles and different treatments by other utilities have their engineers expecting lives between and 70 years.484 According to Mr. Pous, it is simply not realistic to believe or assume that ETI would operate now or in the future in a manner that its poles would only last two-thirds the life expectance being achieved by others.485 Mr. Watson responded that the increased life span urged by Mr. Pous based on his general discussion of varieties of poles with longer lives is not verifiable, not consistent with the Company-specific data or the specific experience of its distribution personnel, and is plainly exaggerated.486

Staff Ex. 2 (Mathis Direct) at 28-29.

ETI Ex. 71 (Watson Rebuttal) at 29-31.

Cities Ex. 5C (Pous Depreciation Study) at 35-36.

Id. at 37.

Id. Id. at 36.

ETI Ex. 71 (Watson Rebuttal) at 28-29.

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The ALJs reviewed the evidence and arguments of the parties with respect to this issue and were most persuaded by the CIs that resulted from the recommendations of Staff and ETI.

Considering all the historical mortality data available for this account (the overall experience band), Staff’s selected Iowa Curve produces a CI of 41.44, while ETI’s produces a CI of only 20.66 when measured against the overall (1958 – 2010) experience band.487 The ALJs recommend that the Commission adopt Staff’s proposal of 40 R1.

(iii) Account 365 – Overhead Conductors and Devices The Commission approved average service life is 44 years.488 All parties propose a change to this life parameter. Mr. Watson proposed a life parameter of 39 R0.5, Ms. Mathis proposes a life parameter of 40 R0.5, and Mr. Pous proposed a life parameter of 42 S.-5.

Mr. Watson noted that his analysis took into account the fact that the currently authorized life is longer than the history would support, and that the young average age of the current plant in service (12.15) points toward placing more weight on recent bands for life selection. He also noted that ETI’s movement toward re-conductoring lines supports the conclusion that lives in this account will be shorter.

Ms. Mathis indicated that her recommendation is based on comparing the account’s historical mortality data for the period of 1958 through 2010 to the 40 R0.5 Iowa Curve.489 Considering all the historical mortality data available for this account (the overall experience band), the selected Iowa Curve produces a CI of 29.63.490 Mr. Watson countered that Ms. Mathis used the wrong curve to represent the Company’s proposal in her calculations. He stated that when her analysis is corrected

Staff Ex. 2 (Mathis Direct) at 29, Table-6.

Cities Ex. 5C (Pous Depreciation Study) at 38.

Staff Ex. 2 (Mathis Direct) at 30.

Id. at 31, Table-7.

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to make the proper comparison, ETI’s proposal has a higher CI (and thus a better fit) across all experience bands save one.491

Mr. Pous testified that his life parameter best matches the actuarial analysis taking into account the unusually high level of retirement activity recorded in the first 0.5 year of age. As Mr. Pous noted, “the highest retirement ratio for this investment in the first 23 years occurred at age 0.5 years, for brand new assets. While such events can and have occurred associated with utility plant, it is not the type of event that is reasonably expected to repeat itself in future periods as different equipment it purchases if it was an equipment problem, or different installation processes are employed if the early retirement were due to installation issues.”492 Mr. Pous criticized Mr. Watson’s recommendation on several grounds: (1) it is not consistent with expected lives reported by ETI personnel; (2) it did not account for anomalies and/or unusual activity in the retirement data; (3) the major re-conductoring activity shown in the account should not be expected to continue; and (4) the life-curve combination chosen by Mr. Watson is not long enough to match the actual data.493

Mr. Watson took issue with Mr. Pous. He stated that Mr. Pous simply misread the data Mr. Watson argued that Exhibit DAW-R-1 to his rebuttal testimony shows that retirements are decreasing.494 Mr. Watson believes that his proposed life parameter is a better fit to the actual data.

The very small amount of plant that may not last until the tail of the curve used by Mr. Watson does not alter this conclusion.495 Finally, ETI argues that Mr. Pous provides no persuasive basis for second guessing the opinion of Company personnel regarding re-conductoring.

The ALJs are persuaded by ETI’s evidence and argument. It does appear that Ms. Mathis used the wrong curve in her calculations. If corrected, Mr. Watson’s proposal renders the higher CI.

ETI Ex. 71 (Watson Rebuttal) at 36.

Cities Ex. 5C (Pous Depreciation Study) at 38-39.

Id. at 38-41.

ETI Ex.71 (Watson Rebuttal) at 32-33.

Id. at 32, 33-35.

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Mr. Pous’ arguments fair no better. To the ALJs’ eye, Mr. Pous did misread the data, and the conclusions drawn by Mr. Pous are simply inaccurate. The ALJs recommend that the Commission adopt ETI’s proposed life parameter of 39 R0.5.

(iv) Account 367 – Underground Conductors and Devices The Commission approved average service life is 40 years.496 Mr. Watson’s life parameter for this account (35 R1.5) is based on his review of the various placement and experience bands, as well as the characteristics and longevity of the conductors in place in the ETI system and the retirement patterns that are unique to underground conductor performance and the locations where it is buried.497 Ms. Mathis agreed with Mr. Watson on this account. Cities propose a significantly longer life (45 S-0.5). Mr. Pous stated that Mr. Watson’s and Ms. Mathis’ recommendations do not account for the increased durability of newer types of conductor, and that the actuarial analysis should focus on more recent data that he believes is more consistent with the newer conductors.498

Mr. Watson testified that Mr. Pous’ recommendation should be rejected for a variety of reasons. The Southern California Edison-based opinions regarding longer life for the conductor, relied on by Mr. Pous, relate to plant installed less than ten years ago. Therefore, based on his own theory, much of the investment in question in this account is still the older, shorter-lived variety, and his recommendations are premature. Moreover, Mr. Watson’s plotting of the dispersion curves show that his is a better fit than that of Mr. Pous. In this instance, Mr. Pous’ analysis, relying only on the shortest band, failed to pick up the older investment that constitutes almost 80 percent of the surviving investment.499

It appears that Mr. Pous, in relying on the shortest band, did fail to take into account investment that comprises almost 80 percent of the surviving investment in this account. That is a significant flaw in his analysis. Similarly, his reliance on the Southern California Edison-based Cities Ex. 5C (Pous Depreciation Study) at 41.

ETI Ex. 13 (Watson Direct) at Ex. DAW-1, p. 45.

Cities Ex. 5C (Pous Depreciation Study) at 41-44.

ETI Ex. 71 (Watson Rebuttal) at 40.

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opinions relate to newer plant, which again calls his analysis into question in the present circumstances. The ALJs recommend that the Commission approve ETI’s recommended service life of 35 R1.5.

(v) Account 368 – Line Transformers The Commission approved anticipated service life is 39 years.500 Mr. Watson proposed a service life of 29 L1,501 with which Ms. Mathis agreed. Mr. Watson stated that this is consistent with the data showing decreasing lives for these assets, the expected lives per Company personnel, and the fact that transformers are junked or sold rather than repaired.502

Mr. Pous recommended that the expected service life be decreased to 33 years, representing a percent reduction in the anticipated service life. Mr. Pous stated that his analysis is based on actuarial analyses and the Company’s addition of approximately $80 million of pad mounted transformers since the last case, when the Commission approved a 39-year anticipated average service life. According to Mr. Pous, ETI personnel have stated that pole mounted transformers have a life of between 25 and 35 years. However, pad mounted transformers are expected to last up to years by the same Company personnel. Given the sizable investment since the last case in the pad mounted transformers with a longer expected service life, a decrease in the anticipated service life of greater than 15 percent is not warranted, according to Mr. Pous. Moreover, Mr. Pous stated his analysis uncovered abnormally high retirement ratios in the 21.5 to 22.5 year age brackets indicative of one-time events such as the ice storm or changes in accounting systems. As such, Mr. Pous performed his curve fitting analysis recognizing the unusually high retirement activity between years 21.5 and 22.5 rather than emphasizing such unusual activity as Mr. Watson did for his proposal to reduce service life by 26 percent.503

Cities Ex. 5C (Pous Depreciation Study) at 44.

ETI Ex. 13 (Watson Direct) at Ex DAW-1 at 50.

Id. at 47.

Cities Ex. 5C (Pous Depreciation Study) at 45.

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Mr. Watson recommended a decline in average service life from a 39-year anticipated service life to a 29-year anticipated service life citing the high occurrence of lightning in the ETI service area.504 However, Mr. Pous noted that the effects of lightning in ETI’s service area would have been present in ETI’s last base rate case when a 39-year anticipated service life was approved by the Commission. Both Mr. Watson and Mr. Pous recognized that the pad mounted transformers are not subject to the same forces of retirement like weather, lightning, and animal disturbances.505 However, Mr. Watson did not realistically factor ETI’s relative increased investment in pad mounted transformers into his analysis. Moreover, when performing his curve fitting analysis, Mr. Watson neither analyzed nor adjusted for the abnormal unusual retirement ratios between years 21.5 and 22.5.506 Instead, Mr. Watson attempted to select a life analysis that anticipates a high level of retirement within that time period in the future.507 Cities argue that, by failing to recognize the sizable new investment in pad mounted transformers and failing to consider the unusual retirement ratios, Mr. Watson proposed an average service life that is lower than the bottom end of the range of life estimates of Company personnel for pad mounted transformers. Moreover, Mr. Watson’s proposal does not even reach the midpoint of life estimates expected by Company personnel for pole mounted transformers.

The arguments and evidence advanced by Cities witness Pous are persuasive to the ALJs.

Mr. Watson’s contention regarding the occurrences of lightening in the ETI service area was equally applicable at the time the existing approved rate was set, and is, therefore, of little value in this proceeding. Further, Mr. Watson’s failure to analyze the abnormal retirement ratios between years 21.5 and 22.5 also argues against his analysis. The ALJs recommend that the Commission adopt Mr. Pous’ proposed life of 33 L0.5.

ETI Ex. 13 (Watson Direct) at Ex DAW-1 at 50.

Id. Cities Ex. 5C (Pous Depreciation Study) at 47.

ETI Ex. 13 (Watson Direct) at Ex DAW-1 at 50-51.

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(vi) Account 369.1 – Overhead Services The Commission previously approved anticipated service life for this account is 36 years.508 Mr. Watson’s analysis of this account shows that overhead assets have retired earlier and have been replaced more frequently than is consistent with the existing 36 S4 life. The average age of current investment is 10.12 years. Consistent with this data and his review of various curves and placement and experience bands, he recommended shortening the life to 26 L4. Ms. Mathis agrees with this proposal.509

Mr. Pous recommended that the expected service life be shortened to 33 years based on the lack of Company historical data and based on comparative utility experience including recent studies by Mr. Watson, where he proposed significantly longer average service lives. Mr. Pous testified that an evaluation of the actual data casts serious doubt about the reliability of the data for depreciation purposes. ETI does not have any records of services in this subaccount surviving past 1978.

Mr. Pous stated that his recommended 33-year life expectancy for this sub-account is still far shorter than industry expectations, but is consistent with the depreciation study recently conducted for EGSL where the depreciation expert hired by EGSL recommended a 33-year life.510

ETI argues that Mr. Pous apparently made no attempt to perform any curve fitting regarding this account, as none appears in his study; in the absence of performing this essential analysis, he settles for again casting doubt on the reliability of Company accounting data. ETI contends that, in reality, Mr. Pous appears to present no recommendation for this account based on evaluation of any of the accounting data that actually depicts the past and current characteristics of the assets.511

Cities Ex. 5C (Pous Depreciation Study) at 48.

ETI Ex. 13 (Watson Direct) at Ex. DAW-1 at 49.

Cities Ex. 5C (Pous Depreciation Study) at 48-49.

Id. at 48-50.

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ETI argues that its recommended life is clearly supported by the Company-specific data, graphically depicted in Mr. Watson’s rebuttal testimony, while Mr. Pous’ suggested life parameter is not even close, and is based on unsupported speculation.512

Although the evidence on this issue is sparse, the ALJs ultimately are persuaded that ETI’s (and Staff’s) position is more reasonable. Accordingly, the ALJs recommend the Commission adopt ETI’s proposed 26 L4 life span.

(b) Net Salvage Value Staff disagrees with Mr. Watson’s recommendations for five of the distribution accounts, and Mr. Pous disagrees regarding two of the accounts. The parties’ positions on distribution net salvage values in dispute are set out immediately below:

Distribution Plant Net Salvage Account Approved Rate ETI Proposal Staff Proposal Cities Proposal 361 -5% -10% -5% -10% 362 +15% -20% -10% 0% 365 +10% -7% -7% 0% 368 0% 0% -5% 0% 369.1 -10% -5% -10% -5% 369.2 -10% -5% -10% -5% (i) Account 361 – Structures and Improvements The existing net salvage value for this account is negative five percent, which is the value proposed by Staff. Mr. Watson and Mr. Pous, on the other hand, proposed a salvage value of negative 10 percent.

Mr. Watson’s recommendation is based on the most recent five-year and ten-year net salvage ratios, which are negative 9.70 percent and negative 36.70 percent, respectively. Ms. Mathis’ recommendation is based on analysis of historical salvage data for the period of 1984 through 2010.

Specifically, the two-year moving average median for the same period produces a net salvage rate of ETI Ex. 71 (Watson Rebuttal) at 46-48.

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negative 5.87 percent, which is very close to the currently approved net salvage rate for this account.513 Moreover, the one-year, three-year, four-year, five-year, six-year, and seven-year moving average medians of negative 6.95 percent, negative 5.11 percent, negative 3.64 percent, negative 1.90 percent, negative 4.57 percent, and negative 7.24 percent, respectively, support this recommendation. Additionally, this account contains a few significant outliers, such as negative 655.91 percent in 2002 and negative 322.55 percent in 2005.514 Ms. Mathis’ use of the median average eliminates the skewing effect of these outlying values.

As discussed in Section VII.C.1, the use of the median is the most appropriate methodology.

For this reason, the ALJs recommend the Commission approve Staff’s proposed negative 5 percent net salvage value.

(ii) Account 362 – Station Equipment The existing net salvage value of this account is positive 15 percent. Mr. Watson proposed that it be changed to negative 20 percent, Staff proposes it be changed to negative 10 percent, and Cities propose it be changed to zero.

Mr. Watson’s study shows that the most recent five-year and ten-year net salvage ratios are negative 22.10 percent and negative 43.55 percent, respectively. He recommended negative percent net salvage based on the Company’s experience.515

Ms. Mathis’ recommendation is based on analysis of historical salvage data for the period of 1984 through 2010. Specifically, the recommendation is supported by the two-year moving average median for the same period of negative 12.23 percent.516 Moreover, the one-year, three-year, five-year, six-year, seven-year, and eight-year moving average medians of negative 11.07 percent,

Staff Ex. 2 (Mathis Direct) at 27.

Id. at Appendix C at 4.

ETI Ex. 13 (Watson Direct) at Ex. DAW-1 at 68.

Staff Ex. 2 (Mathis Direct) at 27.

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negative 14.16 percent, negative 7.62 percent, negative 8.19 percent, negative 11.75 percent, and negative 14.15 percent, respectively, support her recommendation.517

Mr. Pous’ recommendation is based on what he characterizes as the Company’s actual, unadjusted, experience; recognition of the type of investment in the account; recognition of significant value of scrap copper; investigation of retirement mix compared to investment mix over the past ten years; and recognition of industry values.518 According to Mr. Pous, given the significant increase in the value of copper, the retirement of a transformer could be expected to significantly influence the net salvage value for this account.

Mr. Pous’ recommendation is the outlier among the three before the ALJs, and the ALJs are not convinced that the reasons put forth by Mr. Pous in support of his position are sufficient to carry the day. The real argument here is between ETI and Staff, which centers on the use of the median (Staff) and the mean (ETI). As discussed in Section VII.C.1, the use of the median is the most appropriate methodology. For this reason, the ALJs recommend the Commission approve Staff’s proposed negative 10 percent net salvage value.

(iii) Account 365 – Overhead Conductors and Devices The current net salvage value for this account is positive 10 percent.519 ETI and Staff recommend changing it to negative seven percent, and Cities recommend changing it to zero.

Mr. Pous recommended a reduction in the current net salvage values to zero based on review of the actual historical data and the relative mix of the investment recorded in this account.

Mr. Pous noted that $40 million of investment recorded in this account is associated with clearing rights of way, which will not likely be retired or incur cost of removal or gross salvage. Another $40

Id. at Appendix C at 4-5.

Cities Ex. 5C (Pous Depreciation Study) at 26.

Id. at 28.

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million is associated with investment in copper conductors, which has escalated in demand in recent years and should result in positive net salvage.520

Mr. Watson corrected his analysis and recognized that timing differences between the recording of accounting adjustments related to net salvage (i.e., salvage and removal costs for a particular transaction were not recorded at the same time) made one of the recent years less representative of reasonably expected ongoing net salvage levels. He focused, therefore, on longer period averages and recommends negative seven percent net salvage consistent with the most recent ten-year ratios.521 Mr. Watson explained that his adjustments removed relocation activity altogether from this account because it is not characteristic of the vast majority of retirements and because, if the adjustment is not made, it will shorten and skew the life analysis. Further, Mr. Watson stated that Mr. Pous’ claims regarding the impact of copper prices ignore those prices’ future volatility and are not supported by any analysis or quantification specific to these accounts. Mr. Watson indicated that his recommendations are based on the most clear and reliable source – Company-specific accounting data – not “selective comparisons of industry norms,” as alleged by Mr. Pous.522

The ALJs find Mr. Watson’s explanations of the rationale behind his analysis to be both credible and convincing. Accordingly, the ALJs recommend the Commission adopt ETI’s requested negative 7 percent net salvage value.

(iv) Account 368 – Line Transformers The existing net salvage value for this account is zero, which both Mr. Watson and Mr. Pous recommended be retained. Ms. Mathis, on the other hand, argued that the net salvage value should be changed to negative five percent.

The argument here is whether the median or the mean best represents the appropriate net salvage value. ETI argues for the mean, and Staff argues for the median. As discussed in Id. at 28-29.

ETI Ex. 13 (Watson Direct) at Ex. DAW-1 at 69.

ETI Ex. 71 (Watson Rebuttal) at 68-69.

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Section VII.C.1, the use of the median is the most appropriate methodology. For this reason, the ALJs recommend the Commission approve Staff’s proposed negative five percent net salvage value.

(v) Account 369.1 – Overhead Services The existing net salvage value for this account is negative 10 percent, which Staff recommends be retained. Mr. Watson and Mr. Pous argue in favor of a change to negative 5 percent net salvage value.

The argument here is whether the median or the mean best represents the appropriate net salvage value. ETI argues for the mean, and Staff argues for the median. As discussed in Section VII.C.1, the use of the median is the most appropriate methodology. For this reason, the ALJs recommend the Commission approve Staff’s proposed negative 10 percent net salvage value.

(vi) Account 369.2 – Underground Services ETI began specifically charging salvage and removal cost to this account just in the last two years, producing a five-year net salvage ratio of negative 15.75 percent. Mr. Watson recommended moving from the current negative 10 percent to negative five percent net salvage.523 Mr. Pous agreed. Because of the limited available data, Ms. Mathis recommended retaining the existing negative 10 percent net salvage.524

The ALJs agree with Staff that because of the limited retirement activity, a reasonable net salvage rate cannot be calculated from the historical salvage data. Accordingly, the ALJs recommend the Commission adopt the negative 10 percent net salvage value proposed by Staff.

5. General Plant General plant includes some accounts that are subject to depreciation, and some that are subject to amortization. ETI proposes to adopt “Vintage Group Amortization,” consistent with ETI Ex. 13 (Watson Direct) at Ex. DAW-1 at 70.

Staff Ex. 2 (Mathis Direct) at 34.

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FERC Rule AR-15 for Accounts 391-397.1 and Account 398. This approach, approved by both the FERC and the Commission (Docket No. 38339), does not affect the annual level of expense, but provides for timely retirement of assets and simplifies accounting for general property.525 Ms. Mathis concurred in the Company’s proposal to adopt Vintage Group Amortization and with its recommendations for lives, amortization periods, and net salvage.526

The increase in expense for general plant proposed by ETI is due to the need to reduce the deficit in the general plant reserve caused by inadequate account level rates in the past.527 This is a matter of debate among the parties, as discussed in more detail below.

(a) Account 390 – Structures and Improvements (Life Parameter) Based on his analysis of the data in comparison to various potential dispersion curves, Mr. Watson recommended an increase in the life of this account to 45 R2.528 Ms. Mathis agreed with this life. Mr. Pous proposed a significantly longer life (54 S0.5) and claimed that Mr. Watson did not adequately investigate the data and investments in this account. Mr. Pous concluded that “superstructures and roadways” are a significant element in the account which can be expected to have a long life.529

ETI contends that Mr. Pous’ analysis is incorrect. First, as confirmed by his workpapers, Mr. Watson conducted an analysis of five bands, not a single band as alleged by Mr. Pous.

Furthermore, Mr. Pous’ argument regarding long lives, based on the idea that the investment dates back to 1927, is contrary to the actual data showing a minute amount of old investment (0.02 percent of the account) dating back only to 1939. The average age of investment in the account, however, is

ETI Ex. 13 (Watson Direct) at Ex. DAW-1 at 2-3.

Staff Ex. 2 (Mathis Direct) at 35-37.

ETI Ex. 13 (Watson Direct) at Ex. DAW-1 at 2-3.

Id. at Ex. DAW-1 at 56.

Cities Ex. 5C (Pous Depreciation Study) at 51.

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only 15.87 years. Mr. Watson explained that the actual data shows no investment has achieved a life of 85 years, as alleged by Cities.530

The ALJs believe that the actuarial analysis and curve fitting shown in Mr. Watson’s direct and rebuttal testimony demonstrate a more reasonable approach, as recognized by Staff witness Mathis. Therefore, the ALJs recommend the Commission adopt the 45 R2 life parameter recommended by ETI.

(b) Account 390 – Structures and Improvements (Net Salvage Value) Account 390 is a depreciable account for structures and improvements. Though the current authorized net salvage is zero, Mr. Watson recommended a negative five percent net salvage value, and Staff agrees with this recommendation. Mr. Pous recommended a positive 15 percent net salvage value.

Mr. Watson based his recommendation on the most recent five-year and ten-year ratios, which are negative 1.51 percent and negative 34.27 percent.531 Mr. Pous disagreed, arguing that: (1) Mr. Watson’s data adjustments present an incorrect picture of the salvage history; and (2) Mr. Watson failed to account for the difference in net salvage values between the retirements of leaseholds, versus Company-owned facilities, which should not produce negative salvage.532

According to ETI, Mr. Pous’ argument that retirement and sales of buildings will result in positive net salvage is not backed up by the Company-specific data for this account. Such data shows that negative net salvage has occurred in every period of the most recent ten-year moving average. Averages of six years or longer range from negative 4.56 percent to negative 34.27 percent.533 ETI also argues that Mr. Pous’ attempt to use sales of facilities as an element of depreciation analysis is contrary to Commission precedent regarding building sales ’and that his ETI Ex. 71 (Watson Rebuttal) at 49.

ETI Ex. 13 (Watson Direct) at Ex. DAW-1 at 73.

Cities Ex. 5C (Pous Depreciation Study) at 31.

ETI Ex. 71 (Watson Rebuttal) at 73-74.

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opinion is contrary to the facts that such sales are unique circumstances that do not reasonably represent the ongoing year-to-year retirement activity that should form the basis of depreciation analysis.

The ALJs find that Mr. Pous’ arguments are not supported by the facts and that Mr. Watson’s explanations are the more credible. Accordingly, the ALJs recommend the Commission adopt ETI’s proposed negative five percent net salvage value for this account.

(c) General Plant Reserve Deficiency A $21.3 million deficit has developed over time in the reserve for the accounts that ETI proposes should be converted to General Plant Amortization. This deficit, or under-recovery, has occurred because assets have been retired more quickly than can be addressed by the existing amortization rate. ETI, therefore, proposes a $2.1 million annual expense level to recover the deficit over ten years.534 Ms. Mathis recommended that the amortization of the reserve deficiency be rejected and that the deficit be recovered through application of the remaining life method to the individual accounts where the deficit occurred.535

ETI argues that although Ms. Mathis’ recommendation could theoretically allow recovery, her calculation of the amortization for the accounts that created the deficit is erroneous and insufficient to carry out her proposed concept for recovery. During her cross examination, Ms. Mathis agreed that she had intended to take the elements of the remaining life calculation method exclusively from Mr. Watson’s depreciation study. 536 ETI contends that she failed to pull the correct values from Mr. Watson’s study and her numbers did not match the corresponding entries from Mr. Watson’s study.537 For example, Ms. Mathis affirmed that her remaining life calculations were intended to allow recovery of the remaining investment in general plant account 391.2. The

ETI Ex. 13 (Watson Direct) at Ex. DAW-2 at 2, App. A-2 at 1-2.

Staff Ex. 2 (Mathis Direct) at 38.

Tr. at 1752-1753.

Tr. at 1746-1759.

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remaining investment she provided for was $10.9 million of an original cost of $21.7 million.538 The actual remaining investment in the account, however, as shown in the data she purported to rely on, was a credit balance of negative $4.4 million, meaning that not only the original cost, but $4.4 million additional investment remained unrecovered.539 Ms. Mathis had no explanation for the difference. In fact, it appears that she erroneously substituted the theoretical reserve for the account in Mr. Watson’s study ($10.789 million) as the actual book reserve, resulting in an erroneous calculation of the amount yet to be recovered.540 Mr. Watson’s rebuttal points out the errors in the calculation and provides an exhibit to properly reflect the remaining life approach that Ms. Mathis intended.541

However, Mr. Watson’s rebuttal also explained the reasons that the Company’s approach is better. By using a ten-year amortization period for the deficit, ETI lowers the annual amount of the expense in rates to $2.1 million. Once Ms. Mathis’ calculation is corrected, because the remaining lives through which the asset value is recovered are so short, ’her remaining life approach increases the annual expense of amortization to $5.8 million. Given the significant level of expense involved, ETI personnel had asked Mr. Watson to moderate the remaining life approach in this instance by using a ten-year amortization period that was consistent with the approach used by another affiliate within the Entergy system. Moreover, although Ms. Mathis purports to rely on the Commission’s decision in Docket No. 38339 in support of her proposal, that case includes no discussion of rejecting the proposal on general plant that Mr. Watson makes here.542

The ALJs have reviewed the evidence cited by both parties and the testimony offered in support of their respective positions. It is clear to the ALJs that Ms. Mathis inadvertently did exactly what ETI alleges – she got numbers confused and, in so doing, confused her analysis. The ALJs find

Tr. at 1754; Staff Ex. 2 (Mathis Direct) at Ex. JLM-2 at 4.

Tr. at 1755.

Tr. at 1759-1761.

ETI Ex. 71 (Watson Rebuttal) at 84, Ex. DAW-R-5.

Id. at 80-81.

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that ETI’s proposed $2.1 million annual expense level to recover the deficit over ten years be approved by the Commission.

(d) Amortization Period for Account 391.2 – Computer Equipment Mr. Pous challenged the amortization period for this account, contending, contrary to Staff and Mr. Watson, that the Company’s proposal to amortize general plant using “Vintage Group Amortization” is not consistent with FERC pronouncement AR-15. ETI argues that Mr. Pous’ critique is wrong because the five-year life of which Mr. Pous complains is based on standard life analysis. The life has nothing to do with AR-15, which does not determine such matters.

Mr. Watson’s study clearly explains that he based the life parameter on standard actuarial analysis.543

According to ETI, Mr. Pous’ own recommendation points out the fallacy of his arguments about AR-15. He recommended a one-year increase in the amortization, which does not match the previous period of depreciation for this account, or the previous depreciation rate, despite that being the supposed flaw in Mr. Watson’s approach.544 Mr. Watson explained that the use of AR-15 does not involve any independent tinkering with the life of the asset account because the AR-15 process “provides for the amortization of general plant over the same life as recommended,” based on standard life analysis, which Mr. Watson’s study recognized.545

The ALJs are persuaded by ETI’s arguments on this point. FERC pronouncement AR-15 requires amortization over the same life as recommended based on standard life analysis.

Mr. Watson’s study employed standard life analysis to ascertain the recommended five-year life.

The ALJs therefore recommend the Commission adopt the five-year life proposed by ETI.

ETI Ex. 13 (Watson Direct) at Ex. DAW-1 at 58.

Cities Ex. 5 (Pous Direct) at 36.

ETI Ex. 13 (Watson Direct) at Ex. DAW-1 at 2.

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6. Fully Accrued Depreciation Mr. Pous claimed that the Company has failed to conform its Commission-authorized depreciation rates when it stops accruing depreciation on accounts and sub-accounts that are fully accrued. He testified that the Company must continue to depreciate such accounts, despite the fact that this policy would mandate that the Company intentionally create negative depreciation amounts that do not relate to the existence of any depreciable asset still in existence. Mr. Pous testified that neither standard depreciation definitions nor GAAP or National Association of Regulatory Utility Commissioners (NARUC) depreciation guidance support the Company’s action.546 The impact of Mr. Pous’ recommendation is to impute an additional $6,447,731 depreciation amount to reduce rate base and amortize that credit over four years, with an associated revenue requirement reduction of $1,611,933.547

ETI argues that Mr. Pous pointed to no instance in which his theory has been adopted by the Commission, or any other regulatory body. Other regulators within the Entergy system have rejected his position.548 The RRC, which sets gas utility rates under essentially the same regulatory framework as PURA, has rejected Mr. Pous’ position on three separate occasions.549 ETI contends that Mr. Pous’ suggestion violates GAAP, which requires that once an asset’s service value (original cost less net salvage) has been fully amortized through the application of the most recently approved depreciation rates, there is no further service value to be recognized. This has been ETI’s practice as long as ETI regulatory accounting witness Considine has been aware. Furthermore, ETI suspends depreciation only so long as the account is fully amortized. Once additional activity hits the account, depreciation will begin again under the Company’s automated systems.550

ETI also argues that Mr. Pous’ retroactive approach is unreasonably selective. He would reach back into recoveries under existing rates to reclaim revenues associated with the depreciation Cities Ex. 5 (Pous Direct) at 39-45.

Id. at 45.

ETI Ex. 46 (Considine Rebuttal) at 45-46.

ETI Ex. 71 (Watson Rebuttal) at 81, n. 61; ETI Ex. 46 (Considine Rebuttal) at Ex. MPC-R-11.

ETI Ex. 46 (Considine Rebuttal) at 44-45, 47.

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expense that relates to the fully accrued accounts. According to ETI, Mr. Pous takes no notice of the depreciation taken on new assets that are not included in rate base or recovered through depreciation expense under existing rates. ETI witness Considine notes that Mr. Pous has essentially formulated a one-sided exact recovery mechanism for depreciation expense that is completely unique in the annals of base rates.551

According to ETI, Mr. Pous also ignores that the remaining life depreciation method already addresses any over- or under-accrual of depreciation expense. As depreciation rates and the remaining life are adjusted over time, any over (under) recovery will be carried forward and the net (if any) of the original investment less any accumulated reserve will begin to be recovered under the new and future rate structures. This is the basic concept of remaining life depreciation rates. Thus, ETI contends that no further actions or adjustments are appropriate.552

The ALJs find that Mr. Pous’ recommendation has previously been rejected, by other regulatory bodies. There is nothing in the arguments advanced by Cities that changes that fact.

Accordingly, the ALJs recommend the Commission reject Cities’ proposal.

7. Other Depreciation Issues – Accumulated Provision for Depreciation ETI proposes to amortize the $21 million general plant deficiency over ten years. Both the Cities and Staff agree with and use the accumulated depreciation reserve amounts per account from Mr. Watson’s study.553 TIEC witness Pollock, in arguing against amortization of the amortized general plant reserve deficiency, testified that this reserve deficiency should instead be simply reallocated to other depreciable general plant accounts that have depreciation surplus.554

Mr. Pollock discussed transferring the depreciation reserve between the amortizable and depreciable general plant accounts. He failed to show, however, how the reserve reallocation would Id. at 43, 45.

ETI Ex. 71 (Watson Rebuttal) at 78.

Id. at 77.

TIEC Ex. 1 (Pollock Direct) at 38-39.

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be computed and provided no workpapers to substantiate his analysis. ETI argues that without a verifiable basis for the computations, his recommendations to recompute general plant depreciation accruals should be rejected.

ETI also argues that Mr. Pollock’s testimony shows that he has reallocated the amortizable general plant deficiency from the amortized general plant accounts to the depreciable general plant accounts. The depreciable plant accounts have shorter remaining lives than the ten-year amortization of the deficiency proposed by ETI.555 ETI contends that common sense dictates that transferring dollars from an account with a relatively longer remaining life to one with a shorter life will yield a higher annual depreciation or amortization expense, yet Mr. Pollock somehow takes this step and still arrives at a lower level of expense.

According to ETI, Mr. Pollock’s methodology has the effect of “amortizing the difference between the book and theoretical reserve over a time period that is significantly shorter than the average remaining life of the assets within this function.”556 ETI asserts that such an adjustment to depreciation and amortization expense was rejected by the Commission in the CenterPoint rate case, and it should be rejected here.557

TIEC argues that it does not propose any amortization of any accounts. Rather, TIEC states that it is proposing a more efficient method for ETI to cure its deficits. Because ETI retired equipment prior to the end of the assumed life of those assets, there is approximately a $21,300,000 deficiency in general plant accounts. ETI seeks to amortize the deficiency over ten years so that the book reserve will “catch-up” with the theoretical depreciation reserve for the deficient reserve. TIEC contends that its position is that the catch-up adjustment is not necessary.558

ETI Ex. 13 (Watson Rebuttal) at Ex. DAW-1, App. A-1 at 4.

ETI Ex. 71 (Watson Rebuttal) at 75.

Id. at 75-76.

TIEC Ex. 1 (Pollock Direct) at 37.

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The ALJs have reviewed the evidence and arguments advanced by the parties and find that those of ETI are more persuasive. Accordingly, the ALJs recommend the Commission reject TIEC’s recommendation.

D. Labor Costs 1. Payroll and Related Adjustments A number of parties suggest various adjustments to ETI’s proposed payroll and related costs.

In the application, ETI’s Test Year payroll costs were adjusted downward by $957,695 to reflect a decrease in the employee headcount levels at ETI during the Test Year. At the same time, payroll costs were increased in the amount of $1,105,871 to account for employee pay raises. The net result was that ETI’s Test Year payroll expense was adjusted upward by $148,176. Similar calculations were made for ESI employees, resulting in a net upward adjustment for ESI payroll expenses of $852,493. Thus, ETI requested an upward adjustment of $1,000,669 ($148,176 plus $852,493) for ETI and ESI payroll expenses.559

Cities oppose one part of these proposed adjustments. As noted above, ETI is proposing an upward adjustment to account for pay raises given to ETI and ESI employees. One set of those raises was given to employees in early August 2011, one month after the end of the Test Year.

Another set of raises was given to employees in April 2012, roughly nine months after the end of the Test Year. Cities witness Garrett testified that it is acceptable to make an adjustment for the raises made in August 2011 because they occurred shortly after the end of the Test Year. However, he stated that it is unreasonable to include an adjustment for the raises given in April 2012. He believes that any increase in costs due to the April 2012 pay raises might be offset by changes in productivity and the overall workforce that may occur during the same time period, such as the replacement of higher-paid workers who retire with new, lower paid employees.560 Thus, Cities propose an adjustment that would reverse ETI’s proposed increase for the April 2012 pay raises thereby

ETI Ex. 8 (Considine Direct) at 24-25; 3 at Sched. A-3 and WP/P AJ22.

Cities Ex. 2 (Garrett Direct) at 13-15.

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reducing payroll expense by $1,185,811.561 No other party makes a similar challenge to the April 2012 pay raise.

With regard to the adjustments proposed by ETI, Staff witness Givens accepted the adjustments for headcount changes and the pay raises, but recommended a further downward adjustment of $778,034 to account for a further decrease in ETI employee headcount levels from 678 at Test Year-end to 660 as of February 2012. She also recommended an upward adjustment of $158,589 to account for an increase in ESI employee headcount levels from 3,055 to 3,089 as of December 2011.562 Ms. Givens also recommended that, in addition to adjusting payroll expense levels, the more recent headcount numbers should be used to adjust the level of payroll tax expenses, benefits expenses, and savings plan expenses.563 As an alternative to its primary line of attack (discussed above), Cities agree with the adjustments recommended by Staff.

ETI also agrees, in concept, with the adjustments recommended by Staff, but contends that Ms. Givens made some errors in her calculations. First, according to ETI, Ms. Givens used erroneous headcounts for the end of the Test Year for ETI and ESI. According to the Company, ETI’s headcount at Test Year-end was 675 and ESI’s was 3,054. Ms. Givens wrongly used headcounts of 678 and 3,055, respectively, which caused a double counting of three ETI employees and one ESI employee.564 Second, Ms. Givens made an error in the calculation of benefits costs associated with the updated ESI headcount. Ms. Givens inadvertently used the ETI percentage in the calculation rather than the ESI percentage shown on her exhibit.565 Third, Ms. Givens’ adjustment for savings plan expense was not necessary and is thus inappropriate. According to ETI witness Considine, savings plan expense is already included in benefits expense levels so it would be double counting to adjust for both benefits expense and savings plan expense.566 Fourth, Ms. Givens’

Id. at 19.

Staff Ex. 1 (Givens Direct) at 10-12.

Id. at 13-15.

ETI Ex. 46 (Considine Rebuttal) at 32-33.

Id. at 33.

Id. SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 165 PUC DOCKET NO. 39896

full-time equivalent calculations need to be corrected. She included an incorrect assumption regarding part time employee salaries. Ms. Givens assumed that a part time employee’s average salary is 50 percent of the full time average salary. In his rebuttal testimony, Mr. Considine provided the correct calculation of full time equivalents, thereby making it unnecessary to rely upon an assumed average.567 According to Mr. Considine, the combined impacts of these errors is that Ms. Givens’ ETI headcount adjustment overstated her O&M payroll reduction by $224,217, and her ESI headcount adjustment understated her O&M payroll increase by $37,531.568 No party challenged these corrected numbers.

The ALJs are unpersuaded by Cities’ attempt to exclude the April 2012 pay raises. There can be no real dispute about the fact that the pay raises are known and measurable. Moreover, there is an obvious logical inconsistency in the Cities’ position – on the one hand they oppose consideration of certain pay raises because they fall outside the Test Year, and on the other hand they support consideration of headcount reductions even though they also fall well outside the Test Year.

The ALJs are also persuaded that, conceptually, the adjustments suggested by Staff are reasonable and appropriate. Indeed, all parties agree on this point. Moreover, no party challenged the corrections to Staff’s adjustments that were suggested by ETI, and the ALJs can find no basis for challenging those corrections. Thus, the ALJs recommend that the Commission: (1) accept the payroll adjustments proposed in the ETI application; and (2) accept the further payroll adjustments proposed by Staff, corrected by ETI.

2. Incentive Compensation One of the hotly contested issues concerns the extent to which ETI should be allowed to recover, through its rates, the incentive compensation it pays to its employees. All parties agree that Commission precedent generally identifies two types of incentive compensation, only one of which is recoverable. Specifically, pursuant to Commission precedent, incentive compensation that is tied Id. at 34.

Id. at MPC-R-5, and MPC-R-6.

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to operational goals is recoverable, while incentive compensation that is tied to financial goals is not.569 In its application, however, ETI requests that it be allowed to recover its Test Year costs of all of its incentive compensation costs, regardless of whether those costs are tied to operational goals or to financial goals.

(a) Financially Based Incentive Compensation Should Not Be Recoverable ETI acknowledges that costs of incentive compensation tied to financial goals have typically been disallowed by the Commission. However, ETI asks for the Commission to reconsider its precedents on this issue.570 ETI argues that the Commission precedent is not, and should not be, a hard and fast rule. ETI contends that the reason why cost recovery has been denied for incentive compensation in prior rates cases is that, in those prior cases, there was “a lack of evidence showing sufficient customer benefits.”571 ETI asserts that, in this case, it has assembled evidence not previously considered by the Commission that shows the benefits to customers of using financial measures in incentive compensation programs. For example, ETI argues that incentive compensation that encourages the financial health of a company also benefits customers because:

(1) if a company maintains a financially healthy position, it will tend to have a lower cost of capital that will in turn benefit customers through lower rates; (2) a financially healthy company will be more prepared for emergency events such as storms (which is particularly important in the Gulf Coast areas served by ETI, which are subject to experiencing hurricanes); and (3) with financial health, the costs of doing business with suppliers (of both goods and services, including labor) will remain lower because, for example, if a company was not in a financially stable condition, suppliers would tend to demand higher prices or more onerous credit terms, resulting in higher costs that would lead to higher rates than would otherwise occur.

See, e.g.,TIEC Initial Brief at 51-52; see also AEP Application of AEP Texas Central Company for Authority to Change Rates, See Docket No. 33309, Order on Rehearing at FoF 82 (Mar. 4, 2007); Application of AEP Texas Central Company for Authority to Change Rates, Docket No. 28840, Order at FoF 164-170 (Aug. 15, 2005).

Tr. at 1726.

ETI Initial Brief at 129.

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ETI witness Kevin Gardner, Vice President of Human Resources for ESI, testified that customers receive benefits from those portions of the incentive compensation plans that are tied to financial goals and measures. He explained that incentive compensation based on financial metrics is a reasonable, necessary, and common component of compensation for companies like ETI. He also opined that such incentives are a market necessity that ETI must include in its compensation package so that it can hire and retain talented employees. He contended that customers benefit from the incentives because they attract and keep qualified people.572 Mr. Gardner further testified that disallowing financially-based incentives would only encourage utilities to eliminate them, thus weakening the alignment of employees’ financial interests with the interest of the ratepayers in having an efficiently run and financially healthy utility. He opined that having only operational incentives could encourage utilities to overspend in some areas resulting in an incomplete, unbalanced incentive program that would be atypical when compared with American industry in general.573

A second ETI witness, Dr. Jay Hartzell, also testified in favor of the concept of allowing ETI to recover its costs associated with its financially-based incentive compensation. He is a professor of finance in the business school at the University of Texas at Austin. Dr. Hartzell acknowledged the historical distinction that has been made by the Commission between compensation tied to financial measures and compensation tied to operational measures. However, he argues that this distinction is based upon a “false dichotomy” and that the more appropriate focus should be on whether customers benefit from the incentive in question, regardless of whether it is a financial or operational incentive.574 Dr. Hartzell summarized his key opinion as follows:

In my opinion, a well-designed compensation plan that includes incentive compensation tied to cost controls, profitability, and stock prices would tend to provide greater benefits to customers than an otherwise similar compensation plan that did not include any such incentive compensation.575

ETI Ex. 36 (Gardner Direct) at 31.

Id. at 32.

ETI Ex. 15 (Hartzell Direct) at 3-4, 6, and 9-10.

Id. at 7.

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Dr. Hartzell argues that compensation linked to stock prices (provided it is part of a reasonable, well-designed compensation plan) has four advantages for customers, :

x helps ensure that managers will consider the financial health of the company when they make decisions, and it is in customers’ interests for the company be financially healthy; x provides an incentive for managers and employees to ensure that the company operates efficiently, resulting in lower rates than would otherwise occur; x provides a monitoring mechanism for managerial decision-making and the overall quality of management; and x results in lower customer costs because capital markets will tend to reward efficient long-term investments or capital expenditures.576 Dr. Hartzell cited a number of studies which support the theory that the benefits of incentive compensation linked to stock price and profitability measures extend to customers of the company, such as by lowering the company’s cost of capital, increasing the company’s ability to respond to external shocks, improving customer satisfaction, and increasing oversight on managerial decisions.577

Conversely, Dr. Hartzell opined that if the use of incentive compensation linked to profitability and stock prices is discouraged, via Commission policy disallowing recovery of the costs of such compensation, then utility customers would be adversely affected. For example, if employees did not receive any incentive compensation, salaries would have to be higher to attract and retain the same quality of talent. Dr. Hartzell also testified that a compensation plan solely consisting of salary and incentives based on operational performance could likely lead to “horizon problems,” meaning that, absent incentives to focus on the long run health of the company, managers might maximize their immediate compensation at the expense of longer-run benefits that the customer could have enjoyed.578

Id. at 13-14.

ETI Ex. 15 (Hartzell Direct) at 15-21.

Id. at 22-25.

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All of the other parties oppose ETI’s efforts to recover the costs of its incentive compensation tied to financial goals. The parties uniformly agree that the Commission has a well- established and straightforward policy regarding the recoverability of incentive compensation through rates: incentive compensation that is tied to operational goals is recoverable; incentive compensation tied to financial goals is not.579 They contend that ETI’s position in this case flies directly in the face of that policy. TIEC points out that ETI has offered no legal authority, such as a statute or rule, which would justify its desire to have the Commission reverse its policy and allow the recovery of incentive compensation tied to financial goals. State Agencies similarly argue that ETI failed to establish a reason why the Commission should deviate from its long-standing policy.

The parties also support the reasoning behind the Commission’s policy: that financially-based incentives are of more immediate benefit to shareholders, not ratepayers, and therefore are not necessary and reasonable for the provision of service.

State Agencies point out that, in support of his theory that financially-based incentives provide benefits to ratepayers, Dr. Hartzell relied upon studies of utilities in competitive markets.

Thus, State Agencies contend, the studies are of little to no benefit in evaluating the effects of financially-based incentives upon ETI customers because ETI is a monopoly that is not subject to competitive pressures. Moreover, State Agencies examine at length the underlying studies relied upon by Dr. Hartzell and assert, essentially, that the studies do not fully support the findings that Dr. Hartzell ascribes to them.

Staff refutes ETI’s contention that the only reason why cost recovery has historically been denied for financially-based incentive compensation is that there has been a lack of evidence showing customer benefits. For example, Staff points out that, in one of the prior dockets cited by ETI, the Commission disallowed recovery for financially-based incentive costs after stating, “Incentive compensation based on financial measures or goals is of more immediate benefit to

TIEC Reply Brief at 35; State Agencies Initial Brief at 14; OPC Reply Brief at 12; Staff Initial Brief at 56; Cities Initial Brief at 67; see also, Application of AEP Texas Central Company for Authority to Change Rates, Docket No. 33309, Order on Rehearing at FoF 82 (Mar. 4, 2007); Application of AEP Texas Central Company for Authority to Change Rates, Docket No. 28840, Order at FoF 164-170 (Aug. 15, 2005).

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shareholders.”580 This suggests that the question is not, as ETI contends, whether the incentives provide any benefit to ratepayers. Rather, the question is whether the incentives are primarily intended to provide benefits to shareholders.

Mark Garrett, an attorney and certified public accountant who works as a consultant in the area of public utility regulation, testified on behalf of the Cities in opposition to cost recovery for financially-based incentive compensation. He stated there are a number of reasons why it makes sense to exclude financially based incentive costs from rates: (1) there is no certainty from year to year what the level of incentive payments will be (because incentive payments are conditioned upon future events and triggers that might not occur), thereby making it difficult to set rates and recover a level of expense; (2) many of the types of factors that increase earnings per share—such as an unusually hot summer or customer growth—are outside the control of employees and have no value to customers; and (3) earnings-based incentives can discourage energy conservation.581 Mr. Garrett also discussed the results of a survey of 24 other states, which revealed that 17 states closely follow Texas’ approach, and none allow full recovery of incentive compensation.582

Mr. Garrett testified that ETI will not be placed at a competitive disadvantage in its ability to obtain and retain qualified employees if its financially-based incentives are disallowed. He stated that the Company’s total payroll costs for 2011 were 10 percent above the market price, and that most of the above-market payroll costs derived from the incentive program.583

The ALJs conclude that ETI should not be entitled to recover its financially based incentive compensation costs. Based upon prior Commission precedents, the ALJs conclude that the issue is not, as ETI contends, whether such incentives might provide any benefits to customers. The proper question to be asked is whether they provide benefits most immediately or predominantly to shareholders. Without a doubt, the primary purpose of financially based incentives, such as Staff Reply Brief at 44, quoting Application of Oncor Electric Delivery Company for Authority to Change Rates, Docket No. 35717, Order on Rehearing at FoF 92 (Nov. 30, 2009).

Cities Ex. 2 (Garrett Direct) at 29-30 Id. at 32-38.

Id. at 45-46.

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incentives tied to earnings per share or stock price, is to benefit shareholders, not ratepayers. Even construing Dr. Harzell’s testimony in the most generous light, any benefits that might accrue to ratepayers would be merely tangential to that primary purpose.

Moreover, even if the ALJs were to completely accept as true the opinions offered by Dr. Hartzell, it would be of limited benefit to ETI because his opinions were almost completely theoretical. The premise of his testimony was that “a well-designed compensation plan” that includes incentive compensation tied to financial goals would “tend to provide greater benefits to customers” than a plan that did not include such compensation.584 He stressed that the customer benefits of incentive compensation tied to financial goals can only exist if such compensation is part of a larger, reasonable, and well-designed overall compensation plan.585 However, he did not meaningfully apply this abstract theory to ETI’s compensation plan. For example, Dr. Harzell did not offer an evaluation of ETI’s compensation plan and conclude that it is “well designed,” nor did he testify that ETI’s incentives tied to financial goals actually provide benefits to its customers. He admitted that he did not study the details of ETI’s incentive plans, nor did he do any type of analysis to see if the costs of ETI’s incentive programs outweighed their benefits.586 He did not know the amounts of incentive compensation that was paid by ETI.587 One of his major premises was that financially-based incentives can benefit customers by lowering their costs, but he did not know how ETI customer’s costs compared with customer costs in the other Entergy operating companies.588 Another of his major premises was that financially-based incentives can benefit customers by ensuring the financial health of the Company, but he made no attempt to determine whether ETI was, in fact, a financially healthy company.589 By confining his testimony to the abstract, it is impossible to know whether Dr. Hartzell believes that ETI’s incentive compensation tied to financial goals achieves the customer benefits that he believes such compensation can theoretically achieve.

ETI Ex. 15 (Hartzell Direct) at 7 (emphasis added).

See, e.g., ETI Ex. 15 (Hartzell Direct) at 13.

Tr. at 484.

Tr. at 478.

Tr. at 480.

Tr. at 481-82.

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It is true that Mr. Gardner described some of the specifics of ETI’s incentive plans. However, because Dr. Hartzell did not explain the metrics of what he would consider “a well-designed compensation plan,” it is impossible to know if ETI’s plan meets those metrics.

Simply put, the ALJs conclude that ETI has failed to establish a sufficient justification for overturning the well-established Commission policy that financially based incentive compensation is not recoverable.

(b) The Adjustment for Financially-Based Incentive Compensation Costs Having concluded that ETI is not entitled to recover the costs of its financially based incentive programs, it is necessary to determine the amount of those costs so that they may be removed from consideration in this rate case. The parties disagree on the correct amount. Staff argues that $5.3 million of ETI’s incentive compensation is financially based.590 TIEC contends the correct number is $6.2 million.591 Cities contend it is $8.4 million.592

Broadly speaking, ETI has two categories of incentive compensation programs – annual programs and long-term programs. ETI witness Gardner testified that 100 percent of ETI’s long-term programs are financially based, whereas an average, representing a far lower percentage, of the Company’s annual programs are financially based.593 Staff witness Givens applied those percentages to determine her estimate of the amount spent by ETI in the Test Year on financially based incentives. As to the Company’s long-term programs, she recommended removing the entire costs of those programs (i.e. 100 percent) from the cost of service. As to the Company’s annual programs, she recommended removing average percentage of the costs of those programs.

Ms. Givens then applied the FICA tax rate to the total amount she identified as financially based costs to account for direct taxes that ETI would have paid as a result of those costs. By her estimate, Staff Initial Brief at 56. (As discussed more below, Staff’s original estimate was roughly $5.6 million.

The estimate was reduced, however, in response to supplemental payroll tax information supplied to Staff by ETI.)

TIEC Initial Brief at 53-54.

Cities Initial Brief at 70.

ETI Ex. 36 (Gardner Direct) at 30.

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the FICA taxes associated with ETI’s financially based incentives paid in the Test Year totaled $429,096. In total, Ms. Givens recommended removing $5,609,093 (representing ETI’s financially based incentives paid in the Test Year, plus FICA taxes associated with those payments) from ETI’s requested O&M expenses. However, based upon subsequent additional information supplied by ETI594 relative to the actual payroll taxes paid by the Company for its financially based incentive compensation, Staff has agreed to lower its estimate of FICA taxes from $429,096 to $143,801.

Thus, Staff now recommends removing $5,323,798 (representing ETI’s financially based incentives paid in the Test Year, plus FICA taxes associated with those payments) from ETI’s requested O&M expenses.595

Like Ms. Givens for Staff, TIEC witness Pollock relied on the numbers and percentages concerning ETI’s incentive programs that were provided by Mr. Gardner. However, Mr. Pollock calculated those numbers and percentages in a slightly different manner, leading to a different recommended reduction amount. Just as Ms. Givens did, as to the Company’s long-term programs, he recommended removing the entire costs of those programs from the cost of service. ETI witness Gardner testified that actual percentages of each annual program were quite different than the average percentages for all programs used by Ms. Givens.596 Thus, as to the Company’s annual programs, while Ms. Givens applied the average percentage reduction to all of the annual programs, Mr. Pollock applied the actual percentage reductions applicable to each of the annual programs.

Based on Mr. Pollock’s calculations, TIEC recommends removing $6,196,037 (representing ETI’s financially based incentives paid in the Test Year) from ETI’s requested O&M expenses.597 TIEC appears not to have taken into account any payroll taxes associated with ETI’s financially based incentives.

Cities witness Garrett took a substantially different approach when he calculated his estimate of ETI’s financially based incentive costs. He agreed with Ms. Givens and Mr. Pollock that ETI Ex. 46 (Considine Rebuttal).

Staff Ex. 1 (Givens Direct) at 15-22; Staff Initial Brief at 56-63.

ETI Ex. 36 (Gardner Direct) at 30 and KGG-4.

TIEC Ex. 1 (Pollock Direct) at 41-45 and JP-7; TIEC Initial Brief at 51-54.

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100 percent of the Company’s long-term program costs should be removed from the cost of service.

As to the annual programs, however, Mr. Garrett defined what qualifies as “financially based” much more broadly than ETI, Staff, and TIEC. ETI witness Gardner testified that, when the Company’s five annual programs were averaged together, specific percentages of those programs were financially based, aimed at “cost control,” and aimed at “cost control, operational, safety.” 598 Mr. Garrett added together the percentages representing the financially-based costs, the cost-control costs, and roughly one-third of the cost-control, operational safety costs to arrive at the figure he identified as the amount of ETI’s costs for its annual programs that is “related to financial performance measures.”599 Cities contend this approach is supported by the decision in a prior docket.600 Based on Mr. Garrett’s calculations, Cities recommend removing $8,397,232 (representing ETI’s incentives “related to financial performance measures” paid in the Test Year) from ETI’s requested O&M expenses.601 Mr. Garrett also agreed with Ms. Givens that an additional reduction should be made to account for the FICA taxes that ETI would have paid as a result of those costs.602

The ALJs reject Cities’ attempt to broadly expand the definition of what qualifies as a financially based incentive to include items such as cost control measures. Cities’ primary justification for doing so is that the Commission has done so previously in the AEP Texas case. As pointed out by ETI, however, the Commission did so in that case merely because AEP Texas lumped its cost control measures in with its financially based incentive costs. The evidence in this case demonstrates that ratepayers benefit when a utility incentivizes its employee to control costs. Even TIEC witness Pollock testified that “incentives that encourage employees to minimize costs are probably more or less in the best interest of ratepayers.”603 ETI further provided evidence

ETI Ex. 36 (Gardner Direct) at 30 and KGG-4.

Cities Ex. 2 (Garrett Direct) at 39-40, 46-50, MG2.10.

Cities Initial Brief at 68, Application of AEP Texas Central Company for Authority to Change Rages, Docket No. 28840, Final Order (August 15, 2005).

Cities Ex. 1 (Garrett Direct) at 51-52 and MG2.10; Cities Initial Brief at 70.

Cities Ex. 1 (Garrett Direct) at 53.

Tr. at 1528.

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establishing that cost control incentives that result in lower costs for the Company likewise result in lower rates for customers.604

As to the approaches advocated by TIEC and Staff, the ALJs conclude that TIEC’s approach more accurately captures the true cost of ETI’s financially based incentive programs. Rather than averaging across all of ETI’s annual programs (as was done by Staff), TIEC used the percentage applicable to the single annual program that included a component of financially based costs. Thus, the ALJs recommend removing $6,196,037 (representing ETI’s financially based incentives paid in the Test Year) from ETI’s requested O&M expenses. Additionally, the ALJs agree with Staff and Cities that an additional reduction should be made to account for the FICA taxes that ETI would have paid as a result of those costs. That amount is not specifically known at this time.

3. Compensation and Benefits Levels In the application, ETI included, as part of its labor costs, $54,965,005 in base payroll paid by ETI and ESI in the Test Year. It also included $20,428,817 in costs associated with various benefits (such as medical/dental, and life insurance) that ETI and ESI provided to their employees.605 Cities contend that the amounts for base pay and the benefits package should be reduced by $989,370 and $2,860,034, respectively, because the amounts paid were above the market price.606 No other party challenges the reasonableness of the base payroll and benefits package.

As to base payroll, Cities contends that the amount paid by ETI and ESI was 1.8 percent above the prevailing market price (above market).607 Cities witness Garrett acknowledges that ETI and ESI are free to pay their employees at above market wages, but he contends that ratepayers should only be asked to pay the market rate for wages, which he contends constitute the only “necessary” costs of providing utility service. Thus, Mr. Garrett and Cities recommend a 1.8 percent

ETI Ex. 50 (Gardner Rebuttal) at 6-7, ETI Initial Brief at 137-38.

Cities Ex. 2 (Garrett Direct) at 25, MG2.8, and MG2.9.

Id. Id. at 25 and MG2.8.

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downward adjustment to base payroll expense (or $989,370) “to bring the company’s base payroll down to a market-based level.”608

As to the Company’s benefits package, Cities points out that the amount paid by ETI and ESI was 14 percent above market when compared to a peer group of Fortune 500 companies.609 Cities witness Garrett again contends that ratepayers should only be asked to pay the market rate for benefits, which he contends constitute the only “necessary” costs of providing utility service. Thus, Mr. Garrett and Cities recommend a 14 percent downward adjustment to benefits expenses (or $2,860,034).610

ETI concedes that its Test Year base pay was 1.8 percent “above the market median,” but argues that this is not the same thing as being “above market.” As ETI witness Gardner explained, “being ‘at market’ means being within a reasonable range, such as +/-10 percent, of the market median; therefore, the Company’s base pay levels are at market.”611 According to Mr. Gardner, some compensation consultants use an even broader range, such as a +/- 15 percent range, for determining whether compensation levels are at market.612 Mr. Gardner testified that, because no two jobs are likely to be identical, attempting to benchmark jobs to a “market price” is an inexact science, involving inherent imprecision. Thus, Mr. Gardner testified that, when using a benchmark analysis to compare companies’ levels of compensation, it is advisable to view the market level of compensation as a range (e.g., +/- 10 percent of a mid-point) rather than a precise, single point.613

ETI also disputes Cities’ contention that the Test Year costs of the Company’s benefits package were 14 percent “above market.” Mr. Gardner acknowledged that the costs were 14 percent higher than those of Fortune 500 companies, but he pointed out the costs were only 1 percent above

Id. at 26-27 and MG2.8.

Id. at 58 and MG2.9; ETI Ex. 36 (Gardner Direct) at 41-42.

Cities Ex. 2 (Garrett Direct) at 58-59 and MG2.9.

ETI Ex. 50 (Gardner Rebuttal) at 11.

ETI Ex. 36 (Gardner Direct) at 23, and ETI Ex. 50 (Gardner Rebuttal) at 11 n. 1.

ETI Ex. 50 (Gardner Rebuttal) at 11-12.

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the market median of a peer group of utility companies.614 ETI contends that the comparison against the peer group of utility companies provides a more appropriate comparison for ETI than Fortune companies. ETI also points out that, even if equal weight were given to the comparisons against the Fortune 500 companies and the peer utilities group, the value of the Company’s benefit plans would average within a +/- 10 percent range and, therefore, be at market. Thus, ETI argues that its benefit plan levels are within a reasonable range, and no disallowance should be required.615

The ALJs conclude that ETI has met its burden to prove the reasonableness of its base pay and incentive package costs. The ALJs agree that it is reasonable to view market price for these categories of costs as lying within a range of +/- 10 percent of median, rather than being a single point along a spectrum. As to both base pay and the incentive package, ETI has proven that its costs fall within such an acceptable range. Accordingly, the ALJs recommend rejecting the adjustments sought by Cities.

4. Non-Qualified Executive Retirement Benefits ETI provides three types of supplemental executive retirement plans: the Pension Equalization Plan, the Supplemental Retirement Plan, and the System Executive Retirement Plan.616 In the application, ETI included, as part of its labor costs, $2,114,931 in costs associated with its executive retirement plans. The expenses represent non-qualifying retirement plan expenses designed to provide retirement benefits to key managerial employees and executives who are invited to participate in the plans. They are generally available only to employees and executives earning more than $245,000 per year.617

On behalf of the Staff, Ms. Givens recommended a complete disallowance of the costs for these programs, on the grounds that they are offered to only select, highly compensated employees and are excessive. Ms. Givens offered the opinion that the expenses were not reasonable and ETI Ex. 36 (Gardner Direct) at 42.

ETI Ex. 50 (Gardner Rebuttal) at 13-14; ETI Initial Brief at 139-142.

ETI Ex. 50 (Gardner Rebuttal) at 14.

Staff Ex. 1 (Givens Direct) at 22-23; Cities Ex. 2 (Garrett Direct) at 54.

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necessary for the provision of electric utility service and were not in the public interest.618 On behalf of Cities, Mr. Garrett agreed with Ms. Givens’ recommendation, arguing that it is fair to have ratepayers pay for benefits included in regular pension plans, but that shareholders ought to pay for any additional benefits included in supplemental plans, “since these costs are not necessary for the provision of utility service, but are instead discretionary costs of the shareholders.”619 Mr. Garrett also testified that costs associated with supplemental executive retirement plans are typically excluded by utility commissions in Oklahoma, Oregon, Idaho, Arizona, and Nevada.620 On behalf of OPC, Dr. Szerszen also recommended a complete disallowance of the portion of these costs allocated from ESI to ETI.621 She stated that ETI has not shown that ratepayers benefit from the expenses, the costs are not necessary to provide utility service, and that the ESI allocation method is unjustified.622

ETI disagrees with all of these criticisms and maintains that the costs of the plans should be recoverable. ETI witness Gardner testified that the supplemental executive retirement plans are needed for attracting, retaining, and motivating highly competent and qualified leaders. He explained that the Pension Equalization Plan provides supplemental retirement benefits to account for the fact that Internal Revenue Code regulations limit the level of retirement benefits that qualify for tax treatment favorable to ETI and Entergy. The existence of this supplemental benefit program allows the Company to pay retirement benefits to highly-compensated employees that are proportionate to the compensation they receive while active in their employment. The Supplemental Retirement Plan and the System Executive Retirement Plan provide supplemental benefits beyond the amounts restricted in the qualified plan to some participants to attract, retain, and motivate employees.623 According to Mr. Gardner, these types of retirement benefits are widely provided by

Staff Ex. 1 (Givens Direct) at 23; Staff Initial Brief at 64.

Cities Ex. 2 (Garrett Direct) at 55; Cities Initial Brief at 71-72.

Cities Ex. 2 (Garrett Direct) at 56-57.

OPC Ex. 1 (Szerzen Direct) at 68. Dr. Szerzen quantifies the costs of the plans as $1,391,861 (a much lower estimate than those of Ms. Givens and Mr. Garrett).

Id. at 68-69.

ETI Ex. 50 (Gardner Rebuttal) at 15-16.

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companies within the utility business sector.624 Accordingly, ETI argues that it needs to offer them in order to be competitive in the employment market with peer companies, and thereby to retain and adequately compensate these employees in terms of future retirement benefits.

The ALJs conclude that the supplemental executive retirement plans are not reasonable and necessary for the provision of electric utility service and are not in the public interest. They are non-qualifying retirement plan available only to employees and executives earning more than $245,000 per year, and they constitute benefits over and above the Company’s standard retirement benefits package. Because these costs are not necessary for the provision of utility service, but are instead discretionary costs, they should be paid by the shareholders. Accordingly, the ALJs recommend an adjustment to remove $2,114,931, representing the full costs associated with ETI’s non-qualified executive retirement benefits.

5. Employee Relocation Costs In the application, ETI included, as part of its labor costs, $436,723 in employee relocation costs.625 ETI contends that, in order to be competitive in the employment market, it must provide relocation assistance to certain of its employees. ETI witness Gardner testified that ETI’s relocation policies and costs are reasonable and consistent with general industry practice. He also testified that the Company’s average relocation costs are in line with the relocation costs for the companies surveyed by the Employee Relocation Council.626

Staff recommends an adjustment to remove the entire $436,723 of ETI’s relocation expenses.627 No other party challenged the legitimacy of relocation expenses. Staff points out that ETI pays 110 percent of the market median for total annual compensation.628 Staff contends that the fact that ETI pays more than the average market wage demonstrates that employees should be Id. at 16.

Staff Ex. 1 (Givens Direct) at 25.

ETI Ex. 36 (Gardner Direct) at 45-46.

Staff Initial Brief at 64; Staff Ex. 1 (Givens Direct) at 24.

Staff Ex. 1 (Givens Direct) at 24 (citing ETI Ex. 36 (Gardner Direct) at 26).

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sufficiently enticed to join and move around within its organization without the need for ETI to pay relocation expenses to attract employees. Therefore, Staff argues that the relocation expenses do not meet the reasonable and necessary standard required for inclusion in cost of service, nor are the expenses in the public interest.629 Staff also points out that similar types of payments were removed from cost of service in recent proceedings, such as in Docket No. 28906, where payments for moving expenses or signing bonuses were removed from cost of service.630

ETI responds by pointing out that Staff does not challenge the reasonableness of the amount spent on relocations by ETI. It also contends that most of its peers offer moving assistance. Thus, it would be competitively disadvantaged if it did not offer it as well. ETI reiterates that its relocation costs are reasonable and necessary and should be authorized.631

The ALJs conclude that ETI has the better argument. There is no allegation that ETI was too lavish in its relocation expenditures. The only complaint offered by Staff is that ETI’s overall compensation costs are 110 percent of the market median. It does not necessarily follow that the relocation program is unnecessary. ETI provided substantial evidence that, without a relocation program, it would be at a competitive disadvantage with its peers. Accordingly, the ALJs reject Staff’s request to disallow the Company’s relocation expenses.

6. Executive Perquisites In the application, ETI included, as part of its labor costs, $40,620 in costs associated with its executive perquisites. Those perquisites consist of financial counseling and tax gross-ups for system officers and executives. Specifically, the financial counseling program promotes maximizing investment growth opportunities for eligible officers and executives, and allows reimbursement for certain expenses incurred for personal financial counseling services.632 Staff recommends an

Staff Initial Brief at 64; Staff Ex. 1 (Givens Direct) at 24.

Staff Initial Brief at 64; Staff Ex. 1 (Givens Direct) at 24, citing Application of LCRA Transmission Services Corporation to Change Rates, Docket No. 28906, Final Order (Apr. 5, 2005).

ETI Initial Brief at 143.

Staff Ex. 1 (Givens Direct) at 23.

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adjustment to remove the full cost of the executive perquisites ($40,620), reasoning that the costs are not reasonable and necessary for the provision of electric utility service.633 ETI does not oppose that adjustment.634 The ALJs agree that the adjustment is warranted. Therefore, the ALJs recommend an adjustment to remove $40,620, representing the full cost of ETI’s executive perquisite costs.

E. Interest on Customer Deposits Staff witness Givens adjusted ETI’s requested interest expense of $68,985 by removing $(25,938) from FERC account 431.635 This decrease is a result of applying the interest rate of 0.12 percent for calendar year 2012 on deposits held by utilities.636 Using the active customer deposits amount of $35,872,476 and the 2012 interest rate, Ms. Givens calculated a recommended interest expense of $43,047 ($35,872,476 multiplied by .12 percent).637

This change, which reflects Commission-approved interest rates for 2012 as set in December 2011, complies with Project No. 39008 and ETI agreed with this amount. Accordingly, the ALJs recommend that the Commission approve this amount.

F. Property (Ad Valorem) Tax Expense During the Test Year, ETI’s property tax expense equaled $23,708,829.638 Patricia Galbraith, ETI’s Tax Officer, testified that a pro forma adjustment should be made to this level of expense for a known and measurable change that reflects the level of property tax expense ETI will experience in the Rate Year. Specifically, her proposed adjustment would increase the Test Year level of expense by $2,592,420 to $26,301,249.639 As Ms. Galbraith testified, ETI’s property tax expense for the calendar year 2012 will be paid in January of 2013 and be based on 2011 calendar Staff Initial Brief at 65; Staff Ex. 1 (Givens Direct) at 23.

ETI Initial Brief at 144.

Staff Ex. 1 (Givens Direct) at 24.

Setting Interest Rates for Calendar Year 2012, Project No. 39008, Order (Dec. 8, 2011).

Staff Ex. 1 (Givens Direct) at 24-25.

ETI Ex. 26 (Galbraith Direct) at 5; ETI Ex. 3 at Sched. G-9.

ETI Ex. 26 (Galbraith Direct) at 5 and PAG-1; ETI Ex. 3 at Sched. G-9.

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year-end values for both net operating income and net plant amounts.640 Her proposed adjustment is based on an expected ad valorem rate increase of 1 percent and expected increases in both net plant values and ETI net operating income that will equal 9.81 percent.641

TIEC, Cities, and Staff oppose the property tax adjustment proposed by ETI. TIEC argues that ETI’s proposed adjustment should be rejected entirely, on the grounds that it is not a known and measurable change from ETI’s Test Year property tax costs. Ms. Galbraith admitted that she does not know, with certainty, what the relevant property tax rate will be in 2012, nor has ETI received any tax bills advising that tax rates will rise.642 Thus, TIEC witness Pollock testified that ETI’s proposed adjustment is not known and measurable and recommended that the Commission reject the adjustment and include only the Test Year level of expense in cost of service.643 TIEC further points out that the Commission has twice rejected requests to include projected property tax expense in rates.644 For example, in Docket No. 28813, Cap Rock prepared an independent analysis indicating that property taxes were expected to increase to $2,700,000 per year from its test year tax level of approximately $900,000 per year. The analysis used an estimated tax assessment of $110,000 with an estimated tax rate of $2.47 per $100 of value. The ALJs in that case concluded that the property tax increases were estimates at the time of the hearing, and thus they were not known and measurable and should not be allowed.645 Subsequently, the Commission adopted the ALJs’

Tr. at 1235.

ETI Ex. 26 (Galbraith Direct) at PAG-1.

Tr. at 1221, 1238.

TIEC Ex. 1 (Pollock Direct) at 40–41.

In re Cap Rock Corp., Petition of PUC (Staff) to Inquire into the Reasonableness of the Rates and Services of Cap Rock Energy Corporation, Docket No. 28813, Order on Rehearing at FoF 137 (Nov. 9, 2005) (“Cap Rock failed to prove any increase in property taxes above those in the test year-$899,597-was known and measurable.”); Application of Gulf States Utilities Company for Authority to Change Rates, Application of Sam Rayburn G&T Electric Coop., Inc. for Sale Transfer or Merger, Appeal of Gulf States Utilities Company from Rate Proceedings of Various Municipalities, Docket Nos. 8702, 8922, 8939, 8940, 8946, 8233, 8944, 8945, 8947, 8948 and 8949, Order at FoF 111 (May 2, 1991) (“The 1988 calendar year level of actual property taxes paid should be used in determining rate year taxes because it is a known and measurable change.”).

Docket No. 28813, PFD at 99 (Mar. 17, 2005).

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finding.646 The Commission rejected a similar request from ETI’s predecessor Gulf States Utilities (GSU).647 In consolidated Docket No. 8702, the Commission rejected GSU’s request for projected 1989 property taxes and instead only allowed the actual calendar year property tax expenses.648 In both cases the Commission found that projected tax expense is not a known and measurable change.649 Accordingly, TIEC contends that ETI’s request for a forecasted tax expense increase should be rejected.650

Staff concedes that some level of increase is warranted but argues that the increase should be smaller than ETI is asking for. Rather than an increase of $2,592,420, Staff contends that ETI’s Test Year property tax expenses should be adjusted upward by only $1,214,688.651 Staff witness Givens arrived at this increase by applying the effective tax rate for the calendar year 2011 to the Staff’s Test Year end plant in service recommendation. She testified that both of these inputs to her calculation are known and measurable and thus may be used to determine the increase.652

Cities also concede that some level of increase is warranted, but argue that the increase should be smaller than ETI is asking for, and smaller than Staff proposes. Cities contend that ETI’s Test Year property tax expenses should be adjusted upward by only 1,134,442.653 Cities witness Garrett offered the opinion that ETI’s proposed adjustment was based on estimates that were unreasonably high when compared to the actual tax valuation increases experienced since 2008. Mr. Garrett arrived at his projected increase in tax expense by applying the average annual valuation increase experienced over the period of 2009-11 to net plant value for 2011. Cities argue that both

Docket No. 28813, Order on Rehearing at FoF 137 (Nov. 9, 2005).

Docket No. 8702, Order at FoF 111 (May 2, 1991).

Docket No. 8702, Order at 52.

Docket No. 28813, Order on Rehearing at FoF 137 (Nov. 9, 2005); Docket No. 8702, Order at 52, FoF (May 2, 1991).

TIEC Initial Brief at 54-56.

Staff Ex. 1 (Givens Direct) at 25.

Id. at 25-26.

Cities Ex. 2 (Garrett Direct) at 61.

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of these inputs to the calculation are known and measurable and thus may be used to determine the increase.654

ETI responds to its opponents by pointing out that the Commission has, in the past, recognized that the adjustment proposed by Staff, which was obtained by applying a historical effective tax rate to the level of test year end plant in service, is known, measurable, and appropriate.655 ETI also notes that, although it had not done so at the time Ms. Galbraith filed her testimony, ETI has since filed its 2011 year end FERC Form 1 data and now knows both the final net income amounts and net plant values for year end 2011 that will be used to determine the Company’s 2012 tax expense (that will be paid in January of 2013).656 ETI contends that those known values are substantially larger than the estimates used by Ms. Galbraith when she calculated the proposed adjustment, such that the known increases in 2011 net operating income and net plant amounts over 2010 are so large that, even without the 1 percent increase in tax rate assumed in the property tax adjustment, Rate Year property tax expenses will be larger than the $26,301,249 amount requested by the Company.657

The issue with regard to property taxes is whether a level of increase is known and measurable. The ALJs conclude that the approach taken by Staff does the best job of generating a known and measurable value for ETI’s property tax burden in the Rate Year. As explained above, Staff’s approach is supported by prior Commission precedent. Moreover, unlike the approaches advocated by ETI and Cities, Staff’s approach requires no guesswork about future tax rates.

Accordingly, the ALJs recommend that ETI’s property tax burden should be adjusted upward by

Id. ETI Initial Brief at 145; see also, Application of AEP Texas Central Company for Authority to Change Rates, Docket No. 28840, Final Order at FOF 189-191 (Aug. 15, 2005); Petition of General Counsel to Inquire Into the Reasonableness of the Rates and Services of Central Telephone Company of Texas, Docket No. 9981, 19 Tex. P.U.C. BULL. 936, 1080-82, 1217 (Sept. 8, 1993); Application of Central Power and Light Company for Rate Changes and Inquiry Into the Company’s Prudence with Respect to South Texas Project Unit 2, Docket No. 9561, 17 Tex. P.U.C. BULL. 157, 231-232 (Dec. 19, 1990).

Tr. at 1236-37.

ETI Initial Brief at 146-47.

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applying the effective tax rate for the calendar year 2011 to the final, adopted Test Year-end plant in service value for ETI.

G. Advertising, Dues, and Contributions In the application, ETI included, as part of its operating expenses, $2,046,214 in costs associated with advertising, dues, and contributions.658 Staff recommended an adjustment to remove $12,800, representing contributions to organizations primarily focused on influencing legislative activities. Staff reasons that these costs are not reasonable and necessary for the provision of electric utility service.659 ETI makes no response to the suggested adjustment.660 The ALJs agree that the adjustment is warranted. Therefore, the ALJs recommend an adjustment to remove $12,800 from ETI’s costs of advertising, dues and contributions.

H. Other Revenue-Related Adjustments Several items within the Company’s revenue requirement are interrelated. This means that changes to one area or item will impact one or more additional items, such as the Texas state gross receipts tax, the PUC Assessment tax, and Uncollectible Expenses.661 From the discussions in briefs, it does not appear that there are any substantive differences among the parties regarding these amounts, which will ultimately be determined during number running.

I. Federal Income Tax As explained by ETI witness Rory Roberts, the Company calculated its income tax expense in the cost of service by taking into account only the revenues and expenses included in the cost of service.662 To the extent the Commission makes changes to the revenues and expenses that are ultimately included in the cost of service, the income tax expense amount included in the cost of ETI Ex. 3, Sched. G-4.

Staff Initial Brief at 66; Staff Ex. 1 (Givens Direct) at 26.

ETI Initial Brief at 147.

Staff Ex. 1 (Givens Direct) at 28-29.

ETI Ex. 21 (Roberts Direct) at 10; Ex. 3 Sched. G-7.

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service will change accordingly. This represents a proper matching of income tax effects to the expenses and revenues that produced those tax effects.663

Mr. Roberts contended that the Commission’s past practice of reducing tax expense for a consolidated tax adjustment based on some measure of the tax “savings” the utility realized by joining in a consolidated group federal income tax return was inappropriate. He testified that it is improper to reduce tax expense for deductions or losses that are not also included in the cost of service. In the case of the Commission’s consolidated tax adjustment, tax expense is reduced to the extent that utility income is used to offset non-utility affiliate losses, even though those losses are not included in cost of service or borne in any manner by the utility’s customers.664

Despite his disagreement with the approach, Mr. Roberts performed a calculation of the adjustment using the interest credit methodology adopted by the Commission. He concluded that, instead of positive taxable income, ETI had net tax losses over the 15-year calculation period and thus provided no taxable income that could be used to offset affiliate losses.665 In fact, over the 15-year period, ETI’s tax losses were offset by taxable income produced by other affiliates. Thus, ETI contends that, were the Commission to be consistent in applying its interest credit methodology, it should increase ETI tax expense included in cost of service due to the fact that its affiliates’ taxable income had to be used to offset ETI’s tax losses. Nevertheless, in its application, ETI rejected the interest credit methodology and has not requested that ETI’s tax expense be increased as a result of the consolidated tax adjustment calculation. No other party to the proceeding challenged the Company’s position on federal income tax expense in testimony or at the hearing. The ALJs find no reason to do so either.

J. River Bend Decommissioning Expense ETI has an ownership interest in River Bend. In the application, ETI requested that $2,019,000 be included in its cost of service to account for the Company’s annual decommissioning ETI Ex. 21 (Roberts Direct) at 10.

Id. at 10-11.

Id. at 10, and RLR-5.

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expenses associated with River Bend.666 This is the same amount that was requested and approved on December 13, 2010, in Docket No. 37744.667 The amount of $2,019,000 was derived from an ETI decommissioning study that was completed in 2009. In this case, ETI chose not to propose any change to its 2009 estimate. ETI contends that this decision is supported by an August 9, 2011, letter from the Nuclear Regulatory Commission.668

Cities argue that the decommissioning expense should be reduced to $1,126,000.669 Cities point out that the larger amount sought by ETI was merely the amount agreed to by the parties, as opposed to being substantively considered and approved by the Commission in Docket No. 37744.670 In the current case, ETI was asked through discovery to provide an updated estimate of the annual decommissioning expense responsibility for Texas retail customers calculated using the most current Texas jurisdictional decommissioning fund balance. ETI responded that the current annual decommissioning revenue requirement is $1,126,000.671

Under P.U.C. SUBST. R. 25.231(b)(1)(F)(i), the annual cost of decommissioning for ratemaking purposes must “be determined in each rate case based on . . . the most current information reasonably available regarding the cost of decommissioning, the balance of funds in the decommissioning trust, anticipated escalation rates, the anticipated return on the funds in the decommissioning trust, and other relevant factors.” The cost determined must then be expressly included in the cost of service established by the Commission’s order.

The parties agree that $1,126,000 is the best estimate of the current annual revenue requirement to meet ETI’s estimated decommissioning cost. However, ETI relies on P.U.C. SUBST.

R. 25.231(b)(1)(F)(iv) and Staff witness Cutter’s testimony to contend that it need not adjust the ETI Ex. 3 Scheds. M-1 and M-2; ETI Ex. 8 (Considine Direct) at 57-58.

ETI Ex. 8 (Considine Direct) at 58.

Id. at 58 and MPC-2.

Cities Ex. 2 (Garrett Direct) at 64-65.

Application of Entergy Texas, Inc. for Authority to Change Rates and Reconcile Fuel Costs, Final Order at FoF 32 (Dec. 13, 2010); Cities Initial Brief at 73.

Tr. at 348-49.

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current amount being charged.672 Pursuant to subpart (iv), ETI is required to periodically study its decommissioning costs, and such a study must be done “at least every five years.” Because its last study was done in 2009, ETI contends that it need not do a new study now, but may simply rely of the outcome of its last study, which showed that its annual revenue requirement is $2,019,000.673

Cities agree that ETI is not required to conduct a new decommissioning study at this time.

However, the most current information reasonably available clearly shows that the annual amount required to meet the total cost determined in the Company’s last decommissioning study has decreased. Cities argue that to ignore the most current information available disposal would unreasonably shift future costs to current customers and would be a violation of P.U.C. SUBST.

R. 25.231(b)(1)(F)(i). The ALJs agree. ETI’s annual decommissioning revenue requirement should reflect the most current calculation of $1,126,000. Therefore, an adjustment of $893,000 to the pro forma cost of service is needed to reflect the difference between the requested level for decommissioning costs of $2,019,000 and recommended level of $1,126,000.

K. Self-Insurance Storm Reserve Expense [Germane to Preliminary Order Issue No. 5] In prior dockets, the Commission authorized ETI to recover $3,650,000 annually for storm damage expenses and to maintain a reasonable and necessary storm damage reserve account of $15,572,000.674 ETI requests to increase the authorized storm damage reserve account to $17,595,000 (an increase of $2,023,000) and to increase the annual accrual to $8,760,000 (an increase of $5,110,000). ETI’s proposed annual accrual is composed of two elements: (1) an annual accrual of $4,890,000 to provide for average annual expected losses from all storms that do not exceed $100 million; and (2) a 20-year annual accrual of $3,870,000 to bring the reserve up from its current deficit of $59,799,744 to ETI’s target reserve of $17,595,000.

No party disputes that ETI’s proposal to self-insure for catastrophic property loss is appropriate under PURA § 36.064 and P.U.C. SUBST. R. 25.231(b)(1)(G). However, Cities, OPC, ETI Ex. 46 (Considine Rebuttal) at 38-39.

Id. Staff Ex. 4 (Roelse Direct) at 8.

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and Staff oppose the amount of ETI’s proposed annual accrual, and Cities and OPC also oppose ETI’s proposed target reserve. The parties’ recommendations are:

Annual Accrual Target Reserve Current $3,650,000 $15,572,000 ETI $8,760,000 $17,595,000 Cities $6,150,339 $15,572,000 OPC-1 $2,335,047 $15,572,000 OPC-2 $3,650,000 $15,572,000 Staff $8,270,000 $17,595,000 The first component of ETI’s requested annual accrual is $4,890,000 for expected annual losses. ETI explains that this is the amount of annual losses projected to be incurred by ETI from all storm damage, except those over $100 million (the minimum amount likely to be securitized),675 adjusted to reflect current conditions and current cost levels.676 This recommended accrual was calculated by ETI witness Gregory Wilson using a Monte Carlo simulation of ETI’s loss history.677 A statistical distribution was estimated from ETI’s trended loss experience, and the model indicated an average annual loss of $4,890,000. Mr. Wilson excluded losses from Hurricanes Rita, Gustav, and Ike from the model because those losses were securitized and not recovered through the insurance reserve.678 ETI adds that results from the model simulation were also adjusted by removing any simulated year in which the total storm loss exceeded $100 million, which would likely be securitized.

The second component of the proposed annual accrual is $3,870,000 per year for 20 years to restore the reserve from the current deficit of $59,799,744 up to the $17,595,000 requested target level. In ETI’s opinion, a 20-year period balances the interests of future and past ratepayers. It

ETI Ex. 19 (McNeal Direct) at 32.

ETI Ex. 14 (Wilson Direct) at 5.

Id. at Ex. GSW-3.

Id. at 9.

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added that Mr. Wilson’s calculations were prepared in accordance with generally accepted actuarial procedures, with certain adjustments to reflect the nature of ratemaking for public utilities.679

ETI also requests a target reserve of $17,595,000. It argues that this would be an actuarially sound provision to cover self-insured losses. ETI noted that the target reserve was also developed by Mr. Wilson through the Monte Carlo simulation based upon the ETI’s loss history.680

Cities recommend maintaining the current target reserve of $15,572,000 and adopting an annual storm damage accrual of $6,150,399. Cities’ proposed annual accrual is comprised of two parts: (1) keeping the current accrual of $3,650,000 for projected annual storm expense; and (2) adding $2,500,399 annually to bring ETI’s reserve deficit amount, as adjusted by Cities, up to a target reserve of $15,572,000. Cities’ witness Jacob Pous testified that the current target reserve of $15,572,000 should be maintained given ETI’s plan to divest itself of the transmission system, which would reduce storm damage expenses.681 For the same reason, Mr. Pous also stated that the Commission should maintain the current annual accrual amount that was approved most recently in Docket No. 37744.682

According to Cities, ETI witness Wilson acknowledged that his calculations assumed that the current transmission system would be owned by ETI, and if the transmission system were sold, his analysis would need to be adjusted.683 Cities also note that Mr. Wilson included ETI’s 1997 ice storm expenses within the historical storm data used for his calculations.684 As discussed in Section V.F., Cities challenge these expenses. If the Commission determines that those costs should be excluded, Mr. Wilson agreed that it would be inappropriate to include them in his analysis.685 In addition, Cities stated, Mr. Wilson’s Monte Carlo model analysis has been rejected in several cases ETI Ex. 14 (Wilson Direct) at 11-12.

Id. at 9.

Cities Ex. 5 (Pous Direct) at 65-66.

Id. at 66; see also Docket No. 37744, Final Order at FoF 31 (Dec. 13, 2010).

Tr. at 1247.

Tr. at 1244-1246.

Tr. at 1246-1247.

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by the Commission, as noted by Staff witness Chris Roelse.686 Cities noted that Mr. Wilson limited the storm reserve expense in his model to $100 million, as anything over that amount might be securitized.687 But, Cities contend, Mr. Wilson did not consider that the storm loss history provided to him by ETI included only storm damage expenses and not capital costs, which are also included when determining the amount capable of being securitized. Thus, in Cities opinion, Mr. Wilson’s cap of $100 million was overstated, and for all these reasons Cities argues that Mr. Wilson’s analysis should not be considered reliable.

Finally, Cities note that ETI requested that the annual storm reserve accrual “would be made . . . only until it reaches the recommended target level, at which point contributions to the reserve would reduce to the lower of annual expected losses or actual losses.”688 In Cities view, this request should be rejected and the accrual should only be modified through a future rate case.

OPC also recommends adjustments to the storm damage reserve and the annual accrual. As discussed in Section V.F., OPC argues that ETI failed to prove that its storm damage expenses booked since 1996 were reasonable and prudently incurred. Consequently, OPC recommends disallowing all of those charges. Removing those charges would leave ETI with a positive storm reserve balance of $41,871,059, which exceeds the currently approved storm reserve balance of $15,572,000 by $26,299,059. OPC witness Benedict proposed that this surplus be refunded to rate payers at a rate of $1,314,953 per year for 20 years. He also recommended that current annual storm damage accrual of $3,650,000 be maintained, less his proposed customer refund of $1,134,953 per year, leaving a net annual storm damage accrual of $2,335,047 per year. Mr. Benedict acknowledged that some storm damage expenses incurred by ETI since 1996 likely were reasonable and necessary. Therefore, as an alternative proposal, Mr. Benedict suggested that ETI’s current storm balance reserve be set at the last approved amount of $15,572,000 (i.e., without any surplus or deficit) and that the currently approved total annual accrual of $3,650,000 be maintained. In

Staff Ex. 4 (Roelse Direct) at 12.

ETI Ex. 14 (Wilson Direct) at 9.

ETI Initial Brief at 151.

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addition, OPC argues that Mr. Wilson’s Monte Carlo model analysis was flawed because it included expenses that ETI did not establish were reasonable and prudently incurred.689

Staff witness Chris Roelse agreed that ETI’s proposed target reserve of $17,595,000 is reasonable. However, he recommended an annual accrual of $8,270,000, which is $490,000 less than ETI’s request. Mr. Roelse pointed out that ETI’s witness calculated the proposed annual accrual based on a Monte Carlo simulation, which projects a loss experience over a longer time than the period captured in the available loss history. However, Mr. Roelse stated, the Commission has not approved the use of these models in prior dockets; instead, it has relied on averaging known insurance losses over a period of time to compute the annual accrual. Using historical loss data, Mr. Roelse calculated an annual expected storm loss of approximately $4,400,000. When this amount is added to the proposed annual accrual of $3,870,000 to restore the reserve balance from its current deficit, it produces a total annual accrual of $8,270,000, which Staff recommends.690

In response, ETI agreed that if portions of the underlying costs upon which the Monte Carlo analysis was performed are removed from the reserve, then the outcome of Mr. Wilson’s analysis would be different. However, ETI stressed that questions about the underlying expenses are not an attack on the Monte Carlo analysis itself. Rather, Mr. Wilson provided an analysis based upon information supplied by ETI, and he did not claim to support the expenses themselves. But ETI disagreed with the challenges to the underlying costs, as discussed in Section V.F.691

Most of Cities’ and OPC’s objections to ETI’s requested storm damage annual accrual and target reserve relate to their objections to the underlying expenses, as discussed in Section V.F. For the reasons stated in that section, the ALJs denied those objections, and they do not support rejecting ETI’s request for the annual accrual or target reserve. Likewise, the ALJs find that Cities’ concerns about ETI selling its transmission system are too uncertain to justify altering the storm damage reserve at this time.

OPC Ex. 6 (Benedict Direct) at 6-16; OPC Initial Brief at 14-20; OPC Reply Brief at 13-15.

Staff Ex. 4 (Roelse Direct) at 10-15; Staff Initial Brief at 13-14.

ETI Reply Brief at 81.

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Cities also raised a question about whether Mr. Wilson properly calculated the cap he used to exclude from his analysis storms that would likely result in securitized costs. Staff pointed out that the Commission has not approved the use of the Monte Carlo simulation model in prior dockets.

Rather, the Commission has traditionally used known insurance losses over a period of time. The ALJs note that neither PURA nor the Commission’s rules either require or prohibit the use of actuarial models, such as the Monte Carlo simulation. The prior dockets cited by Staff did not adopt the recommendations developed by actuarial models, but the Commission also did not expressly reject the models in those cases. Likewise, however, ETI has not cited any Commission decisions that expressly adopted or used such models.

Staff witness Chris Roelse explained that the Commission has traditionally averaged known insurance losses over a period of time to compute the annual accrual. He made such a calculation that produced an annual accrual for storm damage loss of $4,400,000. When added to the proposed annual accrual of $3,870,000 to restore the reserve balance from its current deficit, the total annual accrual equals $8,270,000. No party challenged that calculation. Because a question remains as to whether Mr. Wilson properly calculated his cap to exclude storm damage expenses that would likely be securitized, the ALJs find it is more reasonable to adopt the annual accrual proposed by Staff.

Therefore, the ALJs recommend that the Commission approve a total annual accrual of $8,270,000, comprised of an annual accrual of $4,400,000 to provide for average annual expected storm losses, plus an annual accrual of $3,870,000 for 20 years to restore the reserve from its current deficit. The ALJs also recommend approval of ETI’s proposed target reserve of $17,595,000. Finally, the ALJs recommend that the Commission require ETI to continue recording its annual accrual until modified by an order in a future rate case, as requested by Cities. Otherwise, ETI could continue to receive rates based on the total accrual amount, but not record the receipts in the storm damage reserve. The ALJs find that such circumstances would not result in just and reasonable rates.

L. Spindletop Gas Storage Facility Cities challenged ETI’s use of the Spindletop Facility, arguing that the costs of operating it outweigh the benefits gained from it. In Section V.H., the ALJs rejected Cities’ contention that a substantial portion of ETI’s annual costs to operate the Spindletop Facility should be removed from SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 194 PUC DOCKET NO. 39896

ETI’s rate base. For the same reason he challenged the Spindletop Facility costs associated with rate base, Cities witness Nalepa also challenges a portion of ETI’s costs derived from the Spindletop Facility that are associated with operating expenses. Specifically, Mr. Nalepa and Cities argue that $2,090,116 (consisting of $309,751 in depreciation expense and $1,780,365 associated with the Spindletop Facility) ought to be removed from ETI’s operating expenses.692 For the same reason that they rejected Cities’ Spindletop Facility arguments relevant to rate base, the ALJs also reject Cities’ Spindletop Facility arguments relevant to operating expenses.

VIII. AFFILIATE TRANSACTIONS [Germane to Preliminary Order Issue No. 3] PURA requires that more stringent standards be applied to affiliate expenses than are applied to other utility company expenses. Section 36.058 begins by stating “except as provided by Subsection (b),” the PUC may not allow as capital cost or as expense a payment to an affiliate for the cost of a service, property, right, or other item or interest expense. Subsection 36.058(b) provides that the Commission may allow an affiliate payment “only to the extent” that the PUC finds the payment is reasonable and necessary for each item or class of item as determined by the Commission.

The seminal case interpreting PURA’s affiliate transaction standard under Section 36.058 is Railroad Commission v. Rio Grande Valley Gas Company.693 In that case, the court recognized that PURA’s affiliate transaction statute created a presumption that a payment to an affiliate is unreasonable. The court explained:

Rio’s entire approach has been that the Commission is required to allow the residual affiliate charges unless they are shown to be imprudent, unreasonable, or out of line.

Although this may be true with respect to arms length transactions, it is not true with respect to affiliates about which the Legislature has its suspicion and which to any reasonable mind are clearly tainted with the possibility of self-dealing.

Cities Ex. 6 (Nalepa Direct) at 19; Cities Initial Brief at 76. 683 S.W. 2d 783 (Tex. App.—Austin 1985, no writ).

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The court went on to state that the burden was upon Rio to show that its affiliate charges were just and reasonable. The court interpreted the PURA affiliate transaction statute and explained four major areas in which Rio had failed to meet its burden of proof:

x Plaintiff had the burden of showing that the prices it was charged by its affiliate were no higher than the prices charged by the supplying affiliate to its other affiliates. . . . x Plaintiff had the burden of showing that expenses which may not be allowed for rate making purposes for any reason . . . were not included in the “allocated expenses.” . . . x Plaintiff had the burden of proving that each item of allocated expense was reasonable and necessary. . . . x Plaintiff had the burden of proving that the allocated amounts reasonably approximated the actual cost of services to it. . . .

In 2000, the Third Court of Appeals once again spoke on the issue of affiliate transactions in the utility setting. In Central Power and Light Company/Cities of Alice v. Public Utility Commission, the court cited to Rio Grande Valley Gas Company and stated:

Because of the possibility for self-dealing between affiliated companies, however, expenses paid to an affiliated entity are presumptively not included in the rate base.

A utility can overcome this presumption against affiliate expenses only if it demonstrates that its payments are ‘reasonable and necessary for each item or class of items as determined by the commission.’694 PURA Section 36.058 places a greater burden of proof on the utility to prove the reasonableness and necessity of its affiliate transactions because of the nature of the relationship between the utility and its affiliates. These transactions are not considered to be arms-length, and there is a potential for self-dealing. The transactions must be disallowed for regulatory purposes, unless the utility presents sufficient evidence that it has met each of the affiliate transaction statutory requirements. If the regulatory tests for affiliate transactions are not properly enforced, the regulated utility may become a vehicle for cross-subsidization by ratepayers of other regulated or unregulated affiliates.

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OPC witness Szerszen was the only witness to challenge ETI’s affiliate transactions,695 recommending a total affiliate disallowance (after erratas) of $8,945,221.696 Dr. Szerszen reviewed a select subset of ETI’s affiliate expenses using the PURA affiliate transaction standards. She reviewed the Company’s affiliate transactions on a project by project basis, noting that such a review was more efficient and easier to understand.697 Dr. Szerszen testified that a review by the Company’s 25 classes of service presents a far too macro view of affiliate transactions that does not allow an adequate review of ETI’s affiliate transactions according to PURA mandates and takes the focus away from the important issues.698

OPC notes that PURA Subsection 36.058(f) requires that if the Commission finds an affiliate expense for the test period to be unreasonable, then the Commission is to make a determination of what level of the expense is reasonable. By analyzing ETI’s affiliate transactions on a project basis, OPC contends that it has facilitated the Commission’s ability to make such a determination for each of ETI’s classes of service; instead of an “up or down” decision on the macro level of expense for the class, the Commission can disallow the portion not shown to be reasonable and approve the remainder as reasonable.

ETI disagrees with OPC’s contentions and argues that Dr. Szerszen’s approach to addressing the Company’s affiliate case is inappropriate for a number of reasons and should be rejected.

x First, her approach is directly contrary to the Commission’s Guiding Principles included as part of the Commission’s Transmission and Distribution Cost of Service Rate Filing Package that was issued on April 2, 2003.699 Item 2 of the Guiding Principles clearly states that a class of Cities witness Mark Garrett recommended disallowance of certain short-term incentive compensation affiliate costs, but those disallowances are largely also recommended by Dr. Szerszen. See ETI Ex. 69 (Tumminello Rebuttal) at 17. ETI contends that the duplicated disallowances by Dr. Szerszen and Mr. Garrett would result in double counting $217,520 of the requested affiliate charges and requests that if the ALJs rule in OPC’s and Cities’ favor regarding these short-term incentive compensation costs, that disallowance should be reduced by $217,520. ETI Initial Brief at 157, n. 898.

Tr. at 1607.

OPC Exhibit No. 1 (Szerszen Direct) at 42-43.

OPC Exhibit No. 1 (Szerszen Direct) at 42-43; Tr., at 1671-72.

See ETI Ex. 69 (Tumminello Rebuttal) at Ex. SBT-R-1.

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service approach is required for purposes of complying with the provisions of Section 36.058 of PURA.700 Dr. Szerszen ignores the class of service approach required by Section 36.058 of PURA as detailed in the Guiding Principles, and instead states OPC’s case on a project code-by- project code basis. x Second, Dr. Szerszen’s approach is directly contrary to the Commission’s directives in Docket No. 16705. In that docket, the Commission disallowed a substantial amount of affiliate expense because Entergy Gulf States, Inc. had done then what Dr. Szerszen proposes here – based the affiliate analysis solely on project codes, rather than affiliate classes of service. Because the Commission found that a scope statement/project code-based affiliate analysis is “impossible,” the Company, in its subsequent base rate cases, including its filing in this docket, changed to a class-based presentation, as directed by the Commission. x Third, by refusing to consider a class-based analysis, Dr. Szerszen has ignored the Company’s testimony, presented by 19 affiliate witnesses, which explains in detail why the Company’s affiliate-incurred costs meet the Section 36.058 of PURA and Rio Grande standards.701 According to ETI, the Company’s affiliate class witnesses, who are knowledgeable about the activities that are encompassed in each of their classes, have each shown why the services provided through those classes are necessary. They have each also addressed numerous Commission-recommended metrics to measure the reasonableness of costs, including cost trends, staffing trends, the budgeting process, and, if applicable, benchmarking and outsourcing comparisons.702 Their testimony and exhibits, according to ETI, show numerous different “views” of the costs in their classes, including the project codes that comprise their classes.

Each affiliate witness also addressed the “not higher than” and “reasonably approximates cost” standards applicable to affiliate costs. ETI contends that the evidence provided by its witnesses meets the requirements of these Guiding Principles and supports the Company’s burden of proof for the recovery of affiliate costs. ETI also contends that Dr. Szerszen ignores this overwhelming evidence and the careful attention paid to presenting it in an organized manner. In addition, she presents no evidence in accordance with the Guiding Principles that supports her proposed disallowances. x Fourth, the Company’s case is much less cumbersome and less complex than the approach suggested by OPC, which would require a showing on the necessity, reasonableness, “not higher than,” and “reasonably approximates cost” standards for each of almost 1,300 project codes subject to this docket. Even if the Company were to do that, Dr. Szerszen’s “cherry picking” approach among the project codes ignores any savings in other project codes that would Dr. Szerszen conceded that the Guiding Principles require that a utility’s affiliate case be presented in a sufficient number of class or other logical groupings. Tr. at 1632.

Dr. Szerszen claimed that, instead of considering the narrative class testimony, she instead “looked at more of the detail,” presumably meaning the exhibits. Tr. at 1629.

ETI Ex. 69 (Tumminello Rebuttal) at Ex. SBT-R-1. Dr. Szerszen conceded that the Company’s testimony included proof items such as benchmarking data, outsourcing, staffing trends, and cost trends. Tr. at 1631.

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comprise a class of affiliate costs, thereby resulting in an overall reasonable level of costs within the class even assuming that any of her complaints about individual project codes had merit. x Fifth, ETI contends that Dr. Szerszen fails to mention Section 36.058(f) of PURA, which requires that the Commission determine the reasonable level of “an affiliate expense” if it first finds that the expense presented is unreasonable. But rather than offering an alternative “reasonable” level of an expense“”, she either categorically disallows all costs in that project; or, in some instances, substitutes an arbitrary sharing or allocation of costs between ETI and its regulated affiliates, or ETI and its non-regulated affiliates. In doing so, Dr. Szerszen does not make any evidence-based attempt to ground her alternative allocation (and associated disallowance of ETI affiliate costs) on any objective basis reflecting cost causation principles.

ETI contends that the effect of her approach is to presume that the Company needs zero dollars in its cost of service to perform a variety of essential utility support activities. x Sixth, Dr. Szerszen’s positions in the 2009 Oncor rate case,703 which she agrees are similar to her positions in this ETI base rate case,704 were rejected by the two SOAH ALJs and the Commission in that docket. ’’Many of the allegations and arguments made by Dr. Szerszen in this case are very similar, if not identical, to the points she asserted in the Oncor case.

The ALJs agree that the Commission’s Guiding Principles set forth the minimum that a utility must present to establish a prima facie case, and it is clear that ETI met that burden. That, however, is not the end of the question. Permitting a utility to escape further scrutiny of its affiliate transactions by resting on its prima facie presentation imposes too many limits and, as suggested by OPC, presents too macro a view to be a legitimate review for rate case purposes.

OPC performed essentially a sample review of ETI’s affiliate transactions. The review was not exceptionally large, and (as evidenced by ETI’s concurrence in the removal of some of the costs) it represented an additional layer of review to ensure that improper costs would not inadvertently be charged to ratepayers. That, of course, is not the sole focus of OPC’s review, but it is important for purposes of determining whether the review itself is appropriate. If intervenors and Staff were limited to the macro level of review urged by ETI, such matters would never be revealed and there would exist a possibility that ratepayers would be charged for matters not their responsibility. The ALJs do not characterize OPC’s review as “cherry picking.” It is more a reasonable sample for Application of Oncor Electric Delivery Company, LLC for Authority to Change Rates, Docket No. 35717 (PFD issued on Jun. 2, 2009; Order on Rehearing issued on Nov. 30, 2009) (Oncor).

Tr. at 1656.

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examination that gives ETI a reasonable opportunity to explain the reasons for the charges to ratepayers. Accordingly, the ALJs find that the Commission’s Guiding Principles do not limit the review performed by OPC, and the review performed by OPC is not contrary to the Commission’s holdings in Docket No. 16705.

A. Large Industrial & Commercial Sales Reallocation OPC contends that ETI incurs considerable amounts of sales and marketing expenses that are exclusively for the benefit of the larger commercial and industrial customers. However, most of ESI’s sales, marketing, and customer service expenses are allocated to residential and small business customers.705 The vast majority of the sales, marketing and customer service expenses are allocated to the operating companies based on customer counts, the majority of these expenses are consequently allocated to residential and small business customers. In the test year, residential and small general service customers made up 94.8 percent of the ETI total customer count. ETI’s General Service, Large General Service, and Large Industrial Power Service, and Lighting classes combined comprise only 5.2 percent of ETI’s customers. For the test year, OPC argues that ETI is requesting the recovery of $2.086 million of sales, marketing, billing and load research expenses that benefitted only the large customer service classes. OPC contends that it is inappropriate for residential and small customers to pay for these expenses, when cost causation is so readily identifiable, particularly since a disproportionately small portion of larger customer sales and marketing expenses is allocated to ETI’s largest customers.706 The total recommended reallocated large customer expense is $2,086,145.

ETI and TIEC oppose OPC’s recommendation, arguing that it is “cherry-picking” and that the evidence does not demonstrate that the $2.086 million of affiliate expense should be directly assigned to the large commercial and industrial classes.707

OPC Ex. 1 (Szerszen Direct) at 45.

OPC Ex. 1 (Szerszen Direct) at 45.

ETI Ex. 55 (LeBlanc Rebuttal) at 5; TIEC Ex. 3 (Pollock Cross Rebuttal) at 36.

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With respect to the first argument, ETI and TIEC contend that Dr. Szerszen developed her adjustment by examining a limited sample of affiliate project code summaries and making the call, based on project code descriptions, that certain affiliate costs for marketing, sales and customer service expense should be directly assigned to large commercial and industrial customers.708 Both TIEC and ETI contend that the bias and results-oriented nature of her recommendation became apparent when Dr. Szerszen admitted on cross examination that she made no effort to examine whether certain affiliate costs should be directly assigned to residential and small customers.709 Both ETI and TIEC contend that it is inappropriate to take a “limited sample of costs” and directly assign them to a particular class.

According to TIEC, Dr. Szerszen admitted that it could have been appropriate to make an adjustment for direct assignment of costs to small commercial and residential customers based on principles of cost causation.710 However, she made no effort to do that herself, nor did she ask ETI to conduct such an analysis.711 The parties argue that the evidence shows that Dr. Szerszen’s recommendation rests on an incomplete analysis of ETI’s affiliate costs and her recommendation should be rejected because direct assignment of costs is only appropriate if there has been a thorough and complete cost study analysis to determine what costs are or are not appropriate for direct assignment to all of the classes.

TIEC further argues that the evidence did not demonstrate that the $2.086 million of affiliate expense that Dr. Szerszen proposes for direct assignment to large commercial and industrial customers is solely attributable to costs caused by those customers. Mr. Pollock testified that the project codes Dr. Szerszen selected include load research expenses that benefit residential and small commercial customers.712 TIEC pointed out that ETI witness Stokes testified that the billing methods used for the affiliate expenses for customer service operations and retail operations were

Tr. at 1609.

Tr. at 1609-10.

Tr. at 1685.

Tr. at 1613-1624.

TIEC Ex. 3 (Pollock Cross Rebuttal) at 35.

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fair and reasonable.713 According to TIEC, Dr. Szerszen’s proposal should be rejected because her assertion that these expenses exclusively benefit large commercial and industrial customers is incorrect.

The ALJs have reviewed the arguments of the parties and find that Dr. Szerszen’s analysis is far from complete. It appears to be result-oriented, ignoring critical aspects (such as failing to make an adjustment for direct assignment of costs to small commercial and residential customers based on principles of cost causation). The ALJs believe that Dr. Szerszen’s analysis with respect to this issue should not be adopted.

B. Administration Costs Dr. Szerszen recommended disallowance of $94,709 (25 percent) of the charges in Project F3PCFACALL, contending that ESI failed to directly charge any of the costs in this project code to ETI. She claimed that the billing method applied to this project code by ESI (that is, Billing Method “SQFALLC”), which is based on square footage, is not appropriate for these types of costs.714

ETI witness Plauche explained that the costs captured in this project code are primarily for the oversight of administrative functions, such as facilities, real estate, and security.715 This project code applies to the administration of these types of functions. These services benefit all companies that receive facility services and are not attributable to any one specific Entergy affiliate. Therefore, it is appropriate to bill these costs to all companies based on their pro rata share of square footage occupied.716

The ALJs concur that this is the appropriate method to employ and, therefore, recommend that the Commission approve the inclusion of these costs as requested by ETI.

ETI Ex. 66 (Stokes Rebuttal) at 3.

OPC Ex. 1 (Szerszen Direct) at 80-82.

ETI Ex. 20 (Plauche Direct) at 15-26.

ETI Ex. 69 (Tumminello Rebuttal) at Ex. SBT-R-2 at 10.

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C. Customer Service Operations Class Dr. Szerszen recommended disallowances in seven project codes covered primarily by ETI’s Customer Service Operations Class: (1) F3PCR29324 (Revenue Assurance - Adm.) for a disallowance of $70,849; (2) F3PCR53095 (Headquarter’s Credit & Collect) for a disallowance of $110,338; (3) F3PCR73380 (Credit Systems) for a disallowance of $73,562; (4) F3PCR73458 (Credit Call Outsourcing) for a disallowance of $197; (5) F3PCR73381 (Customer Svc Cntr Credit Desk) for a disallowance of $43,378; (6) F3PCR73390 (Customer Svs Ctl - Entergy Bus) for a disallowance of $60,926; and (7) F3PCR73403 (Customer Issue Resolution – ES) for a disallowance of $1,869.717

1. Projects F3PCR29324 (Revenue Assurance - Adm.), F3PCR53095 (Headquarter’s Credit & Collect), F3PCR73380 (Credit Systems), and F3PCR73458 (Credit Call Outsourcing) For the costs captured by these project codes, Dr. Szerszen recommended that the costs be reallocated based on the Company’s 10 percent “bad debt” expense percentage.

ETI witness Stokes responded that the costs captured by these project codes are for management and supervision of credit, collection, and revenue assurance activities for all of the Operating Companies. These functions ensure the most efficient processes are used in managing write-offs for all the Operating Companies and have contributed to Entergy’s first quartile ranking in benchmarking of credit and collection operations. These managerial and supervisory costs, which include bankruptcy administration, surety administration, arrears management, collection agency administration, skip tracing, and final bill collections, remain consistent whether ETI’s bad debt percentage is 10 percent, 30 percent, or any other percent and are appropriately allocated using the CUSTEGOP billing method, which is based on the number of electric and gas customers for each Operating Company.718

OPC Ex. 1 (Szerszen Direct) at 76-78.

ETI Ex. 66 (Stokes Rebuttal) at 15-16.

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ETI has provided credible evidence that it has chosen the correct billing methodology.

Therefore, the ALJs recommend the Commission approve inclusion of these costs as requested by ETI.

2. Projects F3PCR73381 (Customer Svc Cntr Credit Desk), F3PCR73390 (Customer Svs Ctl - Entergy Bus), and F3PCR73403 (Customer Issue Resolution – ES) Dr. Szerszen recommended that these costs be reallocated using the CUSTCALL billing method. Given ESI’s demonstrated tracking capabilities, Dr. Szerszen reallocated the costs of this project using a 10.8 percent customer call allocator, which is on the low end of the 10.70 percent-11.04 percent Test-Year CUSTCALL allocators.719

ETI witness Stokes believes that Dr. Szerszen’s proposed reallocation is arbitrary and fails to consider the cost causation associated with the actual project code at issue. These costs are not driven by a specific proportion of calls from each Operating Company (that is, by the CUSTCALL allocator). The costs captured by Project F3PCR73345 reflect the costs of overseeing the Quick Payment Center vendors in each of the Entergy Operating Companies, regardless of the number of calls by customers to the Company.

The ALJs are persuaded that the allocation methodology chosen by ETI is the superior method and that the CUSTCALL allocator would not be appropriate given the cost causation associated with the project. Accordingly, the ALJs recommend the Commission approve the costs proposed by ETI.

D. Distribution Operations Class Dr. Szerszen addressed three project codes that are within the Distribution Operations Class: (1) F5PCDW0200 (Lineman’s Rodeo Expenses) for a disallowance of $7; (2) F3PCTJGUSE (Joint

OPC Exhibit No. 1 (Szerszen Direct) at 77 and 118; OPC Exhibit No. 27 (ETI’s Ex. SBT-15, Attachment 6) at 2; Tr., at 838-839.

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Use With Third Party – E) for a disallowance of $6,405; and (3) F3PCTJTUSE (Joint Use With 3rd Parties – A) for a disallowance of $36,293.720

1. Project F5PCDW0200 (Lineman’s Rodeo Expenses) Dr. Szerszen claimed that the expenses captured by this project should be disallowed because ETI is a monopoly and Texas ratepayers should not have to pay for corporate image costs.

ETI witness Tumminello responds, stating that this minimal amount is related to a safety competition known as the “Lineman’s Rodeo,” it is not a corporate “image” expense. The cost, according to Ms. Tumminello, is driven by Entergy employee safety in the Distribution business units.721

The ALJs agree that the Lineman’s Rodeo competition is not a corporate image expense, rather it is designed to promote employee safety. The ALJs recommend the Commission approve inclusion of the costs captured by this project as requested by ETI.

2. Projects F3PCTJGUSE (Joint Use With Third Party – E) and F3PCTJTUSE (Joint Use With Third Parties – A) Dr. Szerszen recommends exclusion of these two projects, which she claims represent the difference between the costs incurred for ETI for pole rental costs and the revenues received from pole space rentals.

With respect to this proposed disallowance, ETI witness McCulla states that Dr. Szerszen has confused the rental of space on transmission poles and the rental of space on distribution poles. She has essentially performed a cost-benefit analysis that erroneously compares the cost of providing rental space on distribution poles with the income received solely from rental of space on transmission poles. Mr. McCulla explained that data for the distribution poles show that the more than $2.5 million in revenues from distribution pole rentals far exceeds the $67,174 in costs billed to OPC Ex. 1 (Szerszen Direct) at 66, 75.

ETI Ex. 41 (Tumminello Direct) at Ex. SBT-E at 1234.

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ETI under these two project codes and, therefore, Dr. Szerszen’s misassumption that the revenues were less than the costs incurred is unfounded.722

The ALJs find that Dr. Szerszen erred. Making the correct comparison, as demonstrated by Mr. McCula, shows there is no basis for the disallowance claimed by Dr. Szerszen. The ALJs, therefore, recommend the Commission deny the requested disallowance.

E. Energy and Fuel Management Class Dr. Szerszen addresses seven project codes that are within the Energy and Fuel Management Class: (1) F3PCCSPSYS (System Planning And Strategic) for a disallowance of $29,304; (2) F3PCWE0140 (EMO Regulatory Affairs) for a disallowance of $114,468; (3) F3PPSPE002 (SPO 2009 Renewable RFP Expense) for a disallowance of $3,014; (4) F3PPSPE003 (SPO Summer 2009 RFP Expense) for a disallowance of $56,672; (5) F3PPSPE004 (SPO Summer09RFP IM&Propslsubmt) for a disallowance of $42,018; (6) F3PPWET300 (SPO 2008 Western Region RFP-Te) for a disallowance of $645; and (7) F3PPWET303 (SPO2008WinterWestnRegionRFP-IM) for a disallowance of $4,200.723 1. Project F3PCWE0140 (EMO Regulatory Affairs) Dr. Szerszen testified that Texas ratepayers do not receive benefits as a result of the costs captured by this project code and should therefore not be charged those costs.724 ETI witness Cicio explained that Dr. Szerszen misinterpreted an RFI response to conclude that Texas ratepayers did not receive benefits from the activities whose costs were booked through this project code. That project code is not intended to capture costs for docketed or large System Planning and Operations projects. Mr. Cicio states that it is not possible to assign a specific project code for every discrete activity performed by each employee, nor would it be appropriate to attempt to do so. Regardless of the number of activities specifically identified through project codes, there ETI Ex. 59 (McCulla Rebuttal) at 8-12.

OPC Ex. 1 (Szerszen Direct) at 55, 60, and 65-66.

Id. at 55.

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will remain the need to have generic project codes that capture time spent on more general, undocketed matters and activities that are no less beneficial to ratepayers.725 The ALJs agree that Texas ratepayers receive benefits as a result of the costs charged to this account. Accordingly, the ALJs recommend the Commission approve inclusion of the costs as requested by ETI.

2. Projects F3PPSPE003 (SPO Summer 2009 RFP Expense), F3PPSPE003 (SPO Summer 2009 RFP Expense), F3PPSPE004 (SPO Summer09RFP IM & Propslsubmt), and F3PPWET303 (SPO2008 Winter Westn RegionRFP-IM) Dr. Szerszen testified that the costs captured by these projects should be disregarded because they were incurred during the 2008-2009 period, which is outside of the Test Year, and are nonrecurring.726

ETI witness Cicio explained that although these projects were initiated prior to the Test Year, the costs that the Company seeks to recover through these project codes were expenses incurred during the Test Year, including development activities, request for proposal issuance, bidders conferences, written and posted questions and answers from market participants and other interested parties, submission of proposals, screening of proposals, proposal evaluation, follow-up questions and clarifications, recommendations and awards, contract negotiations, Independent Monitor reports, and regulatory approvals, if necessary. These routinely encompass a multi-year time frame, and the costs required to perform those activities, although associated with a project that may have been initiated several years previously, are properly incurred over the life span of the project. He also states that they are recurring because they reflect the kinds and levels of charges that would be expected to be incurred on an ongoing basis in association with requests for proposals managed by ESI on behalf of the Entergy Operating Companies, and the Company has been involved in these types of solicitations since 2002.727

ETI Ex. 45 (Cicio Rebuttal) at 8-9.

OPC Ex. 1 (Szerszen Direct) at 65.

ETI Ex. 45 (Cicio Rebuttal) at 13-14.

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The ALJs find that the costs captured by these projects were incurred during the Test Year and represent the kinds and levels of costs routinely incurred on a recurring basis. Accordingly, the ALJs recommend that the Commission approve their inclusion as requested by ETI.

3. Project F3PCCSPSYS (System Planning and Strategic) Dr. Szerszen recommended total disallowance of the costs captured by this project code because they are allocated based on the total assets of the Entergy affiliates.728 Dr. Szerszen’s conclusion appears to be that no such corporate-level costs should be allocated to ETI because there are other project codes that allocate corporate planning and analysis-type costs only to the regulated utilities, such as ETI; thus, any corporate-level costs that are allocated to all subsidiaries, whether regulated or non-regulated, should not be charged to ETI.

ETI witness Tumminello testified that Dr. Szerszen’s theory neither considers the Entergy organization as a family of companies and ETI’s place in that family, nor the fact that these services are not only relevant to ETI as part of the Entergy family, but are reasonable, necessary and meet the Commission’s affiliate cost recovery standard. ESI’s corporate oversight services are provided to both individual companies and groups of companies within the Entergy ’corporate structure. As a member of the corporate group, ETI receives the benefit of corporate-level planning, reporting, and forecasting activities provided by ESI.729

The ALJs find that ETI (and, therefore, its ratepayers) does receive benefits as a member of the Entergy family of companies and that it is appropriate for it to receive charges for those services.

Therefore, the ALJs recommend the Commission approve the inclusion of costs as requested by ETI.

F. Environmental Service Class Dr. Szerszen recommended disallowance of $301,879 in six project codes primarily within ETI’s Environmental Services Class: (1) F3PCCE0129 (Corporate Sustainability Strat) for a

OPC Ex. 1 (Szerszen Direct) at 60-61.

ETI Ex. 69 (Tumminello Rebuttal) at 10-11.

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disallowance of $6,781; (2) F3PCCE0193 (Corp Environmental Special Pro) for a disallowance of $1,203; (3) F3PCCEIE01 (Corp Environmental Initiatives) for a disallowance of $2,413; (4) F3PCCEII01 (Corp Environmental Initiatives) for a disallowance of $2,413; (5) F3PCCEP001 (Corporate Environmental Policy) for a disallowance of $269,248; and (6) F5PPBCNAVF (Avian Flu Contingency Planning) for a disallowance of $47.730

Dr. Szerszen’s reasoning for this disallowance was that these six project codes, which all deal with corporate environmental policy, initiatives, strategy, and consulting services, were allocated based on Billing Method CAPAOPCO, which is based on the fossil plant capacity of the regulated utility operating companies, even though “non-regulated entities clearly benefit from the corporate level expenses.”731 Dr. Szerszen recommended a $47 disallowance for Project F5PPCCNAVF (Avian Flu Contingency Planning), asserting that this charge is a “corporate imaging expense that should not be borne by Texas ratepayers.”732

According to ETI, Dr. Szerszen has a fundamental misunderstanding of how the affiliate billing system works and, as a result, she incorrectly assumed that ESI charges are not being properly allocated. ETI argues that the non-regulated Entergy affiliates do receive the proper and appropriate allocation of costs. The two service companies for non-regulated affiliates also provide services to their non-regulated affiliates directly. There simply is no subsidization or improper allocation.733

Dr. Szerszen noted that Entergy’s website indicates that nuclear-related environmental issues are being pursued.734 She argued that this shows that the non-regulated affiliates are under-allocated OPC Ex. 1 (Szerszen Direct) at 62-63.

Id. Id. at 66.

See, e.g., ETI Ex. 41 (Tumminello Direct) at 10-15. Moreover, while ESI bills the regulated utility affiliates such as ETI at cost, it bills the non-regulated affiliates at cost plus a 5 percent mark-up pursuant to a June 1999 Securities and Exchange Commission order. ETI Ex. 41 (Tumminello Direct) at 15. This percent mark-up is then flowed back to entities that receive service from ESI. Therefore, the regulated affiliates are, by federal order, receiving essentially a rebate from the non-regulated affiliates.

OPC Ex. 1 (Szerszen Direct) at 62.

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environmental-related costs. Ms. Stokes explained that the project codes at issue “deal with services provided to the operating companies. . . . and just looking at the website there are other things . . . that are not covered or paid for by Texas ratepayers in these project codes that are in this testimony.”735 Therefore, according to Ms. Stokes, these project codes are not allocated in such a way that under-recovers costs from the non-regulated affiliates; they pay their own way.

Finally, the Project Summary for the Avian Flu Contingency Planning project shows that these costs involve developing and communicating Avian Flu business continuity plans and then maintaining, checking, and adjusting those plans once established.736 These are not “corporate imaging expenses” as characterized by Dr. Szerszen.

The ALJs agree that ETI’s evidence demonstrates the recoverability of the costs captured by these project codes. Therefore, the ALJs recommend the Commission approve their recovery.

G. Federal PRG Affairs Class Dr. Szerszen recommended disallowances for three project codes primarily in the Federal PRG Affairs Class: (1) F5PPSPE044 (PMO Support Initiative-System) for a disallowance of $344; (2) F3PPUTLDER (Utility Derivatives Compliance) for a disallowance of $20,447; and (3) F3PCSYSRAF (System Regulatory Affairs-Federal) for a disallowance of $352,084.737

1. Project F5PPSPE044 (PMO Support Initiative-System) Dr. Szerszen recommended disallowance of $344.29 from Project F5PPSPE044 (PMO Support Initiative System). ETI responds, however, that a review of the Project Summary for that project code in Ex. SBT-E reveals that ETI already removed those costs before even filing its direct

Tr. at 884.

ETI Ex. 41 (Tumminello Direct) at SBT-E at 1342-43.

OPC Ex. 1 (Szerszen Direct) at 46-47, 66-67.

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case. Therefore, according to ETI, Dr. Szerszen is recommending disallowance of a cost that is not in this case.738

The ALJs agree that examination of the exhibit referenced by ETI appears to reveal that the costs challenged by Dr. Szerszen have been removed from this case through a pro forma adjustment.

Accordingly, the ALJs recommend the Commission reject OPC’s challenge.

2. Project F3PPUTLDER (Utility Derivatives Compliance) Dr. Szerszen recommended disallowance of $20,447 of derivatives expenses because ETI did not use derivative instruments and therefore should not be charged these costs and because ratepayers do not benefit from derivatives.739

ETI witness Tumminello responded that Project F3PPUTLDER was charged by a group developing compliance mechanisms to protect Entergy’s regulated utility interests in observance of the Dodd-Frank Act. Although ETI does not currently use any derivative activities, understanding the impacts of that Act is necessary to ensure current and future compliance through Entergy. The definitions under the legislation have not been finalized, and there remain issues that ETI must be aware of to fully comply. These costs, therefore, are necessary and reasonable charges that should not be disallowed.740

The explanation offered by ETI for the inclusion of these charges appears reasonable to the ALJs. Even though ETI does not now use derivatives, it is possible that it will in the future and it is important that it be aware of the regulatory framework associated with such actions to avoid problems. The ALJs therefore recommend the Commission approve inclusion of these costs as requested by ETI.

ETI Initial Brief at 174-175.

ETI stated that it assumes that Dr. Szerszen must be referring to Project Code F3PPUTLDER (Utility Derivatives Compliance) because her recommended disallowance is the same total ETI adjusted amount shown on the Project Summary for that project code. See SBT-E at 1113. The ALJs make the same assumption as it appears reasonable.

ETI Ex. 69 (Tuminello Rebuttal) at Ex. SBT-R-2 at 3.

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3. Project F3PCSYSRAF (System Regulatory Affairs-Federal) In the regulatory affairs category, ETI requests the recovery of various legal, testimony-related, communications, and filing costs associated with both Texas-specific regulatory activities, FERC-related regulatory activities, and non-Texas specific regulatory activities. OPC witness Szerszen did not recommend a disallowance of the $1,442,223 in adjusted Test Year expenses for regulatory affairs that ETI has shown to be specific to the Texas jurisdiction.741 Rather, Dr. Szerszen recommended that all regulatory affairs expenses not specific to Texas be disallowed.742 These expenses total $759,868.743

Project F3PCSYSRAS (System Regulatory Affairs – State) was incurred for administrative activities for senior management, project work associated with system-wide regulatory matters, system-wide regulatory strategies and emerging regulatory issues, and it relates to multiple regulated jurisdictions.744 Project No. F3PCSYSRAF (System Regulatory Affairs – Federal) was incurred for regulatory oversight and coordination of FERC matters.745 OPC contends that ETI provided no evidence that Texas ratepayers receive any tangible benefits from “system” regulatory affairs costs in proportion to the costs being allocated to Texas.

Project F3PCSYSRAS costs are allocated to the subsidiaries based on electric customer counts, and OPC states that it is questionable whether Entergy’s positions on “emerging” state or national regulatory issues or “system-wide regulatory strategies” are conveying any benefits to its electric customers beyond those already captured in the Texas-specific regulatory affairs project codes.746 In fact, according to OPC, the Company’s shareholders are the primary beneficiaries of these system-wide regulatory strategies.747 The federal regulatory affairs costs captured under See OPC Ex. 3 (Szerszen Workpapers) at 368-371.

OPC Ex. 1 (Szerszen Direct) at 46-47.

Id. at 46.

OPC Ex. 3 (Szerszen Workpapers) at 365.

OPC Ex. 1 (Szerszen Direct) at 46-47; OPC Ex. 3 (Szerszen Workpapers) at 367.

OPC Ex. 3 (Szerszen Workpapers) at 368-371.

OPC Ex. 1 (Szerszen Direct) at 47.

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Project F3PCSYSRAF are allocated to the regulated subsidiaries based on each company’s load responsibility ratio; this ratio assumes that every FERC docket and/or FERC issue is related to ETI’s peak demand. According to OPC, this is not reality, nor is it consistent with FERC’s primary responsibility to ensure that electric wholesale buyers and sellers are provided open access transmission across utility systems.

ETI witness May offered the following as rebuttal of Dr. Szerszen’s contentions regarding these two project codes:

The affiliate charges to Project Codes F3PCSYSRAS and F3PCSYSRAF are directly associated with the issues and matters within the federal jurisdiction of the Federal Energy Regulatory Commission (“FERC”) including but not limited to the Open Access Transmission Tariff (“OATT”) as well as any other federal statutes, rules and regulations. These are the result of issues and matters raised concerning the OATT, operations of the transmission system, requests for transmission service and interpretation of applicable provisions under the jurisdiction of FERC. They are costs incurred on an Entergy System-wide basis that cannot be directly assigned to any one Operating Company, such as ETI.748 He then went on to state that the affiliate Test Year issues and costs related to these project codes are reflective of typical issues and costs that the Company experiences on an ongoing basis.749 With respect to the benefits derived by Texas ratepayers as a result of activities conducted under these project codes, Mr. May stated that:

the benefit to ETI involves a multitude of issues that are directly related to the jurisdiction of the FERC, including but not limited to any revisions to Service Schedules under the System Agreement that applies to all operating companies including ETI, power purchase agreements for cost-based, short-term power sales, and compliance with FERC by each Operating Company to the market-based rate tariff and cost-based rate tariff. The Entergy Operating Companies’ market-based rate tariff and cost-based rate tariff are joint tariffs containing terms and conditions of service.750

ETI Ex. 57 (May Rebuttal) at 25.

ETI Ex. 57 (May Rebuttal) at 25.

ETI Ex. 57 (May Rebuttal) at 27-28; see also, Tr. at 370-371.

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Mr. May also explained why the billing methods applied to these two project codes are appropriate.

The cost drivers for Project F3PCSYSRAF are labor, employee expenses, consultant expenses, and other general operating expenses incurred for the benefit of the Entergy Operating Companies and their regulated customers. Therefore, a billing method based on load responsibility – “LOADOPCO” – is appropriate for this type of project code. Project F3PCSYSRAS captures costs associated with general regulatory support work that is applicable across all of the jurisdictions. The primary activities associated in this project code include but are not limited to: special project work associated with system-wide regulatory matters, analysis of emerging state or national regulatory and accounting issues affecting the Entergy System, and internal process improvement work. What drives the cost of this project code is the average number of both electric and gas customers served – CUSTEGOP – because all such customers benefit from these services provided by ESI to ETI.751 In short, according to ETI, the activities undertaken under both of these project codes benefit Texas ratepayers, and they are properly allocated to the regulated operating companies using the billing methods employed.

The ALJs believe that resolution of this question is a close call. Although ETI provided an adequate explanation of the reasons underlying the allocation of costs to Texas ratepayers and the appropriateness of the allocation methodologies used, the one troubling aspect, as noted by OPC, was that Mr. May’s testimony regarding Projects F3PCSYSRAF and FP3PCSYSRAS contradicted the fact that ESI has a specific project dedicated to open access transmission issues entitled “FERC- Open Access Transmission” (Project F3PCE01601).752 As OPC notes, if Mr. May was correct that OATT issues have been included in Projects F3PCSYSRAF and FP3PCSYSRAS the project pages should arguably be more specific about the purpose of the expenditure. Nevertheless, the ALJs find ETI’s testimony credible and recommend that the costs of Projects F3PCSYSRAF and FP3PCSYSRAS not be disregarded.

ETI Ex. 57 (May Rebuttal) at 28-29.

OPC Ex. 11; also found in OPC Exhibit No. 3 (Szerszen Workpapers)at 363-364.

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H. Financial Services Class Dr. Szerszen recommended disallowances in nine project codes that are primarily captured within ETI’s Financial Services Class of affiliate costs: (1) F3PCF05700 (Corporate Planning & Analysis) for a disallowance of $4,254; (2) F3PCF21600 (Corp Rptg Analysis & Policy) for a disallowance of $320,157; (3) F3PCFF1000 (Financial Forecasting) for a disallowance of $96,734; (4) F3PPADSENT (Analytic/Decision Support-Entergy) for a disallowance of $93,544; (5) F3PPSPSENT (Strategic Planning Svcs-Entergy) for a disallowance of $45,265; (6) F3PCR73345 (Quick Payment Center, Adm) for a disallowance of $14,484; (7) F3PCF20990 (Operations Exec VP & CFO) for a disallowance of $146,267; (8) F3PCFF1001 (OCE Support) for a disallowance of $1,923; and (9) F3PCF23936 (Manage Cash) for a disallowance of $15,677.753

1. Projects F3PCF05700 (Corporate Planning & Analysis), F3PCF21600 (Corp Rptg Analysis & Policy), F3PCFF1000 (Financial Forecasting), F3PPADSENT (Analytic/Decision Support-Entergy), and F3PPSPSENT (Strategic Planning Svcs- Entergy) Dr. Szerszen proposed to disallow all costs related to these five project codes, which she collectively describes as addressing Corporate Planning, Reporting, and Forecasting issues because she contends that an assets-based allocator should not be used to allocate these costs and, regardless of the allocator used, these types of services do not benefit Texas ratepayers because ESI has, in other instances, directly billed corporate-level services to ETI.

ETI witness Tumminello responded, stating that Dr. Szerszen failed to consider the Entergy organization as a family of companies and ETI’s place in that family. The services provided under these project codes are not only relevant to ETI as part of the Entergy family, but are reasonable and necessary. ESI’s corporate oversight services are provided to both individual companies and groups of companies within the Entergy Companies’ corporate structure. As a member of the corporate group, ETI receives the benefit of corporate-level planning, reporting, and forecasting activities provided by ESI. Ms. Tumminello contested that the use of an asset-based allocator is appropriate

OPC Ex. 1 (Szerszen Direct) at 56, 60-62, and 74, and Schedules CAS-9, CAS-10, and CAS-15.

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because this is an example of the stewardship of the company-wide assets and such an allocator is, therefore, appropriate.754 The ALJs agree.

The ALJs find that ETI’s proposed allocator is appropriate and that the costs benefit Texas ratepayers. Accordingly, the ALJs recommend the Commission approve the costs proposed by ETI.

2. Projects F3PCF20990 (Operations Exec VP & CFO) and F3PCFF1001 (OCE Support) Dr. Szerszen recommended disallowance of all costs captured by these project codes because, in her opinion: (1) there are “no perceivable benefits to ETI’s ratepayers”; (2) they should be paid for by the parent entity (presumably meaning Entergy’s shareholders); and (3) an assets- based allocator is not appropriate.755

As to Dr. Szerszen’s assertion that Texas ratepayers do not benefit from the costs captured by these project codes, ETI witness Domino, President of Entergy, provided anecdotal evidence that that Entergy was vital to ETI’s restoration efforts on two fronts. First, the parent provided cash to ETI for its hurricane restoration efforts; second, ETI was not required to pay dividends to the parent while it was strapped for funds due to hurricane restoration efforts.756 With respect to the argument that an asset-based allocator is not appropriate, Ms. Tumminello testified that the functions covered by this project code relate to the oversight of all system operations and the stewardship of corporate assets and that because ETI is part of a corporate group, the allocated charges associated with these services are relevant to ETI as part of that group. Furthermore, ETI argues, the asset-based allocator is appropriate because it reflects the cause of the costs incurred, in that services provided relate to the stewardship of all the corporation’s assets.757

ETI Ex. 69 (Tumminello Rebuttal) at 10-11.

OPC Ex. 1 (Szerszen Direct) at 56-57.

Tr. at 141.

ETI Ex. 69 (Tumminello Rebuttal) at 9-11.

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Dr. Szerszen took too narrow a view and, without justification, argued that these costs provide no benefit to Texas ratepayers. There are innumerable benefits provided by the corporate structure adopted; those mentioned by Mr. Domino are just a few. Ms. Tumminello’s testimony explained why an asset-based allocator is appropriate. Accordingly, the ALJs recommend the Commission approve the inclusion of these costs as requested by ETI.

3. Project F3PCR73345 (Quick Payment Center, Adm) Dr. Szerszen recommended that these costs be reallocated using the CUSTCALL billing method. Given ESI’s demonstrated tracking capabilities, Dr. Szerszen reallocated the costs of this project using a 10.8 percent customer call allocator, which is on the low end of the 10.70 percent-11.04 percent Test-Year CUSTCALL allocators.758 As a result of Dr. Szerszen’s reallocation, $14,484 associated with this project should, according to Dr. Szerszen, be disallowed.759

ETI witness Stokes responded, stating that Dr. Szerszen’s proposed reallocation is arbitrary and fails to consider the cost causation associated with the actual project code at issue. These costs are not driven by a specific proportion of calls from each Operating Company (that is, by the CUSTCALL allocator). The costs captured by Project F3PCR73345 reflect the costs of overseeing the Quick Payment Center vendors in each of the Entergy Operating Companies, regardless of the number of calls by customers to the Company.760

The ALJs are persuaded that the allocation methodology chosen by ETI is the superior method and that the CUSTCALL allocator would not be appropriate given the cost causation associated with the project. Accordingly, the ALJs recommend the Commission approve the costs proposed by ETI.

OPC Exhibit No. 27 (ETI’s Ex. SBT-15, Attachment 6) at 2; Tr. at 838-839.

OPC Exhibit No. 1 (Szerszen Direct) at 77 and 118.

ETI Ex. 66 (Stokes Rebuttal) at 11.

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4. Project F3PCF23936 (Manage Cash) Dr. Szerszen recommended disallowance of $15,677 from Project F3PCF23936 (Manage Cash), arguing that this project: (1) is duplicative of ETI-specific financing and cash management activates; (2) the allocator is wrong; and (3) Entergy, not ETI ratepayers, should pay for this activity.761

ETI witness McNeal testified that the services are not duplicative of the cash management services performed by the Cash Management department in the Treasury Class. The services provided under Project F3PCF23936 are associated with daily cash management responsibilities, such as loading bank balances, setting daily cash position for all the Entergy Companies, transmitting wire/ACH files to Entergy Company banks for vendor payments, and maintaining proper cash controls over these cash functions. These services are necessary for the daily operation of all the Entergy Companies, including ETI, and are thus not directly associated with any one specific legal entity. The costs are driven by the time spent on the daily cash management activities, which is directly related to the number of bank accounts that the Entergy Companies have open.

Since the services provided under this project code cannot be identified to a particular Entergy Company, the billing method based on the number of open bank accounts is the best allocation.

Billing method BNKACCTA does that and, according to Mr. McNeal, is therefore appropriate for allocating costs for this project code.762

The evidence demonstrates that the activities captured by this project code are not directly associated with any one specific entity; rather, they benefit all the entities under the Entergy umbrella. It also appears that a billing method based on the number of open bank accounts is the appropriate allocation methodology. Accordingly, the ALJs recommend the Commission approve inclusion of costs as requested by ETI.

OPC Ex. 1 (Szerszen Direct) at 74 and Schedule CAS-15.

ETI Ex. 61 (McNeal Rebuttal) at 4, 6; Tr. at 546-547.

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I. Human Resources Class Dr. Szerszen recommended disallowances for three project codes that are primarily within the Human Resources Class of affiliate costs: (1) F3PCHRCCSM (HR Competitive Compensation) for a disallowance of $20,146; (2) F5PCZUBENQ (Non-Qualified Post-Retirement) for a disallowance of $115,078; and (3) F5PPZNQBDU (Non-Qual Pension/Benf-Dom Utl) for a disallowance of $241,073.763

1. Project F3PCHRCCSM (HR Competitive Compensation) Dr. Szerszen testified that an asset-based allocator is not appropriate for a project, such as Project F3PCHRCCSM, that captures overall executive management-related costs.764

ETI contends that the functions covered by this project code relate to the oversight of all system operations and the stewardship of corporate assets and that because ETI is part of a corporate group, the allocated charges associated with these services are relevant to ETI as part of that group of companies. Furthermore, ETI argues, the asset-based allocator is appropriate because it reflects the cause of the costs incurred, in that services provided relate to the stewardship of all the corporation’s assets.765

A corporation cannot function without executives, who are charged with the responsibility of overseeing, among other things, the assets of the corporation. This is an important function that Dr. Szerszen did not acknowledge in her testimony. The utility and executive management class costs that she challenged are reasonable and necessary costs that are allocated to ETI based on a logical allocator – the assets the executives are charged with overseeing. The ALJs recommend that OPC’s challenge be rejected.

OPC Ex. 1 (Szerszen Direct) at 56, 68.

OPC Ex. 1 (Szerszen Direct) at 56.

ETI Ex. 4 (Domino Direct) at 18-38; ETI Ex. 69 (Tumminello Rebuttal) at 9-11.

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2. Projects F5PCZUBENQ (Non-Qualified Post-Retirement) and F5PPZNQBDU (Non-Qual Pension/Benf-Dom Utl) With respect to Projects F5PCZUBENQ and F5PPZNQBDU, Dr. Szerszen testified that: (1) there is no evidence that Texas ratepayers benefit from the pension-related benefits in these codes; and (2) the LBRBILAL allocator (Labor Billings to All) is not appropriate because the benefits are unrelated to ESI labor costs.766

Initially, ETI agrees that $112,531 of the costs in total for both of these project codes should be excluded because that amount is attributable to nuclear and non-regulated employees.767

With respect to the remaining costs, ETI disagrees. The ALJs, however, have already resolved this issue in their discussions related to Section VII.D.4, above, where they concluded that that the supplemental executive retirement plans are not reasonable and necessary for the provision of electric utility service and are not in the public interest. Accordingly, the ALJs recommend the Commission accept OPC’s proposed disallowance of $356,151 (which includes the $112,531 agreed to by ETI).

J. Information Technology Class Dr. Szerszen recommended disallowances in two project codes that are primarily within ETI’s Information Technology Class: (1) F3PPFXERSP (Evaluated Receipts Settlement) for a disallowance of $10,279; and (2) F3PCFX3555 (BOD/Executive Support) for a disallowance of $3,148.768

OPC Ex. 1 (Szerszen Direct) at 68.

ETI Initial Brief at 179.

OPC Ex. 1 (Szerszen Direct) at 56, 71.

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1. F3PPFXERSP (Evaluated Receipts Settlement) Dr. Szerszen testified that Project F3PPFXERSP is not moving forward due to tax and freight implications and, as such, the cost is not recurring.769 Ms. Tumminello testified in response that the “Evaluated Receipt Settlement” program was originally being capitalized in a capital project. But when it was decided that the program would be cancelled, the capital project was closed and the charges to the project were expensed. Although the costs for this particular project do not recur every year, they are part of normal utility operations, and this type of project does recur as necessary.770

Although the ALJs understand the concept of normally recurring cost types, they do not believe that the costs captured by this project code fall within that category. Those costs related to a project that was cancelled and sufficient explanation of how similar projects in the future might occur was not provided. Accordingly, the ALJs recommend the Commission reject inclusion, as proposed by OPC.

2. Project F3PCFX3555 (BOD/Executive Support) Dr. Szerszen argued that Project F3PCFX3555 is an executive-related project that does not provide perceivable benefits to ETI ratepayers, the Entergy shareholders should bear this cost, and an assets-based allocator is not appropriate.771

ETI argues that the functions covered by this project code relate to the oversight of all system operations and the stewardship of corporate assets and that because ETI is part of a corporate group, the allocated charges associated with these services are relevant to ETI as part of that group of companies. Furthermore, ETI argues, the asset-based allocator is appropriate because it reflects the

OPC Ex. 1 (Szerszen Direct) at 71.

ETI Ex. 69 (Tumminello Rebuttal) at SBT-R-2 at 4.

OPC Ex. 1 (Szerszen Direct) at 56.

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cause of the costs incurred, in that services provided relate to the stewardship of all the corporation’s assets.772

A corporation cannot function without executives who are charged with the responsibility of overseeing, among other things, the assets of the corporation. This is an important function that Dr. Szerszen did not acknowledge in her arguments. The utility and executive management class costs that she challenged are reasonable and necessary costs that are allocated to ETI based on a logical allocator – the assets the executives are charged with overseeing. The ALJs recommend that OPC’s challenge be rejected.

K. Internal and External Communications Class Dr. Szerszen recommended disallowances in four project codes that are primarily within ETI’s Internal and External Communications Class: (1) F3PCR40118 (Utility Communications for a $6 disallowance; (2) F5PCZPDEPT (Supervision and Support – Public) for a $138 disallowance; (3) F5PPICC000 (Integrated Customer Communications) for a $199 disallowance; and (4) F5PPICCEMP (ICC - Employee Education Initiative) for a $3 disallowance.773

ETI witness Tumminello responded to Dr. Szerszen’s claim that the costs captured by these project codes are corporate image costs by stating that the costs are for advertising activities that are of a good will or institutional nature, which is primarily designed to improve the image of the utility or the industry, including advertisement which inform the public concerning matters affecting the Company’s operations, such as, the costs of providing service, the Company’s efforts to improve the quality of service, the Company’s efforts to improve and protect the environment. According to FERC, such costs are properly includable in FERC Account 930.1 and are recoverable. According to Ms. Tumminello, as contemplated by FERC, the fact that ETI is a monopoly has no bearing on the recoverability of these costs.774

ETI Ex. 4 (Domino Direct) at 18-38; ETI Ex. 69 (Tumminello Rebuttal) at 9-11.

OPC Ex. 1 (Szerszen Direct) at 66.

ETI Ex. 69 (Tumminello Rebuttal) at SBT-R-2 at 4-6.

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OPC provided little support for its claim that costs covered by these project codes should not be recoverable, essentially limiting the basis to the contention that ETI is a monopoly and ratepayers should not be charged with such costs. ETI did little better, but it did provide the testimony of Ms. Tumminello, which confirms that the costs are properly includable in FERC Account 930.1 and are, therefore, recoverable. In the end, the ALJs must go with the weight of the evidence, which is in ETI’s favor. The ALJs recommend the Commission reject OPC’s contention that costs covered by these project codes are not recoverable.

L. Legal Services Class Dr. Szerszen recommended disallowances in 13 project codes that are primarily within the Legal Services Class: (1) F3PPCASHCT (Contractual Alternative/Cashpo) for a disallowance of $2,553; (2) F3PCF99180 (CORP. COMPLIANCE TRACKING SYS) for a disallowance of $9; (3) F3PPINVDOJ (DOJ Anti Trust Investigation) for a disallowance of $1,039,664;775 (4) F3PCE01601 (Ferc - Open Access Transmission) for a disallowance of $84,183; (5) F3PCERAKTL (RAKTL Patent Matter) for a disallowance of $75; (6) F3PPEASTIN (Willard Eastin et al) for a disallowance of $19,714; (7) F3PPTCGS11 (TX Docket Competitive Generation) for a disallowance of $310,746; (8) F5PCE13759 (Jenkins Class Action Suit) for a disallowance of $205,107; (9) F5PCZLDEPT (Supervision & Support – Legal) for a disallowance of $225,794; (10) F3PCCDVDAT (Corporate Development Data Room) for a disallowance of $6,147; (11) F3PCSYSAGR (System Agreement-2001) for a disallowance of $880,841; (12) F3PPWET302 (SPO 2008 Winter Western Region) for a disallowance of $13,919; and (13) F3PPWET308 (SPO Calpine PPA/Project Houston) for a disallowance of $435,963.

Dr. Szerszen also proposed disallowance of $765 in charges for related Project Code F3PPTDHY19 (Dept. of Justice Investigation), which is actually primarily attributable to the Transmission Operations Class, rather than the Legal Services Class. Because the issues are intertwined, that project will be discussed here, rather than in the Transmission Operations Class.

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1. Project F3PPCASHCT (Contractual Alternative/Cashpo) With respect to Project F3PPCASHCT ($2,553 disallowance), ETI agrees that these costs are non-recurring and should be disallowed. Accordingly, the ALJs recommend the Commission exclude those costs.

2. Project F5PCZLDEPT (Supervision & Support – Legal) As to Project F5PCZLDEPT ($225,794), OPC, through its Second Errata, removed that proposed disallowance, and it is no longer contested by Dr. Szerszen. Accordingly, the ALJs recommend the Commission approve inclusion of those costs.

3. Project F3PCF99180 (Corp. Compliance Tracking Sys) F3PCF99180 (Corp. Compliance Tracking Sys) is one of the project codes that Dr. Szerszen claimed should be disallowed because ETI is a monopoly and Texas ratepayers should not have to pay for corporate image costs.776

ETI witness Tumminello testified that these costs are for advertising activities that are of a good will or institutional nature, which is primarily designed to improve the image of the utility or the industry, including advertisement which inform the public concerning matters affecting the Company’s operations, such as, the costs of providing service, the Company’s efforts to improve the quality of service, the Company’s efforts to improve and protect the environment. According to FERC, such costs are properly includable in FERC Account 930.1 and are recoverable. According to Ms. Tumminello, as contemplated by FERC, the fact that ETI is a monopoly has no bearing on the recoverability of these costs.777

OPC provided little support for its claim that costs covered by these project codes should not be recoverable, essentially limiting the basis to the contention that ETI is a monopoly and ratepayers should not be charged with such costs. ETI did little better, but it did provide the testimony of OPC Ex. 1 (Szerszen Direct) at 66.

ETI Ex. 69 (Tumminello Rebuttal) at SBT-R-2 at 4-6.

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Ms. Tumminello, which confirms that the costs are properly includable in FERC Account 930.1 and are, therefore, recoverable. The weight of the evidence is in ETI’s favor. The ALJs recommend the Commission reject OPC’s contention that costs covered by these project codes are not recoverable.

4. Projects F3PPINVDOJ (DOJ Anti Trust Investigation) and F3PPTDHY19 (Dept. of Justice Investigation) Entergy is currently under investigation by the Department of Justice (DOJ) for certain business practices of the Operating Companies, including the procurement of generating assets and power, dispatch of generation within the Entergy system, and transmission capacity expansion. This is a civil investigation under Section 2 of the Sherman Act and Section 7 of the Clayton Act. The investigation has been ongoing since 2010, and Entergy does not know when the investigation will conclude.778

Dr. Szerszen testified that there are two reasons why ratepayers should not pay for the DOJ expenses. First, ETI does not have the ability to make its own power procurement, generation dispatch, or transmission capacity decisions. These decisions are made by ESI and Entergy’s corporate management, which has traditionally planned and managed the electric operating companies’ generation and transmission functions on a system-wide basis. Second, ETI is not responsible for the development and administration of the system agreement, and should not be held responsible for these antitrust investigation expenses. Furthermore, according to Dr. Szerszen, if the DOJ finds that Entergy has acted illegally, it is even more inappropriate to charge ETI ratepayers for corporate-level illegal actions. These expenses should be borne by Entergy’s corporate parent and/or the corporation’s shareholders, and not the ratepayers.779

ETI contends that Dr. Szerszen fundamentally misunderstands the nature of the System Agreement and the benefits that ETI derives from that agreement. All of the Entergy Operating Companies voluntarily entered into the System Agreement so that the Entergy system can be planned and operated on a total system basis, in order to maximize economic benefit and reliability OPC Ex. 1 (Szerszen Direct) at 51-52.

Id. at 52.

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of service. All of the Operating Companies benefit from integrated planning and operations in this manner. This does not mean that ETI has no decision-making role in these activities. ETI notes that under Section 5.01 of the System Agreement, the agreement is administered through an Operating Committee, which includes an ETI representative, as well as representatives of the other Operating Companies and Entergy. ETI’s representative is one of the voting members of the Committee, and all decisions of the Operating Committee must be approved by a majority vote. As a voting member of the Operating Committee, ETI is responsible for administering the System Agreement and does participate in decision-making on generation and transmission matters.780

ETI acknowledges that ESI is tasked with providing services and making decisions related to generation dispatch, power procurement, and transmission operations on behalf of the Entergy Operating Companies and at the direction of the Operating Committee, but these activities are for the benefit of the Operating Companies and their ratepayers. ETI receives the benefits of these services and integrated planning and operations under the System Agreement and, according to ETI, should also be responsible for its portion of costs related to those services and operations.781

As to Dr. Szerszen’s contention that the costs should be disallowed because DOJ might find that Entergy acted illegally, ETI notes that the DOJ is not an adjudicatory body or regulatory agency and, thus, it does not make “findings of fact.” If DOJ believes the civil antitrust laws have been violated, it can file a complaint in federal district court. To date, no complaint has been filed. ETI points out that ESI routinely incurs legal costs in responding to regulatory audits and investigations on behalf of ETI and the other Operating Companies in the same manner in which other operating costs are incurred. ESI is authorized to retain legal counsel on behalf of, and for the benefit of, ETI and the other Entergy Operating Companies. ESI is authorized to allocate the respective costs to the Operating Companies under a service agreement with the Entergy Operating Companies designated as Rate Schedule FERC No. 435. This service agreement is on file with, and was approved by,

ETI Ex. 65 (Sloan Rebuttal) at 8.

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FERC under FERC Docket No. ER07-38-000.782 Thus, according to ETI, it is appropriate that ETI is allocated its share of the costs of legal services related to the DOJ investigation.783

The DOJ antitrust investigation is a massive undertaking. Unfortunately, it is a part of the ordinary course of modern business life. OPC’s arguments that ESI is solely responsible for decision-making under the System Agreement miss the mark, as pointed out by ETI. It is clear that ETI and the other Operating Companies play an active role in the decision-making. As to OPC’s arguments about what would happen if Entergy were found to have violated the antitrust laws, those arguments are little more than speculation. As ETI noted, the DOJ is not an adjudicatory body and its investigation can only result in the filing of a complaint in Federal court (if the DOJ believes that such an action is justified). Until that time, it is imperative for the company to fully respond to the DOJ investigation. The ALJs find that ETI has met its burden of proving that Texas ratepayers should be charged the costs of the DOJ investigation allocated to them by ETI.

5. Project F3PCE01601 (Ferc - Open Access Transmission) Project F3PCEO1601 costs are incurred to manage costs associated with regulatory oversight and coordination of the Entergy System Open Access Transmission Service before FERC. OPC contends that not only are most of the FERC dockets accruing costs under Project F3PPEO1601 no longer open as of December 31, 2011,784 most of the closed dockets have absolutely nothing to do with Texas operations.785 Furthermore, according to OPC, ETI witness Sloan agreed that only three of the dockets shown in OPC Exhibit No. 12 were open at the end of the test year, and one of the open dockets involves a transmission service agreement involving the Missouri Joint Municipal Electric Utility Commission and various cities in Missouri and Arkansas.786

Entergy Serv. Inc., 117 FERC ¶ 61,288 (2006).

ETI Ex. 65 (Sloan Rebuttal) at 8-9.

OPC Ex. 12 (OPC RFI No. 7-3); OPC Ex. 3 (Szerszen Workpapers) at 363.

OPC Ex. 12 (OPC RFI No. 7-3); OPC Ex. 1 (Szerszen Direct) at 54.

Tr. at 280.

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ETI responds that the activities in this project relate to oversight and coordination of the OATT proceedings before the FERC. Costs billed to this project code are related to ESI’s representation of the Operating Companies, including ETI, before the FERC on OATT issues.

Revenues derived from provision of service under the OATT are credited to all of the Operating Companies on a load responsibility ratio basis. ETI’s retail share of these revenues was $168,366 during the test period, demonstrating the benefits derived by Texas ratepayers as a result of the activities undertaken through this project code.787

Activities relating to a company’s OATT are not one-time activities; they will continue from year to year. OPC’s contention that because most of the dockets listed as having taken place during the Test Year were completed by the end of the Test Year they should be disregarded is not well-founded. It is clear that the activities covered by this project code not only benefit ETI’s Texas ratepayers, but will continue (albeit under new docket numbers) into future years. The ALJs recommend that costs under this project code be allowed.

6. Project F3PCERAKTL (RAKTL Patent Matter) The costs under this project code involve the RAKTL patent, which relates to call center operations. RAKTL is a patent infringement claim lodged against several Entergy companies. The alleged patents are for voice prompting technology used in call centers.788

Dr. Szerszen testified that it is not appropriate to charge ETI for the costs associated with this litigation because ETI did not purchase the call center telephone equipment at issue, and therefore should not be required to pay any legal costs associated with patent infringement investigation or settlement costs. ESI is totally responsible for system-wide technology purchases and operations, and, according to Dr. Szerszen, it is not reasonable to require the operating companies to pay legal costs associated with ESI technology acquisition or technology application errors.789

ETI Ex. 65 (Sloan Rebuttal) at 10. Id. at 4; OPC Ex. 1 (Szerszen Direct) at 49-50.

OPC Ex. 1 (Szerszen Direct) at 50.

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ETI contends that ESI incurred the legal expenses on this patent matter on behalf of the Entergy Operating Companies, whose residential and small commercial customers call into the call centers to obtain customer service for issues related to connection and disconnection of electric service, billing issues, and other customer transactions. The call centers provide an interface between ETI customers and the Entergy Operating Companies and, as such, are valuable in providing quality service to customers. Consequently, according to ETI, costs related to the call centers, including the costs of defending lawsuits involving technologies used at those call centers, is a reasonable and necessary expense that is appropriately allocated to ETI.790

OPC tends to ignore the purpose and benefits of a centralized service company such as ESI.

If ETI were to fund stand-alone call centers, it is likely that the costs to Texas ratepayers would be higher than those proposed by ETI in this case. Part of the costs that ESI incurs is the cost of patent claims. Those are legitimate costs that should be borne by all who receive service from ESI.

Accordingly, the ALJs recommend the Commission reject OPC’s challenge.

7. Project F3PPEASTIN (Willard Eastin et al.)

This project code, which contains costs in the amount of $19,714, collects costs related to an age discrimination law suit filed by Willard Eastin, et al. against Entergy. The defendants to the lawsuit were Entergy, ESI, Entergy Louisiana, Inc. (ELL), and Entergy New Orleans, Inc. (ENOI).

The plaintiffs to the lawsuit were employees of ESI, ELL, and ENOI.791

OPC witness Szerszen testified that ETI should not be required to pay any of the costs of this litigation. Although ESI provides services to the Operating Companies, this does not imply that the Operating Companies should be charged costs associated with the service company’s employment practice problems or errors according to Dr. Szerszen.792

ETI Ex. 65 (Sloan Rebuttal) at 4.

ETI Ex. 65 (Sloan Rebuttal) at 2; OPC Ex. 1 (Szerszen Direct) at 49-50.

OPC Ex. 1 (Szerszen Direct) at 50.

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ETI argues that costs are driven by ESI having the need for legal services to defend itself. As shown on the Project Code Summary for this project, since all ESI functions are in service to the various affiliates and arise as a consequence of providing such services, it is appropriate to relate these legal costs to the total ESI billings to the affiliates.793

ETI has provided little in the way of explanation regarding these costs or the litigation that generated them. What is troubling to the ALJs is that the only named defendants are Entergy, ESI, ELL, and ENOI; ETI is not included among the named defendants. If this were simply a cost of doing business for ESI, as claimed by ETI, why were ELL and ENOI named? No explanation was offered. It appears to the ALJs that although this litigation is related to ESI’s operations, it is more immediately related to ELL and ENOI. The ALJs do not believe that ETI’s Texas ratepayers should be charged for these costs; therefore the ALJs recommend that $19,714 not be included.

8. Project F3PPTCGS11 (TX Docket Competitive Generation) The costs billed through this project code all pertain to ETI’s CGS matter currently pending before the Commission in Docket No. 38951.794

OPC witness Szerszen testified that because no decision has been made yet as to the disposition of the expenses associated with the CGS tariff, ETI should not be expensing the costs associated with that docket. Dr. Szerszen disallowed $310,746 in Test-Year expenses, and recommended that ETI be allowed to defer the expenses until the Commission determines the appropriate regulatory treatment.795

ETI argues that these costs were incurred during the Test Year in a pending Commission docket, and ETI continues to incur costs related to this matter. As such, according to ETI, these

ETI Ex. 65 (Sloan Rebuttal) at 2. Id. at 5; OPC Ex. 1 (Szerszen Direct) at 50.

OPC Ex. 1 (Szerszen Direct) at 50.

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costs are appropriately included in ETI’s cost of service and should neither be disallowed nor deferred.796

OPC’s arguments with respect to these costs are not well-founded. It appears to be likening these regulatory costs to rate case expense, which would be subject to Commission review and approval in the proceeding to which they relate. But that is not the nature of these expenses. They are simply regulatory expenses incurred in the course of ongoing regulatory proceedings. They are ordinary and necessary expenses, the reasonableness of which OPC did not challenge. Accordingly, the ALJs find that it is appropriate for ETI to charge these expenses to its Texas ratepayers.

9. Project F5PCE13759 (Jenkins Class Action Suit) The project code relates to a class action lawsuit filed in Texas District Court in 2003 on behalf of all Texas retail customers served by ETI’s predecessor-in-interest, EGSI (Jenkins Class Action). The Jenkins Class Action plaintiffs allege that they have been damaged due to manipulation of the dispatch and pricing of the Entergy system’s generating units and electricity purchases. As a result of this alleged manipulation, they contend that ETI’s Texas retail customers were charged more than they should have been for purchased power.797 Dr. Szerszen asserted there are three reasons why these legal expenses should not be borne by ETI:

x ESI charges 100 percent of the legal expenses to ETI, even though ETI is only one of several defendants; x ETI claims that it is defending practices relating to system operations, but fails to acknowledge that Entergy’s system operations are comprised of many generation and transmission components other than those of ETI; and x ETI does not have any authority to administer the System Agreement, that being a function solely within the purview of ESI.798

ETI Ex. 65 (Sloan Rebuttal) at 5.

OPC Ex. 1 (Szerszen Direct) at 49; ETI Ex. 65 (Sloan Rebuttal) at 2-3.

OPC Ex. 1 (Szerszen Direct) at 49.

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Dr. Szerszen testified that “[i]t would be more appropriate for the Entergy parent to be charged for these lawsuit expenses, particularly since ETI cannot make unilateral power purchases and power sales decisions.”799

ETI responds that the plaintiffs in this lawsuit are challenging the reasonableness of ETI’s Commission-set rates and that the Commission has filed an amicus brief in support of ETI’s position in the case. ETI further argues that retail ratepayers are benefitting from ETI’s pursuit of the litigation because ETI is defending practices that are in place to ensure the lowest reasonable cost consistent with system reliability. Finally, ETI states that the costs are reasonable and necessary expenses because the plaintiffs purport to represent only ETI’s ratepayers and seek to recover damages inconsistent with ETI’s filed rates approved by the Commission.800

The ALJs understand Dr. Szerszen’s concerns that there are multiple defendants involved in this litigation, there are many aspects to Entergy’s system operations, and ETI does not have power to unilaterally make decisions under the System Agreement. The crucial point, however, is that these are Texas ratepayers pursuing a challenge to ETI’s Texas rates. The matter centers around Texas, and the costs of the litigation should be borne by Texas ratepayers.

10. Project F3PCSYSAGR (System Agreement-2001) OPC witness Szerszen disallowed $880,841 in legal expenses regarding the 2001 complaint filed by the Louisiana Public Service Commission and the City of New Orleans seeking revisions to the Entergy System Agreement.801 OPC states that it generally agrees with ETI witness Sloan that the complaint challenges the equalization of costs between all Entergy Operating Company jurisdictions.802 However, OPC does not agree that the inquiry “will” affect all Entergy jurisdictions. Texas has benefitted from the complaint primarily through the past receipt of equalization payments pursuant to FERC’s decision in this complaint matter. However, Entergy’s Id. ETI Ex. 65 (Sloan Rebuttal) at 3.

OPC Ex. 1 (Szerszen Direct) at 53.

ETI Ex. 65 (Sloan Rebuttal) at 9.

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SEC Form10-K shows that for 2012 and 2013, ETI will receive no equalization payments, and further shows that ETI received no rough production cost equalization payments in 2010.803 Thus, according to OPC, the legal expenses sought to be recovered under Project F3PCSYSAGR are non- recurring for ETI and therefore not representative of future costs and should be removed from ETI’s cost of service.804

ETI established that this litigation involved the System Agreement, which governs the equalization of costs between all of the Entergy Operating Company jurisdictions, it provides benefits to ETI’s Texas ratepayers as well as those of the other Entergy Operating Companies.

OPC’s argument that ETI did not receive equalization payments in 2010 and is non-recurring for ETI does not overcome the benefits received by ETI’s Texas ratepayers. The ALJs recommend that OPC’s disallowance be denied.

11. Project F3PCCDVDAT (Corporate Development Data Room) ETI requests the recovery of $6,147 in ESI allocated costs for the corporate development data room. The stated purpose of the data room is for due diligence reviews associated with Entergy merger, acquisition, or diversification activities. The expenses associated with the corporate development data room are for the gathering, collating, indexing, manning, and storage of data during the due diligence reviews.805 OPC contends that the costs incurred for the corporation’s analysis of merger, acquisition, and diversification opportunities should not be charged to ETI’s ratepayers. Entergy has not acquired any utilities or utility operations that might produce system-wide benefits to utility customers.806 The $6,147 of expenses for the corporate development room are not reasonable and necessary expenses that ratepayers should shoulder and therefore, according to OPC, recovery of these expenses should be disallowed.

ETI Ex. 98 (Entergy’s SEC Form 10-K) at 79-80.

OPC Ex. 1 (Szerszen Direct) at 52-53.

OPC Ex. 3 (Szerszen Workpapers) at 394.

OPC Ex. 1 (Szerszen Direct) at 45-46.

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ETI responds that these costs are driven by each company’s need for corporate services and the costs, therefore, are appropriately allocated based on the level of service provided by ESI, which is a reasonable proxy of each company’s need for corporate services.807 Further, just because Entergy has not acquired any utility or utility operations in the recent past does not mean that these are not reasonable and necessary costs. Entergy points out that as Dr. Szerszen noted in her description of this project, it is not only for the acquisition of other operating units, but also used to analyze diversification activities, which is a legitimate and reasonable undertaking by an integrated utility and its parent company.

The ALJs believe that there are legitimate costs that may not on their face appear to be properly allocable to entities such as ETI, but on closer examination they merit such an allocation.

These fall into that class. As Ms. Tumminello testified, the Corporate Development Data Room includes costs not only related to mergers and acquisitions, but also diversification activities that could benefit ETI ratepayers. Accordingly, they are properly allocated to ETI ratepayers.

12. Project F3PPWET302 (SPO 2008 Winter Western Region) Dr. Szerszen argued that Project F3PPWET302 costs should be disregarded because they were incurred during the 2008-2009 period, which is outside of the Test Year, and they are nonrecurring.808 ETI witness Cicio explained that although this project was initiated prior to the Test Year, the costs that the Company seeks to recover through this project code were expenses incurred during the Test Year. These costs included development activities, requests for proposal issuance, bidders’ conferences, written and posted questions and answers from market participants and other interested parties, submission of proposals, screening of proposals, proposal evaluation, follow-up questions and clarifications, recommendations and awards, contract negotiations, Independent Monitor reports, and regulatory approvals, if necessary. He stated that these types of costs routinely encompass a multi-year time frame, and the costs required to perform those activities, although associated with a ETI Ex. 69 (Tumminello Rebuttal) Ex. SBT-R-2 at 1.

OPC Ex. 1 (Szerzen Direct) at 65.

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project that may have been initiated several years previously, are properly incurred over the life span of the project. He also stated that they are recurring because they reflect the kinds and levels of charges that would be expected to be incurred on an ongoing basis in association with request for proposals managed by ESI on behalf of the Entergy Operating Companies, and the Company has been involved in these types of solicitations since 2002.809

The ALJs find that the costs captured by Project F3PPWET302 were incurred during the Test Year and represent the kinds and levels of costs routinely incurred on a recurring basis.

Accordingly, the ALJs recommend the Commission approve their inclusion as requested by ETI.

13. Project F3PPWET308 (SPO Calpine PPA/Project Houston) With respect to Project F3PPWET308, which deals with the Calpine-Carville purchased power agreement, Dr. Szerszen testified that the costs were either non-recurring, or rate case expenses, or expenses that should have been charged to Louisiana ratepayers.810

ETI witness Cicio explained that these are recurring costs because they reflect the kinds and levels of charges that the Company expects to incur on an ongoing basis in association with RFPs managed by ESI on behalf of the Entergy Operating Companies; they were not incurred as part of some rate case preparation and, therefore, are not a rate case expense that is otherwise sought for recovery by ETI; and the costs in the matter are costs that were billed only to Texas and should not have been billed to Louisiana because there is a separate project code that captures the Louisiana costs that are billed to Louisiana.811

The ALJs find that these costs, like those captured by Project F3PPWET302, are recurring in that they represent the kinds and levels of costs routinely incurred on a year-in and year-out basis.

Further, the ALJs find that the costs should not have been charged to Louisiana and that there

ETI Ex. 45 (Cicio Rebuttal) at 13-14.

OPC Ex. 1 (Szerszen Direct) at 65-66.

ETI Ex. 45 (Cicio Rebuttal) at 14-17.

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existed a separate project code to capture costs attributable to Louisiana. Accordingly, the ALJs recommend the Commission approve the inclusion of these costs as requested by ETI.

M. Other Expenses Class Dr. Szerszen recommended disallowances in 11 project codes that are primarily within the Other Expenses Class of affiliate costs: (1) F3PCSPETEI (Entergy-Tulane Energy Institute) for a disallowance of $14,288; (2) F3PCC08500 (Executive VP, Operations) for a disallowance of $4,117; (3) F3PPBFMESI (ESI Function Migration Relocation) for a disallowance of $4,187; (4) F3PPBFRESI (ESI Business Function Relocation) for a disallowance of $11,444; (5) F3PPDRPESI (ESI Disaster Recovery Plan Charge) for a disallowance of $761; (6) F5PPBFMREL (Business Function Migration Employee) for a disallowance of $33,624; (7) F5PPBFRREL (Business Function Relocation) for a disallowance of $15,624; (8) F5PPBFRSEV (Business Function Relocation Severance) for a disallowance of $3,066; (9) F5PPDRPREL (Disaster Recovery Plan Relocation) for a disallowance of $31,006; (10) F5PPETXRFI (2009 Texas Ike Recovery Filing) for a disallowance of $441; and (11) F5PPKATRPT (Storm Cost Processing & Review) for a disallowance of $929.812

1. Projects F3PCSPETEI (Entergy-Tulane Energy Institute) and F5PPKATRPT (Storm Cost Processing & Review) ETI agrees with Dr. Szerszen that the $14,288 amount she proposed to disallow for Project F3PCSPETEI (Entergy-Tulane Energy Institute) can be treated as a donation, and so should be removed from ETI’s cost of service. ETI also agrees with Dr. Szerszen to remove the $929 billed to ETI under Project F5PPKATRPT (Storm Cost Processing & Review). The charges for the remaining nine project codes, however, are contested.

OPC Ex. 1 (Szerszen Direct) at 56, 67, and 72.

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2. Project F3PCC08500 (Executive VP, Operations) As to Project F3PCC08500 (Executive VP Operations), Dr. Szerszen testified that an asset-based allocator is not appropriate for these types of executive management costs, and there is “no perceivable benefit” to ETI ratepayers for these types of allocated costs.813

Ms. Tumminello disagreed, stating that asset-based allocation methods are selected for projects where the costs are driven by the oversight and stewardship of corporate assets of the Entergy Companies including, but not limited to, services provided by financial management and certain finance functions, among others. Each Entergy affiliate with assets on Entergy’s consolidated balance sheet will be billed their proportionate share of the costs. The use of the Total Assets allocation method is, in fact, an appropriate method to allocate corporate-level corporate governance type services.814

The ALJs find credible ETI’s assertion that the costs captured by this project code are for oversight and stewardship of the corporate assets of Entergy and, therefore, an asset-based allocator is appropriate. Accordingly, the ALJs recommend the Commission reject OPC’s challenge to the inclusion of these costs.

3. Projects F3PPBFMESI (ESI Function Migration Relocation), F3PPBFRESI (ESI Business Function Relocation), F3PPDRPESI (ESI Disaster Recovery Plan Charge), F5PPBFMREL (Business Function Migration Employee), F5PPBFRREL (Business Function Relocation), F5PPBFRSEV (Business Function Relocation Severance), F5PPDRPREL (Disaster Recovery Plan Relocation), and F5PPETXRFI (2009 Texas Ike Recovery Filing) The remaining eight of the project codes attributable to the Other Expenses Class all deal with system restoration and business continuity resulting from Hurricane Katrina, with one applying to Hurricane Ike. Dr. Szerszen testified that these costs should be disallowed because they should not be considered to be system restoration costs or, if they are, citing to PURA § 36.405, ETI should have requested recovery of these costs in its first base rate following Hurricane Katrina (Docket Id. at 56-57.

ETI Ex. 69 (Tumminello Rebuttal) at 9-10.

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No. 34800). She also testified that ETI has not shown that Texas ratepayers benefited from these costs.815

Ms. Tumminello testified that because of the magnitude of Hurricane Katrina, these expenses were necessary so that activities in connection with the restoration of service and infrastructure associated with electric power outages affecting customers could continue. These expenses relate to critical functions needed to support storm restoration, such as business function relocation, and provided a direct benefit to ratepayers. Ms. Tumminello stated that the costs in seven of these project codes (F3PPBFMESI, F3PPBFRESI, F3PPDRPESI, F5PPBFMREL, F5PPBFRREL, F5PPBFRSEV, and F5PPDRPREL) are being amortized over five years. Though these particular costs do not recur every year, they are a part of ETI’s normal utility operations given the service area served by ETI, and do recur as necessary.816

As to Dr. Szerszen’s legal conclusion that ETI is no longer authorized to recover Hurricane Katrina costs, ETI argues that PURA § 36.405 does not restrict or even apply to ETI’s recovery of such costs. That section deals with securitization of system restoration costs, but ETI did not seek to securitize any Hurricane Katrina costs. Even so, argues ETI, if that section did apply, it does not restrict system restoration cost recovery solely to Docket No. 34800; that is, the “next base rate proceeding” following the hurricane. Instead, the final clause in PURA § 36.405(a) states in full that the Company is entitled to recover such costs “in its next base rate proceeding or through any other proceeding authorized by Subchapter C or D.” The same point applies to the Hurricane Ike costs; while ETI did securitize the Hurricane Ike costs that it had incurred up to the date subject to that securitization, it continued to incur costs in this test year for that storm restoration (in this case, $441 billed to the Ike-related project code). The costs in these projects were incurred during the test year for this docket and could not have been recovered in an earlier docket. Moreover, ETI’s filing in

OPC Ex. 1 (Szertrszen Direct) at 72, Schedule CAS-14.

ETI Ex. 69 (Tumminello Rebuttal) at16.

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this docket was filed in accordance with PURA Subchapter C as a rate change proposed by a utility.

As such, ETI contends that it is entitled to recover these costs.817

To the ALJs, the most important part of the argument is that ETI did not seek to avail itself of PURA § 36.405 with respect to Hurricane Katrina costs. It is difficult to understand how that section, which deals with securitization of hurricane costs, could block recovery when ETI did not seek to securitize those costs. Similarly, with respect to Hurricane Ike costs, the $441 challenged by Dr. Szerszen was not incurred until the Test Year and could not have been securitized.

Ms. Tumminello provided testimony that the costs were reasonable and necessary, representing a part of ETI’s normal utility operations. Accordingly, the ALJs recommend the Commission approve inclusion of the costs.

N. Regulatory Services Class Dr. Szerszen challenged one project code that is primarily within the Regulatory Services Class of affiliate costs: Project F3PPE9981S (Integrated Energy Management for ESI) for a disallowance of $171,032.

Dr. Szerszen testified that these costs were incurred for the implementation, coordination, and promotion of demand side and supply side management and energy efficiency programs. But, she stated, these costs should instead have been recovered through ETI’s Energy Efficiency Cost Recovery Factor (EECRF) Rider and, as such, it is inappropriate to recover these costs through affiliate billings in base rates.818

ETI witness May testified that recovery of these costs through base rates rather than through the EECRF Rider is appropriate because these activities are not subject to an active ETI energy efficiency program. These activities are more in the nature of general research and development activities that help drive the Company’s strategy on these topics, such as the timing of implementing related programs. In the meantime, until these activities result in an actual program proposal, these ETI Initial Brief at 188-189.

OPC Ex. 1 (Szerszen Direct) at 69-70.

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are legitimate known and measurable costs that the Company has incurred and should then be recovered from retail customers.819 At the hearing, Mr. May further explained that the costs in this project code are labor costs that are “not really consistent” with the energy efficiency rule, but instead involve “primarily costs of investigating” potential future activities (such as smart meters and electric vehicle chargers) that are generally not consistent with the energy efficiency rider.820 ETI witness Considine also addresses this issue from a regulatory accounting perspective. He testified: “Because these are not costs that must be, or are currently being recovered through the EECRF, they are not double recovered and should be included in the Company’s cost of service.”821 According to ETI, the costs in this project code, therefore, are not costs that should or can be recovered through ETI’s EECRF Rider.

This is a close call. The Commission’s Energy Efficiency Rule places limits on the amount of research and development costs a utility may recover,822 which supports the argument that the costs should be included in the EECRF. Further, it appears to the ALJs that research and development costs, by their very nature, do not relate to an active program, which negates many of the arguments advanced by ETI witnesses May and Considine. In the end, the ALJs believe that these costs should be included in the EECRF. Accordingly, the ALJs recommend the Commission disallow costs in the amount of $171,032 relating to Project F3PPE9981S.

O. Retail Operations Class Dr. Szerszen challenged three project codes that are primarily within ETI’s Retail Operations Class of affiliate costs: (1) F5PPICCIMG (ICC – “Image” Message) for a disallowance of $3,912; (2) F3PPR56640 (Wholesale - EGS-TX) for a disallowance of $229,938; and (3) F3PPR56920 (Wholesale - All Jurisdictions) for a disallowance of $333.

ETI Ex. 57 (May Rebuttal) at 30-31.

Tr. at 1929-1930 and 1934-1935.

ETI Ex. 46 (Considine Rebuttal) at 36.

P.U.C. SUBST. R. 25.181(i).

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1. Project F5PPICCIMG (ICC – “Image” Message) Project Code F5PPICCIMG (ICC-“Image” Message) is one of the project codes that Dr. Szerszen testified should be disallowed because ETI is a monopoly and Texas ratepayers should not have to pay for corporate image costs.823

Ms. Tumminello testified that the costs are for advertising activities that are of a good will or institutional nature, which is primarily designed to improve the image of the utility or the industry, including advertisement which inform the public concerning matters affecting the Company’s operations, such as, the costs of providing service, the Company’s efforts to improve the quality of service, the Company’s efforts to improve and protect the environment. According to FERC, such costs are properly includable in FERC Account 930.1 and are recoverable. According to Ms. Tumminello, as contemplated by FERC, the fact that ETI is a monopoly has no bearing on the recoverability of these costs.824

OPC provided little support for its claim that costs covered by these project codes should not be recoverable, essentially limiting the basis to the contention that ETI is a monopoly and ratepayers should not be charged with such costs. ETI did provide the testimony of Ms. Tumminello, which confirms that the costs are properly includable in FERC Account 930.1 and are, therefore, recoverable. In the end, the weight of the evidence is in ETI’s favor. The ALJs recommend the Commission reject OPC’s contention that costs covered by these project codes are not recoverable.

2. Projects F3PPR56640 (Wholesale - EGS-TX) and F3PPR56920 (Wholesale - All Jurisdictions) As to Projects F3PPR56640 and F3PPR56920, Dr. Szerszen stated that these costs are associated with assisting ETI’s wholesale customers in evaluating alternative energy supply and

OPC Ex. 1 (Szerszen Direct) at 66.

ETI Ex. 69 (Tumminello Rebuttal) at SBT-R-2 at 4-6.

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demand options and that ETI’s retail customers should not be charged for expenses associated with ETI’s wholesale customers.825

ETI witness Stokes noted that ETI has allocated costs to its single large wholesale customer through its jurisdictional allocation in this rate case and, therefore, to disallow the costs in these two project codes would essentially result in a double disallowance of those costs. She also explained that the costs were properly allocable to ETI (keeping in mind that ETI then allocated costs to this customer) as reasonable and necessary due to the need to have staff on hand to handle contract negotiations and the like with this large wholesale customer.826

The ALJs are persuaded by ETI’s argument that disallowing the costs associated with Projects F3PPR56640 and F3PPR56920, which are already allocated to ETI’s single large wholesale customer through its jurisdictional allocation, would constitute a double disallowance. Accordingly, the ALJs recommend the Commission reject OPC’s challenge to these costs.

P. Supply Chain Class Dr. Szerszen challenged two project codes that are primarily within the Supply Chain Class: (1) F3PPH54075 (Business Development - TX) for a disallowance of $1,888; and (2) F5PCZSDEPT (Supervision & Support - Supply) for a disallowance of $146. Dr. Szerszen claimed the costs associated with these project codes should be disallowed because ETI is a monopoly and Texas ratepayers should not have to pay for corporate image costs.827

Ms. Tumminello testified that the costs are for advertising activities that are of a good will or institutional nature, which is primarily designed to improve the image of the utility or the industry, including advertisement which inform the public concerning matters affecting the Company’s operations, such as, the costs of providing service, the Company’s efforts to improve the quality of service, the Company’s efforts to improve and protect the environment, etc. According to FERC, OPC Ex. 1 (Szerszen Direct) at 73.

ETI Ex. 66 (Stokes Rebuttal) at 6-9.

OPC Ex. 1 (Szerszen Direct) at 66.

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such costs are properly includable in FERC Account 930.1 and are recoverable. According to Ms. Tumminello, as contemplated by FERC, the fact that ETI is a monopoly has no bearing on the recoverability of these costs.828

OPC provided little support for its claim that costs covered by these project codes should not be recoverable, essentially limiting the basis to the contention that ETI is a monopoly. ETI did provide the testimony of Ms. Tumminello, which confirms that the costs are properly includable in FERC Account 930.1 and are, therefore, recoverable. The ALJs go with the weight of the evidence, which is in ETI’s favor. The ALJs recommend the Commission reject OPC’s contention that costs covered by these project codes are not recoverable.

Q. Transmission and Distribution Support Class Dr. Szerszen challenged three project codes that are included within the Company’s Transmission and Distribution Support Class of affiliate costs: (1) F3PCT53130 (Operations Manager, Claims Management) for a disallowance of $42,287.50; (2) F3PCTDAMAG (Damage Claims Of Entergy Property) for a disallowance of $5,555; and (3) F3PCTPUBLC (Public Claims) for a disallowance of $3,968. Dr. Szerszen’s rationale for disallowing 50 percent of the costs in each of these codes is the same. She believes that ETI’s property damage and workers compensation claims should be direct billed instead of allocated through a customer count-based allocator; managerial and supervisory costs should be allocated to the jurisdictions based on the jurisdictional direct charges; and the Company has not met its burden of proof as to these charges.829

Ms. Tumminello addressed Project F3PCT53130, stating that workers’ compensation claims are tracked by jurisdiction as Dr. Szerszen suggested, and are the basis for billing method COMCLAIM. Project F3PCTWCOMP is used to capture the costs of workers’ compensation claims, and bills to both regulated and non-regulated affiliates. Project F3PCT53130 captures costs that are primarily for the oversight of the Entergy Companies’ Claims Management organization as it relates to property damage and liability. These services benefit only the companies that serve ETI Ex. 69 (Tumminello Rebuttal) at SBT-R-2 at 4-6.

OPC Exhibit No. 1 (Szerszen Direct) at 79-80.

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retail electric and gas customers. Since only the regulated utility operating companies (and not the non-regulated companies) serve retail customers, it is appropriate to bill these costs to the regulated companies based on their pro-rata share of total customers.830

Projects F3PCTDAMAG and F3PCTPUBLC are addressed by ETI witness Corkran. With respect to Project F3PCTDAMAG, Mr. Corkran stated that the costs associated with this project are associated with the Public Claims employees in the Claims Management Organization. Those employees pursue the recovery of claims allowed by law when the public inflicts damage to Company property. The costs of this service are allocated among all of Entergy’s Operating Companies through billing method CUSTEGOP, which allocates costs based on the number of customers in each Operating Company. Dr. Szerszen claimed that the affiliate costs associated with pursuing those claims should be directly charged to each Entergy Operating Company based on the extent to which each claim pertains to the Operating Company instead of generally allocating the costs to all utility customers. Mr. Corkran testified that the allocation methodology is appropriate because the Public Claims employees provide knowledgeable, centralized, and consistent pursuit of damage claims. The actual monies recovered for damage to ETI’s property are returned to ETI ratepayers as credits against the cost of repairing those damaged facilities, i.e., the recoveries are not allocated pursuant to CUSTEGOP. Only the Public Claims employees’ time and overheads are allocated pursuant to CUSTEGOP, which is reasonable and appropriate because the overall time spent by Public Claims employees in pursuing the recovery of claims is driven by the number of gas and electric customers in each Operating Company.831

With respect to Project F3PCTPUBLC, Mr. Corkran stated that the costs associated with this project are related to Public and Auto Liability employees in the Claims Management Organization.

These employees pursue the resolution and settlement of damage claims made against the Operating Companies in a timely and fair manner through denials, negotiations, and payments. Such claims include allegations of damaged appliances due to voltage fluctuation, food loss due to power outages, and damage caused by Company vehicles (e.g., mailboxes, fence posts, and automobiles).

ETI Ex. 69 (Tumminello Rebuttal) at SBT-R-2 at 10.

ETI Ex. 48 (Corkran Rebuttal) at 13-15.

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This is an important process that ensures that only warranted and justifiable claims are paid. The CUSTEGOP billing method is appropriate because the Public and Auto Liability employees provide knowledgeable, centralized, and consistent resolution of damage claims. The actual payments associated with ETI public damage claims are charged to ETI through the use of other project codes.

Only the Public and Auto Liability employees’ time and overheads are allocated pursuant to CUSTEGOP, which is reasonable and appropriate because the overall time spent by Public and Auto Liability employees in processing claims is driven by the number of gas and electric customers in each Operating Company.832

The explanations that ETI provides for the charges captured by these project codes and the method of allocation employed makes sense to the ALJs. In a large organization, it is necessary to have a group of people to process claims efficiently so that economies of scale can be realized; that is what ETI is doing with these project codes. These costs benefit all companies within the Entergy umbrella (or within the regulated entities portion as noted), so the allocation methodology employed is appropriate. The ALJs recommend the Commission reject OPC’s challenge to the recovery of these costs.

R. Tax Services Class Dr. Szerszen proposed a 25 percent ($221,007) disallowance of costs billed to ETI from a single project code in this Tax Services Class: Project Code F3PCF10445 (Entergy Consolidated Tax Services). The costs in this project were incurred in the preparation, research, and other costs associated with Entergy’s consolidated tax return. Dr. Szerszen testified that an assets-based allocator is not appropriate for these costs and that the costs in the project should instead be directly billed to each affiliate based on the time spent on preparing that affiliate’s income and expense data.833

Company witness Galbraith, who sponsors ETI’s Tax Services Class, stated that Dr. Szerszen apparently believes that all costs associated with the preparation of Entergy’s consolidated tax return Id. OPC Ex. 1 (Szerszen Direct) at 63.

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are captured by this project code and are allocated, when they should be direct-billed. Most of the costs associated with preparation of Entergy’s consolidated tax return, according to Ms. Galbraith, are assigned to other project codes and are direct billed. Ms. Galbraith then explained that: (1) 56 percent of the time that Tax Services spent on the Entergy consolidated tax return were direct billed through other project codes to the affiliates; (2) the project code also captures costs for tax research (both federal and state and local), monthly closing activities not specific to one legal entity, tax training that is not jurisdiction specific, compliance with file retention policy, and administration staff time; and (3) why the assets-based allocator is the best method for allocating these departmental costs. According to Ms. Galbraith, the costs captured by this code are not susceptible to direct billing.834 The ALJs find that Dr. Szerszen did fail to consider that most of the costs of preparing Entergy’s tax return are direct billed and that the costs covered by this project code are not susceptible to such a billing, which is why they are allocated. The ALJs, therefore, recommend the Commission reject OPC’s challenge to ETI’s allocation of these costs.

S. Transmission Operations Class Dr. Szerszen challenged three project codes that are primarily within the Transmission Operations Class: (1) F3PPTDHY19 (Dept. of Justice Investigations) for a disallowance of $765; (2) F3PPTREORG (Transmission Re-Organization) for a disallowance of $3,661; and (3) F3PPF30211 (ESI Transmission Bldg (Reclassification)) for a disallowance of $229,991.835

Dr. Szerszen addressed Project F3PPTREORG (Transmission-Reorganization) and testified that costs covered by this project were incurred in 2009 and 2010 and, therefore, are not recurring.836 Ms. Tumminello responds that, while these particular costs do not recur every year, they are

ETI Ex. 26 (Galbraith Direct) at 10-12.

Project F3PPTDHY19 (Dept. of Justice Investigations) was discussed in Section VIII.L. (Legal Services Class) and will not be repeated here OPC Ex. 1 (Szerszen Direct) at 54, Schedule CAS-8.

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representative of normal recurring utility operations and do recur as necessary and, as such, they should not be disallowed.837

Dr. Szerszen testified that Project F3PPF30211 (ESI Transmission Bldg.) captures interest costs after the ESI transmission building was placed in service. She contends that the costs are reclassified pre-Test Year payments and post-Test Year interest costs that are not known and measureable.838 Ms. Tumminello testified that Dr. Szerszen has misconstrued accounting entries.

She explains that these charges capture 12 months of interest payments and the annual bond fee incurred only during the Test Year.839

The ALJs find that the costs associated with Project F3PPTREORG are representative of costs that recur every year and should not be disallowed. It appears to the ALJs that Dr. Szerszen did misconstrue accounting entries in preparing her analysis of Project F3PPF30211and that the charges in that project capture fees paid during the Test Year. Accordingly, the ALJs recommend that OPC’s proposed disallowance be denied.

T. Treasury Operations Class Dr. Szerszen challenged three project codes that are primarily within the Treasury Operations Class: (1) F5PCZZI07P (Directors & Officers (EIM)) for a disallowance of $14,483; (2) F3PCF25300 (Daily Cash Mgt Activities) for a disallowance of $7,286; and (3) F3PCF26022 (Financing & Short Term Funding) for a disallowance of $96,700.

With respect to Project F5PCZZ107P (Directors & Officers (EIM)), Dr. Szerszen testified that the directors and officers liability insurance subject to this project code is primarily aimed at

ETI Ex. 69 (Tumminello Rebuttal) at SBT-R-2 at 1.

OPC Ex. 1 (Szerszen Direct) at 71.

ETI Ex. 69 (Tumminello Rebuttal) at 15. See also Ex. SBT-R-5.

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benefiting shareholders, rather than ratepayers and, because ETI does not manage ESI’s operations, it should not be responsible for indemnifying against shareholder lawsuits.840

ETI witness McNeal stated that ESI provides essential administrative and operational services to ETI on a daily basis. To do this, it must employ (and retain) qualified officers and directors. These individuals must be assured that they can make reasoned decisions without fear of personal liability and the manner to provide them this assurance is to purchase director’s and officer’s liability insurance. Because ETI benefits from the services provided by the officers and directors, ETI argues, it is appropriate to allocate a portion of the cost of the director’s and officer’s liability insurance to ETI.841

Dr. Szerszen addressed Projects F3PCF25300 (Daily Cash Mgt Activities) and F3PCF26022 (Financing & Short Term Funding), contending that these projects are duplicative of ETI-specific financing and cash management activities; that these costs should be borne by Entergy shareholders; and that the bank accounts-based and level of service-based allocators applicable to this projects are not appropriate.842

ETI responds that Project F3PCF25300 captures costs for activities performed by the Cash Management Department for work associated with maintaining bank relationships, bank fee analysis, administrative of bank systems and controls, and all other banking and cash management activities that are general in nature. These are not specific to any one company, but are applicable to all of the companies within the umbrella of the Entergy corporate family. There are Company- specific activities that are charged directly to ETI under different project codes, and this constitutes the majority of financing and cash management activities during the Test Year. For Project F3PCF25300, the costs are driven by cash management products and services delivered to all the Entergy companies. Because the number of transactions executed on behalf of each Entergy company is directly related to the number of bank accounts by company irrespective of account size,

OPC Ex. 1 (Szerszen Direct) at 59.

ETI Ex. 61 (McNeal Rebuttal) at 7-8.

OPC Ex. 1 (Szerszen Direct) at 74-75, Ex. CAS-15.

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billing method BNKACCTA, which allocates costs based on the number of open bank accounts is, according to ETI, the appropriate method to allocate the costs of these services.843

With respect to Project F3PCF26022, ETI explains that the project code captures costs for managing Entergy companies’ liability portfolios comprised of Entergy company securities, bank lines, and project financings. The work is performed for the benefit of all companies under the Entergy corporate umbrella, not just ETI and is not duplicative of services performed for ETI. When work is performed by ESI personnel that relates specifically to ETI, then ETI is charged directly under a different project code. The services include analyzing and supporting general capital structure policy, developing and analyzing general financial policies, investigating and evaluating financing options generally that might prove beneficial for any or all Entergy companies, including ETI, and facilitating ongoing administration related to all Entergy Operating Company financings.

Accordingly, ETI argues that it is appropriate to allocate a share of those costs to ETI. The costs of this project are driven by the level of service needed to complete the project or activity. Allocator LVSVCAL allocates costs based upon the overall service level of ESI. This allocation is appropriate because ESI is providing the service and no one Operating Company alone benefits from the services provided under this project code.844

OPC appears to have taken too narrow a view with respect to these project codes. First, it appears that where services are performed solely for ETI, they are charged to ETI through specific project codes. The project codes that OPC challenges are for company-wide services that are partially allocated to ETI. It is logical to assume that a certain level of services can be performed more efficiently at a company-wide level and that Texas ratepayers will benefit by paying only the allocated portion of those costs, as is done in these cases. The allocators chosen by ETI appear to reasonably reflect the cost-causation. Therefore, the ALJs recommend that OPC’s challenge be rejected.

ETI Ex. 61 (McNeal Rebuttal) at 3-6; Tr. at 546.

ETI Ex. 61 (McNeal Rebuttal) at 2-3; Tr. at 547-548.

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U. Utility and Executive Management Class OPC challenges five project codes that are primarily within the Utility & Executive Management Class: (1) F3PPCCS010 (Climate Consulting Services) for a disallowance of $19,821; (2) F3PCCPM001 (Corporate Performance Management) for a disallowance of $173,867; (3) F3PCC31255 (Operations-Office of the CEO) for a disallowance of $372,919; (4) F3PPCAO001 (Chief Administrative Officer) for a disallowance of $177,156; and (5) F3PPCOO001 (Chief Operating Officer) for a disallowance of $74,485.

As to the first, Project F3PPCCS010 (Climate Counseling Services), Dr. Szerszen testified that these costs are incurred for the development of company-wide environmental policies, procedures, and programs; that expenses are improperly allocated to the subsidiaries based on each company’s fossil operating capacity; and, as a result, the non-regulated affiliates are not allocated any environmental initiative expenses. She therefore recommended that 50 percent of this project’s costs be disallowed.845

ETI witness Stokes addressed Dr. Szerszen’s challenge to this project. Ms. Stokes explained that although nuclear-related environmental projects are being pursued, they are not being pursued using the project code referenced by Dr. Szerszen in her challenge. The costs for non-regulated affiliates are charged to projects not included in ETI’s affiliate costs in this case. Non-regulated affiliates use project codes specific to their businesses to maintain a separation of costs between regulated and non-regulated Entergy subsidiaries.846

For the remaining four project codes in this class, Dr. Szerszen stated that executive management is primarily concerned with overall corporate functions rather than issues for any one specific subsidiary, and there is no relationship between an assets-based allocator and executive management.847

OPC Ex. 1 (Szerszen Direct) at 62.

ETI Ex. 66 (Stokes Rebuttal) at 5.

OPC Ex. 1 (Szerszen Direct) at 56, 60.

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ETI responds to these arguments by stating that the functions covered by these project codes relate to the oversight of all system operations and the stewardship of corporate assets and that because ETI is part of a corporate group, the allocated charges associated with these services are relevant to ETI as part of that group of companies. Furthermore, ETI argues, the asset-based allocator is appropriate because it reflects the cause of the costs incurred, in that, services provided relate to the stewardship of all the corporation’s assets.848

A corporation cannot function without executives, who are charged with the responsibility of overseeing, among other things, the assets of the corporation. This is an important function that Dr. Szerszen did not acknowledge in her testimony. The utility and executive management class costs that she challenges are reasonable and necessary costs that are allocated to ETI based on a logical allocator – the assets the executives manage. The ALJs recommend that OPC’s challenge be rejected.

IX. JURISDICTIONAL COST ALLOCATION [Germane to Preliminary Order Issue No. 13] Jurisdictional cost allocation involves the proper method for allocating production costs between ETI’s Texas retail customers and its wholesale customers, which are subject to FERC jurisdiction. During the Test Year, ETI provided electric service to retail customers and to three wholesale customers—including ETEC—under service agreements and rates approved by FERC.

ETEC is a partial requirements customer, and it will be ETI’s only wholesale customer during the Rate Year. ETI estimated its cost of serving wholesale customers in a jurisdictional separation study that split ETI’s cost of service between retail and the wholesale jurisdictions.849

To calculate the wholesale cost allocation factor, ETI proposed the use of 150 MW for the wholesale load. This results in a retail production demand allocation factor of 95.3838 percent. The 150-MW load represents the contractual minimum amount of capacity for which ETEC is obligated

ETI Ex. 4 (Domino Direct) at 18-38; ETI Ex. 69 (Tumminello Rebuttal) at 9-11.

Cities Ex. 4 (Goins Direct) at 4.

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to pay under its partial requirements agreement. No party contests this aspect of ETI’s proposed allocation of costs between retail and wholesale customers.850

However, Cities contest the type of allocation methodology used to assign demand-related (fixed) production costs to each jurisdiction. In this proceeding, ETI used the A&E 4CP allocation method. Although this is the same methodology ETI used in this proceeding’s class cost-of-service study (to assign demand-related production costs to each retail customer class), ETI used a different methodology – 12 Coincident Peak (12CP) – in its last rate case to assign costs between jurisdictions.851

A. A&E 4CP Kroger witness Kevin C. Higgins explained the A&E 4CP method:

[T]he Average and Excess Demand method uses an average demand or total energy allocator to allocate that portion of the utility’s generating capacity that would be needed if all customers used energy at a constant 100 percent load factor. The cost of capacity above average demand is then allocated in proportion to each class’s excess demand, where excess demand is measured as the difference between each class’s individual peak demand and its average demand. In this manner, the incremental amount of production plant that is required to meet loads that are above average demand is assigned to the users who create the need for the additional capacity. . . . the A&E/4CP variant . . . uses 4 CP to measure excess demand, whereas the conventional version uses class non-coincident peak . . . .852 ETI witness Myra L. Talkington also explained that the A&E 4CP method, noting that ETI’s coincident peak demand is measured for the months of June through September. Ms. Talkington recommends the A&E 4CP allocation because it “reasonably reflects the mix of the Company’s customers and their respective electrical load characteristics and the relative cost incurred to serve

ETI Ex. 7 (May Direct) at 23-24. Ms. Talkington used the 150 MW number sponsored by Mr. May, and the associated energy use, to calculate the jurisdictional allocation factor. ETI Ex. 22 (Talkington Direct) at 11-12.

Cities Ex. 4 (Goins Direct) at 10.

Kroger Ex. 2 (Higgins Cross Rebuttal) at 3 (footnotes deleted).

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such loads.”853 She also believes this allocation methodology provides a reasonable balance between the contribution to the system peak and energy requirements.854

As noted above, ETI’s use of A&E 4CP is a change from the 12CP methodology it used when it operated within two states. Ms. Talkington testified that 12CP was appropriate in the past because System Agreement costs were allocated between Entergy Operating Companies using 12CP.

The Texas retail portion of the production costs were then allocated between the retail classes using the A&E 4CP methodology (as ETI is doing in this case). However, according to Ms. Talkington, now that ETI operates in only one state, no jurisdictional allocation among states is necessary; therefore, only one allocation methodology, i.e., A&E 4CP, should be used to allocate production costs between the retail classes and the wholesale jurisdiction. Ms. Talkington testified that the A&E 4CP methodology factors in year-round demand through the average and excess function and also matches the allocator used to allocate costs within the retail class.855

Cities opposes the use of A&E 4CP and suggest a 12CP methodology is preferable.

Commission Staff does not oppose ETI’s use of A&E 4CP. No other party takes a position on this issue.

B. 12CP The12CP methodology allocates production capacity costs in proportion to each class’s demands that occur on the date and time of ETI’s system peak in each of the 12 months.856 Cities believe it is more appropriate for ETI to allocate fixed production costs between the wholesale customers and Texas retail customers using 12CP. Cities witness Dennis W. Goins testified that the 12CP approach is consistent with the cost-of-service approach FERC typically uses to allocate demand-related production costs reflected in wholesale rate schedules, and it is consistent with the assignment of MSS-1 costs (as well as MSS-2 transmission costs) to ETI under the Entergy System ETI Ex. 23 (Talkington Direct) at 6; OPC Ex. 6 (Benedict Direct) at 17.

ETI Ex. 23 (Talkington Direct) at 6.

ETI Ex. 67 (Talkington Rebuttal) at 6-7.

TIEC Ex. 3 (Pollock Cross Rebuttal) at 26.

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Agreement. Dr. Goins reviewed ETI’s Rate Year purchased power capacity costs month by month.

He determined that ETI’s heavy reliance on capacity purchases to serve retail and wholesale load, and the relative stability of those projected monthly purchased power capacity costs, suggest that the 12CP method should properly split ETI’s demand-related production costs between the Texas retail and wholesale jurisdictions.857

Dr. Goins calculated Test Year 12CP allocation factors for the Texas retail and wholesale jurisdictions, and provided them to Cities witness Karl Nalepa for inclusion in his jurisdictional separation study. He determined the following:858

Jurisdiction A&E 4CP 12CP Texas Retail 95.3838% 94.6208% Wholesale 4.6162% 5.7923% Total 100% 100%

In making this calculation, Dr. Goins used a loss-adjusted 150 MW (ETEC’s monthly billing MW) as a proxy for the 12 monthly CPs. In his view, the 150 MW is indicative of ETI’s capacity obligations to ETEC, and it reflects known and measurable changes compared to test-year wholesale CPs (which would include CPs for wholesale customers that ETI no longer serves).859

Cities point out that ETI previously allocated production costs to the wholesale jurisdiction on a 12CP basis. ETI first requested that the Commission change the 12CP method in Docket No. 37744.860 According to Cities, ETI’s request to change the 12CP methodology in Docket No. 37744 is significant because ETI’s wholesale load consisted of Brazos Electric Cooperative, Inc. (Brazos) and ETEC. The Brazos contract assigned Brazos’ share of ETI’s production costs based upon a 12CP allocator. Thus, contends Cities, all costs that would have been over-allocated to retail Cities Ex. 4 (Goins Direct) at 10-12.

Cities Ex. 4 (Goins Direct) at 12.

Cities Ex. 4 (Goins Direct) at 10-12.

The parties in that docket stipulated the majority of issues in the case, including issues relating to jurisdictional allocation.

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customers would have been pocketed by ETI (if the 12CP allocator had changed). Cities argue that ETI’s request to deviate from its approved 12CP allocator will result in retail customers subsidizing production costs. Dr. Goins calculated that the 12CP allocation factor for ETI’s wholesale jurisdiction is approximately 5.38 percent versus 4.62 percent under the A&E 4CP method.861 Cities conclude that retail customers will subsidize the difference between the two allocators, which is 0.76 percent. Because the allocation is applied to all production costs, including purchased power capacity costs, the 0.76 percent difference is significant, contend Cities.

According to ETI, Cities’ arguments are based on a non-existent situation—the provision of service to Brazos—and should be rejected. The ALJs acknowledge that ETI is no longer serving Brazos. Dr. Goins noted such in his testimony. Rather, the basis for his recommendation was: (1) the 12CP approach is consistent with FERC’s wholesale rate allocation; (2) the 12CP method is used to derive each Entergy Operating Company’s load responsibility ratio and share of monthly MSS-1 and MSS-2 charges; and (3) ETI’s purchased power capacity costs do not vary significantly month to month. Although Ms. Talkington understood that the A&E 4CP methodology is the same one used to allocate production costs between classes, TIEC witness Pollock noted that it is often not appropriate to use the same allocation method for both jurisdictional and class allocations. He noted that, in jurisdictional separation, allocations are between retail and wholesale entities, with wholesale subject to FERC regulation.862 ETI did not fully explain why A&E 4CP is the best methodology for allocation production costs between the retail and wholesale jurisdictions.

Dr. Goins’ and Mr. Pollock’s testimonies were ultimately more persuasive on this issue.

Accordingly, the ALJs recommend the use of 12CP to allocate capacity-related production costs between the retail and wholesale jurisdictions.

Cities Ex. 4 (Goins Direct) at 11-12.

TIEC Ex. 3 (Pollock Cross Rebuttal) at 29. The ALJs acknowledge that Mr. Pollock does not contest ETI’s use of the A&E 4CP jurisdictional allocation methodology—rather, his testimony was explaining why 12CP is not appropriate as an allocator among the different customer classes.

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X. CLASS COST ALLOCATION AND RATE DESIGN [Germane to Preliminary Order Issue No. 1] ETI witness Talkington testified regarding the allocation methods for each of the major function/classification cost categories used in the Company’s retail class cost-of-service study.

Ms. Talkington also sponsors ETI’s proposed rate design. Contested issues are set out below.

A. Renewable Energy Credit Rider [Germane to Preliminary Order Issue No. 19] The Legislature has established a goal for the installation of an additional 5,000 MW of generating capacity from renewable energy technology. It also set out annual goals for electric utilities to meet on a cumulative basis in order to encourage the development of renewable energy generation in Texas.. A utility may meet its annual goals by installing generation, by purchasing capacity based on renewable energy technology, or by purchasing sufficient renewable energy credits (RECs).863

1. ETI’s Proposed Cost Recovery Staff witness William B. Abbott explained that the Company currently recovers its REC costs through base rates. Each credit represents one megawatt-hour (MWh) of renewable energy that meets certain criteria set forth in P.U.C. SUBST. R. 25.173(e), and these credits can be traded among participants in the Texas market. ETI proposes to remove these costs from base rates and implement a REC Rider to recover its projected REC costs. After the initial rider is established, the REC Rider would be reset annually to recover projected REC costs for the upcoming year, adjusted by any past over- or under-recovery and any revenue-related expenses.864 With the introduction of the REC Rider, ETI would withdraw its current Renewable Portfolio Standard Calculation Opt-Out Credit Rider, which provides a credit to offset the base rate REC costs for certain customers who are

PURA §39.904(a) and (b).

See ETI Ex. 31 (LeBlanc Direct) at 26.

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exempt from paying REC costs. These customers would instead be exempt from charges under the proposed REC Rider.865

ETI suggests that a rider is necessary because the level of REC costs incurred from year to year is not known, and the cots are unknowable and very volatile. ETI witness Heather G. LeBlanc testified that certain customers can opt out, and a rider is the most efficient manner to administer such opt out.866

Initially, ETI based its rates for the proposed rider on the Company’s Test Year renewable energy credit costs, which were incurred on a Texas retail basis for the 12 months ending June 30, 2011. ETI requested $623,303 and, after applying the revenue-related expense factor of 1.01307, proposed a revenue requirement of $631,450.867 In rebuttal testimony, Ms. LeBlanc stated that the Company’s proposal should be updated to reflect the most current data available. She stated that “events” since the Company’s initial filing in November 2011 caused costs for the Company to increase.868 She calculated an updated amount of $1,145,043, which, when the revenue-related expense factor is applied, results in an updated revenue requirement of $1,160,008.869 She believes that the updated amounts further support the Company’s position that REC costs are volatile.

2. Opposition to ETI’s Proposal Cities, OPC, State Agencies, and Commission Staff oppose ETI’s proposed REC Rider.

State Agencies argue that ETI’s proposed REC Rider should be rejected because it deviates from the Commission’s ratemaking policies and is inconsistent with PURA. State Agencies witness Kit Pevoto testified that the proposed rider is not appropriate because: (1) the rider is piecemeal ratemaking, which deviates from the Commission’s traditional ratemaking policies and is Staff Ex. 7 (Abbott Direct) at 11-12.

ETI Ex. 31 (LeBlanc Direct) at 25.

Id. at 24. This amount is then divided by all non-transmission level kWh sales.

ETI Ex. 55 (LeBlanc Rebuttal) at 10-11.

Id. at 11. This amount is then divided by all non-transmission level kWh sales.

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inconsistent with PURA; (2) the reconciliation (true-up) process in the proposed tariff is not specifically provided for by PURA or PUC rule, or required to implement the REC process; (3) the redetermination of rates in the proposed annual filings would be based on projected or estimated costs, rather than historical test year costs; which is not in compliance with PURA or the Commission’s rules; and (4) ETI has not justified the need to have a rate recovery for REC costs outside of the traditional PURA base rate recovery. Ms. Pevoto explained that the traditional test year cost of service ratemaking process, including regulatory lag, helps to match costs and revenues and to provide incentives that balance the utility’s and its customers’ interests. The proposed REC rider deviates from the traditional PURA rate-setting because it allows the Company to reset its rates automatically each year without going through a comprehensive rate proceeding. In her view, the rider would eliminate the regulatory lag incentive for ETI to prudently manage these costs because the rider allows for annual cost recovery adjustments. Ms. Pevoto observed that various provisions in PURA authorize riders for collection of other expenses, but no such provision exists for recovery of REC expenses, even though the Legislature mandated that utilities be responsible for a certain level of REC MWs. And she noted that if ETI’s REC expenses increase due to increases in total REC MW requirements, ETI can request to include those increased costs in a future rate case.870

In reference to Ms. LeBlanc’s rebuttal testimony that “events” caused ETI’s REC costs to increase, State Agencies contend that ETI may have paid more for RECs during the Test Year because it contacted suppliers only after the REC requirement was mandated. ETI acknowledged that RECs were in the $1.10 to $1.25 range at the beginning of the year and then appreciated to over $2.00 and peaked out at $2.55 in the first quarter of 2012. Moreover, one of the largest REC suppliers unexpectedly withdrew its offers in March of 2011, which also led to price increases.

March 31 is the end of the compliance period, and the deadline may increase the volume of purchases, which can add to price increases.871 State Agencies note that ETI did not participate in the competitive REC market until February 2012 and bought its RECs near the peak price. State Agencies contend that only Test Year costs of $623,303 should be included in base rates.

State Agencies Ex. 2 (Pevoto Direct) at 6, 8-11.

State Agencies Ex. 12, RFI.

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Cities witness Karl Nalepa also opposed the REC Rider. He testified that the Commission should not permit ETI to single out REC costs from base rates because it presented no evidence that these costs should be treated differently than they are now. He added that RECs are not related to fuel so much as they are related to retail sales and plant output. In his opinion, the Test Year amount for REC of $633,985 should be included in base rates.872 Cities witness James Z. Brazell also testified that ETI currently recovers a large portion of its revenues through non-fuel piecemeal riders. While he believes some riders are necessary and appropriate, ETI’s general movement of cost recovery from base rates to riders (as evidenced in this proceeding) is inconsistent with PURA and the prohibition against piecemeal ratemaking.873

OPC also opposed ETI’s proposed REC Rider on the basis that it constitutes piecemeal ratemaking. OPC witness Nathan A. Benedict noted that in Project No. 35628, the Commission rejected alternative mechanisms for the recovery of REC costs but reserved the right to consider the issue at a later date.874 He stressed that, when rejecting alternative recovery mechanisms for REC costs, the Commission recognized that REC costs are variable, that the purchase of RECs is mandated by law, and that certain customers can opt out of the Renewable Portfolio Standard program. Thus, in Mr. Benedict’s view, the Commission has already rejected the arguments advanced by ETI here. He added that ETI did not indicate a negative and substantial impact as a result of transmission customers opting out of the Renewable Portfolio Standard program, and ETI appears to be currently administering the program effectively without REC Rider. In short, Mr. Benedict concluded that costs related to renewable energy credits should be recovered through base rates, and ETI’s current opt-out rider should continue as the vehicle for ETI to handle transmission-level opt-outs.875

Cities Ex. 6 (Nalepa Direct) at 30-32. Mr. Nalepa’s figure of $633,985 differs from that the figure of $623,303 found in ETI’s testimony at ETI Ex. 31 (LeBlanc Direct) at 24 and State Ex. 9.

Cities Ex. 1 (Brazell Direct) at 14-16.

OPC Ex. 6 (Benedict Direct) at Ex. NAB-8, Project No. 35628, Rulemaking Relating to Industrial Customer Opt-Out of Renewable Portfolio Standard, Order at 6 (December 4, 2008).

OPC Ex. 6 (Benedict Direct) at 37-41. ETI currently has a Renewable Portfolio Standard Calculation Opt-Out Credit Rider to credit REC costs collected in base rates from transmission level customers who have opted out of the program.

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Commission Staff also opposes ETI’s request, stating that it amounts to unauthorized piecemeal ratemaking that should be disallowed. In Staff’s view, the existing opt-out rider should be maintained but updated to reflect the test year data used to set the ETI’s base rates. Because ETI’s proposed rider would include a true-up provision that would guarantee recovery of all of its REC costs, Staff witness Abbott testified that it would violate PURA § 36.051, which provides the utility a reasonable opportunity to earn a reasonable return on invested capital but does not guarantee full recovery of all costs. Mr. Abbott acknowledged that the Legislature has authorized the recovery of certain specific costs outside of base rates, but no such authorization exists for the recovery of REC costs.876

In addition, Mr. Abbott criticized the proposed REC rider because in the future it would allow prospective recovery of estimated REC costs. He believed that such an arrangement would eliminate any regulatory lag and thus eliminate any incentive for ETI to minimize the costs of purchasing the required RECs.877 Mr. Abbott also pointed out that the proposed rider contains a single rate for all customer classes and includes a “revenue related expense factor,” which increases the overall rider revenue requirement to, in part, account for projected uncollectable bills.878 This would shift the costs of uncollectable bills from customer classes with greater bad debt onto customer classes with lower bad debt. Further, Mr. Abbott stated, the proposed true-up portion of the REC Rider would eliminate the need for a bad debt factor, as any actual under-collected amounts would carry forward and could be recovered in future filings. Also, the single rate could result in cost-shifting between customer classes, as over- or under- recoveries resulting from billing determinant forecast error would vary by customer class. Finally, Mr. Abbott stated, the ETI’s proposed billing determinants are based on a historical year. But if load grows over the long term,

Staff Ex. 7 (Abbott Direct) at 12-13. Mr. Abbott cites to PURA §§ 36.203 (Fuel Cost Recovery), 36.205 (Purchased Power Cost Recovery), 36.209 (Transmission Cost Recovery), 36.210 (Distribution Cost Recovery), 39.107(h) (Advanced Meter Deployment Surcharge), 39.461 (Hurricane Reconstruction Costs), 39.905(b)(1) (Energy Efficiency Cost Recovery).

While the price of RECs at any point in time are set by the market, presumably a purchaser has some ability to seek relatively better terms—such as making an effort to accurately forecast the number of credits required and perhaps purchasing or contracting to purchase available credits beforehand if prices are favorable, seeking volume discounts, banking excess credits when prices are favorable, etc. Schedule Q-8.8 at 45.4.

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this will lead to persistent over-recovery of the REC Rider revenue requirements, as Rate Year billing determinants will tend to exceed the historical billing determinants systematically.879

Based on these concerns, Mr. Abbott recommended that the Commission deny ETI’s request for a REC Rider, and that the ETI’s Test Year REC costs of $623,303 be included in base rates.

Additionally, he recommended that the Renewable Portfolio Standard Calculation Opt-Out Credit Rider should be maintained; however, the credit rates should be updated to reflect the Test Year data used to set ETI’s base rates. In the alternative, if the Commission approves the REC Rider requested by ETI, Mr. Abbott recommended the following changes from the Company’s request:

¾ The REC Rider should be set every year to collect the previous year’s actual REC costs (instead of projected REC costs), plus any over- or under- recovery from prior periods.

¾ The previous year’s actual REC costs should be allocated to each customer class based upon each class’s actual energy usage over the time period for which the RECs were acquired.

¾ Any over- or under- recovery balances should be tracked by each customer class, and thus a separate REC Rider rate should be calculated for each customer class based on that class’s allocated REC costs adjusted by that class’s over- or under- recovery balance.

¾ The REC Rider rates should be calculated using billing determinants based upon ETI’s best forecast of each customer class’s energy usage over the rider’s Rate Year.880 3. ETI’s Response ETI contends that adoption of the rider does not result in piecemeal ratemaking because these are the types of costs that the Company cannot control. Ms. LeBlanc believes that there is a greater

Staff Ex. 7 (Abbott Direct) at 13-14.

Staff Ex. 7 (Abbott Direct) at 14-15.

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risk of over-recovery of REC costs through base rates than there would be under the proposed rider.881

As to the issue that the Company would be disincentivized to purchase RECs at an appropriate time, ETI claims that the proposed rider has a true-up mechanism that would allow for review. ETI disputes State Agencies’ claims that ETI could have purchased RECs at a lower level at other points in the year, stating there is no evidence that the Company could have bought RECs at a lower level at other points in the year.

Finally, ETI takes issue with the parties’ argument that there is no statutory recovery for REC costs outside of base rates. ETI argues that there is no statutory authority requiring the Company to refund costs to opt-out industrial customers. According to ETI, no explicit statutory authority is necessary, and the parties have failed to establish that any harm would result from implementation of the rider.

4. ALJs’ Analysis The ALJs are persuaded by the testimonies of Staff and intervenor witnesses Pevoto, Nalepa, Abbot, Benedict, and Brazell that ETI’s proposed REC rider should be rejected. The testimony supports a finding that adoption of the rider results in piecemeal ratemaking. ETI’s argument that costs are volatile and, therefore, should be isolated and recovered in a manner similar to an annual fuel factor filing was not supported by sufficient evidence. Additionally, the ALJs agree that the proposed rider eliminates any incentive for ETI to minimize the costs of purchasing the required RECs. ETI proffered unconvincing argument and insufficient evidence that standard cost recovery was insufficient for ETI to recover its total REC costs and a reasonable return.

The ALJs further find that the Test Year expense of $623,303 should be used for setting rates in this case.882 ETI failed to proffer sufficient evidence and argument to support any increase to its ETI Ex. 55 (LeBlanc Rebuttal) at 11.

This is the amount referenced in Ms. LeBlanc’s testimony at ETI Ex. 31 at 24 and confirmed in State Agencies Ex. 9.

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initial request through rebuttal testimony. As recommended by Staff witness Abbott, the Renewable Portfolio Standard Calculation Opt-Out Credit Rider should be maintained, with an adjustment to the credit rates to reflect the Test Year data used to set ETI’s base rates.

B. Class Cost Allocation [Germane to Preliminary Order Issue No. 14] A cost-of-service study is an analysis used to determine the responsibility for a utility’s costs for each customer class. Thus, it determines whether the revenues a class generates cover that class’s cost-of-service. A class cost-of-service study separates the utility’s total costs into portions incurred on behalf of the various customer groups. Most of a utility’s costs are incurred to jointly serve many customers. For purposes of rate design and revenue allocation, customers are grouped into homogeneous classes according to their usage patterns and service characteristics.

The parties generally agreed that ETI’s cost-of-service study comported with accepted industry practices, but some parties had issues with specific items discussed below.

1. Municipal Franchise Fees Municipal Franchise Fees (MFF) are charges for a utility’s use of municipal rights-of-way.

The charges are levied by municipalities based on the amount of electricity sold within the municipal boundaries. They are also referred to as street rental taxes. The MFF charged to ETI are based on ordinances passed by the cities in which ETI makes retail sales. Different cities have enacted different levels of MFF on in-city kWh sales, ranging from 0.0956¢ to as much as 0.2644¢ per kWh.883 For the portion of fees ETI collects through base rates, ETI proposes to allocate among customer classes based on customer class revenues relative to total revenues.884 Once MFF costs are

TIEC Ex. 1 (Pollock Direct) at 52 and Ex. JP-9. Nineteen cities also charge MFF through separate “Incremental Franchise Fee Recovery” Riders. These incremental MFF are not included in ETI’s proposed revenue requirements in this case. TIEC Ex. 1 (Pollock Direct) at 53.

Schedule P-13 at10, lines 32-33; the allocation factor “RSRRTOA-Total” is rate schedule revenue.

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allocated to the rate classes, ETI proposes to collect the costs from all customers regardless of their geographic location.885

ETI proposes the same allocation and collection of MFF in this case as was approved by the Commission in Docket No. 16705, ETI’s last litigated rate case.886 The positions of the parties, as set out in testimony and briefs, are listed below:

Party/Precedent MFF Allocation Between Collection of MFF Expenses From: Customer Classes By: ETI Total revenues All customers Cities Total revenues All customers OPC kWh sales in city All customers Staff kWh sales in city All customers TIEC Franchise fee payments in city Only from municipal customers Docket No. 16705 Total revenues All customers

(a) MFF Allocation Between Customer Classes Cities and ETI recommend adoption of ETI’s proposal to allocate to customer classes based on total rate schedule revenues, which the Commission approved in Docket No. 16705. ETI notes that it is following Commission precedent, and it opposes the use of different allocation factors for these FERC accounts: Account 408.152, Franchise Tax State; Account 408.154 Franchise Tax Local; and Account 408.163, Street Rental.

OPC witness Benedict testified that MFF should be allocated on the basis of in-city kWh sales, without an adjustment for the MFF rate in the municipality in which a given kWh sale occurred. Staff witness Abbot concurs. Stated differently, Messrs. Benedict and Abbot suggest

OPC Ex. 8 (Benedict Cross Rebuttal) at 9.

Application of Entergy Gulf States, Inc. for Approval of Its Transition to Competition Plan and the Tariffs Implementing the Plan, and for the Authority to Reconcile Fuel Costs, to Set Revised Fuel Factors, and to Recover a Surcharge for Underrecovered Fuel Costs, Docket No. 16705, Second Order on Rehearing at 98 (FoF 224) (Oct. 13, 1998).

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allocating MFF relative to each class’s inside-city kWh sales with the same MFF per unit cost (i.e., 0.1965¢ per kWh) for all customer classes.887 Mr. Benedict noted that this allocation method is based on Commission precedent, as indicated in the recent CenterPoint rate case, Docket No. 38339:

CenterPoint’s allocation of municipal franchise fees to the customer classes based upon in-city kilowatt-hour (kWh) sales and collection of the fees from all customers within the customer class is reasonable and consistent with Commission precedent.888 Mr. Benedict also noted that allocating on the basis of in-city kWh sales is consistent with PURA § 33.008(b).889

Commission Staff supports Mr. Benedict’s analysis. Staff points out that PURA § 33.008(b), which authorizes the collection of municipal franchise fees, states that “[t]he compensation a municipality may collect from each electric utility . . . shall be equal to the charge per kilowatt hour . . . times the number of kilowatt hours delivered within the municipalities boundaries.”890 According to Staff, PURA § 33.008(b) plainly links the amount of municipal franchise fees to each class’s in-city kWh sales. Moreover, the Commission has an established policy of allocating municipal franchise fees based on in-city kWh sales.891 According to Staff, the Commission should reaffirm See OPC Ex. 7 (Benedict Cross Rebuttal) at 4-5; Staff Ex. 7 (Abbott Direct) at 22; TIEC Ex. 3 (Pollock Cross Rebuttal) at 34.

OPC Ex. 6 (Benedict Direct) at Ex. NAB-1, Application of CenterPoint Electric Delivery Company, LLC, for Authority to Change Rates, Docket No. 38339, Order on Rehearing at 34, (FoF 179) (June 23, 2011).

OPC Ex. 7 (Benedict Cross Rebuttal) at 5.

PURA § 33.008(b)(emphasis added).

Application of TXU Electric Company for Approval of Unbundled Cost of Service Rate Pursuant to PURA § 39.201 and Public Utility Commission Substantive Rule 25.344, Docket No. 22350, Order at FoF 156 (Oct. 4, 2001). The Commission reached an identical conclusion in Application of Reliant Energy HL&P for Approval of Unbundled Cost of Service Rate Pursuant to PURA 39.201 and Public Utility Commission Substantive Rule 25.344, Docket No. 22355, Order at FoF 222A (Oct. 4, 2001). More recently, Application of CenterPoint Electric Delivery Company, LLC, for Authority to Change Rates, Docket No. 38339, Order on Rehearing at FoF 179 (June 23, 2011) (stating that “CenterPoint’s allocation of municipal franchise fees to the customer classes based upon in-city kilowatt-hour (kWh) sales and collection of the fees from all customers within the customer class is reasonable and consistent with Commission precedent.”).

Staff notes in their initial brief that the Commission has further indicated that this allocation should be conducted without any adjustment for differences in the rates charged by individual municipalities within a utility’s service territory. Application of AEP Texas Central Company for Authority to Change Rates, Docket No. 33309, Order on Rehearing at FoF 150 (Mar. 4, 2008) (stating in connection with a proposed municipal SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 265 PUC DOCKET NO. 39896

this precedent in this case by allocating ETI’s MFF to each customer class on the basis of in-city kWh sales.

TIEC witness Pollock disagrees with OPC’s and Staff’s proposed allocation method, although Mr. Pollock stated their proposal was better than ETI’s proposed allocation. He believes OPC’s and Staff’s proposal fails to recognize the different MFF rates charged by cities. Because cities that have a preponderance of industrial sales generally charge lower MFF rates, this proposal would require LIPS customers to pay 0.1965¢ per kWh, which is more than the weighted average MFF cost to the LIPS class of 0.1612¢ per kWh. Thus, Mr. Pollock argues that this would require LIPS customers to subsidize other customer classes and would not be consistent with cost causation.

Mr. Pollock thought his proposal to allocate MFF by city by class resulted in each customer class paying only the MFF expenses actually incurred.892

The ALJs find OPC’s and Staff’s proposed allocation methodology best comports with PURA § 33.008 and Commission precedent. As noted by Mr. Benedict, PURA was amended after the Commission’s decision in Docket No. 16705, which allocated MFF on the basis of rate schedule revenue. PURA § 33.008 expressly calls for a kWh basis for allocation and this is confirmed in the cases litigated since Docket No. 16705, which were cited by Commission Staff. Accordingly, the ALJ recommend that MFF be allocated on the basis of in-city kWh sales, without an adjustment for the MFF rate in the municipality in which a given kWh sale occurred.

(b) MFF Collection All parties except TIEC recommend that the Commission approve ETI’s proposed allocation of franchise fee rentals to all customers. Cities witness Mr. Brazell testified that franchise fees are in the nature of a rental, not a tax, and like all rental charges ETI incurs, the expense should be spread among all customers. He stated that MFF charges have always been collected from all customers, whether or not they take service within the corporate limits, except for the limited incremental

franchise fee expense rider that “[h]aving different rates in each municipality in TCC’s service territory is contrary to the Commission’s desire for uniform, simple rates”).

TIEC Ex. 3 (Pollock Cross Rebuttal) at 8, 33-35.

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franchise fees specifically addressed by PURA § 39.456. Mr. Brazell explained that electrical facilities within ETI’s system are physically interconnected and electrically synchronized. The facilities located within a city’s boundaries are not isolated physically or electrically from the facilities outside the city limits. Rather, they are tied to one another and function as a single integrated system, and ETI’s facilities inside each city benefit all customers in ETI’s service area, whether or not those customers are within the city. Therefore, Mr. Brazell recommended that the Commission approve ETI’s request to recover MFF in base rates from all customers.893

Mr. Benedict holds the same opinion. He stated that the Commission’s policy to collect MFF from all customers within a customer class is also consistent with the concept that MFF are system costs that are rightly paid by all customers taking service from the system. He explained that MFF are paid by a utility to municipalities for use of the municipalities’ rights-of-way. Because these rights-of-way are necessary to operate an integrated electric delivery system from which all customers benefit, regardless of geographic location, Mr. Benedict stated that MFF should be collected uniformly from all customers within a given rate class. He stressed that the Commission agreed with this reasoning in Docket No. 16705, where the Commission concluded:

Current cost of services studies are not based on geographical differences. Classes are not divided based on geography, and industrial sites are not self-sufficient islands. The use of city streets and property enables [EGSI] to have an integrated utility system from which all ratepayers benefit.894 Mr. Pollock objected to the proposals by Mr. Brazell and Mr. Abbott. He stated that Mr. Brazell’s recommendation to adopt ETI’s proposed MFF allocation should be rejected because there is no evidence that outside city customers benefit from ETI’s use of city streets and rights-of- way or that the benefits are evenly distributed between inside and outside city customers. Further, according to Mr. Pollock, the standard used in class cost-of-service studies is cost causation, not

Cities Ex. 1 (Brazell Direct) at 28-32.

OPC Ex. 6 (Benedict Direct) at Ex. NAB-2, Docket No. 16705, Second Order on Rehearing at 98, (FoF 224).

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benefits, and he believes allocating MFF based on outside city usage is contrary to cost causation principles.895

The ALJs recommend adoption of ETI’s proposal to collect costs from all customers taking service from the system. The ALJs find persuasive the fact that MFF is compensation for the use of municipalities rights-of-way, which is used to operate an integrated electric delivery system from which all customers benefit.

2. Miscellaneous Gross Receipts Taxes Miscellaneous gross receipts taxes (MGRT) are state taxes imposed on each utility company’s taxable gross receipts derived from sales in an incorporated city or town having a population of more than 1,000. Like MFF, these taxes are levied only on sales within the cities. ETI proposes to allocate MGRT to all retail customer classes based on customer class revenues relative to total revenues.896

TIEC objects to ETI’s allocation of MGRT based on class revenues for the same reasons stated for ETI’s allocation of MFF. It argues that these costs should be allocated and charged to customers within the municipalities to which the MGRT applied.

The allocation of MGRT is similar to the allocation of MFF and should be similarly applied.

For the reasons set out above and to ensure consistent treatment, the ALJs do not recommend the direct method of allocation suggested by TIEC. Rather, these costs should be allocated to the rate classes according to ETI’s cost of service study.

TIEC Ex. 3 (Pollock Cross Rebuttal) at 7, 32-33.

ETI Ex. 3, Schedule P-13 at 10, line 34.

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3. Capacity-Related Production Costs (a) Allocation Methodology ETI proposes to allocate capacity-related production and transmission costs to the retail classes on the basis of A&E 4CP. As noted by TIEC and Commission Staff, this allocation methodology is consistent with the method ETI used in Docket No. 16705, its last contested rate proceeding:

Finding of Fact No. 221. The continued use of the A&E 4CP allocator is the most reasonable methodology for allocating production and transmission plant among classes. The A&E 4CP allocator sufficiently recognizes customer demand and energy requirements and assigns cost responsibility to peak and off-peak users. It best recognizes the contribution of both peak demand and the pattern of capacity use through the year.

Finding of Fact No. 222. The A&E 4CP method is also preferable because it is devoid of any double counting problem.897 ETI witness Ms. Talkington explained that the A&E 4CP allocation is appropriate because it is a method that reasonably reflects the mix of the Company’s customers, their respective electrical load characteristics, and the relative costs incurred to serve such loads. She testified that the A&E 4CP method provides a reasonable balance between the two primary costing concerns: contribution to the system peak and energy requirements. While the contribution made to the system peak is inherently recognized with the use of the average four coincident peaks, energy is also recognized by reflecting the average demands.898

OPC witness Benedict proposed the use of the average and single coincident peak (A&P) method to allocated production (and transmission costs, which are discussed in the section below)

Docket No. 16705, Second Order on Rehearing at 97, FoF 221 and 222 (Oct. 14, 1998).

ETI Ex. 22 (Talkington Direct) at 5. As noted previously, A&E 4CP is developed by adding each rate class’s average demand for the test year (the “average” component representing the rate class’s average energy consumption), weighted by the ETI system load factor, to each rate class’s amount of average coincident peak demand for the months of June through September in excess of its average demand, weighted by one minus the ETI system load factor.

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among retail classes. As noted in the discussion concerning jurisdictional allocation, A&E 4CP is a variant of the A&E allocator. Mr. Benedict believes that A&E 4CP fails to properly assign cost responsibility to both peak and off-peak usage.899 Instead, he found that the A&E 4CP allocator results in the same factors reached by the 4CP method, which means that A&E 4CP assigns cost responsibility only to peak demand and not to off-peak demand. He believes that the A&P methodology is the proper plant allocator because it takes into account both peak usage and off-peak usage patterns.900

Mr. Benedict’s methodology and recommendation was disputed by Kroger witness Higgins.

He indicated that the A&E method does not converge to a CP result. Rather, the A&E method addresses a fundamentally important question in production cost allocation—once capacity needed to serve the average demand on the system is accounted for, how does the regulator fairly assign the responsibility for the additional or excess capacity that is needed to meet the various capacity requirements (placed on the system by each customer class). Mr. Higgins concluded that the A&E method makes an objective and reasonable allocation. However, he did not advocate changing ETI’s use of A&E 4CP.901

Mr. Higgins explained that:

[T]he Average and Excess demand method begins by allocating a portion of costs on the basis of average demand—or energy. The remaining (or “excess”) capacity needs of the system are then allocated to classes based on peak usage—class NCP in the case of the “standard” approach, 4 CP in the case of the A&E/4CP method. In contrast, the A&P method proposed by Mr. Benedict, which is classified by the NARUC Manual as a “Judgmental Energy Weighting” approach, incorporates a subjective determination that includes the full value of average demand both in the “average” component of the A&P calculation as well as in the peak component of that calculation.902

Mr. Benedict performed a mathematical proof that he believed demonstrated that the A&E 4CP allocator is nearly identical to the 4CP allocator. OPC Ex. 6 (Benedict Direct) at 21-22.

Id. Kroger Ex. 2 (Higgins Cross Rebuttal) at 4-5.

Id. at 6 (emphasis in originial).

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TIEC witness Pollock also disputed Mr. Benedict’s proposed methodology, stating that A&P does not reflect cost causation and is not reasonable for ETI. He believes that Mr. Benedict’s support of the A&P method is based on an oversimplification of the planning process. He also noted that A&E is recognized in the NARUC Electric Utility Cost Allocation Manual and has been repeatedly used by the Commission.903

The following calculations performed by Messrs. Benedict and Higgins demonstrate the different results stemming from the allocation methodologies:904

ETI OPC Kroger Proposed Recommended Standard Alternative Rate Class A&E/4CP (%) A&P (%) A&E 12CP Residential 47.4494 40.1181 48.4013 43.4768 Small General Service 2.0990 2.0595 2.7209 2.0169 General Service 18.0259 19.4933 18.5183 18.6122 Large General Service 7.0794 8.3822 6.6558 7.4339 Lg. Indust. Power Serv. 20.4401 25.5485 20.2122 22.9417 Total Lighting 0.2900 0.2768 0.4042 0.1394 Total Texas Retail 95.3838 95.8784 96.9127 94.6208 Total Wholesale and 4.6162 4.1216 3.0873 5.3792 Wheeling Total Company 100.0000 100.0000 100.0000 100.0000

The ALJs recommend the use of A&E 4CP to allocate capacity-related production costs, as proposed by ETI. The weight of the evidence as well as Commission precedent does not support the methodology proposed by Mr. Benedict. A&E 4CP was approved for the Company in Docket No. 16705, and the extensive testimonies (which included calculations and graphs) of Messrs. Higgins and Pollock indicate that, not only is the methodology frequently adopted by the Commission, it is also a standard and reasonable methodology. As noted by ETI, it reasonably reflects the mix of the Company’s customers and their respective load characteristics and the relative

TIEC Ex. 3 (Pollock Cross Rebuttal) at 12-14, citing the NARUC Electric Utility Cost Allocation Manual, January 1992.

OPC Ex. 6 (Benedict Direct) at 25; Kroger Ex. 2 (Higgins Cross Rebuttal) at 5.

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costs incurred to serve such loads. It recognizes the contribution of both peak demand and the pattern of capacity use throughout the year.905 It also recognizes that ETI, like all Texas utilities, is a summer peaking utility. The ALJs recommend that ETI’s allocation of capacity production costs be adopted.

(b) Reserve Equalization Payments A subset of the Company’s requested capacity-related production costs relate to reserve equalization payments made by the Company pursuant to the Entergy System Agreement (Service Schedule MSS-1). The System Agreement, which is approved by the FERC, prescribes a method by which each Entergy Operating Company’s share of Entergy system reserves are calculated. ETI, as one of the Operating Companies, is responsible to provide the system with its allocated share of system reserves. Some Entergy Operating Companies own less than their share of system reserves and are considered “short” with respect to generation capability. Companies that own more than their share are considered “long” companies. Short companies make payments to long companies pursuant to the terms of the System Agreement. Because ETI is a short company, it makes reserve equalization payments which are included in the cost of service.906

ETI allocates MSS-1 payments using A&E 4CP. Mr. Benedict argues that this allocation method is not consistent with the way costs are incurred, as ETI does not make MSS-1 payments on the basis of A&E 4CP. According to Mr. Benedict, ETI incurs costs by being short with respect to system reserves—the payment is simply the number of MW by which it is short, multiplied by a $/MW rate as determined by a contract formula. The degree to which ETI is short is determined by comparing its generation capability to its allocated share of system reserves. Total system reserves are allocated to the other Operating Companies on the basis of the Responsibility Ratio. Thus, as determined by the Responsibility Ratio, ETI’s share of system reserves relative to its generating capability is what causes ETI to make MSS-1 Reserve Equalization payments.907

See Docket No. 16705, Second Order on Rehearing at FoF 221 (Sept. 4, 1998).

OPC Exhibit No. 6 (Benedict Direct) at 29-30.

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Mr. Benedict concluded that, because Reserve Equalization payments are incurred on the basis of ETI’s Responsibility Ratio, which is a rolling 12CP allocator, the payments should be allocated to ETI’s rate classes on a similar basis. As a result, he recommended that Reserve Equalization payments be allocated on the basis of 12CP.908

According to OPC, Mr. Benedict’s proposal for allocating MSS-1 payments has been criticized because 12CP measures class demands at ETI’s peak monthly demands whereas the Responsibility Ratio is measured at the Entergy system’s peak monthly demands. OPC agrees that 12CP uses peak hours that may differ from those used to compute the Responsibility Ratio, but contends that the Company fails to mention that the A&E 4CP method it uses to allocate MSS-1 payments is also subject to the same critique. When choosing between the 12CP allocator and the A&E 4CP allocator for the purpose of allocating reserve equalization payments, OPC believes 12CP is more desirable. ETI’s contributions to the Entergy system’s peaks in all 12 months, not just the four summer months, determine ETI’s share of Entergy system reserves. ETI’s share of system reserves, relative to its generation capability, is what causes reserve equalization payments to the other Entergy Operating Companies. Moving to a 12CP allocation for MSS-1 payments aligns cost allocation more closely with cost causation.

TIEC witness Pollock explained that the Entergy System Agreement is regulated by the FERC, which does not control the rate design policy applicable to Texas retail customers under Commission jurisdiction. He views the System Agreement as an accounting mechanism to equalize the benefits and costs associated with interconnected operation and joint planning. In his opinion, it is not relevant to determining which production capacity allocation method best reflects cost causation for Texas retail customer. According to Mr. Pollock, the MSS-1 payments are no different in concept from the costs associated with ETI’s high-voltage transmission lines, which are allocated on an A&E 4CP basis. He further indicated that the 12CP method ignores the reality the ETI is a predominantly summer peaking utility.909

Id. at 31.

TIEC Ex. 3 (Pollock Cross Rebuttal) at 27-29.

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The ALJs do not find sufficient support to allocate the reserve equalization payments differently than other capacity-related production costs. For the same reasons noted in the section above, the ALJs find the weight of the evidence supports allocation using A&E 4CP. While 12CP is a reasonable methodology for jurisdictional separation between retail and wholesale entities, the evidence does not support this methodology for allocation of reserve equalization payments.

4. Transmission Costs As noted above, ETI also allocates transmission costs using the A&E 4CP methodology.

Again, TIEC and Staff cite to the Commission’s decision in Docket No. 16705, which adopted the A&E 4CP approach for both production and transmission costs. OPC witness Benedict, however, proposes allocating transmission plant using A&E methodology that he proposed for the allocation of production plant.910 TIEC argues that methodologies similar to Mr. Benedict’s proposal have been repeatedly rejected by the Commission, and the A&E 4CP methodology has been repeatedly approved. TIEC suggests that Mr. Benedict offers no rationale for a different result for transmission costs. According to TIEC, the rationale that he offers for using the A&P method for production costs—the potential trade-off between capital costs and fuel costs—is entirely absent with respect to transmission plant.

Mr. Benedict does not even assert that such trade-offs exist. Rather, the only basis he offers for using the average and peak methodology is his assertion that the A&E 4CP allocator “mathematically reduces to a 4CP allocator.”911 TIEC points out that the Commission, by rule, has adopted the 4CP method for the allocation of transmission plant within ERCOT.912

ETI witness Talkington indicated the same reasons and rationale for using the A&E 4CP methodology to allocate transmission costs as she noted for capacity-related production costs.913

OPC Ex. 6 (Benedict Direct) at 26-28.

TIEC Initial Brief at 68, citing OPC Ex. 6 (Benedict Direct) at 27.

P.U.C. SUBST. R. 25.192 specifically provides that transmission costs are allocated based on the “coincident peak demand for the months of June, July, August, and September (4CP) . . . .”

ETI Ex. 67 (Talkington Rebuttal) at 8-9.

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Kroger witness Higgins also disputed the use of A&E 4CP for allocation of transmission costs for the same reasons noted above concerning production cost allocation. Moreover, he compared the different allocation factors—specifically, ETI’s proposed A&E 4CP, the A&E, and Mr. Benedict’s recommended A&P. His calculations indicated that A&E 4CP and the A&E produce similar results, while A&P radically departs from ETI’s proposed allocations.914

The ALJs do not find sufficient or persuasive evidence to change ETI’s proposed methodology for allocation of transmission costs. A&E 4CP is a well-accepted method for allocating such costs, which the Commission has repeatedly adopted. The ALJs recommend the use of the A&E 4CP to allocate ETI’s transmission costs.

C. Revenue Allocation Wal-Mart, Kroger, TIEC, and Commission Staff advocate that the rates be set on the basis of the utility’s costs of service. These parties recommends the adoption of ETIs proposed base rate revenue allocation, recovering from each class 100 percent of it respective Test-Year base rate costs per the revenue requirement ultimately adopted.

TIEC witness Pollock testified that revenue allocation is the process of determining how any base revenue change approved by the Commission should be spread to each customer class served by the utility. ETI proposed an overall increase in non-fuel revenues of 17.53 percent, but the increase is not spread proportionally to all the classes.915 Rather, ETI proposed class revenue requirements that are closely aligned with the Company’s proposed cost of service. Set out below is the impact of ETI’s proposed base rate increase for each class:916

Class Change in Base Revenues Residential 25.10%

Kroger Ex. 2 (Higgins Cross Rebuttal) at 5-6.

ETI’s revenue requirement does not include the costs associated with its requested REC Rider.

See Kroger Ex. 1 (Higgins Direct) at 5-6; see also Cities Ex. 6 (Nalepa Direct) at 34.

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Small General Service 1.82% General Service 5.54% Large General Service 19.06% Large Industrial Power Service 11.17% Lighting Service 29.36% System Average 17.53%

The contested issue concerns whether rates should be set at cost, and any approved change in base rate revenues should reflect the actual cost of providing service, or whether any rate increase should be phased in for certain classes (notably Residential and Lighting classes) to reduce the impact (rate shock)

1. Argument for Moving Rates to Cost ETI and the parties in support of ETI’s class revenue allocation contend it is appropriate to set rates at each class’ cost of service as ETI has proposed in order to avoid continuing inappropriate and inequitable cost shifting between customer classes. TIEC witness Mr. Pollock testified that cost-based rates send the proper price signals to customers. He noted other reasons for using cost- of-service principles: equity, engineering efficiency (cost-minimization), stability, and conservation.

If rates are not based on cost, then some customers subsidize part of the cost of providing service to other customers. Moreover, he suggested that by providing balanced price signals, cost-based rates encourage conservation and may prevent waste or inefficient use. If rates are not based on a class cost-of-service study, then consumption choices can be distorted.917

Mr. Pollock developed a class revenue allocation based on his proposed jurisdictional and class cost-of-service studies. If these recommendations are adopted, his class revenue allocation produced the following results:

TIEC Ex. 1 (Pollock Direct) at 63-65.

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Rate Class Present Non-Fuel Proposed Base Revenues Revenue Increases Service Percent Increase Residential $379,382,000 $80,390,000 21.2% Small General $26,430,000 $283,000 1.1% General $159,768,000 $9,797,000 6.1% Large General $49,380,000 $8,714,000 17.6% Large Indus. Power $104,308,000 $9,862,000 9.5% Lighting $10,813,000 $2,143,000 19.8% Total $730,080,000 $111,189,000 15.2% As discussed below, Mr. Pollock also recommended lower rates for Schedules SMS and AFC, which would reduce ETI’s revenues by about $2 million. To offset this loss, he testified that revenues would need to be increased for other classes to achieve the total increase requested by ETI.

These changes would produce the following results:918

Rate Class Service Present Non-Fuel Proposed Base Percent Increase Revenues Revenue Increases Residential $379,382,000 $81,500,000 21.5% Small General $26,430,000 $340,000 1.3% General $159,768,000 $10,205,000 6.4% Large General $49,380,000 $8,860,000 17.9% Large Indus. Power $104,308,000 $10,153,000 9.7% Lighting $10,813,000 $2,160,000 20.0% Total $730,080,000 $113,218,000 15.5% SMS/AFC Impacts $13,816,000 ($2,029,000) -14.7% Total Sales $743,896,000 111,189,000 14.9%

Id. at 63-67 and Exs. JP-12 and JP-13.

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If the Commission disallows other elements of ETI’s rate request, Mr. Pollock testified that class revenue allocation should be reduced in accordance with how such disallowed costs were allocated to each rate class.919

Mr. Pollock’s tables provide examples of the impact on each class of customers when the Commission makes final decisions concerning the Company’s proposed rate design and the final revenue requirement.

Staff witness Abbott testified that the Commission ordinarily sets rates for each customer class to recover the costs incurred by the utility to serve that class. In this case, ETI’s proposed revenues for all customer classes result in base revenues that are close to the cost of service allocated costs. No single customer class’ proposed revenue requirement differs from ETI’s calculated cost to serve that class by more than 3 percent. Staff acknowledges that certain classes face proportionally larger rate increases to bring them closer to unity, where revenue recovery is based on actual cost of service. However, Staff agrees with Mr. Pollock that setting each customer class at their cost of service avoids inflating rates for some customer classes and subsidizing the usage of others. Staff believes that recovering from each class its respective base rate cost is equitable and provides appropriate pricing signals to facilitate the most efficient use of resources in the provision and consumption of electricity. Staff also argues that the Commission has approved such class cost of service allocation in recent rate cases.920

Wal-Mart and Kroger concur with Staff and TIEC.

Id. at 67.

Staff cites Application of CenterPoint Electric Delivery Company, LLC for Authority to Change Rates, Docket No. 28339, Order at FoF 175 (May 12, 2011) and Docket No. 16705, Second Order on Rehearing at FoF 245 (Sept. 4, 1998). TIEC witness Pollock also testified that Commission precedent supports allocation of costs based on the cost of service study. He also cited to the CenterPoint case and to Application of AEP Texas Central for Authority to Change Rates, Docket No. 28840, Order at 50 (Aug. 15, 2005). TIEC Ex. 1 (Pollock Direct) at 65.

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2. Argument for Gradualism Cities witness Karl Nalepa pointed out that, under ETI’s proposed rates, the Residential and Lighting customer classes receive the highest rate increases while the Small General Service, General Service, and Large Industrial Power Service classes receive below system average rate increases of 1.62 percent, 4.81 percent, and 10.77 percent, respectively. However, he examined Test Year customer quantities, energy and loads by customer class for each of ETI’s last three cases, and he concluded that residential and lighting customers are not imposing an undue cost burden on the system. Instead, other classes are growing at a faster rate, causing system costs to increase.

Moreover, Mr. Nalepa testified that a number of events are occurring with the Entergy system that will have significant impact on costs, including: Entergy’s efforts to join MISO; plans by EAI and EMI to leave the Entergy System Agreement; and the possible divestiture of the transmission system by all Entergy Operating Companies. Given these uncertainties, Mr. Nalepa proposed that any rate increase or decrease be spread proportionately across the system classes. Then, once Entergy and ETI address the proposed system cost changes, a reasonable class cost allocation study can be presented.921

State Agencies do not take a position on overall class revenue allocation but request that ETI’s proposed rate increase for the Lighting class be moderated. ETI proposes to set base rate revenues for the Lighting class based on the class cost allocation study, without any adjustment, which would result in a 20.38 percent increase to the Lighting class, when the entire ETI system would receive a 15.32 percent increase. Thus, under ETI’s proposal, this class would receive a percentage increase about 1.33 times the system average. Ms. Pevoto contended that that this increase would be excessive and would create significant rate shock to the class. Because the services of the Lighting class provides benefits all customers on the system, Ms. Pevoto believes it would be reasonable to mitigate the rate shock so that lighting customers can afford to continue their lighting service. Otherwise, she suggested, some lighting customers may reduce lighting services or

Cities Ex. 6 (Nalepa Direct) at 34-37.

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refrain from ordering additional lights. This, in turn, would adversely affect the benefits that lighting service provides to the public.922

Ms. Pevoto also pointed out that in 2009, the Commission adopted a rate moderation proposal for a similar rate class served by another utility. In that case, the Commission recognized that the Lighting class was unique in the combination of the public good it performs and in its demand characteristics.923 To mitigate the rate shock on the lighting customers in the present case, Ms. Pevoto recommended a cap on any base rate increase that would be equal to the smaller of: (1) the lighting class percentage rate increase resulting from the PUC-approved cost of service allocation study, or (2) the allowed system percentage rate increase. If the percentage rate increase is smaller than the allowed system percentage rate increase, then no mitigation adjustment would be necessary. However, if the PUC-approved cost of service allocation results in a percentage base rate increase for the lighting class that is greater than the allowed system percentage increase, then she urged that a mitigation reduction should occur. She also proposed that any mitigation reduction for the lighting class should be spread to other remaining classes, based on each class’ cost of service.924

ETI argues that the State Agencies are proposing the continuation of a significant subsidy by other classes. The Company notes that its allocation of costs to the Lighting class is based on the revenue requirement developed for that class. ETI acknowledges that its proposed increase for the Lighting class is 20.38 percent greater than the system average increase, but it is less than the Residential class’s proposed increase of 21.64 percent. ETI witness Ms. Talkington testified that the Company does not support any subsidies between rate classes. She testified that previous rate cases with subsidies for the Lighting class have pushed the class farther away from cost.925

OPC argues that cost of service should not be the sole factor in setting rates and that gradualism should be used in appropriate circumstances. OPC witness Benedict disagreed with State Agencies Ex. 2 (Pevoto Direct) at 12-13.

Application of Oncor Electric Delivery Company for Authority to Change Rates, Docket No. 35717, Order on Rehearing at 32 (Nov. 30, 2009).

State Agencies Ex. 2 (Pevoto Direct) at 15-16.

ETI Ex. 67 (Talkington Rebuttal) at 18-19.

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Mr. Pollock’s (and Staff’s) citation to the CenterPoint and AEP TCC rate cases to reject the concept of gradualism because both CenterPoint and TCC are unbundled transmission and distribution (T&D) utilities whose charges had a small impact on retail customers’ total bill. He noted that the number runs for TCC and CenterPoint showed retail revenue increases of only 0.14 percent and 1.30 percent, respectively, with some classes receiving rate decreases.926 Mr. Benedict cited the following language by the Commission in its Order for the TCC case:

The Commission declines to adopt gradualism in this case. This proceeding develops the T&D rates, as opposed to the broader rates developed for a fully integrated utility. As the T&D rates are only a subset of the total rates paid by customers, changes to the T&D rates would not have as large an impact as they would if the broader rates for a customer class were changed by the same percentage. . . . 927 In Mr. Benedict’s opinion, gradualism should be employed when setting rates for ETI because ETI is an integrated utility and has proposed a large rate increase.928

Mr. Benedict also emphasized the imprecise nature of a cost of service study. He noted that ETI’s cost of service study had 47 allocation factors and, even at the summary level, 22 expense categories and 24 rate base categories.929 Thus, he stated, there are a host of decisions made by the cost of service analyst which, in combination with the various account entries, yield a class’ reported cost of service. Mr. Benedict also pointed to disagreement among qualified experts on the “correct” allocation for certain classes of costs.930 In addition to these allocation questions, Mr. Benedict stated that any disallowances made to ETI’s requested costs will have asymmetric effects on class OPC Ex. 8 (Benedict Cross Rebuttal) 11-12; Ex. NAB-4, Docket No. 28840, TCC Number Run (July 21, 2005); and Ex. NAB-5, Docket No. 38339, Revised Number Running Schedules (Feb. 18, 2011).

Id. citing Docket No. 28840, Order at 23 (Aug. 15, 2005).

OPC Ex. 8 (Benedict Cross Rebuttal) at 9-14.

Allocation factors are provided in Schedule P-7.1; Expenses are summarized in Schedule P-7.4; Rate Base is summarized in Schedule P-7.5.

He noted, for example, that his direct testimony and Mr. Nalepa’s direct testimony proposed a different allocation methodology for production-related capacity costs, transmission costs, and certain System Agreement costs. Mr. Pollock proposed a different allocation method for municipal franchise fees and local gross receipts taxes. Mr. Abbott recommended different allocation methods for municipal franchise fees and other franchise taxes.

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cost of service depending on how the costs were allocated. Thus, while the cost of service study is an important element of ratemaking, Mr. Benedict stressed that it is not the only consideration.931

Due to the wide variation of rate increases obtained from ETI’s cost of service study, Mr. Benedict thought that rate moderation (gradualism) would be appropriate. However, he added, until decisions are made regarding the cost disallowances and allocation modifications proposed by the parties, it is unclear which rate classes should be granted rate moderation and the degree to which rate moderation is needed. Mr. Benedict said that the system average rate increase should be used as a benchmark for rate moderation, but not assigned uniformly to all classes as Mr. Nalepa proposed or to just one class as Ms. Pevoto suggested. Instead, he believed it would be reasonable to establish a floor and a ceiling for the increases in revenue from each class, such that a class’ individual percentage increase in revenue requirement is within a defined range of the system’s average revenue increase. Therefore, Mr. Benedict recommended that any rate increase for a particular class be restricted to a range of 0.75 to 1.25 times the system’s average increase. This would result in rate increases up to 25 percent lower or 25 percent higher than the average rate increase for the system as a whole. Based on a system average increase of 17.53 percent, individual class increases would range from 13.15 percent to 21.91 percent under Mr. Benedict’s proposal.932

3. ALJs’ Recommendation The parties presented persuasive argument on both sides of the issue. Clearly, in any rate case, movement toward unity—setting rates to cost—is appropriate when such movement does not result in rate shock to a particular class or classes. If rate shock is likely, Commission precedent supports the use of gradualism. These policies apply to both a fully integrated utility, as well as a T&D. The salient issue is whether the utility’s proposed increase is so out of proportion or harsh to a particular class that some form of gradualism should be applied. In this rate case, the preponderance of the evidence does not support the use of gradualism, even for the Lighting class.

While that class may receive an increase almost 1.33 times the system average increase, Commission

OPC Ex. 8 (Benedict Cross Rebuttal) at 14-17.

OPC Ex. 8 (Benedict Cross Rebuttal) at 17-19.

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precedent indicated an appropriate ceiling of 1.5 or even 1.75 times the system average is appropriate.933 As to applying OPC’s proposed floor and ceiling approach, this method was introduced in cross-rebuttal with no calculations depicting the impact on each class. The ALJs do not recommend its adoption because it fails to offer significant movement towards class responsibility for cost of service. The ALJs do not recommend Mr. Nalepa’s suggestion to impose any revenue change on an equal percent basis because it offers no movement towards unity.

Accordingly, the ALJs concur with the parties supporting ETI that revenue allocation in this case should be based on each class’s cost of service and consistent with the ALJs’ recommendations in the PFD that impact revenue allocation.

D. Rate Design [Germane to Preliminary Order Issue Nos. 15, 18, and 20] Staff explained that the Commission has traditionally established class costs of service based on the principle of cost causation. Staff believes the Commission has consistently required substantial justification for departing from this principle when setting rates that result in cross-subsidization between customer classes. With respect to intra-class cost causation and rate design, Staff maintains that the considerations are somewhat different. Rather, the Commission has traditionally given more weight to policy considerations other than cost causation in determining intra-class rate design issues because the danger of permanent subsidies within a particular class is relatively low.934 For instance, Staff witness Abbott testified that customer usage within a class may vary throughout the year. He noted that a low-load-factor customer might become a high-load-factor customer, resulting in a different mix of charges throughout the year.935 While an individual customer’s usage characteristics might frequently change and thereby lessen the impact of cost shifting within a class, Mr. Abbott testified that such customers were unlikely to shift to a different customer class.936 While subsidies in the customer class allocation context might be permanent, this See Docket No. 28840, Order at 23 (rejecting ALJs’ proposed ceiling of 1.75 times the system average).

Staff cites to Mr. Abbott’s cross-examination at Tr. at 1818 (“Q: And is there a distinction between factors that you would consider such as costs or other factors when you’re discussing class allocation as opposed to rate design issues? A: I would say there are different considerations and weights to considerations and the analysis of allocating costs to classes versus the analysis of allocating costs to rates within a class.”).

Tr. at 1818.

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was not necessarily the case for intra-class rates. Moreover, these shifting usage characteristics make it more difficult to identify cost drivers within a rate class. Staff suggests that consideration be given to policies such as customer impact and energy efficiency.

The ALJs agree with Staff’s analysis. Mr. Abbott recommended that the Commission apply gradualism—limiting the magnitude of rate changes—to help stabilize customer expectations and reduce risk.937 ETI witness Talkington also advised caution in response to suggested changes to ETI’s proposed rate design, noting that the ultimate impact on a customer’s bill is important.938 However, the ALJs’ rate design recommendations are based on the evidence and argument for each customer class or rate schedule. Thus, the ALJs’ recommendation on the specific rates or charges for the industrial customers will impact all other customer classes but that impact is not known at this time.

1. Lighting and Traffic Signal Schedules Cities witness Dennis W. Goins explained ETI’s Lighting and Traffic Signal Schedules.

ETI’s principal rate schedule for street lighting customers is Schedule SHL (Street and Highway Lighting Service), while Schedule TSS (Traffic Signal Services) is the principal rate schedule for ETI’s traffic lighting customers that own and maintain their lighting facilities. For Schedule SHL, the rate includes four categories of service (Rate Groups A, C, D, and E). Rate Group A includes ETI’s standard fixture and lamps mounted on existing standard wood poles that ETI installs and maintains. If a customer wants nonstandard lighting facilities (those not provided in Rate Group A), the customer is assigned to Rate Group C and required to prepay ETI for the incremental cost of the nonstandard facilities. Lighting facilities that are customer-owned and customer-maintained are assigned to Rate Group D, while incidental lighting services (for example, underpass lighting) are assigned to Rate Group E. Customers in Rate Groups A and C pay a fixed monthly charge per lighting fixture, while customers in Rate Groups D and E pay a fixed (and identical) energy charge per kWh. Each customer’s monthly bill also includes charges for ETI’s fixed fuel factor

Staff Ex. 7 (Abbott Direct) at 25-26.

ETI Ex. 67 (Talkington Rebuttal) at 16.

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(Schedule FF) and applicable riders applied to monthly kWh per fixture. Under Schedule TSS, traffic signal customers are subject to a minimum monthly charge ($3.20 proposed) per point of delivery, plus a fixed kWh rate and all applicable rider charges.939

Cities request that the Commission require ETI to institute a discounted lighting rate for Light Emitting Diode (LED) installations. Mr. Goins testified that the basic structure and pricing provisions of the SHL and TSS rates were designed for lighting fixtures that use older, less energy-efficient bulb technology, and ETI did not conduct any analyses to estimate the cost differential of serving street lighting and traffic signal customers that use energy-efficient LED fixtures. In fact, Dr. Goins noted that the basic structure and pricing provisions of the SHL and TSS rates have been place for years.940

In Dr. Goins’ opinion, adoption of LED lighting rates would help reduce energy consumption in Texas because such rates help offset the high front-end cost of LED lights and encourage municipalities to adopt energy-efficient LED options. In 2010, the Commission approved a street and traffic signal rate for El Paso Electric Company that included separate charges for LED traffic signals.941 In that case, the fixed monthly rate for LED signals was generally less than one-third the comparable rate for incandescent signals.

Dr. Goins recommended that the Commission require ETI to modify monthly fixed charges in Schedule SHL (Rate Groups A and C) and the monthly minimum charge in Schedule TSS to reflect a 25 percent discount for LED installations. Under his proposal, the discounted Rate Group A fixed charges (if applicable) in Schedule SHL would be applied according to the estimated monthly kWh consumption of the installed LED fixture. In addition, he recommended reducing by percent the Schedule SHL kWh charges applicable to LED customers assigned to Rate Groups D and E to reflect the lower cost of operating and maintaining LED fixtures. And he added that, in the Cities Ex. 4 (Goins Direct) at 22-23.

Id. at 23.

Application of El Paso Electric Company to Change Rates, to Reconcile Fuel Costs, to Establish Formula-Based Fuel Factors, and to Establish an Energy Efficiency Cost Recovery Factor, Docket No. 37690 (July 30, 2010).

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future, ETI should be required to provide detailed information regarding differences in the cost of serving LED and non-LED lighting customers.942

Dr. Goins also requested that the Commission require ETI to eliminate the service condition applicable to Rate Groups A and C in Schedule SHL that charges a $50 fee for any replacement of a functioning light with a lower-wattage bulb. He stated that this fee actively discourages customers from adopting more energy-efficient lighting technologies (for example, LED devices), and was not supported in ETI’s filing. In Dr. Goins’ view, this barrier to conservation and efficiency improvements should be eliminated.943

Staff disagrees with Cities’ request that ETI institute a discounted lighting rate for LED installations. Mr. Abbott testified that Cities did not provide empirical cost data to support this request. Without data on which to base an LED installation discount, he recommended that the Commission not require ETI to provide such a discount at this time. However, because of the growing use of LED installations and the potential cost savings to be realized from these installations, Mr. Abbott did recommend that the Commission require ETI to perform a cost study to determine appropriate cost-based rates for LED installations. This cost study could be used to develop LED lighting rates, which Mr. Abbott recommended ETI be required to submit as part of its next base-rate case.944

ETI is willing to perform a study to determine the feasibility of implementing LED lighting rates as part of its next base rate case filing. ETI witness Talkington explained that the Company does not currently offer ETI-owned LED lights but may do so in the future. She stated that if a customer wishes to use LED technology, it can install LE fixtures and receive service under Schedule SHL, Rate Groups D and E, or the existing Schedule TSS.945

Cities Ex. 4 (Goins Direct) 22-26.

Id. Staff Ex. 7 (Abbott Direct) at 28.

ETI Ex. 67 (Talkington Rebuttal) at 17.

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Ms. Talkington took issue with Dr. Goins’ proposed 25 percent decrease in Schedule SHL (Rate Groups A and C) and Schedule TSS for an LED option because the 25 percent rate reduction was not calculated. Thus, ETI prefers that it propose rates after a cost study. Ms. Talkington also disagreed with Dr. Goins’ proposal for a 25 percent decrease in the energy-only options under Schedule SHL, Rate Groups D and E or Schedule TSS for customer-owned lights. She believes that a customer will have the benefit of more efficient LED lights by the reduction in energy consumed.946

The ALJs find persuasive Dr. Goins’ testimony that: (1) the cost of street and traffic lighting services can be significant for many cities and towns; (2) government agencies face increasing pressure to control budgets and energy-efficient lighting is a good option; (3) LED fixtures use significantly less energy than incandescent and most other light options, last longer, and may require less maintenance; and (4) LED lighting rates would encourage municipalities to adopt energy-efficient LED options and help offset the high front-end cost of LED lights.947 However, the ALJs concur with ETI and Staff that ETI should be directed to perform a LED lighting cost study before extensive changes are made to its lighting rates. The ALJs further recommend that ETI conduct this study before filing its next rate case and provide the results of any completed study to Cities and interested parties as soon as practicable but no later than the filing of its next rate case, as requested by Cities. Further, the ALJs recommend that the study include detailed information regarding differences in the cost of serving LED and non-LED lighting customers, if ETI has LED lighting customers taking service at the time it conducts its study. Finally, the ALJs note that ETI did not dispute Dr. Goins’ suggestion to eliminate the service condition for Rate Groups A and C in Schedule SHL that charges a $50 fee for any replacement of a functioning light with a lower-wattage bulb. As noted by Dr. Goins, this fee discourages customers from adopting more energy-efficient lighting (such as LED devises). The ALJs concur and recommend that ETI modify the applicable tariffs to eliminate this fee for any replacement of a functioning light with a lower-wattage bulb.

Id. at 17-18.

Cities Ex. 4 (Goins Direct) at 24-25.

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2. Demand Ratchet Staff witness Abbott testified that a demand ratchet is a provision in a utility’s tariff that allows it to bill a customer based upon on the greater of either demand by that customer in the current month, or some fixed percentage of the customer’s demand occurring during previous months. The Commission approved a settlement in Docket No. 37744, ETI’s last base rate case, in which, among other things, ETI agreed to eliminate all life-of-contract demand ratchets from its tariffs for new customers with the implementation of rates. ETI further agreed that, in its next rate case, it would eliminate the life-of-contract ratchet for existing customers.948 The Docket No. 37744 stipulation stated:

Life-of-Contract Demand Ratchet. The Signatories agree that the life-of-contract demand ratchet provision in Rate Schedules Large Industrial Power Service [LIPS], Large Industrial Power Service-Time of Day [LIPS-TOD], General Service [GS], General Service-Time of Day [GS-TOD], Large General Service [LGS], and Large General Service-Time of Day [LGS-TOD] shall be excluded from the rate schedules in ETI’s next rate case. The Signatories further stipulate that the foregoing rate schedules will be revised so that the life-of-contract demand ratchet provision shall not be applicable to new customers and, for existing customers, shall not exceed the level in effect on August 15, 2010.949 ETI then filed compliance tariffs in Docket No. 37744, which implemented the first part of the settlement by excluding new customers from its proposed life-of-contract demand ratchet. The following is the relevant sections from that compliance tariff, which is applicable to Large Industrial Power Service (LIPS) customers (all customers taking service under this tariff are required to enter into a service agreement contract with ETI):

Staff Ex. 7 (Abbott Direct) at 16; Application of Entergy Texas, Inc., for Authority to Change Rates and Reconcile Fuel Costs, Docket No. 37744, Order at FOF 26(f) (Dec. 13, 2010). The ratchet is applicable to the General Service (GS), General Service – Time of Day (GS-TOD), Large General Service (LGS), Large General Service – Time of Day (LGS-TOD), Large Industrial Power Service (LIPS), and Large Industrial Power Service – Time of Day (LIPS-TOD).

TIEC Ex. 27 (Docket No. 37744 Stipulation and Settlement Agreement) at 6.

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VI. DETERMINATION OF BILLING LOAD The kW of Billing Load will be the greatest of the following: (A) The Customer’s maximum measured 30-minute demand during any 30-minute interval of the current billing month, subject to §§ III, IV and V above; or (B) 75% of Contract Power as defined in § VII; or (C) (1) For existing accounts with contracts for service for loads existing prior to August 15, 2010 – 60% of the Highest Contract Power established prior to August 15, 2010 as defined in § VII, (2) For new accounts with contracts for service for loads not existing prior to August 15, 2010 – Does Not Apply; or (D) 2,500 kW.

VII. DETERMINATION OF CONTRACT POWER Unless Company gives Customer written notice to the contrary, Contract Power will be as defined below: Highest Contract Power – the greater of (i) the highest Billing Load established under the currently effective contract, or (ii) the kW specified in the currently effective contract.

Contract Power- the highest load established under § VI (A) above during the months ending with the current month. For the initial 12 months of Customer’s service under the currently effective contract, the Contract Power shall be the kW specified in the currently effective contract unless exceeded in any month during the initial 12-month period.950 In this case, ETI changed the tariff provisions for all customers:

VI. DETERMINATION OF BILLING LOAD The kW of Billing Load will be the greatest of the following: (A) The Customer’s maximum measured 30-minute demand during any 30-minute interval of the current billing month, subject to §§ III, IV and V above; or (B) 75% of Contract Power as defined in § VII; or (C) 2,500 kW; or (D) 60% of the kW specified in the currently effective contract.

VII. DETERMINATION OF CONTRACT POWER Unless Company gives Customer written notice to the contrary, Contract Power will be as defined below:

TIEC Ex. 29 (Tariff Approved in Docket No. 37744)(emphasis added).

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Contract Power shall be the highest load established under § VI(A) above during the 12 months ending with the current month. For the initial 12 months of Customer’s service under the currently effective contract, Contract Power shall be the kW specified in the currently effective contract unless exceeded in any month during the initial 12-month period.951 The contested issue concerns ETI’s new language. ETI maintains the new language is not a life-of-contract ratchet. Commission Staff, TIEC, and DOE disagree. Stated simply, Department of Energy (DOE) witness Dwight D. Etheridge testified that the introduction of the term “kW specified in the currently effective contract” transforms what was a 12-month ratchet into a life-of-contract ratchet.952

At the outset, the ALJs note that some of ETI’s proposed tariffs do comply with the stipulation in the prior case. ETI eliminated the life-of-contract provisions for the GS and GS-ToD customer classes. However, ETI’s new language for the remaining ratchet classes, according to Staff witness Mr. Abbott, has the effect of maintaining a slightly different type of life-of-contract demand ratchet.953 The discussion in this section applies to the LIPS class but the same argument follows for LGS and GS classes.

The parties contesting ETI’s demand ratchet language argue that: (1) ETI’s compliance tariff in Docket No. 37744 was consistent with the parties’ agreement; (2) ETI’s proposal imposes a life- of-contract demand ratchet; (3) the service agreement and tariff are linked; and (4) the new demand ratchet is not equitable or cost-based. These arguments are set out below.

ETI 67 (Talkington Direct) at Ex. MLT-R-4 at 15 (emphasis added). ETI changed the relevant language in its tariff in its rebuttal testimony. Thus, the testimony of Messrs. Etheridge and Abbott can be slightly confusing because these witnesses address the tariff initially proposed by ETI.

DOE Ex. 1 (Etheridge Direct) at 11.

Staff Ex. 7 (Abbott Direct) at 16-19.

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¾ The agreed tariff from Docket No. 37744 was consistent with the parties’ agreement and shows how LIPS billing load should be calculated.

Staff, TIEC, and DOE agree that when ETI filed the compliance tariff in Docket No. 37744, the only demand ratchet that remained in the LIPS tariff for ETI’s new customers was a 12-month demand ratchet. ETI removed the life-of-contract ratchet that set a perpetual obligation for a customer to pay for power based on its highest contract power or a percentage of its contract power.

Staff, DOE, and TIEC argue that ETI’s action in removing those provisions was consistent with the agreement and is evidence of what ETI should have done in this case. They contend that ETI witness Ms. Talkington agreed that the settlement eliminated both the highest load established under the currently effective contract and the amount specified in the contract.954 In other words, the compliance tariff tracked the agreement.

ETI does not directly respond to this argument: Ms. Talkington did not address this in her rebuttal testimony. However, ETI states that the ALJs should “not be distracted by ETI’s initial error of unintentionally removing the contracted capacity provision as to new customers in its compliance tariffs in Docket No. 37744.”955 Apparently, ETI believes that the tariffs it filed in compliance with the Docket No. 37744 agreement were in error.

¾ ETI proposes a demand ratchet in this case that is based on the contracted quantity stated in the tariff-required service agreement.

All parties agree that what ETI proposes in this docket is different from the Docket No. 37744 tariff, as evidenced by Ms. Talkington:

Q: So last time, when the company and the parties implemented the elimination of the life-of-contract ratchet, it eliminated the 60 percent ratchet applicable to both actual demand during the contract period or the contract – the amount specified in the contract.

A. Yes, the way it’s put in the schedule, yes.

Q: And that’s different than what you proposed in this case?

Tr. at 1432.

ETI Reply Brief at 91.

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A: It is.

Q: And do you apply a different meaning to the agreement of what the life of contract ratchet meant than was applied in the tariff?

A: Yes. What we have in this case is that the life-of-contract power relates to the highest load established under the currently effective contract . . . 956

According to ETI, its proposed language does not impose life-of-contract ratchet, as defined by Mr. Pollock in Docket No. 37744 or by Messrs. Etheridge and Abbot in this case.

Witness Definition Pollock “A life-of-contract ratchet is based on the highest demand ever imposed by a customer during the term of the contract.” He further explained that ETI’s proposed Docket No. 37744 tariff had “a life-of-contract ratchet [which] imposes a perpetual obligation to pay a minimum demand charge throughout the term of the contract.”957 Etheridge “A life-of-contract ratchet is a ratchet where you’re not looking solely at current loads but some other loads in some prior period, so it creates a perpetual obligation to pay.”958 Abbott “[A] life of contract demand ratchet, which is based upon the highest demand established in the time period. . . . is one type of life-of-contact demand ratchet”959 ETI argues that the above definitions all make reference to the demand actually imposed by the operations of the customer’s physical plant. But the contracted quantity provision it proposes is a minimum kW amount contractually agreed between the two parties to the service agreement, which is a required contract between the customer and ETI.960 ETI argues the provision is not set by actual events during the term of the contract or in a prior period of the term of the contract, or in a monthly or 30-minute time period within the term of the contract; rather, it is set in the contract:

Tr. at 1432-1433 (emphasis added).

DOE Ex. 3 (Docket No. 37744 testimony excerpt) at 5-6.

Tr. at 2004.

Tr. at 1817.

Mr. Etheridge testified that customers taking service under Schedule LIPS must sign a contract for service.

Tr. at 1991.

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That contracted quantity is set as, to use Mr. Etheridge’s words, “an estimate” that cannot be unilaterally changed by the Company; instead, a change to that kW amount could only be made through negotiation between the two parties or through a proceeding before the Commission. To use Mr. Pollock’s definition, it is not a demand “imposed by the customer during the term of the contract.” It is instead a fixed, contractually agreed to amount that is set as a condition of service prior to the contract term.961 In sum, ETI argues the provision in question are not life-of-contract ratchets that lock the customer into the highest demand ever imposed by the customer’s actual load during the term of the contract. Rather, they are, at most, 12-month ratchets that set the billing demand over a 12-month period, but not the life of the contract, at 75 percent.

Staff suggests that the Commission does not, fortunately, have to determine what contract provision may or may not constitute a life-of-contract demand ratchet. Rather, the Commission must ensure that ETI fulfilled its obligations under the Docket No. 37744 settlement. Staff believes that the parties to that settlement understood the meaning of the life-of-contract term, ETI followed through with compliance tariffs that evidenced its understanding, and now ETI should be required to stick with its agreement.

¾ The service agreement and tariff are linked.

According to TIEC, ETI tries to make the argument that its proposal is justified because ETI and its large customers may sign an agreement for service that specifies a customer’s contract power. This does not justify ETI’s proposal because ETI’s form “Agreement for Electric Service” expressly states that the agreement is subject to the terms of “applicable rate schedules.”962 Thus, maintains TIEC, the LIPS tariff billing load provisions impact a customer’s contract power and can reasonably reduce a customer’s billing load below its contract power if the customer has a reduction in load lasting longer than 12 months.

ETI Initial Brief at 211 (footnotes omitted), citing Tr. at 1994, 2012.

ETI Ex. 3, Schedule Q 8.8 at 11.1.

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ETI’s proposal should be rejected, argues TIEC, because it would allow the utility to indefinitely seek revenue from a customer that has nothing to do with the customer’s actual usage or the utility’s costs. For example, if a plant took 150 MW of load in its heyday, under ETI’s proposal, the plant would be obligated to pay demand charges based on 60 percent of its original contract power. This is because ETI’s standard agreement requires the utility’s “express approval” to set a new contract power and the utility therefore could choose not to negotiate (or negotiate in a timely manner) a new contract power.963 If LIPS billing load is tied to contract power, then its customers would be completely at its mercy to negotiate a reasonable contract power based on the customer’s actual usage for the time period. TIEC contends this is a ridiculous result and would render the parties’ agreement to eliminate the life-of-contract ratchet meaningless.

¾ ETI’s new demand ratchet is not equitable or cost-based.

TIEC does not dispute that a 12-month ratchet is reasonable. However, Mr. Pollock, in Docket No. 37744, explained why a perpetual obligation to pay demand costs for load that the utility does not serve is objectionable:

While it is appropriate to require customers to pay for the facilities they use, a perpetual obligation is both extreme and unnecessary. Typical demand ratchets reach back twelve months. A life-of-contract ratchet can reach back decades. This is particularly inappropriate when longstanding customers have permanently reduced operations. A customer that has reduced operations is not purchasing the same level of generation and transmission services as in the past, nor is ETI procuring the same level of generation and transmission services for the customer. Further, because of load growth on the ETI system, the capacity no longer being used by the customer would be used by other customers. Thus, a life-of-contract ratchet does not properly reflect cost-causation.964 ¾ Witness Recommendations.

Staff witness Mr. Abbott recommended that ETI be required to eliminate from its LGS, LGS-ToD, LIPS, and LIP-ToD tariffs the language that results in a ratchet based upon the current

ETI Ex. 3, Schedule Q 8.8 at 11.2.

DOE Ex. 3.

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effective contract-specific demand. Also, if the Commission approves Mr. Abbott’s recommendation, he stated that the billing determinants used to calculate the rates for the affected customer classes will likely change. Therefore, ETI should be required to update the affected billing determinants and reflect the resulting change in its rates in the compliance filing of this docket.965

DOE witness Etheridge also recommends that same for the LIPS tariff. He specified language that will exclude the life-of-contract ratchet language and retain the existing rolling 12-month ratchet language in Schedule LIPS.966 Specifically, he proposed the following:

VI. DETERMINATION OF BILLING LOAD The kW of Billing Load will be the greatest of the following: (A) The Customer’s maximum measured 30-minute demand during any 30-minute interval of the current billing month, subject to §§ III, IV and V above; or (B) [60%] of Contract Power as defined in § VII; or (C) 2,500 kW.

VII. DETERMINATION OF CONTRACT POWER Unless Company gives Customer written notice to the contrary, Contract Power will be as defined below: Contract Power- the highest load established under § VI (A) above during the months ending with the current month. For the initial 12 months of Customer’s service under the currently effective contract, the Contract Power shall be the kW specified in the currently effective contract unless exceeded in any month during the initial 12-month period.

¾ ALJs Recommendation.

The ALJs find that ETI violated its agreement with the signatories in Docket No. 37744: the tariff language proposed by ETI is a life-of-contract demand ratchet. ETI failed to explain how the compliance tariffs adopted in Docket No. 37744 were in error. ETI’s argument that its new language is not a life-of-contract demand ratchet was unpersuasive. To justify its modification, ETI

Staff Ex. 7 (Abbott Direct) at 20.

ETI can adopt similar language for its LGS, LGS-ToD, LIPS, and LIP-ToD tariffs.

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relied only on a portion of Mr. Pollock’s Docket No. 37744 definition. Moreover, both Messrs. Abbott and Etheridge were unequivocal that ETI, contrary to its agreement in the previous rate case, is imposing a life-of-contract or perpetual obligation to pay. Finally, the weight of the evidence supports a finding that the demand ratchet ETI proposes in this case is not equitable or cost based. The ALJs recommend that ETI’s proposed LIPS tariff be amended to include the language proposed by Mr. Etheridge. The ALJs concur with Mr. Etheridge that, with such language, ETI has a financial incentive to negotiate the maximum possible contracted level of capacity, not the minimum, and the result is consistent with the Docket No. 37744 agreement.

3. Large Industrial Power Service (LIPS) TIEC witness Pollock explained that Schedule LIPS recovers base rates through a seasonally adjusted demand charge (per kW) and a two-step non-fuel energy charge (per kWh). The demand charges are also adjusted (either up or down) to reflect the differences in costs by delivery voltage.

ETI’s existing LIPS schedule has no customer charge. In its initial filing, ETI removed all purchased power capacity costs from base rates and proposed recovering them through a PPR as a demand charge. When it did so, the proposed demand charges were increased, but the proposed non-fuel energy charges were substantially reduced. Following the Supplemental Preliminary Order, which removed the PPR from further consideration, ETI proposed to roll these costs back into base rates. The resulting rebundled demand and energy charges would increase by about the same percentage.967

Mr. Pollock testified that the proposed structure of Schedule LIPS does not track costs as derived in ETI’s class cost-of-service study. Specifically, he complained: (1) there is no customer charge, despite the fact that the customer costs allocated to the LIPS class would translate into a monthly rate of over $6,000, and (2) the proposed non-fuel energy charges would recover a significant amount of demand related costs. According to Mr. Pollock, production/transmission demand-related costs are $8.47 per kW, and distribution costs add another $0.99 per kW, for a total of $9.46 per kW. The proposed LIPS demand charges are $7.07 per kW for transmission delivery

TIEC Ex. 1 (Pollock Direct) at 68-69.

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and an additional $1.82 for distribution service, for a total of $8.89 per kW. Thus, in Mr. Pollock’s opinion, the proposed demand charges (given ETI’s requested rate increase) are too low. By contrast, he noted, non-fuel energy costs are about 0.226¢ per kWh, while the proposed non-fuel energy charges would average over 0.600¢. Thus, these charges are 2.5 times higher than the non-fuel energy costs based on ETI’s filing.968

(a) A New Customer Charge TIEC urged that any increase in Schedule LIPS should be used to create a customer charge.

Mr. Pollock calculated that a cost-based customer charge should be about $6,050 per month, and he recommended an initial customer charge of $6,000 per month. This would collect approximately $5.9 million ($6,000 x 984 bills). He added that any remaining increase not accounted for by the initial customer charge should be collected in the demand charges. He also stated that the non-fuel energy charges should not be changed unless the LIPS class is allocated less than a $5.9 million increase. In that event, he recommended that the non-fuel energy charges should be decreased. This would gradually correct the imbalance between the below-cost demand charges and above-cost energy charges. Mr. Pollock further stated that the delivery voltage adjustment applicable to distribution service should be retained so that the rate better reflects the cost. Should the LIPS class not receive an increase or if base rates are decreased, Mr. Pollock recommended that the customer charge should be reduced proportionally. Any remaining revenue surplus should be applied to reduce the non-fuel energy charges to cost and then to reduce the demand charges.969

Staff witness Abbott also recommends the introduction of a customer charge, but a much smaller one than that recommended by Mr. Pollock – $630.970

DOE supports Staff’s proposed $630 customer charge. DOE witness Etheridge testified that TIEC’s proposed $6,000 customer charge far exceeds a reasonable initial customer charge for Schedule LIPS. For example, the existing Commission-approved monthly customer charge for TIEC Ex. 1 (Pollock Direct) at 69-70.

Id. at 70.

Staff Ex. 7 (Abbott Direct) at 27.

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Schedule LGS is $425.05. Mr. Etheridge stated that the introduction of a $6,000 customer charge will lead to large shifts in intra-class revenue responsibility from high load factor customers to low load factor customers because a customer charge does not vary with usage. He noted, as an example, that TIEC’s proposal would increase DOE’s Big Hill annual costs by $72,000 or nearly percent. Moreover, Mr. Etheridge pointed out that two parties are proposing to lower the Schedule LGS customer charge—approving either of these recommendations and TIEC’s would levy Schedule LIPS customers with a new customer charge that is over 23 times the level of the LGS class. He believes such inconsistencies are inexplicable. Additionally, such disparity would present a challenge to any customer migrating from the LGS to the LIPS class.971

DOE witness Etheridge agreed that is appropriate to move toward cost-based rates, however, he indicated that gradualism should be properly applied to move rates toward cost without undue impact on low usage and low load factor customers in the LIPS class. If a new customer charge for the LIPS class is to be imposed—it should be that recommended by Commission Staff.972

The ALJs are persuaded by Mr. Etheridge’s testimony that the adoption of a $6,000 customer charge far exceeds ETI’s existing customer charge in the LGS Schedule and results in a significant and inappropriate impact to low load factor customers. Rather, Mr. Abbott’s proposed customer charge of $630 is an appropriate charge to this customer class, particularly as ETI’s current rates applicable to LIPS customers do not include any customer charge.973

(b) Demand and Energy Charges In an effort to move more towards cost-based rates, Mr. Abbott recommends a slight decrease in the LIPS energy charges and an increase in the demand charges from current rates.974 Mr. Pollock does not recommend an increase in energy charges. However, he recommends increasing demand charges to cover any remaining revenue increase for the LIPS class that is not DOE Ex. 2 (Etheridge Cross-Rebuttal) at 3-4.

DOE Ex. 2 (Etheridge Cross-Rebuttal) at 5.

TIEC Ex. 1 (Pollock Direct) at 70.

Staff Ex. 7 (Abbott Direct) at 27.

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accounted for with the customer charge. He suggested that such a change will gradually correct the imbalance between the below-cost demand charges and above-cost energy charges.975

DOE witness Etheridge expressed concerns with both proposals. He stated that Schedule LIPS customers are, on average, substantially more energy intensive than customers taking service under Schedule LIPS-TOD customers. He indicated that TIEC’s proposed rate design (with the $6,000 customer charge) would double the cost increase associated with base rates and the fuel factor for LIPS-TOD customers compared with the average cost increase for the class as a whole.

Customers with lower load factors than Schedule LIPS-TOD customers would fare even worse.976

Mr. Etheridge also was concerned about Staff’s proposed charges, noting that Mr. Abbott failed to explain how the slight decrease in the LIPS energy charge and the large increase in the demand charge would affect customers with changes in the revenue requirement ultimately assigned to the class. Mr. Etheridge stated that even Staff’s proposed changes will noticeably shift intra-class cost responsibility toward Schedule LIPS customers with relatively low load factors. To address his concern that changes in the revenue requirement may have a significant impact even with Staff’s gradual movement in rates, Mr. Etheridge recommended that Staff’s proposal should set the limit on intra-class cost responsibility shifts.977

The ALJs find evidentiary support for and recommend the adoption of Mr. Abbott’s proposed changes to Schedule LIPS. There is sufficient evidence, based on Mr. Pollock’s testimony, that Mr. Abbott’s suggested changes gradually move the rates towards cost without the risk of rate shock. TIEC’s demand and energy proposals result in unreasonable large shifts in intra-class revenue responsibility. However, the ALJs also agree with Mr. Etheridge that Staff’s proposal may need to be adjusted depending on the ultimate revenue requirement adopted.

TIEC Ex. 1 (Pollock Direct) at 70.

DOE Ex. 2 (Etheridge Cross-Rebuttal) at 5.

DOE Ex. 2 (Etheridge Cross-Rebuttal) at 5.

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4. Schedulable Intermittent Pumping Service (SIPS) DOE proposes that a new rider, Schedulable Intermittent Pumping Service (SIPS), be included in the LIPS tariff. This will allow DOE and other customers with intermittent pumping loads to avoid application of a demand ratchet to schedulable, temporary, increased demand during off-peak months when ETI’s costs are lowest. DOE suggests that the proposed rider will allow the DOE to schedule important testing and oil exchanges, when possible, during off-peak months, is consistent with existing riders, and does not adversely impact other customers.

DOE explained that its Strategic Petroleum Reserve (Reserve) Texas sites—Big Hill in Jefferson County and Bryan Mound in Brazoria County—play an important role in ensuring the energy security of the United States. With a crude oil inventory of about 726.5 million barrels in 2010, the Reserve is the largest emergency supply of oil in the world. The Reserve was established by Congress as a result of the oil supply disruption in the early 1970s.978

DOE witness Etheridge testified that DOE takes service to its Big Hill site under Schedule LIPS at an annual cost of approximately $770,000. Mr. Etheridge explained that the Reserve’s sites typically operate in standby mode, with routine cyclical tests of pumping equipment.

The largest of these tests is performed every other year. These cyclical equipment tests can be coordinated with ETI so that they occur during low peak periods.979

On rare occasions, the Reserve can also be tapped. In its nearly 35 years of operations, there have been three Presidential-ordered drawdowns: January 1991, the beginning of Desert Storm; September 2005, Hurricane Katrina; and July-August 2011, the International Energy Agency coordinated release. The latter was the largest of the three drawdowns at 30.6 million barrels.

Additionally, the Reserve has provided support to the oil industry in localized emergency or operational situations involving a disruption in supply, such as ship channel closures and hurricanes.

DOE Ex. 1 (Etheridge Direct) at 3.

DOE Ex. 1 (Etheridge Direct) at 3-4 SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 300 PUC DOCKET NO. 39896

When oil is exchanged during these situations, the Reserve will operate pumps at higher levels than would occur during normal standby operations.980

Mr. Etheridge proposed a rider to Schedule LIPS where maximum demands during pre- scheduled, non-summer month operations of a limited duration are not subject to demand ratchets.

For this new rider, he proposed that the non-summer months be classified as October through May to give customers and ETI more flexibility. (Under Schedule LIPS, non-summer months are November through April.) Key provisions of the proposed SIPS rider include:

¾ A requirement that customers schedule with ETI limited duration operations during non-summer months four weeks in advance.

¾ ETI must approve scheduled operations.

¾ Operations would not be allowed to exceed 10,000 kW in magnitude nor last for more than 80 hours per year.

¾ ETI could cancel operations at any time if a capacity constraint develops.

If a customer failed to comply, the customer would incur costs associated with ETI’s ratchet.

¾ A customer in compliance would not be subject to ETI’s demand ratchets for loads established during those operations, but would pay the demand charge in the month in which the operations occur.981 Mr. Etheridge gave an example of charges under Schedule LIPS versus charges if the rider were adopted. In September 2010, Big Hill conducted a test and established a maximum measured demand of 11,640 kW, well above the site’s average maximum demand of approximately 3,000 kW.

DOE paid demand charges on the 11,640 kW in September 2010. In October 2010, ETI billed DOE for 75 percent of that level of demand or 8,730 kW based on the rolling 12-month ratchet. Its actual demand was 2,520 kW. In terms of actual costs, DOE paid $683,000 for its September usage. Under the 75 percent ratchet, DOE would pay $609,000 per month. Mr. Etheridge estimated that the

DOE Ex. 1 (Etheridge Direct) at 3-4.

DOE Ex. 1 (Etheridge Direct) at 18.

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charges amounted to $59/kW per year, which could easily represent nearly one-half of the annual carrying cost of a combustion turbine. Whereas, under the proposed rider, if DOE conducted the test in February as it intended to, it would have paid ETI for the 11,640 kW level of demand, but the usage would not be used in conjunction with ETI’s ratchets. Mr. Etheridge concluded ETI’s tariff is not equitable. At the hearing, Mr. Etheridge estimated that the rider’s impact on other customer classes at approximately $500,000, where Schedule LIPS base rate revenues are approximately $110 million.982

According to DOE, for 15 years, June 1996-June 2011, ETI, by contract, accommodated the Reserve’s intermittent load by allowing the DOE to, once annually, “reset” the demand level to be used by ETI when applying demand ratchets. The DOE was able to avoid significant demand charges when typical demand was very low. After June 2011, ETI declined to apply the terms of the long-time contract and allow the reset. DOE concedes that cost-based rates to reflect the Reserve’s unique operations should ultimately be addressed by contract and/or new tariffs.

DOE notes that the very purpose of some riders is to address specific customer characteristics. For instance, Standby and Maintenance Service is available only to those customers that co-generate electricity; the Optional Rider to Schedule LIPS for Pipeline Pumping Service alters the designation of on peak-hours only for customers with pipeline pumping stations. Other riders, claims DOE, seek a win-win for all customers. For instance, the Rider to LIPS for Planned Maintenance rewards customers for scheduling routine maintenance and idling facilities during ETI’s peak summer months of June through September by waiving the demand ratchet. DOE argues that the proposed SIPS rider mirrors Planned Maintenance by waiving the demand ratchet if customers are able to schedule intermittent loads outside of ETI’s peak summer months. Moving toward cost-based rates is not discriminatory, claims DOE. Nor is rewarding customers who use their load scheduling flexibility for the benefit of all customers.

DOE’s proposed SIPS rider is opposed by ETI, TIEC, and Staff.

DOE Ex. 1 (Etheridge Direct) at 19-20; Tr. at 2034.

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ETI witness Talkington testified that the actual Reserve load, as Mr. Etheridge described, does not appear to match the parameters of his proposed SIPS rider. As recently as July and August 2011, the Reserve sites had significant load requirements in order to pump vast quantities of oil. She further testified that the Reserve loads are random in occurrence and are significant. ETI must at all times maintain generation resources to meet this significant and randomly occurring load. In addition, the Company has invested in transmission and other facilities to serve this customer even if there is no or very little consumption. She believed it would not be appropriate or equitable to other customers to remove or forgive the 12-month ratchet provision after the Company made these investments to serve the Reserve and while the Company has maintained generation to meet its load.

If the 12-month ratchet were forgiven, then the costs incurred to serve DOE would have to be borne by other customers in the LIPS rate class.983

TIEC witness Pollock complained that Mr. Ethridge failed to analyze the impact on other LIPS customers. Mr. Pollock contended the rider would discriminate against both Schedule LIPS customers (by redefining the summer billing period) and Schedule SMS customers (whose ability to schedule maintenance power could be subordinate to LIPS customer taking advantage of the new Rider).984

Staff is concerned that the rider’s unusual eligibility requirements—that a customer must schedule load four weeks in advance, limit the high load occurrence to “off-peak months” (which is redefined in the rider), and limit the yearly hours of load—indicate it is tailored solely to meet the unique needs of the Reserve. According to Staff, DOE conceded that, although other customers with intermittent loads might take advantage of the proposed SIPS rider, Mr. Etheridge was not aware of any other actual customer that could do so.985 Staff argues the rider appears to offer unreasonably preferential treatment to the DOE and should be rejected.

ETI Ex. 67 (Talkington Rebuttal) at 41.

TIEC Ex. 3 (Pollock Cross Rebuttal) at 9-10, 44-46.

Tr. at 2008 (“Q: Now, who else would take advantage of this SIPS rate schedule, other than DOE? A: It’s written such that any other customer that would have an intermittent schedulable load could take advantage of it. But I’m not sure if there are other customers on Entergy’s system that could take advantage of it. Q: So SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 303 PUC DOCKET NO. 39896

Beyond issues of discrimination, Staff is also concerned that the rider would shift costs from the DOE to other LIPS customers. Although DOE indicates that any shift would have a small overall impact on the LIPS class, Staff argues that the Commission should not endorse any discriminatory rate rider.

Although Staff and TIEC claim the proposed rider is discriminatory, other riders applicable to Schedule LIPS customers are available at different times of the year as well (Planned Maintenance is available only during the months of June through September) and others are limited to customer-specific needs—such as PPS for pipeline customers. Mr. Etheridge testified that this rider could apply to any customer—it is not restricted solely to the DOE. The ALJs do not find this rider to be unreasonably discriminatory. As to ETI’s concern on this issue, it was focused on whether the DOE’s load met the proposed rider’s requirements. However, if a customer taking service under the rider is unable to schedule its maintenance and oil exchanges with ETI, then the usage would be under the SIPS Schedule and the SIPS tariffed demand ratchet would apply.

Moreover, Mr. Etheridge testified that the impact on other customer classes is limited. As to ETI’s cost recovery, the LIPS rider customers will pay a demand charge to cover the costs they impose on the system in the month SIPS service is taken. The ALJs agree with DOE that the SIPS rider is reasonable and should be adopted.

5. Standby Maintenance Service (SMS) TIEC witness Pollock explained that Schedule SMS applies to customers that use self-generation to supply a portion of their electricity requirements. These customers contract with ETI for either standby and/or maintenance power service to replace capacity or energy normally generated by the customer’s on-site generation. Standby (or backup) power is electric energy or capacity supplied to replace energy or capacity that is unavailable due to an unscheduled or forced outage of the facility. Thus, backup power must be available at any time. Maintenance power is electric energy or capacity supplied during a scheduled outage. Unlike backup power, maintenance power must be arranged with 24-hour notice and only during such times and at such locations that,

you don’t know that there are others who could use it. This could apply just to DOE? A: It could.”).

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in ETI’s opinion, will not result in adversely affecting or jeopardizing firm service to other customers, prior commitments, or commitments to other utilities. In addition, the customer must make arrangements and schedule maintenance power in writing in advance and confirmed in writing by ETI. ETI can also limit requests for maintenance power and allocate and schedule available service, if requests are made from more than one customer. Thus, Mr. Pollock stated that maintenance power is of a lower quality of service than backup or standby power. He also indicated that, because the Company can limit the amount of maintenance power, it is more likely that customers would prefer to schedule maintenance power during the non-summer months.986

ETI witness Talkington explained that standby service includes both the readiness to serve and the actual delivery of power and energy delivered when a customer requires service due to a forced outage or a planned maintenance period. She indicated that many utilities offer a combination of pricing and terms for demand and energy service as well as a form of reservation charge dealing with the readiness to serve. She further indicated that the actual rate design may differ, but standby tariffs usually contain provisions for back-up (forced outage) or maintenance (planned outage). She concluded that ETI’s current rate schedule provides for these features, and ETI is not proposing to change Schedule SMS in this proceeding.987

TIEC proposes to redesign SMS service to better reflect the cost characteristics of standby and maintenance power customers. Mr. Pollock provided his analysis to support TIEC’s position.

Under the current Schedule SMS, customers pay a monthly demand (or billing load) charge of $1.12 per kW for backup power. The corresponding charges for maintenance power are $1.12 per kW for outages during the summer months (May through October) and $0.84 per kW for outages during the non-summer months. Thus, the non-summer month charge is 75 percent of the summer month charge. Energy is priced under an array of time-differentiated charges, as shown in the table below:988

TIEC Ex. 1 (Pollock Direct) at 70-71.

ETI Ex. 67 (Talkington Rebuttal) at 19-20.

TIEC Ex. 1 (Pollock Direct) at 72-73.

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Current Schedule SMS Non-Fuel Energy Charges (¢ per kWh) On- Delivery Voltage Off-Peak Peak989 Distribution (less than 69KV) 3.386¢ 0.514¢ Transmission (69KV and greater) 2.334¢ 0.211¢ Mr. Pollock examined P.U.C. SUBST. R. 25.242(k)(1) and concluded that, for Standby Service, cost-based standby rates should recognize system-wide costing principles and must not be discriminatory. According to his analysis, the SMS demand charges should be $0.82 per kW for delivery at transmission and $2.64 per kW for delivery at distribution. He also determined that cost- based energy charges should be as follows:990

Cost-Based Schedule SMS Non-Fuel Energy Charges (¢ per kWh) Delivery Voltage On-Peak Off-Peak Distribution (less than 69KV) 0.955¢ 0.639¢ Transmission (69KV and greater) 0.916¢ 0.614¢

Mr. Pollock explained that, on average, 7 percent of Schedule SMS billing demand was coincident with ETI’s summer month system peaks. This compares to 74 percent for Schedule LIPS; thus, the ratio of the SMS to LIPS coincidence factors is 12 percent. By Mr. Pollock’s calculations, the resulting demand charge for transmission service would be $0.82 per kW ($7.07 x percent), and the corresponding SMS distribution demand charge would be the sum of the transmission charge and the Schedule LIPS distribution demand charge, or $2.64 per kW ($0.82 + $1.82).991

On-peak hours are from 1:00 p.m. to 9:00 p.m., Monday through Friday of each week, beginning on May and continuing through October 15. In addition, fuel charges are priced at avoided energy cost as calculated under Schedule LQF. TIEC Ex. 1 (Pollock Direct) at 72.

TIEC Ex. 1 (Pollock Direct) at 73-74 and Ex. JP-15.

Id. at 72-74.

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Mr. Pollock testified that he combined production and transmission costs in deriving a cost-based schedule SMS demand charge for transmission delivery, because both production and transmission demand-related costs are allocated to customer classes using the A&E 4CP method.

This method recognizes that production/transmission plant is sized to meet the diversified summer peak demands of all ETI customers. That is, Mr. Pollock stated, the 4CP demands are a primary driver of the costs of the power plants, PPAs, and transmission facilities. As noted above, Mr. Pollock contended and verified by analysis that a cost-based Schedule SMS demand charge should be only 12 percent of the corresponding demand charge for Schedule LIPS.992

Mr. Pollock also stated that he proposed to differentiate the standby demand charge by delivery voltage because it more directly recognizes the different costs to provide service at transmission and distribution voltage. He added that this recommendation is consistent with the current Schedule SMS energy charges.993 However, Mr. Pollock did not apply the 12 percent coincidence ratio to determine the distribution-related schedule SMS demand charge. He explained that distribution facilities are electrically closer to customers, so a customer’s peak demand determines how distribution facilities must be sized to ensure reliable service. He stated that ETI recognized this driver by using maximum diversified demand to allocate distribution demand-related costs. For this reason, Schedule SMS customers require the same amount of distribution capacity as a similarly sized Schedule LIPS customer. Thus, according to Mr. Pollock, the Schedule SMS distribution demand charge should be the same as the corresponding Schedule LIPS demand charge.994

Concerning energy charges, Mr. Pollock testified that the Schedule SMS energy charge should reflect the composite Schedule LIPS energy charges, or 0.614¢ per kWh. In his view, a Schedule SMS customer should also pay additional demand charges during on-peak hours, because this would recognize that an SMS customer that purchases more energy during on-peak hours would more closely resemble a LIPS customer. For this reason, cost-based on-peak energy charge should Id. at 75-77.

TIEC Ex. 1 (Pollock Direct) at 77.

Id. at 77-78.

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be a composite of the Schedule LIPS energy charge and the remaining demand charges (not collected in the SMS demand charge). He calculated an additional on-peak energy charge of 0.303¢, which yields a total on-peak energy charge of 0.917¢. Under this structure, an SMS customer that experiences an outage would pay approximately the same for electricity as a LIPS customer.995 In summary, Mr. Pollock contended that Schedule SMS should be reduced to more closely reflect the cost of providing standby service as follows:996 Cost-Based Schedule SMS Charges Based on ETI’s Proposed Schedule LIPS Design Distribution Transmission Charge (less than (69kV and 69kV) greater) Billing Load Charge ($/kW) Standby $2.64 $0.82 Maintenanc $2.44 $0.62 e Non-Fuel Energy Charge (¢/kWh) On-Peak 0.955¢ 0.916¢ Off-Peak 0.639¢ 0.614¢ Using his recommended Schedule LIPS rate design, he proposed Schedule SMS charges shown in the table below:997

TIEC Proposed SMS Charges Distribution Transmission Charge (less than (69kV and 69kV) greater) Customer Charge $6,000 (Stand Alone) Billing Load Charge ($/kW) Standby $2.46 $0.79 Maintenance $2.27 $0.60 Non-Fuel Energy Charge (¢/kWh) Id. at 77-78; Ex. JP-15.

Id. at 79.

TIEC Ex. 1 (Pollock Direct) at 80.

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On-Peak 0.881¢ 0.846¢ Off-Peak 0.575¢ 0.552¢ Mr. Pollock based his recommended charges on ETI’s proposed revenue requirements and class revenue allocation. If the Schedule LIPS revenue requirement is reduced, the charges should be correspondingly reduced. Mr. Pollock also added a customer charge, but he stated that the customer charge should not apply if a Schedule SMS customer also purchased supplementary power under another applicable rate.998

To determine maintenance power charges, Mr. Pollock maintained the same relationship; that is, the current maintenance power demand charge is 75 percent of the standby power demand charge.

He stated that the 75 percent should apply to the production/transmission component of the recommended standby power demand charge because distribution costs are caused by maximum demands occurring at any time, as previously discussed. This would result in a $0.20 and $0.19 per kW differential based on ETI’s proposed and Mr. Pollock’s recommended Schedule LIPS designs, respectively.999

The ALJs note that Mr. Pollock’s suggested changes to Schedule SMS are extensive. For instance, he introduced a $6,000 customer charge and, for the monthly billing load (demand) charges, he introduced separate rates for distribution and transmission customers.1000

Ms. Talkington testified that Mr. Pollock erred in using load data for the period of 2007 through 2011 to develop a coincidence factor that he then uses to develop a lower back-up and maintenance demand charge for transmission-level customers, while significantly increasing the charge for distribution-level customers. She also stated that Mr. Pollock’s proposal fails to recognize the “readiness to serve” aspect of standby service. ETI must be ready to serve the load

Id. at 79.

TIEC Ex. 1 (Pollock Direct) at 80.

1000 TIEC Ex. 1 (Pollock Direct) at 80.

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represented by the largest generation unit taking standby service, plus account for the forced outage rates for all other existing customer-owned generators.1001

Ms. Talkington also stated Mr. Pollock failed to recognize that standby load does not lend itself to the typical rate design practices. She opined that the cost of providing SMS service is not driven only by the degree to which standby customers contribute to peak demand, but also by the Company’s obligation to serve whenever called upon. This is the major reason Schedule SMS is not included in the development of allocation factors.1002

Ms. Talkington admitted that she is not familiar with how ETI originally developed Schedule SMS, but stated that she knows that when a customer takes back-up or maintenance service, costing is generally designed to mimic what the customer would have paid on standard rates, absent the use of its own generator. She concluded that Mr. Pollock’s analysis is over-simplified and incomplete.1003

In rebuttal testimony, Ms. Talkington proposed a new rate design for SMS service, including a new service, Non-Reserved Service, which is an optional service designed to supplement Maintenance Service. ETI’s new SMS proposal increases ETIs test year base rate revenues by 53.27 percent, with an overall increase of $5.1 million. ETI did not include this rate increase in its notice.1004 Accordingly, the ALJs determine that ETI’s new SMS proposal is not an option to be considered in this case.

Commission Staff does not oppose ETI’s request to retain its current Schedule SMS.

1001 ETI Ex. 67 (Talkington Rebuttal) at 20-21.

1002 ETI Ex. 67 (Talkington Rebuttal) at 21.

1003 ETI Ex. 67 (Talkington Rebuttal) at 21-22.

1004 PURA § 36.102 and P.U.C. PROC. R. 22.51 require a utility to publish notice of its intent to change rates, with proposed revisions of tariffs and a detailed statement of each proposed change, the effect it is expected to have on revenues, the class and number of customers affected by the change.

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ETI did not demonstrate how its current rates are just and reasonable. Rather, ETI’s evidence on the reasonableness of Schedule SMS is conclusory and insufficient in light of Mr. Pollock’s testimony that the rates are not cost-based. Moreover, although Ms. Talkington indicated her concern with Mr. Pollock’s analysis, she provided no quantitative support for her concern. The ALJs, however, are concerned that Mr. Pollock’s suggested changes are not accompanied by a rate impact analysis. And, as noted above, his suggested changes are extensive.

Mr. Pollock’s recommendations included a significant increase in the charge for distribution-level customers. Consistent with his Schedule LIPS recommendation, Mr. Pollock also included a $6,000 customer charge when no previous customer charge existed. Again, there is no analysis as to the effect such a charge would have on customer bills. The testimony of witnesses Benedict, Abbott, Higgins, and Pevoto caution that gradualism should be considered in rate design. As noted by Mr. Higgins, “full movement to cost-based rates in a single step is sometimes opposed on the grounds of intra-class rate impacts.”1005 However, the rate impact at this time is not known.

Based on the evidence and discussion above, the ALJs recommend adoption of Mr. Pollock’s suggested changes to Schedule SMS , with the exception of a $6,000 customer charge. Consistent with the ALJs’ recommendation that a new LIPS charge of $630 is reasonable, the SMS charge should be limited to $630 and, as suggested by Mr. Pollock, not apply if a Schedule SMS customer also purchased supplementary power under another applicable rate.

6. Additional Facilities Charge (AFC) Mr. Pollock testified that Schedule AFC is the mechanism for charging customers directly for the costs of transformers, breakers and lines when those facilities provide service only to specific customers. Some of these facilities are booked to transmission accounts while others are booked to distribution accounts. Schedule AFC is applied as a percentage of the original (un-depreciated) cost of the facilities.1006

1005 Kroger Ex. 1 (Higgins Direct) at 10.

1006 TIEC Ex. 1 (Pollock Direct) at 81.

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TIEC contends that the Schedule AFC charges should be revised. According to Mr. Pollock, the current charges exceed ETI’s ownership and O&M costs; therefore, he recommended that the monthly charges in Schedule AFC be reduced. Under this rate schedule, there are two separate pricing options. Option A charges 1.49 percent per month; Option B applies when a customer elects to amortize the direct assigned facilities over a shorter term, ranging from one to ten years. Thus, the Option B Monthly Recovery Term charge varies depending on the length of the amortization period of the directly assigned investment. A 0.453 percent Monthly Post-Recovery term charge also applies after a facility has been fully depreciated. ETI did not propose to change either the Option A or Option B charges in Schedule AFC.1007

According to Mr. Pollock’s analysis, charges imposed under Option A should be 1.20 percent per month under ETI’s proposed revenue requirements. Under Option B, Mr. Pollock proposes various changes to the Recovery Term charges, and reduces the Monthly Post-Recovery term to 0.35 percent per month. Further, if the Commission approves a lower base revenue requirement than ETI has proposed, Mr. Pollock stated that the recommended Schedule AFC charges (both Option A and Option B) should be reduced in proportion to any authorized reduction in ETI’s proposed rate of return, O&M expense, and property tax expense.1008

In reaching this recommendation, Mr. Pollock used two different methods to derive a cost- based rate: a levelized cost analysis and a revenue requirement analysis. The former resulted in an Option A rate of 1.20 percent per month, and the revenue requirement analysis resulted in a weighted average rate of 1.18 percent. For Option B charges, Mr. Pollock also used a levelized cost analysis for each of the Option B amortization periods, which resulted in lower charges.1009

ETI witness Talkington disagrees with Mr. Pollock’s description of Schedule AFC. She testified that the rate schedule encompasses the costs associated with the installation of facilities other than those normally furnished. Or, under one option, the rates are like a monthly rental charge

1007 Id. at 82-85.

1008 TIEC Ex. 1 (Pollock Direct) at 81-85 and at Exs. JP-17 and JP-18. See ETI Ex. 3, Sch. Q-8-8 at 24.

1009 TIEC Ex. 1 (Pollock Direct) at Ex. JP-18.

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paid for facilities that would not normally be supplied by the Company. She also stated that Mr. Pollock’s example of facilities (transformers, breakers and lines) is understated.1010

ETI contends that revisions to this discretionary rate are unwarranted at this time. The Commission approved this rate structure (and rate) in Docket No. 16705. Moreover, ETI witness Talkington testified that this rate is voluntary—a customer has alternatives beyond those offered by ETI. Therefore, it is actually a market-driven rate. If a customer does not want to use this schedule to obtain the services it provides, the customer can secure services through other sources—either ETI-owned or otherwise. Ms. Talkington further stated that Mr. Pollock’s suggested changes would be detrimental to the customers who do not have AFC rates because the AFC revenue is treated as an offset to the revenue requirement to the rate classes.1011

Staff does not oppose ETI’s request to retain the AFC rate as it is currently designed.

The ALJs find insufficient support in the record to retain ETI’s Schedule AFC as-is. As noted by TIEC, there is no evidence in this case to support ETI’s claim that: (1) the rate is a voluntary rate; (2) there are other options in the market for customers; or (3) that the rate continues to be based on a cost that the market will bear (as the Commission found years ago in Docket No. 16705).1012 While Ms. Talkington disagreed with Mr. Pollock’s proposal because he did not take into consideration the scope of facilities provided and that his proposal could be detrimental to other ratepayers because ETI’s revenues from this rate will decrease, she did not quantify her concerns.1013 The evidence supports a change to Schedule AFC that will move the rate more towards costs, and TIEC’s proposals are the only ones for which there is evidence in the record. The ALJs further agree with Mr. Pollock that his numbers should be reduced in proportion to any authorized reduction in ETI’s proposed rate of return, O&M expense, and property tax expense.

1010 ETI Ex. 67 (Talkington Rebuttal) at 31.

1011 ETI Ex. 67 (Talkington Direct) at 27-28.

1012 See Docket No. 16705, Final Order, FoFs 292-296.

1013 Tr. at 1437, 1439-1440.

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7. Large General Service (LGS) Kroger witness Kevin C. Higgins testified that the LGS rate schedule serves customers with monthly billing demands between 300 kW and 2,500 kW. ETI proposes to increase the LGS demand charge from $8.56 per kW-month to $10.25 per kW-month and to increase the energy charge from $.00854 per kWh to $.01023 per kWh. The Company proposes no change in the customer charge of $425.05 per month.1014

Mr. Higgins testified that ETI’s proposed LGS demand charge would recover only percent of LGS demand-related costs. To compensate for the resultant revenue shortfall, the LGS energy charges proposed by ETI would significantly over-recover energy-related costs. Specifically, the overall LGS energy charge is proposed to be 428 percent of base energy costs. In addition, although the customer charge is proposed to be unchanged, it is set at 328 percent of cost. If, instead, the LGS customer charge were set at cost, it would only be $129.60 per month.1015

Mr. Higgins illustrated his findings in the table below:1016

LG Total Class Functionalized Cost Recovery Functions Costs Collected in (Under)/Over Percentage Rates Collection Recovered Demand $46,266,083 $33,116,674 $(13,149, 409) 71.6% Energy $3,6625,811 $15,556,253 $11,920,442 427.9% Customer $561,445 $1,841,316 $1,279,871 328.0% Total $50,463,339 $50,514,243 $50,904

Mr. Higgins stated that if a utility proposes a demand charge that is below the cost, it is going to seek to recover its class revenue requirement by over-recovering its costs in another area, typically through an energy charge that is above unit energy costs. In his opinion, for LGS, when demand charges are set below costs and energy charges are set above cost, customers with relatively 1014 Kroger Ex. 1 (Higgins Direct) at 7.

1015 Id. at 8.

1016 Kroger Ex. 5.

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higher load factors are required to subsidize the costs of lower load factor customers within the rate class. The subsidy is different for each higher load factor customer (a customer whose load factor is greater than the average for the rate schedule) and consists of the net increase in rates paid by these customers as a result of setting energy charges above energy costs and demand charges below demand related costs. When the customer charge is set significantly above costs, smaller customers are overcharged and subsidize the larger customers.1017

Recognizing that a full movement towards cost-based rates (without gradualism) in a single step may create intra-class rate impacts, Mr. Higgins proposed the following changes to better align costs:1018

ETI Kroger Proposed % of Proposed % of Functions Charge Cost Charge Cost Demand ($/kW) $10.25 72% $12.81 90% Energy ($/kWh) $0.01023 428% $0.00513 216% Customer ($/Mo) $425.05 328% $260.00 201%

Mr. Higgins developed his proposed rate impacts, which indicated a smaller rate impact on higher load factor customers than those with low load factors. He found them to be comparable to the rate impact found in ETI’s proposed rates.1019

ETI witness Talkington did not object to gradually moving rates toward setting demand energy and customer components closer to cost of service in the LGS class.1020

Based on principles of cost-based rates and of gradualism, Staff witness Abbott recommended a decrease in the LGS customer charge to $397.02 from the current (and Company 1017 Kroger Ex. 1 (Higgins Direct) at 9.

1018 Id. at 10-11.

1019 Id. at 11, Ex. KCH-3.

1020 Tr. at 1452.

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proposed) $425.05, and an increase in the energy charges, which is less than the increase proposed by the Company.1021

The ALJs found Mr. Higgins’ proposed changes reasonable and well supported.

Schedule LGS should be amended as proposed by Kroger. Schedule LGS also has a demand ratchet, and the ALJs’ recommendation for the elimination of ETI’s LIPS demand ratchet is applicable to this class.

8. General Service (GS) Based on principles of cost-based rates and of gradualism, Staff witness Abbott recommended a decrease in the GS customer charge to $39.91 from the current (and Company proposed) rate of $41.09. Staff also recommended a decrease in the energy charges.1022

No party disputed Staff’s recommendations, which the ALJs adopt. Schedule GS also has a demand ratchet, and the ALJs’ recommendation for the elimination of ETI’s LIPS demand ratchet is applicable to this class.

9. Residential Service (RS) ETI’s RS rate schedule is composed of two elements: a customer charge of $5 per month and a consumption-based energy charge. The Energy charge is a fixed rate of 5.802ȼ per kWh from May through October (Summer). In the months November through April (Winter), the rates are structured as a declining block, in which the price of each unit is reduced after a defined level of usage. For instance, the same energy charge of 5.802ȼ applies, but only for each of the first 1,000 kWh consumed. Each kWh consumed beyond 1,000 is billed at a lower rate of 3.834ȼ.1023

1021 Staff Ex. 7 (Abbott Direct) at 25-27.

1022 Id. 1023 OPC Ex. 6 (Benedict Direct) at 41, Ex. NAB-1, ETI’s Response to State RFI No. 4-17; ETI Ex. 67 (Talkington Rebuttal) at 9.

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ETI proposes to retain the general structure of the RS rate design but proposes an increase in the dollar amount of each rate element. OPC witness Benedict noted ETI’s proposed changes in his testimony, as set out below:1024

ETI ETI Percent Rate Element Current Proposed Increase Customer Charge (per month) $5.00 $6.00 20.0% Energy Charge (Summer, all 25.3% $0.05802 $0.07268 kWh) Energy Charge (Winter, kWh ≤ 25.3% $0.05802 $0.07268 1000) Energy Charge (Winter, kWh > 25.2% $0.03834 $0.04799 1000)

OPC criticized ETI’s declining block rate structure as being contrary to energy efficiency efforts. OPC witness Benedict noted that under ETI’s proposed rate structure, once kWh usage exceeds 1,000 in a winter month, the per-kWh cost of consumption falls by 34 percent. Thus, because a declining block rate structure lowers the per-unit rate for high levels of consumption, heavy users are induced to consume more than they would otherwise. In his view, this runs contrary to the Legislature’s goal of reducing both energy demand and energy consumption in Texas, as stated in PURA § 39.905:

(a) It is the goal of the legislature that: . . . (2) all customers, in all customer classes, will have a choice of and access to energy efficiency alternatives and other choices from the market that allow each customer to reduce energy consumption, summer and winter peak, or energy costs.

Therefore, Mr. Benedict recommended that the declining block rate be phased out over time. He stated this would ease the transition to a rate structure without a declining block, and it would allow time for customers to switch to more efficient heating systems. Mr. Benedict proposed that the phase-out take place over three rate cases, beginning with a one-third reduction in the block differential proposed by ETI in this case. Reducing ETI’s proposed block differential from 2.469ȼ 1024 OPC Ex. 6 (Benedict Direct) at 42.

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to 1.645ȼ accomplishes the initial one-third reduction, as illustrated below (using ETI’s requested revenue requirement):1025

Reduced ETI ETI Percent Block Rate Percent Rate Element Current Proposed Increase Differential Increase Customer Charge (per month) $5.00 $6.00 20.0% $6.00 20% Energy Charge (Summer, all 25.3% 23.1% $0.05802 $0.07268 $0.07141 kWh) Energy Charge (Winter, kWh ≤ 25.3% 23.1% $0.05802 $0.07268 $0.07141 1000) Energy Charge (Winter, kWh > 25.2% 43.3% $0.03834 $0.04799 $0.05496 1000)

Mr. Benedict stated that his proposal related to an intra-class rate design issue and was not intended to affect the amount of revenue to be collected from the residential class or any other class. If, however, the Commission approves a different revenue requirement for the residential class to reflect various proposed adjustments, rates for the class will need to be recomputed regarding a reduced block differential1026

Staff generally agreed with OPC’s recommendation for a reduction in the rate differential between the residential winter kWh ≤ 1000 block and the winter kWh > 1000 block, due to the inconsistency between the incentives produced under declining block rates and the State’s energy efficiency goals. Staff witness Abbott stated that the extreme cold weather event of February 2011 demonstrated a need to incentivize wintertime energy efficiency measures, or at least a need to avoid encouraging excess energy usage. Therefore, Mr. Abbott agreed that some reduction in the rate block differential is warranted to better encourage wintertime energy conservation at the margin.1027

ETI witness Talkington testified that the RS rates are cost-based with a declining block rate in winter. According to Ms. Talkington, residential load factors in winter increase as energy usage increases, and there is also a decrease in the fixed unit cost ($/kWh) as energy usage increases. She

1025 OPC Ex. 6 (Benedict Direct) at 43-45.

1026 OPC Ex. 6 (Benedict Direct) at 46.

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provided analysis to support her position.1028 Ms. Talkington explained that residential rates do not include demand charges because of the absence of residential demand meters. However, residential energy rates can be structured the same as the non-residential classes; that is, customer charge, demand charge and energy charge. She developed residential rates on this basis to show that the declining block rate is appropriate to account for reductions in the cost of service to residential customers as consumption increases. With no declining block rate, high load factor customers are disadvantaged as the customer charge is reduced and the demand charge is moved into the energy charge. She believes that declining block rates alleviate the disadvantage.1029

Ms. Talkington illustrated the impact of Mr. Benedict’s suggestion to phase out the declining block rate for RS customers. Approximately 54 percent of ETI’s residential customers use more than 1,000 kWh in January and February. For a customer using 3,000 kWh in a winter month of November-April, this customer’s bill would increase by 16.28 percent or about $48 over current rates. (Of ETI’s total number of RS customers, approximately 10 percent use 3,000 kWh or more in the months of January and February.) For that same customer, ETI’s as-filed proposal shows an increase of 11.96 percent or approximately $35. Mr. Benedict’s proposal is $13 greater than ETI’s proposal for one winter month at 3,000 kWh. That dollar amount is over a third of the total increase ETI is proposing.1030

After Mr. Benedict’s proposed phase-out is completed, based on the proposed residential rates in the Company’s case, the residential rate would be $0.06887 per kWh in both summer and winter. A customer using 3,000 kWh in a winter month of November-April would see an increase of 24.89 percent or about $73 over current rates. After the final phase out, Mr. Benedict’s proposal is $38 per month greater than ETI’s as-filed proposal of $35 for one winter month at 3,000 kWh.1031

1027 Staff Ex. 7 (Abbott Direct) at 27.

1028 ETI Ex. 67 (Talkington Rebuttal) at 13, Ex. MLT-R-1.

1029 Id. at 14.

1030 Id. at 15.

1031 Id. at 15-16.

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Ms. Talkington further noted that rate design professionals always take into consideration the effect on customer bills. Even though Mr. Benedict proposes to implement the change over the next three rate cases, she concludes there will still be winners and losers within the residential class as a result of his proposed change. According to Ms. Talkington, some customers have made decisions about investing in electric appliances based on the current rate design. The elimination of the declining block in the winter time changes the economics of customer decisions that have already been made. She believes that great caution needs to be exhibited and very good reasons need to be demonstrated before changes are made to the rate design. She recommended that if a change to the rate structure is recommended, the initial phase-in should be reduced to 10 percent rather than one- third and subsequent reductions should be reviewed for consideration at the occurrence of each rate case filing and not mandated at this time.1032

The ALJs concur with OPC and Staff that the structure of the declining block winter rates provide a disincentive to energy efficiency. However, ETI provided evidence that OPC’s suggested changes, combined with ETI’s proposed rate increase, will have too great an impact. OPC suggested a one-third reduction in the differential, while Ms. Talkington suggested a 10 percent reduction, with subsequent reductions reviewed before being mandated. The ALJs recommend an initial 20 percent reduction, which should alleviate some of ETI’s concerns but still reduce the block differential sufficiently to move towards compliance with the energy goals set out in PURA. The ALJs further recommend that 20 percent subsequent reductions of the differential be required in the next three rate cases unless ETI provides sufficient evidence that such changes are unjust and unreasonable.

XI. FUEL RECONCILIATION [Germane to Preliminary Order Issue Nos. 21-31] In the application, ETI seeks to reconcile approximately $1.3 billion in fuel and purchased power expenses incurred over the 24 month Reconciliation Period. Summaries of ETI’s total fuel and purchased power expenses and over/under recovery balance are shown below.

1032 ETI Ex. 67 (Talkington Rebuttal) at 15-17.

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Fuel Reconciliation Gas and Oil $616,248,686 Emissions Allowance 360,236 Coal 90,821,317 Total Fuel: $707,430,239 Purchase Power Expense 990,041,434 Off-system Sales Revenues (376,671,969) Total Purchased Power: $613,369,465 Total Fuel Costs: $1,321,799,704 Over-recovery Balance: $243,339,353 Special Circumstances $99,715 Sources: ETI Ex. 3 Schedules I-16, H-12.4a-g, H-12.5b-e, I-21; ETI Ex. 11 (McCloskey Direct); ETI Ex. 23 (Zakrzewski Direct).

ETI contends, and the evidence presented at the hearing demonstrates, that these fuel factor expenses were eligible for reconciliation and were reasonable and necessary to provide reliable service to ETI’s customers during the Reconciliation Period. With the exception of three minor issues that are discussed below, none of the intervenors raised a substantive issue with respect to ETI’s fuel reconciliation request.

During the Reconciliation Period, ETI’s Texas fuel factor revenues over-recovered total fuel and purchased power expense by $243,339,353, inclusive of interest. The Commission authorized the refund of the fuel over-recovery balance in Docket Nos. 37580, 38403, and 38967. ETI proposes that the amount of any fuel over-recovery balance not already refunded or authorized for refund be rolled forward as the beginning balance for the next reconciliation period.1033 P.U.C. SUBST. R. 25.236(d)(1) states that in a fuel reconciliation proceeding, the utility has the burden of showing that: (A) its eligible fuel expenses during the fuel reconciliation period were reasonable and necessary expenses incurred to provide reliable electric service to retail customers;

1033 ETI Ex. 40 (Thiry Direct) at 7.

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(B) if its eligible fuel expenses for the reconciliation period included an item or class of items supplied by an affiliate of the electric utility, the prices charged by the supplying affiliate to the electric utility were reasonable and necessary and no higher than the prices charged by the supplying affiliate to its other affiliates or divisions or to unaffiliated persons or corporations for the same item or class of items; and (C) it has properly accounted for the amount of fuel-related revenues collected pursuant to the fuel factor during the reconciliation period.

In Docket No. 15102, an EGSI fuel reconciliation case, the Commission explained the traditional prudence standard to be applied in reviewing decisions made by the utility:

The exercise of that judgment and the choosing of one of that select range of options which a reasonable utility manager would exercise or choose in the same or similar circumstances given the information or alternatives available at the point in time such judgment is exercised or option is chosen.

There may be more than one prudent option within the range available to a utility in any given context. Any choice within the select range of reasonable options is prudent, and the Commission should not substitute its judgment for that of the utility . . . . The reasonableness of an action or decision must be judged in light of the circumstances, information, and available options existing at the time, without benefit of hindsight.1034 ESI purchases power and procures fossil fuels on behalf of the individual Operating Companies. Fossil fuel costs are borne directly by the Operating Company that contracts for and uses the fuel. Once resources are procured to meet forecasted demand, the system is operated during the current day using all of the resources available to the system to meet the total system demand.

Throughout the course of the day, system operators may modify planned operations to maintain reliability, take advantage of less-expensive resources in the hourly wholesale power markets, or make off-system sales. For example, when spot market power purchases are available at a cost

1034 Application of Gulf States Utilities Company to Reconcile its Fuel Costs, Docket No. 15102, Order on Rehearing at 2 (Jun. 24, 1997).

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lower than the cost of energy that can be generated by units owned by the Operating Companies, that energy is purchased to displace owned generation, subject to operating constraints.1035

Expenses for coal, gas, power purchases, and fuel oil are incurred directly by the respective Operating Company. For example, if coal is purchased for ETI’s share of Nelson Station, Unit 6, then ETI is responsible for the invoiced cost and makes payment directly to the supplier. Wholesale power, purchased and sold for the system, however, is accounted for per the terms of the System Agreement. After dispatch, or after-the-fact, the System Agreement prescribes an accounting protocol to bill the costs of operating the system to the individual Operating Companies.1036

The following Fuel Reconciliation-related issues were uncontested:

¾ Natural Gas Purchases ETI witness Karen McIlvoy presented direct testimony describing ETI’s natural gas procurement policies and strategies. She explained that the Company buys gas through a long-term contract with Enbridge, through participation in the monthly and daily markets depending on fuel needs, and on a delivered-to-plant basis or arrange for transportation to the plant. Ms. McIlvoy described how the gas buyers for ETI survey the markets and solicit offers for gas supplies.

Ms. McIlvoy also provided a comparison of the Company’s gas costs to the Inside FERC and Gas Daily published indices for the Houston Ship Channel.1037 No party challenged the Company’s natural gas purchases.

¾ Fuel Oil Ms. McIlvoy testified that the Company purchased fuel oil for start-up and flame stabilization at certain units. Fuel oil can also be used for emergency back-up fuel or as an economic alternative to natural gas at certain units. During the Reconciliation Period, the Company purchased

1035 ETI Ex. 40 (Thiry Direct) at 18-21.

1036 ETI Ex. 39 (Cicio Direct) at 31-37.

1037 ETI Ex. 28 (McIlvoy Direct) at 23, Ex. KDM-3.

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all fuel oil on a short-term basis from spot market sources after solicitation of bids from multiple potential suppliers.1038 No party contested ETI’s fuel oil costs.

¾ Longer-Term Purchased Power ETI witness Robert R. Cooper addressed the Entergy system’s long-term planning process and described the Strategic Resource Plan process. He explained how the system determined its capabilities and needs for additional resources to reliably serve system load requirements.

Mr. Cooper described the process by which the system developed requests for proposals and analyzed a combination of capacity and firm energy contracts to satisfy the system’s identified resource needs.1039 A portion of these system purchases was allocated to ETI. No party proposed a disallowance of these purchases on the basis of prudence.

¾ Short-Term Purchased Power Ms. Thiry described the Power Marketing Team’s procurement strategies, practices and procedures during the Reconciliation Period. Ms. Thiry testified that the Power Marketing Team fulfilled its objective of purchasing energy in the wholesale market when it was more economical than using the system’s generation and in order to maintain system reliability. Ms. Thiry demonstrated that third-party purchases for the system compared favorably to market price indices and to proxy costs of avoided generation.1040 The Power Marketing Team maintained effective cost controls and procured a diverse portfolio of product to provide electricity for customers at a reasonable cost.1041 No party contested the prudence of ETI’s short-term power purchases.

¾ Coal Commodity and Transportation ETI has ownership interest and/or obtains power through Schedule MSS-4 of the Entergy System Agreement, in two coal-burning generating units – Nelson and BCII/U3. ETI owns a 1038 ETI Ex. 28 (McIlvoy Direct) at 5-6.

1039 ETI Ex. 34 (Cooper Direct) at 6-10.

1040 ETI Ex. 40 (Thiry Direct) at 24.

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29.75 percent interest in Nelson 6 and operates the unit. ETI owns a 17.85 percent interest in BCII/U3, but the unit is operated by a third party. ETI witness Ryan Trushenski, the Manager of Coal Supply for ESI, testified that ETI prudently managed its coal supply and transportation expenses during the Reconciliation Period.1042

With respect to coal and transportation expenses at Nelson 6, ETI obtained coal during the Reconciliation Period under a supply contract previously reviewed by the Commission, and entered into a new coal supply contract after a competitive bid process. ETI chose the supplier with the lowest priced coal that met the specifications necessary for use at Nelson 6. Similarly, ETI arranged for transportation of coal according to transportation contracts previously reviewed in prior fuel reconciliations. When those contracts expired, ETI initiated a competitive bid process and chose the lowest cost option available that met its requirements. With respect to BCII/U3, ETI incurred costs to run the unit and took reasonable steps to ensure that the third party operator properly charged for coal and transportation expenses under an arrangement previously reviewed and approved in prior fuel reconciliations.1043 No party challenged the reasonableness and necessity of ETI’s coal or transportation expense during the Reconciliation Period

The three contested issues are discussed below.

A. Spindletop Gas Storage Facility During the Reconciliation Period, ETI incurred $10,261,663 of non-fuel expense associated with operating the Spindletop Facility. Cities challenged ETI’s use of the Spindletop Facility, arguing that the costs of operating it outweigh the benefits gained from it. For the same reason he challenged the Spindletop Facility costs associated with rate base, Cities witness Nalepa also challenges ETI’s non-fuel expense associated with the facility. Specifically, Mr. Nalepa recommends that ETI’s total fuel reconciliation balance be reduced by $6,595,290, which he calculates as the difference between the $10,261,633 non-fuel operational costs associated with the Spindletop Facility over the Reconciliation Period and the costs of alternative sources of providing a 1042 ETI Ex. 33 (Trushenski Direct) at 2.

1043 Id. at 11-13.

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reliable and flexible gas supply over the same period.1044 In Section V.H., above, the ALJs rejected Cities’ contention that the Spindletop Facility is not used or useful. For the same reason they rejected Cities’ Spindletop Facility arguments relevant to rate base, the ALJs also reject Cities’ Spindletop Facility arguments relevant to Fuel Reconciliation.

B. Use of Current Line Losses for Fuel Cost Allocation Cities propose that the allocation of fuel costs incurred over the Reconciliation Period reflect the current line loss study performed by ETI for this case and recommended for approval on a going forward basis. In the fuel reconciliation case, ETI proposes to allocate costs to customers using a line loss study performed in 1997, which Cities claim does not reflect the current cost of providing service to the current wholesale customers and to the various retail customers.1045 According to Cities, updating ETI’s allocation of fuel costs to reflect current line losses and the cost of providing service to customers results in a $3,981,271 reduction to the Texas retail fuel expenses incurred over the Reconciliation Period.1046

ETI responds that the Cities’ recommendation is unprecedented. It notes that the Commission’s substantive rules require use of “a commission-approved adjustment to account for line losses corresponding to the voltage at which the electric service is provided.”1047 Moreover, ETI argues that retroactive use of new loss factors to calculate its fuel over/under-recovery balance would result in a mismatch between the revenues recovered under the fuel factor and the costs billed and allocated to the various customer classes.1048

Fuel costs are collected through Commission-approved fixed fuel factors. One of the elements the fuel factor is required to take into account is line losses. P.U.C. SUBST.

R. 25.237(c)(2)(B) states that the utility must prove that: “the proposed fuel factors utilize a 1044 Cities Ex. 6 (Nalepa Direct) at 42-43; Cities Initial Brief at 84.

1045 Cities Ex. 6 (Napala Direct) at 44; see also Tr. at 1469-1470.

1046 Cities Ex. 6 (Napala Direct) at 47, Table 14.

1047 ETI Ex. 58 (McCloskey Rebuttal) at 2, quoting P.U.C. SUBST. R. 25.237(c)(2)(B) (emphasis added).

1048 Tr. at 1484.

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commission-approved adjustment to account for line losses corresponding to the voltage at which the electric service is provided.”1049 If the Commission were to adopt Cities’ recommendation that the newly-developed line losses be used in the reconciliation of fuel costs, the allocation of those costs would not match the collections (determined through the use of historical line losses). This mismatch could result in some customers receiving more than they are entitled and others receiving less than they are entitled. The ALJs find that the Commission’s rules require the use of Commission-approved line losses that were in effect at the time fuel costs were billed to customers in a fuel reconciliation. The ALJs, therefore, recommend that the Commission reject the Cities’ proposed adjustment.

C. ETI’s Special Circumstances Request In the application, ETI seeks to include $99,715 in the Fuel Reconciliation to allow it to recover “the reversal of certain credits that were previously included in the Company’s [Incremental Purchased Capacity Rider] Rider IPCR.”1050 ETI witness Zakrzewski explained that the FERC revised the amount of purchased capacity-related production costs allocable to ETI through the FERC-approved Rough Production Cost Equalization mechanism for allocating production costs among the Operating Companies. As Mr. Zakrzewski explained, the result of the decision was a recalculation of ETI’s capacity costs recoverable through the Commission-approved Rider IPCR, which expired during the Reconciliation Period.1051

During the hearing, no party contested ETI’s special circumstances request of $99,715 with regard to the IPCR-related adjustment. For the first time in its Initial Brief, however, Cities opposed the request, asserting that it conflicts with the settlement reached in Docket No. 37744.1052 The ALJs are not swayed by Cities’ argument. As pointed out by ETI,1053 Cities provided no testimony or other evidence to support its position. Furthermore, Cities failed to explain how a settlement 1049 P.U.C. SUBST. R. 25.237(c)(2)(B) (emphasis added).

1050 ETI Ex. 23 (Zakrzewski Direct) at 13.

1051 Id. 1052 Cities Initial Brief at 86.

1053 ETI Reply Brief at 93.

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agreement reached in Docket No. 37744 could or should trump the FERC’s jurisdiction to determine the amount of purchased capacity costs attributable to ETI. The only evidence in the record supports ETI’s recovery of these costs. Accordingly, the ALJs recommend that these FERC-imposed costs should be found to be recoverable and Cities’ request to deny their recovery should be rejected.

In summary, the ALJs conclude that, consistent with the requirements of P.U.C. SUBST.

R. 25.236(d)(1), ETI met its burden to prove that: (1) its eligible fuel expenses during the Reconciliation Period were reasonable and necessary expenses incurred to provide reliable electric service to its retail customers; (2) the prices charges by its affiliates were reasonable and necessary and no higher than the prices charged by the supplying affiliates to other affiliates or to unaffiliated persons; and (3) ETI has properly accounted for the amount of fuel-related revenues collected pursuant to the fuel factor during the Reconciliation Period.

XII. OTHER ISSUES A. MISO Transition Expenses [Germane to Preliminary Order Issue Nos. 6-8 and Docket No. 39741 Preliminary Order Issue Nos. 1-9] Entergy is seeking to transfer operational control of the Entergy Operating Companies’ transmission assets to the MISO Regional Transmission Organization (RTO). ETI expects its share of the costs for this transfer will include approximately $17 million of expense.1054 ETI has made two alternate proposals to recover these expenses. ETI’s first proposal requests the Commission to approve a deferred accounting of its transition expense incurred on or after January 1, 2011, and to approve accrual of interest on the deferred amount at ETI’s overall rate of return. Under this proposal, ETI would present the resulting regulatory asset for review in a future proceeding. ETI originally requested this deferred accounting in Docket No. 39741, which was later consolidated into this case for all purposes. In its Preliminary Order in Docket 39741, the Commission stated that it had authority to allow such a deferral of costs “when it is necessary to carry out a provision of PURA.” It also stated that whether ETI’s request met this requirement “hinges on the factual issue of necessity . . . .”

1054 ETI Ex. 42 (Lewis Supplemental Direct) at 5.

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As an alternative proposal, ETI requested the Commission to include $4 million of transition expense in base rates set in the present case, based on a three-year amortization of a total of $12 million in MISO transition expenses. ETI’s Test Year MISO transition expenses totaled only $916,535, but ETI’s request for deferred accounting addressed expenses incurred on or after January 1, 2011, which is after the Test Year concluded. ETI argues that its request is a conservative known and measureable change because the post-Test-Year expenses will be significantly more than $4 million per year. Further, these costs would be removed from ETI’s cost of service if its deferred accounting proposal is approved.

As noted, ETI’s proposals concern MISO transition expenses incurred on or after January 1, 2011. However, ETI also incurred $263,908 in these expenses during the 2010 portion of the Test Year. ETI has proposed a five-year amortization of this amount ($52,800 per year), assuming either its primary proposal or its alternative proposal is adopted. However, if ETI’s primary and alternative proposals are both rejected, ETI requested that no reduction be made to its total Test Year amount of $916,535.1055

Cities, TIEC, State Agencies, and Staff opposed ETI’s requests. They argue that ETI failed to establish that the proposed deferred accounting is necessary to carry out a provision of PURA, as required by the Commission’s Preliminary Order. They also contended that ETI’s alternate request to include $4 million in base rates is not a known and measureable change and should be disallowed.

The ALJs recommend that the Commission deny ETI’s request for deferred accounting of its MISO transition expenses to be incurred on or after January 1, 2011. However, the ALJs do recommend that the Commission authorize ETI to include $2.4 million of MISO transition expense in base rates set in the present case, based on a five-year amortization of $12 million in total projected expenses.

1055 ETI Ex. 42 (Lewis Supplemental Direct) at 4 and Adjustment No. 16.L.

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1. Deferred Accounting In support of its deferred accounting request, ETI cited State v. Public Utility Comm’n of Texas.1056 In that case, the Texas Supreme Court stated that a deferred accounting is “necessary” when it will “ensure that the requirements of [PURA] are met.”1057 In ETI’s opinion, deferred accounting is necessary in the present case to ensure that PURA §§ 36.051 and 36.003(a) are met (i.e., that utilities have a reasonable opportunity to recover their expenses and receive reasonable rates). ETI also relied on Hammack v. Public Utility Commission of Texas, which stated that “a need . . . is a relative requirement, ranging from an imperative need to one that is minimal . . . .”1058

ETI-witness Brett Perlman testified that deferred accounting is also necessary to ensure the requirements of PURA § 31.001(c) are carried out.1059 That section encourages development of a competitive wholesale electric market. ETI noted that the Hammack opinion stated that Section 31.001(c) amounts to a “legislative directive that the Commission formulate policies responsive to the needs of the emerging competitive wholesale market.”1060 Therefore, ETI asserted that RTO membership and deferred accounting are necessary because they will ensure that the Commission meets its obligation under Section 31.001(c). More specifically, ETI stated, both RTO membership and deferred accounting itself constitute examples of policies required by section 31.001(c) to support wholesale competition. Therefore, ETI argues that its request for deferred accounting should be approved because it is necessary to carry out PURA §§ 36.051, 36.003, and 31.001(c).1061

Cities argue that ETI’s request for deferred accounting of MISO transition expenses should be denied because deferred accounting is not necessary to carry out any requirement of PURA.

1056 883 S.W.2d 190 (Tex. 1994).

1057 883 S.W.2d at 194.

1058 Hammack v. Pub. Util. Comm’n of Texas, 131 S.W.3d 713, 723-24 (Tex. App.—Austin 2004, pet. denied).

1059 ETI Ex. 43 (Perlman Supplemental Direct) at 7.

1060 131 S.W.3d at 723.

1061 ETI’s Initial Brief at 231-234; ETI Ex. 42 (Lewis Supplemental Direct) at 2-4; ETI Ex. 43 (Perlman Supplemental Direct) at 5-7.

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Cities witness James Brazell stated that ETI’s proposed transition to MISO is not mandatory, and the anticipated expenses are not extraordinary. He added that ETI has been exploring membership in an RTO for over ten years and those costs have historically been included in ETI’s base rates; therefore, he concluded that deferred accounting was not necessary in the past and is not necessary now. Cities stressed that ETI conceded that deferred accounting of these expenses is not necessary to maintain its financial integrity, and in Cities’ opinion, both State v. Public Utility Comm’n of Texas,1062 and the Commission’s Preliminary Order require a showing of impairment of financial integrity to conclude that deferred accounting is necessary to comply with PURA § 36.051. Cities also stated that ETI failed to show that deferred accounting is necessary to comply with PURA §§ 36.003 and 31.001(c); therefore, Cities argues that ETI’s request for deferred accounting should be denied.

TIEC also opposed ETI’s request for deferred accounting, arguing that ETI failed to demonstrate that it is necessary to carry out PURA §§ 36.051, 36.003, or 31.001(c). TIEC witness Jeffry Pollock stated there is no indication that deferred accounting treatment is necessary for ETI to earn a reasonable return on its invested capital or that denying the deferred accounting would prevent ETI from having just and reasonable rates. Further, Mr. Pollock asserted there is no evidence that a lack of deferred accounting treatment for ETI would prevent Entergy from pursuing its MISO proposal.1063 Mr. Pollock added that ETI has incurred other similar costs to carry out various purposes of PURA without deferred accounting. For example, since 2005, ETI has spent nearly $20 million pursuing various similar activities, including transitioning to competition, investigating RTO options, examining changes to the Entergy System Agreement, and supporting the Entergy OATT. Yet, ETI did not seek deferred accounting for any of those costs. Finally, Mr. Pollock testified that the projected transition costs are not material. He noted that ETI expects to incur $17 million of transition costs.1064 This equates to $5.8 million per year, which is only percent of ETI’s Test Year operating revenues, according to Mr. Pollock. In his opinion, this level

1062 883 S.W.2d 190 (Tex. 1994).

1063 TIEC Ex. 1 (Pollock Direct) at 46-47.

1064 ETI Ex. 42 (Lewis Supplemental Direct) at 5.

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of MISO transition costs is easily subsumed in the normal variation in ETI’s year-to-year expenses.1065

TIEC also disagreed with ETI’s interpretation of State v. Public Utility Comm’n of Texas.1066 In TIEC’s view, that case held that deferred accounting is necessary only when needed to protect the financial integrity of the utility. Likewise, TIEC disagreed with ETI’s argument that Hammack1067 held that “need” is a relative requirement that must be viewed in light of legislative policy directives.1068 TIEC noted that Hammack had nothing to do with deferred accounting.

Instead, it was limited to the issue of whether, in granting a certificate of convenience and necessity for a transmission line under PURA §37.056, the Commission should include evidence that considered customers and market participants throughout the state.1069 In TIEC’s view, the Hammack case is irrelevant in determining whether deferred accounting is necessary to carry out the provisions of PURA §§ 36.003, 36.051, and 31.003(c). State Agencies made similar arguments.

Commission Staff also argues that ETI did not establish why deferred accounting is necessary to carry out a provision of PURA. In Staff’s view, the applicable court cases and other precedent required ETI to show that deferred accounting is necessary to maintain its financial integrity, in order to carry out the provisions of PURA § 36.051. Staff argues that the Commission’s Preliminary Order did not reject the financial integrity standard when it stated: “[t]his standard is not appropriate, however, for all circumstances and the Commission has applied different standards in various circumstances.”1070 Rather, Staff stated, the Commission merely declined to designate a specific standard.

1065 ETI Ex. 1 (Pollock Direct) at 48-49 and Ex. JP-8.

1066 883 S.W.2d 190 (Tex. 1994).

1067 Hammack v. Pub. Util. Comm’n of Texas, 131 S.W.3d 713, 723-24 (Tex. App.—Austin 2004, pet. denied).

1068 ETI Initial Brief at 232-233.

1069 Hammack v. Pub. Util. Comm’n of Texas, 131 S.W.3d 713, 724 (Tex .App.−Austin 2004, pet. denied).

1070 Application of Entergy Texas, Inc. for Authority to Defer Expenses Related to its Proposed Transition to Membership in The Midwest Independent Transmission System Operator, Docket No. 39741 Preliminary Order at 9 (Sep. 2, 2011).

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Staff also rejected ETI’s argument that deferred accounting will “ensure that the Commission meets its obligation under Section 31.001(c) to support the achievement of a competitive wholesale market.”1071 First, Staff noted, the Commission stated in the Preliminary Order that merely showing movement towards a policy goal is not a sufficient standard upon which to approve deferral.1072 Thus, ETI’s statement that deferred accounting will “support” wholesale competition addresses a standard that the Commission already rejected. Second, Staff argues that ETI failed establish that deferred accounting is “necessary” to support a competitive wholesale market or that failure to allow deferred accounting would prevent that goal. In other words, ETI did not show that, absent deferral, it would not join MISO; thus, ETI did not show how deferral would “ensure” that it joins an RTO.

Therefore, Staff concluded, because ETI failed to prove that deferred accounting is necessary to carry out any provision of PURA, ETI’s request should be denied.

In response to these arguments, ETI noted that no party disputed that the Commission may grant deferred accounting “when it is necessary to carry out a provision of PURA.” It also argues that Staff and intervenors misinterpreted State v. Public Utility Comm’n of Texas1073 as holding that deferred accounting is necessary to carry out PURA § 36.051 only when a utility’s financial integrity is at stake. Although lack of financial integrity is an indication that PURA § 36.051 has not been carried out, ETI noted that this section contains other express requirements that can be met through deferred accounting, such as ensuring utilities a reasonable opportunity to recover their costs. ETI also cited other Commission cases in which it authorized deferred accounting when financial integrity was not at stake, such as deferral of rate case expenses and merger costs for subsequent review and recovery.1074 ETI added that deferred accounting would permit the Commission to review ETI’s transition expenses in a subsequent proceeding, after determining whether ETI’s transition to MISO is in the public interest. Thus, under ETI’s proposal, there is no risk that ETI would recover such costs absent a finding that they are reasonable and necessary.

1071 ETI Initial Brief at 234.

1072 Docket No. 39741, Preliminary Order at 11.

1073 883 S.W.2d 190 (Tex. 1994).

1074 ETI Reply Brief at 95-96.

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As for Staff and TIEC’s argument that deferred accounting is not necessary to carry out PURA § 31.001(c), ETI argues that the “necessary” standard is not a “but for” test. In response to arguments that the proposed deferred accounting will merely further policy objectives of Section 31.001(c), which the Commission has deemed insufficient to meet the “necessary” standard,1075 ETI reiterated that the Hammack opinion held that “the Commission’s interpretation of need must be viewed in light of the legislative directive that the Commission formulate policies responsive to the needs of the emerging competitive wholesale market,” as well as “overall policy objectives.”1076 Thus, ETI argues, that it has demonstrated that deferred accounting is necessary to carry out Section 31.001(c) – i.e., it will “ensure” that the requirements of that provision are carried out, and in particular ensure that the Legislature’s specific instruction to develop the wholesale market is carried out.1077

Although ETI’s proposal for deferred accounting has some practical appeal, the ALJs conclude that ETI has not shown that it is necessary to carry out a provision of PURA. The ALJs find that ETI was not required to show that a deferred accounting is necessary to maintain its financial integrity, as argued by intervenors. In State v. Public Utility Comm’n of Texas,1078 the Texas Supreme Court held that preserving the financial integrity of a utility was necessary to carry out a provision of PURA, and thus justified deferred accounting for certain expenses in that case, but the court did not hold that preserving financial integrity was the sole basis upon which a deferred accounting could be approved. Likewise, in its Preliminary Order for the present case, the Commission stated: “This standard [financial integrity] is not appropriate, however, for all circumstances and the Commission has applied different standards in various circumstances, although none of these standards or circumstances has been reviewed by any court.”1079 On the other hand, the ALJs also find that ETI’s contention that deferred accounting of the MISO transition expenses will help the development of a competitive wholesale electric market, as described in

1075 Docket No. 39741, Preliminary Order at 7.

1076 Hammack v. Pub. Util. Comm’n of Texas, 131 S.W.3d 713, 723-24 (Tex. App.—Austin 2004, pet. denied).

1077 ETI Reply Brief at 97-99.

1078 883 S.W.2d 190 (Tex. 1994).

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PURA § 31.001(c), is not sufficient to authorize deferred accounting. Again, the Commission stated in the Preliminary Order that “to carry out a provision of PURA” means more than undefined progress or movement towards a statutory objective.1080

The Commission made clear that ETI’s burden was not only to show that a provision of PURA would be carried out by an accounting deferral of the MISO transition expenses, but that the deferral is necessary to carry out that provision. The Commission added that necessity was a question of fact that “can only be determined after development of an adequate factual record that demonstrates the necessity, of whatever degree.”1081 Intervenors argue that Entergy’s efforts to transfer operational control of the Entergy Operating Companies’ transmission assets to MISO will proceed with or without the deferred accounting requested by ETI; thus, deferred accounting is not necessary. Likewise, intervenors argue that ETI’s alternate proposal to recover the transition costs through base rates shows that deferred accounting is not necessary. ETI, however, asserted that necessity should not be considered a “but for” requirement. It noted that no provision of PURA would be impossible to carry out absent a deferral of rate case expenses or merger expenses, yet the Commission has allowed deferred accounting of such expenses in other cases. ETI also cited the statement in Hammack v. Public Utility Commission of Texas that “a need . . . is a relative requirement, ranging from an imperative need to one that is minimal . . . .”1082 Intervenors criticized ETI’s reliance on the Hammack case because it concerned a transmission line. While that is correct, the case does make the general point that the question of need is not an absolute “but for” test. This is also consistent with the Commission’s statement in the Preliminary Order that ETI’s burden was to demonstrate necessity, “of whatever degree.”

ETI’s complaint is that its MISO transition expenses will soon increase above the Test Year amount, from $916,535 for the Test Year to over $5 million per year, but it will not be able to recover the increased costs through normal Test Year cost-of-service ratemaking principles. Thus, 1079 Docket No. 39741, Preliminary Order at 9 (Nov. 22, 2011).

1080 Id. at 11.

1081 Id. at 8.

1082 Hammack v. Pub. Util. Comm’n of Texas, 131 S.W.3d 713, 723-24 (Tex. App.—Austin 2004, pet. denied).

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although ETI’s financial integrity may not be jeopardized, ETI argues that it nevertheless will not be able to have a reasonable opportunity to recover its expenses and receive reasonable rates as required by PURA §§ 36.051 and 36.003(a). Therefore, ETI believes the proposed deferred accounting is necessary to carry out those provisions of PURA.

The ALJs find that the essence of ETI’s complaint is that regulatory lag works against it in this particular situation. But as noted by the court in State v. Public Utility Comm’n of Texas, regulatory lag is an ordinary element of risk for utilities.1083 One of the characteristics of Test Year cost-of-service ratemaking is that some expenses upon which rates are based may go up and others may go down during the time the rates are in effect. Such changes can be corrected in future ratemaking proceedings, but in this case ETI desires to ensure that it will recover all of its MISO transition costs. But State v. Public Utility Comm’n of Texas and the Commission’s Preliminary Order in this case make clear that eliminating the normal effects of regulatory lag by allowing a deferred accounting should not be undertaken lightly. If ETI’s arguments were taken to their extreme, a utility could obtain deferred accounting any time it anticipated a post Test Year increase in a particular expense, under the argument that it must be allowed to recover all of its expenses to carry out the requirements of PURA §§ 36.051 and 36.003(a). In this case, ETI’s estimated MISO transition costs will equal about $5.8 million per year. As Mr. Pollock noted, this is only one percent of ETI’s Test Year operating revenues, which may easily be subsumed in the normal variation in ETI’s year-to-year expenses. Under these circumstances, ETI has not shown that granting its requested deferred accounting is necessary to carry out the requirements of PURA §§ 36.051 and 36.003(a) that it receive just and reasonable rates. Therefore, the ALJs recommend that the Commission deny ETI’s request for deferred accounting treatment of its MISO transition expenses to be incurred on or after January 1, 2011.

1083 883 S.W.2d 190, 196 (Tex. 1994).

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2. Base Rate Recovery As mentioned above, if the Commission denies ETI’s request for deferred accounting, ETI requested the Commission to include $4 million of MISO transition expense in base rates set in the present case, based on a three-year amortization of $12 million in total projected expenses.

Cities disputed the amount of MISO expenses ETI requested in this proposal. Cities witness Mark Garrett testified that a $4 million annual expense is inconsistent with ETI’s own projected costs. The Test Year expenses were $916,535, and the actual expenses incurred during January through November 2011 were only $2.513 million, which annualized would be $2.742 million..

For 2013, ETI projected MISO transition expenses of only $2.587 million, although ETI’s projected 2012 level of $8.9 million. However, Mr. Garrett added that 2012 is an estimated level and is not consistent with actual 2011 results. In his opinion, the actual 2011 level of about $2.7 million or the expected 2013 level of about $2.6 million should be the outside range of what the Commission should use for setting prospective rates. In any event, however, Cities argue that these projected levels are not sufficiently known and measurable to include for ratemaking purposes.

Cities pointed out that it is unknown whether ETI’s proposed move to MISO will even be approved, or whether the ETI will even continue to incur costs toward a MISO transition. Therefore, Cities argues that only the Test Year level of $916,535 should be included in rates, which would result in a downward adjustment of $3,083,462 to ETI’s request.1084

TIEC also argues that ETI’s alternative proposal should be rejected. Mr. Pollock complained that this proposal would allow ETI to recover post Test Year expenses that are not known and measureable. Mr. Pollock noted that ETI’s own estimate of its share of transition costs has changed.

When ETI filed its request for deferred accounting in Docket No. 39741, it estimated transition costs of $12 million. Now it estimates costs of $17 million, an increase of over 40 percent. Further, Mr. Pollock stated, ETI based its share of the estimated transition costs by assuming a 17 percent responsibility ratio, but ETI’s future responsibility ratios are not known because they are based on projected growth rates of ETI relative other Entergy Operating Companies. Thus, Mr. Pollock 1084 Cities Ex. 2 (Garrett Direct) at 61-63 and Ex. MG2.14; Cities Initial Brief at 89-91; Cities Reply Brief at 112-113.

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concluded that ETI’s share of future MISO transition costs cannot be appropriately measured.1085 In summary, TIEC argues that the Commission should deny ETI’s request for deferred accounting and should allow ETI to recover only Test Year MISO transition expenses.1086 Commission Staff made arguments similar to Cities and TIEC.1087

In response, ETI argues that the $4 million annual expense requested is known and measurable. ETI noted that it already incurred over $3.6 million in transition expense in the nine months since the end of the Test Year,1088 which equates to $4.8 million on an annual basis.

Furthermore, ETI’s expects $17 million in transition expenses to be incurred over three years, which equates to $5.8 million annually.1089 In ETI’s view, the issue is whether it is sufficiently known that ETI will incur at least $12 million in transition expense, not whether ETI can predict an exact level of future expense.1090

The ALJs recommend that the Commission authorize ETI to include $2.4 million in base rates set in the present case for MISO transition expense incurred on or after January 2, 2011, based on a five-year amortization of $12 million in total projected expenses. The primary argument of intervenors against the adjustment is that the total of $12 million is not a known and measurable change. However, the ALJs find that ETI’s evidence established that such expenses will total at least $12 million. It is true that the Test Year expenses were less, but ETI filed its application to effectuate the transfer to MISO in 2012, so it is clear that those expenses will increase significantly to levels well above the Test Year amount. It is true that ETI has not established the precise total amount of MISO transition expenses it will incur, but the ALJs find that those expenses will likely exceed the $12 million included in ETI’s request. ETI requested that the $12 million total be amortized over three years, which would produce a $4 million annual cost. However, ETI also

1085 TIEC Ex. 1 (Pollock Direct) at 49-50.

1086 TIEC Initial Brief at 97-98; TIEC Reply Brief at 70-71.

1087 Staff Reply Brief at 65-66.

1088 ETI Ex. 46 (Considine Rebuttal), Ex. MPC-R-1.

1089 TIEC Ex. 1 (Pollock Direct) at 48:3-4.

1090 ETI Initial Brief at 236-239; ETI Reply Brief at 99-100.

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requested to amortize over five years its $263,908 in MISO transition expenses that were incurred during the 2010 portion of the Test Year ($52,800 per year). If a five-year amortization is appropriate for those expenses, a five-year amortization would also be appropriate for the post Test Year MISO transition expenses. Therefore, the ALJs recommend that the Commission authorize ETI to include in base rates $52,800 in MISO transition expenses for the 2010 portion of the Test Year expenses, plus $2.4 million for the post Test Year adjustment, for a total of $2,452,800.

B. TCRF Baseline [Germane to Supplemental Preliminary Order Issue No. 2] In its Supplemental Preliminary Order, the Commission found that it would be appropriate to establish for ETI baseline values for a TCRF and a DCRF, which may be established in future dockets. ETI’s filing package included worksheets for these baseline values,1091 and ETI attached revised versions of the worksheets to its initial brief to reflect ETI’s revised depreciation calculations. The revised version of the transmission worksheet calculated total transmission cost baseline revenue requirements of $75,074,987-Total Company and $74,997,366-Retail.1092 However, ETI acknowledged that these values may change, depending on the rulings in this case. If the Commission makes other changes to ETI’s requested costs, ETI proposes filing another revised TCRF baseline value calculation in the compliance phase of this case, to reflect the final decisions of the Commission.1093 TIEC, Cities, and Staff also point out that various items in ETI’s calculation have been contested. Therefore, they also recommend that the baseline values be set during the compliance phase of this case. The ALJs agree that TCRF baseline values should be set during the compliance phase of this docket, after the Commission makes final rulings on the various contested issues that may affect this calculation.

C. DCRF Baseline [Germane to Supplemental Preliminary Order Issue No. 2] As discussed above, the Commission found in its Supplemental Preliminary Order that it would be appropriate to establish for ETI baseline values for a DCRF, which may be established in a 1091 ETI Ex. 31 (LeBlanc Direct) at Ex. HGL-5 and HGL-6.

1092 ETI Initial Brief at 239 and Attachment 1.

1093 ETI Initial Brief at 239.

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future docket. ETI’s filing package included worksheets for a DCRF baseline value,1094 and ETI attached a revised version of the worksheet to its initial brief to reflect ETI’s revised depreciation calculations. The revised version of the distribution worksheet calculated total distribution cost baseline revenue requirements of $163,560,232-Total Company and $161,537,490-Retail.1095 However, ETI acknowledged that these values may change, depending on the rulings in this case. If the Commission makes other changes to ETI’s requested costs, ETI proposes filing another revised DCRF baseline value calculation in the compliance phase of this case, to reflect the final decisions of the Commission.1096 TIEC, Cities, and Staff also recommend that the baseline values be set during the compliance phase of this case. The ALJs agree that DCRF baseline values should be set during the compliance phase of this docket, after the Commission makes final rulings on the various contested issues that may affect this calculation.

D. Purchased Power Capacity Cost Baseline [Germane to Supplemental Preliminary Order Issue No. 1] ETI requested a PPR rider in its application, but the Commission held in its Supplemental Preliminary Order that the proposed rider should not be considered due to the pending rulemaking Project No. 39246, which was opened to consider purchased capacity riders. However, the Commission did add the following issue to the present case: “What is the amount of purchased- capacity costs that are proposed to be included in Entergy’s base rates?” ETI requested authority to include $275,809,485 in its PPR rider, but because the Commission excluded the PPR rider from consideration, this amount would now be included in base rates. ETI acknowledged that this amount should be revised to correspond with the Commission’s final decision on purchased power capacity recovery (See Section VII.A.). 1097

State Agencies noted that ETI’s purchased power request included the following:

1094 ETI Ex. 31 (LeBlanc Direct) at Ex. HGL-5 and HGL-6.

1095 ETI Initial Brief at 239 and Attachment 2.

1096 ETI Initial Brief at 239.

1097 ETI Initial Brief at 240.

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1. Third-party contracts; 2. Legacy affiliate contracts; 3. Other affiliate contracts; and 4. Reserve Equalization.

The costs for all of these but third-party contracts are determined through various MSS Schedules in the FERC-approved Entergy System Agreement. Therefore, State Agencies argue that if the Commission decides to allow purchased capacity cost recovery riders in Project No. 39246, the baseline costs for ETI should be limited to only the purchased capacity costs associated with non-affiliate third-party contracts. In State Agencies’ opinion, ETI should not be allowed to pass through purchased capacity costs associated with legacy and other affiliate contracts or reserve equalization purchases, because those are not market competitive contracts. Instead, according to State Agencies, the affiliate contracts and reserve equalization purchases are essentially agreements to share centralized planned generation capacity resources among Entergy Operating Companies and to allocate generation costs among those companies. State Agencies also noted that these capacity payments are determined based on formulae in Service Schedules MSS-1 and MSS-4, included in the FERC-approved Entergy System Agreement. In other words, these costs are not driven by market prices and are not subject to market price volatility. Therefore, State Agencies argue that purchases other than third-party contracts should not be used as a baseline for any rider intended to address market price volatility and competitive wholesale market pressure for purchased generation capacities.1098

Cities agree with the arguments of State Agencies. In addition, Cities stressed that if the Commission establishes a baseline for purchased power capacity costs, the baseline should reflect the unit cost of capacity rather than total dollars. Cities witness Nalepa testified that the unit cost would provide a more accurate measure than total dollars. In Cities’ opinion, if a unit cost finding is not made in this case, then Commission will be prevented from considering all options in the rulemaking.

1098 State Agencies Ex. 2 (Pevoto Direct) at 17.

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TIEC points out that the notice in Project No. 39246 provided that “[t]he purpose of this rulemaking project is to address the recovery of purchased power capacity costs considering generation embedded in base rates, load growth, and the impact of purchased power capacity recovery on the financial standing of the utility.”1099 Accordingly, TIEC argues that the baseline set in this proceeding should reflect ETI’s total purchased power and installed capacity costs determined to be properly included in base rates on a total cost basis and on a per unit ($/MW) basis.1100

As discussed in Section VII.A., the ALJs find that the appropriate amount for ETI’s purchased power capacity expense to be included in base rates is $245,432,884. This responds to the issue included in the Commission’s Supplemental Preliminary Order. This amount includes third- party contracts, legacy affiliate contracts; other affiliate contracts; and reserve equalization.

Whether the amounts for all contracts should be included in the baseline for a purchased capacity rider that may be approved in Project No. 39246 is an issue that should be decided in that proceeding, not in the present case. Therefore, the ALJs make no recommendation on that issue raised by the intervenors.

XIII. CONCLUSION The ALJs recommend that the Commission implement the findings of the ALJs set forth in the discussion above by adopting the following proposed findings of fact and conclusions of law in the Commission’s final order.

XIV. PROPOSED FINDINGS OF FACT, CONCLUSIONS OF LAW, AND ORDERING PARAGRAPHS A. Findings of Fact Procedural History 1. Entergy Texas, Inc. (ETI or the Company) is an investor-owned electric utility with a retail service area located in southeastern Texas.

1099 Project No. 39246, Public Notice (May 10, 2011).

1100 TIEC Initial Brief at 99.

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2. ETI serves retail and wholesale electric customers in Texas. As of June 30, 2011, ETI served approximately 412,000 Texas retail customers. The Federal Energy Regulatory Commission (FERC) regulates ETI’s wholesale electric operations.

3. On November 28, 2011, ETI filed an application requesting approval of: (1) a proposed increase in annual base rate revenues of approximately $111.8 million over adjusted test year revenues; (2) a set of proposed tariff schedules presented in the Electric Utility Rate Filing Package for Generating Utilities (RFP) accompanying ETI’s application and including new riders for recovery of costs related to purchased power capacity and renewable energy credit requirements; (3) a request for final reconciliation of ETI’s fuel and purchased power costs for the reconciliation period from July 1, 2009 to June 30, 2011; and (4) certain waivers to the instructions in RFP Schedule V accompanying ETI’s application.

4. The 12-month test year employed in ETI’s filing ended on June 30, 2011 (Test Year).

5. ETI provided notice by publication for four consecutive weeks before the effective date of the proposed rate change in newspapers having general circulation in each county of ETI’s Texas service territory. ETI also mailed notice of its proposed rate change to all of its customers. Additionally, ETI timely served notice of its statement of intent to change rates on all municipalities retaining original jurisdiction over its rates and services.

6. The following parties were granted intervenor status in this docket: Office of Public Utility Counsel (OPC); the cities of Anahuac, Beaumont, Bridge City, Cleveland, Conroe, Dayton, Groves, Houston, Huntsville, Montgomery, Navasota, Nederland, Oak Ridge North, Orange, Pine Forest, Rose City, Pinehurst, Port Arthur, Port Neches, Shenandoah, Silsbee, Sour Lake, Splendora, Vidor, and West Orange (Cities), the Kroger Co. (Kroger); State Agencies (State Agencies); Texas Industrial Energy Consumers (TIEC); East Texas Electric Cooperative, Inc. (ETEC); the United States Department of Energy (DOE); and Wal-Mart Stores Texas, LLC, and Sam’s East, Inc. (Wal Mart). The Staff (Staff) of the Public Utility Commission of Texas (Commission or PUC) was also a participant in this docket.

7. On November 29, 2011, the Commission referred this case to the State Office of Administrative Hearings (SOAH).

8. On December 7, 2011, the Commission issued its order requesting briefing on threshold legal/policy issues.

9. On December 19, 2011, the Commission issued its Preliminary Order, identifying 31 issues to be addressed in this proceeding.

10. On December 20, 2011, the Administrative Law Judges (ALJs) issued SOAH Order No. 2, which approved an agreement among the parties to establish a June 30, 2012 effective date for the Company’s new rates resulting from this case pursuant to certain agreed language and consolidate Application of Entergy Texas, Inc. for Authority to Defer Expenses Related to its Proposed Transition to Membership in the Midwest Independent System Operator, Docket SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 343 PUC DOCKET NO. 39896

No. 39741 (pending) into this proceeding. Although it did not agree, Staff did not oppose the consolidation.

11. On January 13, 2012, the ALJs issued SOAH Order No. 4 granting the motions for admission pro hac vice filed by Kurt J. Boehm and Jody M. Kyler to appear and participate as counsel for Kroger and the motion for admission pro hac vice filed by Rick D.

Chamberlain to appear and participate as counsel for Wal-Mart.

12. On January 19, 2012, the Commission issued a Supplemental Preliminary Order identifying two additional issues to be addressed in this case and concluding that the Company’s proposed purchased power capacity rider should not be addressed in this case and that such costs should be recovered through base rates.

13. ETI timely filed with the Commission petitions for review of the rate ordinances of the municipalities exercising original jurisdiction within its service territory. All such appeals were consolidated for determination in this proceeding.

14. On April 4, 2012, the ALJs issued SOAH Order No. 13 severing rate case expense issues into Application of Entergy Texas, Inc. for Rate Case Expenses Severed from PUC Docket No. 39896, Docket No. 40295 (pending).

15. On April 13, 2012, ETI adjusted its request for a proposed increase in annual base rate revenues to approximately $104.8 million over adjusted Test Year revenues.

16. The hearing on the merits commenced on April 24 and concluded on May 4, 2012.

17. Initial post-hearing briefs were filed on May 18 and reply briefs were filed on May 30, 2012.

Rate Base 18. Capital additions that were closed to ETI’s plant-in-service between July 1, 2009, and June 30, 2011, are used and useful in providing service to the public and were prudently incurred.

19. ETI’s proposed Hurricane Rita regulatory asset was an issue resolved by the black-box settlement in Application of Entergy Texas, Inc. for Authority to Change Rates and Reconcile Fuel Costs, Docket No. 37744 (Dec. 13, 2010).

20. Accrual of carrying charges on the Hurricane Rita regulatory asset should have ceased when Docket No. 37744 concluded because the asset would have then begun earning a rate of return as part of rate base.

21. The appropriate calculation of the Hurricane Rita regulatory asset should begin with the amount claimed by ETI in Docket No. 37744, less amortization accruals to the end of the Test Year in the present case, and less the amount of additional insurance proceeds received by ETI after the conclusion of Docket No. 37744.

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22. A Test-Year-end balance of $15,175,563 for the Hurricane Rita regulatory asset should remain in rate base, applying a five-year amortization rate beginning August 15, 2010.

23. The Hurricane Rita regulatory asset should not be moved to the storm damage insurance reserve.

24. The Company requested in rate base its Prepaid Pension Assets Balance of $55,973,545, which represents the accumulated difference between the Statement of Financial Accounting Standards (SFAS) No. 87 calculated pension costs each year and the actual contributions made by the Company to the pension fund.

25. The Prepaid Pension Assets Balance includes $25,311,236 capitalized to construction work in progress (CWIP).

26. It is not necessary to the financial integrity of ETI to include CWIP in rate base, and there was insufficient evidence showing that major projects under construction were efficiently and prudently managed.

27. The portion of the Prepaid Pension Assets Balance that is capitalized to CWIP should not be included in ETI’s rate base.

28. The remainder of the Prepaid Pension Assets Balance should be included in ETI’s rate base.

29. ETI should be permitted to accrue an allowance for funds used during construction on the portion of ETI’s Prepaid Pension Assets Balance capitalized to CWIP.

30. The Financial Accounting Standard Board (FASB) Financial Interpretation No. 48 (FIN 48), “Accounting for Uncertainty in Income Taxes,” requires ETI to identify each of its uncertain tax positions by evaluating the tax position on its technical merits to determine whether the position, and the corresponding deduction, is more-likely-than-not to be sustained by the Internal Revenue Service (IRS) if audited.

31. FIN 48 requires ETI to remove the amount of its uncertain tax positions from its Accumulated Deferred Federal Income Tax (ADFIT) balance for financial reporting purposes and record it as a potential liability with interest to better reflect the Company’s financial condition.

32. At Test Year-end, ETI had $5,916,461 in FIN 48 liabilities, meaning ETI has, thus far, avoided paying to the IRS $5,916,461 in tax dollars (the FIN 48 Liability) in reliance upon tax positions that the Company believes will not prevail in the event the positions are challenged, via an audit, by the IRS.

33. ETI has deposited $1,294,683 with the IRS in connection with the FIN 48 Liability.

34. The IRS may never audit ETI as to its uncertain tax positions creating the FIN 48 Liability.

35. Even if ETI is audited, ETI might prevail on its uncertain tax positions.

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36. ETI may never have to pay the IRS the FIN 48 Liability.

37. Other than the amount of its deposit with the IRS, ETI has current use of the FIN 48 Liability funds.

38. Until actually paid to the IRS, the FIN 48 Liability represents cost-free capital and should be deducted from rate base.

39. The amount of $4,621,778 (representing ETI’s full FIN 48 Liability of $5,916,461 less the $1,294,683 cash deposit ETI has made with the IRS for the FIN 48 Liability) should be added to ETI’s ADFIT and thus be used to reduce ETI’s rate base.

40. ETI’s application and proposed tariffs do not include a request for a tracking mechanism or rider to collect a return on the FIN 48 Liability.

41. ETI has not proven that a tracking mechanism or rider to collect a return on FIN 48 Liability is necessary.

42. Investor-owned electric utilities may include a reasonable allowance for cash working capital in rate base as determined by a lead-lag study conducted in accordance with the Commission’s rules.

43. Cash working capital represents the amount of working capital, not specifically addressed in other rate base items, that is necessary to fund the gap between the time expenditures are made and the time corresponding revenues are received.

44. The lead-lag study conducted by ETI considered the actual operations of ETI, adjusted for known and measurable changes, and is consistent with P.U.C. SUBST.

R. 25.231(c)(2)(B)(iii).

45. It is reasonable to establish ETI’s cash working capital requirement based on ETI’s lead-lag study as updated in Jay Joyce’s rebuttal testimony and on the cost of service approved for ETI in this case.

46. As a result of the black-box settlements in Application of Entergy Gulf States, Inc. for Authority to Change Rates and to Reconcile Fuel Costs, Docket No. 34800 (Nov. 7, 2008) and Docket No. 37744, the Commission did not approve ETI’s storm damage expenses since 1996 and its storm damage reserve balance.

47. ETI established a prima facie case concerning the prudence of its storm damage expenses incurred since 1996.

48. Adjustments to the storm damage reserve balance proposed by intervenors should be denied.

49. The Hurricane Rita regulatory asset should not be moved to the storm damage insurance reserve.

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50. ETI’s appropriate Test-Year-end storm reserve balance was negative $59,799,744.

51. The amount of $9,846,037, representing the value of the average coal inventory maintained at ETI’s coal-burning facilities, is reasonable, necessary, and should be included in rate base.

52. The Spindletop gas storage facility (Spindletop Facility) is used and useful in providing reliable and flexible natural gas supplies to ETI’s Sabine Station and Lewis Creek generating plants.

53. The Spindletop Facility is critical to the economic, reliable operation of the Sabine Station and Lewis Creek generating plants due to their geographic location in the far western region of the Entergy system.

54. It is reasonable and appropriate to include ETI’s share of the costs to operate the Spindletop Facility in rate base.

55. Staff recommended updating ETI’s balance amounts for short-term assets to the 13-month period ending December 2011, which was the most recent information available. Staff’s proposed adjustments should be incorporated into the calculation of ETI’s rate base.

56. The following short-term asset amounts should be included in rate base: prepayments at $8,134,351; materials and supplies at $29,285,421; and fuel inventory at $52,693,485.

57. The amount of $1,127,778, representing costs incurred by ETI when it acquired the Spindletop facility, represent actual costs incurred to process and close the acquisition, not mere mark-up costs.

58. ETI’s $1,127,778 in capitalized acquisition costs should be included in rate base because ETI incurred these costs in conjunction with the purchase of a viable asset that benefits its retail customers.

59. In its application, ETI capitalized into plant in service accounts some of the incentive payments ETI made to its employees. ETI seeks to include those amounts in rate base.

60. A portion of those capitalized incentive accounts represent payments made by ETI for incentive compensation tied to financial goals.

61. The portion of ETI’s incentive payments that are capitalized and that are financially-based should be excluded from ETI’s rate base because the benefits of such payments inure most immediately and predominantly to ETI’s shareholders, rather than its electric customers.

62. The Test Year for ETI’s prior ratemaking proceeding ended on June 30, 2009, and the reasonableness of ETI’s capital costs (including capitalized incentive compensation) for that prior period was dealt with by the Commission in that proceeding and is not at issue in this proceeding.

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63. In this proceeding, ETI’s capitalized incentive compensation that is financially-based should be excluded from rate base, but only for incentive costs that ETI capitalized during the period from July 1, 2009 (the end of the prior Test Year) through June 30, 2010 (the commencement of the current Test Year).

Rate of Return and Cost of Capital 64. A return on common equity (ROE) of 9.80 percent will allow ETI a reasonable opportunity to earn a reasonable return on its invested capital.

65. The results of the discounted cash flow model and risk premium approach support a ROE of 9.80 percent.

66. A 9.80 percent ROE is consistent with ETI’s business and regulatory risk.

67. ETI’s proposed 6.74 percent embedded cost of debt is reasonable.

68. The appropriate capital structure for ETI is 50.08 percent long-term debt and 49.92 percent common equity.

69. A capital structure composed of 50.08 percent debt and 49.92 percent equity is reasonable in light of ETI’s business and regulatory risks.

70. A capital structure composed of 50.08 percent debt and 49.92 percent equity will help ETI attract capital from investors.

71. ETI’s overall rate of return should be set as follows: CAPITAL WEIGHTED AVG COMPONENT STRUCTURE COST OF CAPITAL COST OF CAPITAL LONG-TERM DEBT 50.08% 6.74% 3.38% COMMON EQUITY 49.92% 9.80% 4.89% TOTAL 100.00% 8.27% Operating Expenses

72. ETI’s Test Year purchased capacity expenses were $245,432,884.

73. ETI requested an upward adjustment of $30,809,355 as a post-Test Year adjustment to its purchased capacity costs. This request was based on ETI’s projections of its purchased capacity expenses during a period beginning June 1, 2012 and ending May 31, 2013 (the Rate Year).

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74. ETI’s purchased capacity expense projections were based on estimates of Rate Year expenses for: (a) reserve equalization payments under Schedule MSS-1; (b) payments under third-party capacity contracts; and (c) payments under affiliate contracts.

75. ETI’s projection of its Rate Year reserve equalization payments under Schedule MSS-1 is based on numerous assumptions, including load growths for ETI and its affiliates, future capacity contracts for ETI and its affiliates, and future values of the generation assets of ETI and its affiliates.

76. There is substantial uncertainty with regard to ETI’s projection of its Rate Year reserve equalization payments under Schedule MSS-1.

77. ETI’s projection of its Rate Year third-party capacity contract payments includes numerous assumptions, one of which is that every single third-party supplier will perform at the maximum level under the contract, even though that assumption is inconsistent with ETI’s historical experience.

78. There is substantial uncertainty with regard to ETI’s projection of its Rate Year third-party capacity contract payments.

79. ETI’s estimates of its Rate Year purchases under affiliate contracts are based on a mathematical formula set out in Schedule MSS-4.

80. The MSS-4 formula for Rate Year affiliate capacity payments reflects that these payments will be based on ratios and costs that cannot be determined until the month that the payments are to be made.

81. Over $11 million of ETI’s affiliate transactions were based on a 2013 contract (the EAI WBL Contract) that was not signed until April 11, 2012.

82. There is uncertainty about whether the EAI WBL Contract will ever go into effect.

83. ETI projects purchasing over 300 megawatts (MW) more in purchased capacity in the Rate Year than it purchased in the Test Year.

84. ETI experienced substantial load growth in the two years before the Test Year, and it continues to project similar load growth in the future.

85. ETI did not meet its burden of proof to demonstrate that a known and measurable adjustment of $30,809,355 should be made to its Test Year purchased capacity expenses.

86. ETI’s purchased capacity expense in this case should be based on the Test Year level of $245,432,884.

87. ETI incurred $1,753,797 of transmission equalization expense during the Test Year.

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88. ETI proposed an upward adjustment of $8,942,785 for its transmission equalization expense.

This request was based on ETI’s projections of its transmission equalization expenses during the Rate Year.

89. The transmission equalization expense that ETI will pay in the Rate Year will depend on future costs and loads for each of the Entergy operating companies.

90. ETI’s projection of its Rate Year transmission equalization expenses is uncertain and speculative because it depends on a number of variables, including future transmission investments, deferred taxes, depreciation reserves, costs of capital, tax rates, operating expenses, and loads of each of the Entergy operating companies.

91. ETI seeks increased transmission equalization expenses for transmission projects that are not currently used and useful in providing electric service. ETI’s post-Test Year adjustment is based on the assumption that certain planned transmission projects will go into service after the Test Year. At the close of the hearing, none of the planned transmission projects had been fully completed and some were still in the planning phase.

92. It is not reasonable for ETI to charge its retail ratepayers for transmission equalization expenses related to projects that are not yet in-service.

93. ETI’s request for a post-Test Year adjustment of $8,942,785 for Rate Year transmission equalization expenses should be denied because those expenses are not known and measurable. ETI’s post-Test Year adjustment does not with reasonable certainty reflect what ETI’s transmission equalization expense will be when rates are in effect.

94. ETI’s transmission equalization expense in this case should be based on the Test Year level of $1,753,797.

95. P.U.C. SUBST. R. 25.231(c)(2)(ii) states that the reserve for depreciation is the accumulation of recognized allocations of original cost, representing the recovery of initial investment over the estimated useful life of the asset.

96. Except in the case of the amortization of the general plant deficiency, the use of the remaining life depreciation method to recover differences between theoretical and actual depreciation reserves is the most appropriate method and should be continued.

97. It is reasonable for ETI to calculate depreciation reserve allocations on a straight-line basis over the remaining, expected useful life of the item or facility.

98. Except as described below, the service lives and net salvage rates proposed by the Company are reasonable, and these service lives and net salvage rates should be used in calculating depreciation rates for the Company’s Production, Transmission, Distribution, and General Plant assets.

99. A 60-year life for Sabine Units 4 and 5 is reasonable for purposes of establishing production plant depreciation rates.

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100. The retirement (actuarial) rate method, rather than the interim retirement method, should be used in the development of production plant depreciation rates.

101. Production plant net salvage is reasonably based on the negative five percent net salvage in existing rates.

102. The net salvage rate of negative 10 percent for ETI’s transmission structures and improvements (FERC Account 352) is the most reasonable of those proposed and should be adopted.

103. The net salvage rate of negative 20 percent for ETI’s transmission station equipment (FERC Account 353) is the most reasonable of those proposed and should be adopted.

104. The net salvage rate of negative five percent for ETI’s transmission towers and fixtures (FERC Account 354) is the most reasonable of those proposed and should be adopted.

105. The net salvage rate of negative 30 percent for ETI’s transmission poles and fixtures (FERC Account 355) is the most reasonable of those proposed and should be adopted.

106. The net salvage rate of negative 30 percent for ETI’s transmission overhead conductors and devices (FERC Account 356) is the most reasonable of those proposed and should be adopted.

107. A service life of 65 years and a dispersion curve of R3 for ETI’s distribution structures and improvements (FERC Account 361) are the most reasonable of those proposed and should be approved.

108. A service life of 40 years and a dispersion curve of R1 for ETI’s distribution poles, towers, and fixtures (FERC Account 364) are the most reasonable of those proposed and should be approved.

109. A service life of 39 years and a dispersion curve of R0.5 for ETI’s distribution overhead conductors and devices (FERC Account 365) are the most reasonable of those proposed and should be approved.

110. A service life of 35 years and a dispersion curve of R1.5 for ETI’s distribution underground conductors and devices (FERC Account 367) are the most reasonable of those proposed and should be approved.

111. A service life of 33 years and a dispersion curve of L0.5 for ETI’s distribution line transformers (FERC Account 368) are the most reasonable of those proposed and should be approved.

112. A service life of 26 years and a dispersion curve of L4 for ETI’s distribution overhead service (FERC Account 369.1) are the most reasonable of those proposed and should be approved.

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113. The net salvage rate of negative five percent for ETI’s distribution structures and improvements (FERC Account 361) is the most reasonable of those proposed and should be adopted.

114. The net salvage rate of negative 10 percent for ETI’s distribution station equipment (FERC Account 362) is the most reasonable of those proposed and should be adopted.

115. The net salvage rate of negative seven percent for ETI’s distribution overhead conductors and devices (FERC Account 365) is the most reasonable of those proposed and should be adopted.

116. The net salvage rate of negative five percent for ETI’s distribution line transformers (FERC Account 368) is the most reasonable of those proposed and should be adopted.

117. The net salvage rate of negative 10 percent for ETI’s distribution overhead services (FERC Account 369.1) is the most reasonable of those proposed and should be adopted.

118. The net salvage rate of negative 10 percent for ETI’s distribution underground services (FERC Account 369.2) is the most reasonable of those proposed and should be adopted.

119. A service life of 45 years and a dispersion curve of R2 for ETI’s general structures and improvements (FERC Account 390) are the most reasonable of those proposed and should be approved.

120. The net salvage rate of negative 10 percent for ETI’s general structures and improvements (FERC Account 390) is the most reasonable of those proposed and should be adopted.

121. It is reasonable to convert the $21.3 million deficit that has developed over time in the reserve for general plant accounts to General Plant Amortization.

122. A ten-year amortization of the deficit in the reserve for general plant accounts is reasonable and should be adopted.

123. FERC pronouncement AR-15 requires amortization over the same life as recommended based on standard life analysis. A standard life analysis determined that a five-year life was appropriate for general plant computer equipment (FERC Account 390.2). Therefore, a five year amortization for this account is reasonable and should be adopted.

124. ETI proposed adjustments to its Test Year payroll costs to reflect: (a) changes to employee headcount levels at ETI and Entergy Services, Inc. (ESI); and (b) approved wage increases set to go into effect after the end of the Test Year.

125. The proposed payroll adjustments are reasonable but should be updated to reflect the most recent available information on headcount levels as proposed by Commission Staff. In addition to adjusting payroll expense levels, the more recent headcount numbers should be used to adjust the level of payroll tax expense, benefits expense, and savings plan expense.

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126. Staff has appropriately updated headcount levels to the most recent available data but errors made by Staff should be corrected. The corrections related to: (a) a double counting of three ETI and one ESI employee; (b) inadvertent use of the ETI benefits cost percentage in the calculation of ESI benefits costs; (c) an inappropriate reduction of savings plan costs when such costs were already included in the benefits percentage adjustments; and (d) corrections for full-time equivalents calculations. Staff’s ETI headcount adjustment (AG-7) overstated operation and maintenance (O&M) payroll reduction by $224,217, and ESI headcount adjustment (AG-7) understated O&M payroll increase by $37,531.

127. ETI included $14,187,744 for incentive compensation expenses in its cost of service.

128. The compensation packages that ETI offers its employees include a base payroll amount, annual incentive programs, and long-term incentive programs. The majority of the compensation is for operational measures, but some is for financial measures.

129. Incentive compensation that is based on financial measures is of more immediate and predominant benefit to shareholders, whereas incentive compensation based on operational measures is of more immediate and predominant benefit to ratepayers.

130. Incentives to achieve operational measures are necessary and reasonable to provide utility services but those to achieve financial measures are not.

131. The $5,376,975 that was paid for long term incentive programs was tied to financial measures and, therefore, should not be included in ETI’s cost of service.

132. Of the amounts that were paid pursuant to the Executive Annual Incentive Plan, $819,062 was tied to financial measures and, therefore, should be disallowed.

133. In total, the amount of incentive compensation that should be disallowed is $6,196,037 because it was related to financial measures that are not reasonable and necessary for the provision of electric service.

134. The amount of incentive compensation that should be included in the cost of service is $7,991,707.

135. To attract and retain highly qualified employees, the Entergy Companies provide a total package of compensation and benefits that is equivalent in scope and cost with what other comparable companies within the utility business and other industries provide for their employees.

136. When using a benchmark analysis to compare companies’ levels of compensation, it is reasonable to view the market level of compensation as a range rather than a precise, single point.

137. ETI’s base pay levels are at market.

138. ETI’s benefits plan levels are within a reasonable range of market levels.

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139. ETI’s level of compensation and benefits expense is reasonable and necessary.

140. ETI provides non-qualified supplemental executive retirement plans for highly compensated individuals such as key managerial employees and executives that, because of limitations imposed under the Internal Revenue Code, would otherwise not receive retirement benefits on their annual compensation over $245,000 per year.

141. ETI’s non-qualified supplemental executive retirement plans are discretionary costs designed to attract, retain, and reward highly compensated employees whose interests are more closely aligned with those of the shareholders than the customers.

142. ETI’s non-qualified executive retirement benefits in the amount of $2,114,931 are not reasonable or necessary to provide utility service to the public, not in the public interest, and should not be included in ETI’s cost of service.

143. For the employee market in which ETI operates, most peer companies offer moving assistance. Such assistance is expected by employees, and ETI would be placed at a competitive disadvantage if it did not offer relocation expenses.

144. ETI’s relocation expenses were reasonable and necessary.

145. The Company’s requested operating expenses should be reduced by $40,620 to reflect the removal of certain executive prerequisites proposed by Staff.

146. Staff properly adjusted the Company’s requested interest expense of $68,985 by removing $25,938 from FERC account 431 (using the interest rate of 0.12 percent for calendar year 2012), leaving a recommended interest expense of $43,047.

147. During the Test Year, ETI’s property tax expense equaled $23,708,829.

148. ETI requested an upward pro forma adjustment of $2,592,420, to account for the property tax expenses ETI estimates it will pay in the Rate Year.

149. ETI’s requested pro forma adjustment is not reasonable because it is based, in part, upon the prediction that ETI’s property tax rate will be increased in 2012, a change that is speculative is not known and measurable.

150. Staff’s recommendation to increase ETI’s Test Year property tax expenses by $1,214,688 is based on the historical effective tax rate applied to the known Test Year-end plant in service value, consistent with Commission precedent, and based upon known and measurable changes.

151. ETI’s Test Year property tax burden should be adjusted upward by $1,214,688.

152. Staff recommended reducing ETI’s advertising, dues, and contributions expenses by $12,800. The recommendation, which no party contested, should be adopted.

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153. The final cost of service should reflect changes to cost of service that affect other components of the revenue requirement such as the calculation of the Texas state gross receipts tax, the local gross receipts tax, the PUC Assessment Tax and the Uncollectible Expenses.

154. The Company’s requested Federal income tax expense is reasonable and necessary.

155. ETI’s request for $2,019,000 to be included in its cost of service to account for the Company’s annual decommissioning expenses associated with River Bend is not reasonable because it is not based upon “the most current information reasonably available regarding the cost of decommissioning” as required by P.U.C. SUBST. R. 25.231(b)(1)(F)(i).

156. Based on the most current information reasonably available, the appropriate level of decommissioning costs to be included in ETI’s cost of service is $1,126,000.

157. ETI’s appropriate total annual self-insurance storm damage reserve expense is $8,270,000, comprised of an annual accrual of $4,400,000 to provide for average annual expected storm losses, plus an annual accrual of $3,870,000 for 20 years to restore the reserve from its current deficit.

158. ETI’s appropriate target self-insurance storm damage reserve is $17,595,000.

159. ETI should continue recording its annual storm damage reserve accrual until modified by a Commission order.

160. The operating costs of the Spindletop Facility are reasonable and necessary.

161. The operating costs of the Spindletop Facility paid to PB Energy Storage Services are eligible fuel expenses.

Affiliate Transactions 162. ETI affiliates charged ETI $78,998,777 for services during the Test Year. The majority of these O&M expenses—$69,098,041—were charged to ETI by ESI. The remaining affiliate services were charged (or credited) to ETI by: Entergy Gulf States Louisiana, L.L.C.; Entergy Arkansas, Inc.; Entergy Louisiana, LLC; Entergy Mississippi, Inc.; Entergy Operations, Inc.; and non-regulated affiliates.

163. ESI follows a number of processes to ensure that affiliate charges are reasonable and necessary and that ETI and its affiliates are charged the same rate for similar services. These processes include: (a) the use of service agreements to define the level of service required and the cost of those services; (b) direct billing of affiliate expenses where possible; (c) reasonable allocation methodologies for costs that cannot be directly billed; (d) budgeting processes and controls to provide budgeted costs that are reasonable and necessary to ensure appropriate levels of service to its customers; and (e) oversight controls by ETI’s Affiliate Accounting and Allocations Department.

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164. Affiliates charged expenses to ETI through 1292 project codes during the Test Year.

165. ETI agreed to remove the following affiliate transactions from its application: (1) Project F3PPCASHCT (Contractual Alternative/Cashpo) in the amount of $2,553; (2) Project F3PCSPETEI (Entergy-Tulane Energy Institute) in the amount of $14,288; and (3) Project F5PPKATRPT (Storm Cost Processing & Review) in the amount of $929.

166. The $356,151 (which figure includes the $112,531 agreed to by ETI) of costs associated with Projects F5PCZUBENQ (Non-Qualified Post Retirement) and F5PPZNQBDU (Non Qual Pension/Benf Dom Utl) are costs that are not reasonable and necessary for the provision of electric utility service and are not in the public interest.

167. The $10,279 of costs associated with Project F3PPFXERSP (Evaluated Receipts Settlement) are not normally-recurring costs and should not be recoverable.

168. The $19,714 of costs associated with Project F3PPEASTIN (Willard Eastin et al) are related to ESI’s operations, it is more immediately related to Entergy Louisiana, Inc. and Entergy New Orleans, Inc. As such, they are not recoverable from Texas ratepayers.

169. The $171,032 of costs associated with Project F3PPE9981S (Integrated Energy Management for ESI) are research and development costs related to energy efficiency programs. As such, they should be recovered through the energy efficiency cost recovery factor rather than base rates.

170. Except as noted in the above Findings of Fact Nos. 162-169, all remaining affiliate transactions were reasonable and necessary, were allowable, were charged to ETI at a price no higher than was charged by the supplying affiliate to other affiliates, and the rate charged is a reasonable approximation of the cost of providing service.

Jurisdictional Cost Allocation 171. ETI has one full or partial requirements wholesale customer – East Texas Electric Cooperative, Inc. 172. ETI proposes that 150 MW be set as the wholesale load for developing retail rates in this docket. Using 150 MW to set the wholesale load is reasonable. The 150 MW used to set the wholesale load results in a retail production demand allocation factor of 95.3838 percent.

173. The 12 Coincident Peak (12 CP) allocation method is consistent with the approach used by the FERC to allocate between jurisdictions.

174. Using 12CP methodology to allocate production costs between the wholesale and retail jurisdictions is the best method to reflect cost responsibility and is appropriate based on ETI’s reliance on capacity purchases.

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Class Cost Allocation and Rate Design 175. There is no express statutory authorization for ETI’s proposed Renewable Energy Credits Rider (REC Rider).

176. REC Rider constitutes improper piecemeal ratemaking and should be rejected.

177. ETI’s Test Year expense for renewable energy credits, $623,303, is reasonable and necessary and should be included in base rates.

178. Municipal Franchise Fees (MFF) is a rental expense paid by utilities for the right to use public rights-of-way to locate its facilities within municipal limits.

179. ETI is an integrated utility system. ETI’s facilities located within municipal limits benefit all customers, whether the customers are located inside or outside of the municipal limits.

180. Because all customers benefit from ETI’s rental of municipal right-of-way, municipal franchise fees should be charged to all customers in ETI’s service area, regardless of geographic location.

181. It is reasonable and consistent with the Public Utility Regulatory Act (PURA) § 33.008(b) that MFF be allocated to each customer class on the basis of in-city kilo-watt hour (kWH) sales, without an adjustment for the MFF rate in the municipality in which a given kWH sale occurred.

182. The same reasons for allocating and collecting MFF as set out in Finding of Fact Nos. 178- also apply to the allocation and collection of Miscellaneous Gross Receipts Taxes. The Company’s proposed allocation of these costs to all retail customer classes based on customer class revenues relative to total revenues is appropriate.

183. The Average and Excess (A&E) 4CP method for allocating capacity-related production costs, including reserve equalization payments, to the retail classes is a standard methodology and the most reasonable methodology.

184. The A&E 4CP method for allocating transmission costs to the retail classes is standard and the most reasonable methodology.

185. ETI appropriately followed the rate class revenue requirements from its cost of service study to allocate costs among customer classes. ETI’s revenue allocation properly sets rates at each class’s cost of service.

186. It is reasonable for ETI to eliminate the service condition for Rate Groups A and C in Schedule SHL [Street and Highway Lighting Service] that charges a $50 fee for any replacement of a functioning light with a lower-wattage bulb.

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187. It is appropriate to require ETI to prepare and file, as part of its next base rate case, a study regarding the feasibility of instituting LED-based rates and, if the study shows that such rates are feasible, ETI should file proposals for LED-based lighting and traffic signal rates it next rate case.

188. An agreement was reached by the parties and approved by the Commission in Docket No. 37744 that directed ETI to exclude, in its next rate case, the life-of-contract demand ratchet for existing customers in the Large Industrial Power Service (LIPS), Large Industrial Power Service-Time of Day, General Service, General Service-Time of Day, Large General Service, and Large General Service-Time of Day rate schedules.

189. ETI’s proposed tariffs in this case did not remove the life-of-contract demand ratchet from these rate schedules consistent with the parties’ agreement in Docket No. 37744.

190. A perpetual billing obligation based on a life-of-contract demand ratchet, as ETI proposed, is not reasonable.

191. ETI’s proposed LIPS and LIPS Time of Day tariffs should be modified to reflect the agreement that was adopted by the Commission as just and reasonable in Docket No. 37744.

Accordingly, these tariffs should be modified as set out in Findings of Fact No. 192-194.

192. ETI’s Schedule LIPS and LIPS Time of Day § VI should be changed to read: DETERMINATION OF BILLING LOAD The kW of Billing Load will be the greatest of the following: (A) The Customer’s maximum measured 30-minute demand during any 30-minute interval of the current billing month, subject to §§ III, IV and V above; or (B) 60% of Contract Power as defined in § VII; or (C) 2,500 kW.

193. ETI’s Schedule LIPS and LIPS Time of Day § VII should be changed to read: DETERMINATION OF CONTRACT POWER Unless Company gives customer written notice to the contrary, Contract Power will be defined as below: Contract Power - the highest load established under § VI(A) above during the 12 months ending with the current month. For the initial months of Customer’s service under the currently effective contract, the Contract Power shall be the kW specified in the SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 358 PUC DOCKET NO. 39896

currently effective contract unless exceeded in any month during the initial 12-month period.

194. The Large General Service and Large General Service-Time of Day schedules should be similarly revised to eliminate ETI’s life-of-contract demand ratchet.

195. In its proposed rate design for the LIPS class, the Company took a conservative approach and increased the current rates by an equal percentage. This minimized customer bill impacts while maintaining cost causation principles on a rate class basis.

196. It is a reasonable move towards cost of service to add a customer charge of $630 to the LIPS rate schedule with subsequent increases to be considered in subsequent base rate cases.

197. It is a reasonable move towards cost of service to slightly decrease the LIPS energy charges and increase the demand charges as proposed by Staff witness William B. Abbott.

198. DOE proposed a new Schedule LIPS rider—Schedule “Schedulable Intermittent Pumping Service” (SIPS) for load schedulable at least four weeks in advance, that occurs in the off- season (November through April), that can be cancelled at any time, and for load not lasting more than 80 hours in a year. For customers whose loads match these SIPS characteristics (for example, DOE’s Strategic Petroleum Reserve), the 12-month demand ratchet provision of Schedule LIPS does not apply to demands set under the provisions of the SIPS rider. The monthly demand set under the SIPS provisions would be applicable for billing purposes only in the month in which it occurred. In short, if a customer set a 12-month ratchet demand in that month, it would be forgiven and not applicable in the succeeding 12 months.

199. DOE’s proposed Schedule SIPS is not restricted solely to the DOE and should be adopted. It more closely addresses specific customer characteristics and provides for cost-based rates, as does another ETI rider applicable to Pipeline Pumping Service.

200. Standby Maintenance Service (SMS) is available to customers who have their own generation equipment and who contract for this service from ETI.

201. P.U.C. SUBST. R. 25.242(k)(1) provides that rates for sales of standby and maintenance power to qualifying facilities should recognize system wide costing principles and should not be discriminatory.

202. It is reasonable to move Schedule SMS toward cost of service by: (a) adding a customer charge equivalent to that of the LIPS rate schedule only for SMS customers not purchasing supplementary power under another applicable rate; and (b) revising the tariff as follows: SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 359 PUC DOCKET NO. 39896

Distribution Transmission Charge (less than (69KV and 69KV) greater) Billing Load Charge ($/kW): Standby $2.46 $0.79 Maintenanc e $2.27 $0.60 Non-Fuel Energy Charge (¢/kWh) On-Peak 0.881¢ 0.846¢ Off-Peak 0.575¢ 0.552¢ 203. ETI’s Additional Facilities Charge Rider (Schedule AFC) prescribes the monthly rental charge paid by a customer when ETI installs facilities for that customer that would not normally be supplied, such as line extensions, transformers, or dual feeds.

204. ETI existing Schedule AFC provides two pricing options. Option A is a monthly charge.

Option B, which applies when a customer elects to amortize the directly-assigned facilities over a shorter term ranging from one to ten years, has a variable monthly charge. There is also a term charge that applies after the facility has been fully depreciated.

205. It is reasonable and cost-based to reduce the Schedule AFC Option A rate to 1.20 percent per month of the installed cost of all facilities included in the agreement for additional facilities.

206. It is reasonable and cost-based to reduce the Schedule AFC Option B monthly rate and the Post Term Recovery Charge as follows:

Selected Recovery Term Recovery Term Charge Post Recovery Term Charge 1 10.88% 0.35% 2 5.39% 0.35% 3 3.92% 0.35% 4 3.20% 0.35% 5 2.76% 0.35% 6 2.48% 0.35% 7 2.28% 0.35% 8 2.14% 0.35% 9 1.97% 0.35% 10 1.94% 0.35%

207. The revisions in the above Findings of Fact to Schedule AFC rates reasonably reflect the costs of running, operating, and maintaining the directly-assigned facilities.

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208. It is reasonable to modify the Large General Service rate schedule by increasing the demand charge from $10.25 to $12.81; decreasing the energy charge from $.01023 to $.00513; and maintaining the customer charge at $425.05.

209. Staff’s proposed change to the General Service (GS) rate schedule to gradually move GS customers towards their cost of service by recommending a decrease in the customer charge from the current rate of $41.09 to $39.91, and a decrease in the energy charges is reasonable and should be adopted.

210. ETI’s Residential Service (RS) rate schedule is composed of two elements: a customer charge of $5 per month and a consumption-based energy charge. The Energy charge is a fixed rate of 5.802ȼ per kWh from May through October (Summer). In the months November through April (Winter), the rates are structured as a declining block, in which the price of each unit is reduced after a defined level of usage.

211. ETI’s Schedule RS declining block rate structure is contrary to energy efficiency efforts and the Legislature’s goal of reducing both energy demand and energy consumption in Texas, as stated in PURA § 39.905.

212. Schedule RS winter block rates should be modified consistent with the goal set out in PURA § 39.905, with the initial phase-in of a 20 percent reduction in the block differential proposed by ETI and subsequent reductions should be reviewed for consideration at the occurrence of each rate case filing.

213. Other elements of Schedule RS are just and reasonable.

Fuel Reconciliation 214. ETI incurred $616,248,686 in natural-gas expenses during the Reconciliation Period, which is from July 2009 through June 2011.

215. ETI purchased natural gas in the monthly and daily markets and pursuant to a long-term contract with Enbridge Inc. pipeline. ETI also transported gas on its own account and negotiated operational balancing agreements with various pipeline companies.

216. ETI employed a diversified portfolio of gas supply and transportation agreements to meet its natural-gas requirements, and ETI prudently managed its gas-supply contracts.

217. ETI’s natural gas expenses were reasonable and necessary expenses incurred to provide reliable electric service to retail customers.

218. ETI incurred $90,821,317 in coal expenses during the Reconciliation Period.

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219. ETI prudently managed its coal and coal-related contracts during the Reconciliation Period.

220. ETI monitored and audited coal invoices from Louisiana Generating, LLC for coal burned at the Big Cajun II, Unit 3 facility.

221. ETI’s coal expenses were reasonable and necessary expenses incurred to provide reliable electric service to retail customers.

222. ETI incurred $990,041,434 in purchased-energy expenses during the Reconciliation Period.

223. The Entergy System’s planning and procurement processes for purchased power produced a reasonable mix of purchased resources at a reasonable price.

224. During the Reconciliation Period, ETI took advantage of opportunities in the fuel and purchased-power markets to reduce costs and to mitigate against price volatility.

225. ETI’s purchased-energy expenses were reasonable and necessary expenses incurred to provide reliable electric service to retail customers.

226. ETI provided sufficient contemporaneous documentation to support the reasonableness of its purchased-power planning and procurement processes and its actual power purchases during the Reconciliation Period.

227. The Entergy system sold power off system when the revenues were expected to be more than the incremental cost of supplying generation for the sale, subject to maintaining adequate reserves.

228. The System Agreement is the tariff approved by the FERC that provides the basis for the operation and planning of the Entergy system, including the six Operating Companies. The System Agreement governs the wholesale-power transactions among the Operating Companies by providing for joint operation and establishing the bases for equalization among the Operating Companies, including the costs associated with the construction, ownership, and operation of the Entergy system facilities.

229. Under the terms of the Entergy System Agreement, ETI was allocated its share of revenues and expenses from off-system sales.

230. During the Reconciliation Period, ETI recorded off-system sales revenue in the amount of $376,671,969 in FERC Account 447 and credited 100 percent of off-system sales revenues and margins from off-system sales to eligible fuel expenses.

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231. ETI properly recorded revenues from off-system sales and credited those revenues to eligible fuel costs.

232. The Entergy system consists of six Operating Companies, including ETI, which are planned and operated as a single, integrated electric system under the terms of the System Agreement.

233. Service Schedule MSS-1 of the System Agreement determines how the capability and ownership costs of reserves for the Entergy system are equalized among the Operating Companies. These inter-system “reserve equalization” payments are the result of a formula rate related to the Entergy system’s reserve capability that is applied on a monthly basis.

234. Reserve capability under Service Schedule MSS-1 is capability in excess of the Entergy system’s actual or planned load built or acquired to ensure the reliable, efficient operation of the electric system.

235. By approving Service Schedule MSS-1, the FERC has approved the method by which the Operating Companies share the cost of maintaining sufficient reserves to provide reliability for the Entergy system as a whole.

236. Service Schedule MSS-3 of the System Agreement determines the pricing and exchange of energy among the Operating Companies. By approving Service Schedule MSS-3, the FERC has approved the method by which the Operating Companies are reimbursed for energy sold to the exchange energy pool and how that energy is purchased.

237. Service Schedule MSS-4 of the System Agreement sets forth the method for determining the payment for unit power purchases between Operating Companies. By approving Service Schedule MSS-4, the FERC has approved the methodology for pricing Inter-Operating Company unit power purchases.

238. The Entergy system is planned using multi-year, annual, seasonal, monthly, and next-day horizons. Once the planning process has identified the most economical resources that can be used to reliably meet the aggregate Entergy system demand, the next step is to procure the fuel necessary to operate the generating units as planned and acquire wholesale power from the market.

239. Once resources are procured to meet forecasted load, the Entergy system is operated during the current day using all the resources available to meet the total Entergy system demand.

240. After current-day operation, the System Agreement prescribes an accounting protocol to bill the costs of operating the system to the individual Operating Companies. This protocol is implemented via the Intra-System Bill (ISB) to each Operating Company on a monthly basis.

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241. ETI purchased power from affiliated Operating Companies per the terms of Service Schedule MSS-3 of the System Agreement. The payments made under Schedule MSS-3 to affiliated Operating Companies are reasonable and necessary, and the FERC has approved the pricing formula and the obligation to purchase the energy. ETI pays the same price per megawatt hour for energy under Service Schedule MSS-3 as does any other Operating Company purchasing energy under Service Schedule MSS-3 during the same hour.

242. The Spindletop Facility is used primarily to ensure gas-supply reliability and guard against gas-supply curtailments that can occur as a result of extreme weather or other unusual events.

243. The Spindletop Facility provides a secondary benefit of flexibility in gas supply. ETI can back down gas-fired generation to take advantage of more economical wholesale power, or use gas from storage to supplement gas-fired generation when load increases during the day and thereby avoid more expensive intra-day gas purchases.

244. ETI’s customers received benefits from the Spindletop Facility during the Reconciliation Period through reliable gas supplies and ETI’s monthly and daily storage activity.

245. ETI prudently managed the Spindletop Facility to provide reliability and flexibility of gas supply for the benefit of customers.

246. ETI proposed new loss factors, based on a December 2010 line loss study, to be applied for the purpose of allocating its costs to its wholesale customers and retail customer classes.

247. ETI’s proposed loss factors are reasonable and shall be implemented on a prospective basis as a result of this final order.

248. ETI seeks a special-circumstances exception to recover $99,715 resulting from the FERC’s reallocation of rough production equalization costs in FERC Order No. 720-A, and to treat such costs as eligible fuel expense.

249. Special circumstances exist and it is appropriate for recovery of the rough production cost equalization costs reallocated to ETI as a result of the FERC’s decision in Order No. 720-A.

Other Issues 250. A deferred accounting of ETI’s Midwest Independent Transmission System Operator (MISO) transition expenses is not necessary to carry out any requirement of PURA.

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251. ETI should include $2.4 million in base rates for MISO transition expense incurred on or after January 2, 2011, based on a five-year amortization of $12 million in total projected expenses.

252. ETI should include an additional $52,800 in base rates for MISO transition expenses incurred during the 2010 portion of the Test Year, based on a five-year amortization of $263,908 in such expenses.

253. Transmission Cost Recovery Factor baseline values should be set during the compliance phase of this docket, after the Commission makes final rulings on the various contested issues that may affect this calculation.

254. Distribution Cost Recovery Factor baseline values should be set during the compliance phase of this docket, after the Commission makes final rulings on the various contested issues that may affect this calculation.

255. The appropriate amount for ETI’s purchased power capacity expense to be included in base rates is $245,432,884.

256. The amount of ETI’s purchased power capacity expense includes third-party contracts, legacy affiliate contracts, other affiliate contracts, and reserve equalization. Whether the amounts for all contracts should be included in the baseline for a purchased capacity rider that may be approved in Project No. 39246 is an issue that should be decided in that project.

B. Conclusions of Law 1. ETI is a “public utility” as that term is defined in PURA § 11.004(1) and an “electric utility” as that term is defined in PURA § 31.002(6).

2. The Commission exercises regulatory authority over ETI and jurisdiction over the subject matter of this application pursuant to PURA §§ 14.001, 32.001, 32.101, 33.002, 33.051, 36.101–.111, and 36.203.

3. SOAH has jurisdiction over matters related to the conduct of the hearing and the preparation of a proposal for decision in this docket, pursuant to PURA § 14.053 and TEX. GOV’T CODE ANN. § 2003.049.

4. This docket was processed in accordance with the requirements of PURA and the Texas Administrative Procedure Act, TEX. GOV’T CODE ANN. Chapter 2001.

5. ETI provided notice of its application in compliance with PURA § 36.103, P.U.C. PROC.

R. 22.51(a), and P.U.C. SUBST. R. 25.235(b)(1)-(3).

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6. Pursuant to PURA § 33.001, each municipality in ETI’s service area that has not ceded jurisdiction to the Commission has jurisdiction over the Company’s application, which seeks to change rates for distribution services within each municipality.

7. Pursuant to PURA § 33.051, the Commission has jurisdiction over an appeal from a municipality’s rate proceeding.

8. ETI has the burden of proving that the rate change it is requesting is just and reasonable pursuant to PURA § 36.006.

9. In compliance with PURA § 36.051, ETI’s overall revenues approved in this proceeding permit ETI a reasonable opportunity to earn a reasonable return on its invested capital used and useful in providing service to the public in excess of its reasonable and necessary operating expenses.

10. Consistent with PURA § 36.053, the rates approved in this proceeding are based on original cost, less depreciation, of property used and useful to ETI in providing service.

11. The ADFIT adjustments approved in this proceeding are consistent with PURA § 36.059 and P.U.C. SUBST. R. 25.231(c)(2)(C)(i).

12. Including the cash working capital approved in this proceeding in ETI’s rate base is consistent with P.U.C. SUBST. R. 25.231(c)(2)(B)(iii)(IV), which allows a reasonable allowance for cash working capital to be included in rate base.

13. The ROE and overall rate of return authorized in this proceeding are consistent with the requirements of PURA §§ 36.051 and 36.052.

14. The affiliate expenses approved in this proceeding and included in ETI’s rates meet the affiliate payment standards articulated in PURA §§ 36.051, 36.058, and Railroad Commission of Texas v. Rio Grande Valley Gas Co., 683 S.W.2d 783 (Tex. App.—Austin 1984, no writ).

15. The ADFIT adjustments approved in this proceeding are consistent with PURA § 36.059 and P.U.C. SUBST. R. 25.231(c)(2)(C)(i).

16. Pursuant to P.U.C. SUBST. R. 25.231(b)(1)(F), the decommissioning expense approved in this case is based on the most current information reasonably available regarding the cost of decommissioning, the balance of funds in the decommissioning trust, anticipated escalation rates, the anticipated return on the funds in the decommissioning trust, and other relevant factors.

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17. ETI has demonstrated that its eligible fuel expenses during the Reconciliation Period were reasonable and necessary expenses incurred to provide reliable electric service to retail customers as required by P.U.C. SUBST. R. 25.236(d)(1)(A). ETI has properly accounted for the amount of fuel-related revenues collected pursuant to the fuel factor during the Reconciliation Period as required by P.U.C. SUBST. R. 25.236(d)(1)(C).

18. ETI prudently managed the dispatch, operations, and maintenance of its fossil plants during the Reconciliation Period.

19. The Reconciliation Period level operating and maintenance expenses for the Spindletop Facility are eligible fuel expenses pursuant to P.U.C. SUBST. R. 25.236(a).

20. Special circumstances are warranted pursuant to P.U.C. SUBST. R. 25.236(a)(6) to recover rough production equalization payments reallocated to ETI by the FERC.

21. ETI’s rates, as approved in this proceeding, are just and reasonable in accordance with PURA § 36.003.

C. Proposed Ordering Paragraphs In accordance with these findings of fact and conclusions of law, the Commission issues the following orders:

1. The Proposal for Decision prepared by the SOAH ALJs is adopted to the extent consistent with this Order.

2. ETI’s application is granted to the extent consistent with this Order.

3. ETI shall file tariffs consistent with this Order within 20 days of the date of this Order. No later than ten days after the date of the tariff filings, Staff shall file its comments recommending approval, modification, or rejection of the individual sheets of the tariff proposal. Responses to the Staff’s recommendation shall be filed no later than 15 days after the filing of the tariff. The Commission shall by letter approve, modify, or reject each tariff sheet, effective the date of the letter.

4. The tariff sheets shall be deemed approved and shall be become effective on the expiration of 20 days from the date of filing, in the absence of written notification of modification or rejection by the Commission. If any sheets are modified or rejected, ETI shall file proposed revisions of those sheets in accordance with the Commission’s letter within ten days of the date of that letter, and the review procedure set out above shall apply to the revised sheets.

SOAH DOCKET NO. XXX-XX-XXXX PROPOSAL FOR DECISION PAGE 367 PUC DOCKET NO. 39896

5. Copies of all tariff-related filings shall be served on all parties of record.

6. ETI shall prepare and file as part of its next base rate case a study regarding the feasibility of instituting LED-based rates and, if the study shows that such rates are feasible, ETI should file proposals for LED-based lighting and traffic signal rates in that case. If ETI has LED lighting customers taking service, the study shall include detailed information regarding differences in the cost of serving LED and non-LED lighting customers. ETI shall provide the results of this study to Cities and interested parties as soon as practicable but no later than the filing of its next rate case.

7. All other motions, requests for entry of specific findings of fact and conclusions of law, and any other requests for general or specific relief, if not expressly granted, are denied.

SIGNED July 6, 2012.

APPENDIX B Commission's Order on Rehearing in Docket No. 39896 PUC DOCKET NO. 39896 SOAH DOCKET NO. XXX-XX-XXXX

APPLICATION OF ENTERGY TEXAS, § PUBLIC UTILITY COMMISSION INC. FOR AUTHORITY TO CHANGE § RATES, RECONCILE FUEL COSTS, § OF TEXAS AND OBTAIN DEFERRED § ACCOUNTING TREATMENT §

ORDER ON REHEARING

This Order addresses the application of Entergy Texas, Inc. for authority to change rates, reconcile fuel costs, and defer costs for the transition to the Midwest Independent System Operator (MISO). In its application, Entergy requested approval of an increase in annual base- rate revenues of approximately $111.8 million (later lowered to $104.8 million), proposed tariff schedules, including new riders to recover costs related to purchased-power capacity and renewable-energy credit requirements, requested final reconciliation of its fuel costs, and requested waivers to the rate-filing package requirements.

On July 6, 2012, the State Office of Administrative Hearings (SOAH) administrative law judges (ALJs) issued a proposal for decision in which they recommended an overall rate increase for Entergy of $28.3 million resulting in a total revenue requirement of approximately $781 million. The ALJs also recommended approving total fuel costs of approximately $1.3 billion.

The ALJs did not recommend approving the renewable-energy credit rider and the Commission earlier removed the purchased-power capacity rider as an issue to be addressed in this docket.1 On August 8, 2012, the ALJs filed corrections to the proposal for decision based on the exceptions and replies of the parties.2 Except as discussed in this Order, the Commission adopts the proposal for decision, as corrected, including findings of fact and conclusions of law.

Parties filed motions for rehearing on September 25 and October 4, 2012 and filed replies to the motions for rehearing on October 15, 2012. The Commission considered the motions for

Supplemental Preliminary Order at 2, 3 (Jan. 19, 2012).

Letter from SOAH judges to PUC (Aug. 8, 2012).

PUC Docket No. 39896 Order on Rehearing Page 2 of 44 SOAH Docket No. XXX-XX-XXXX

rehearing at the October 25, 2012 open meeting. The Commission granted Commission Staff’s motion for rehearing that requested technical corrections to reflect the rates that resulted from the Commission Staff number-running memo that was filed on August 28, 2012. The Commission modifies findings of fact 205, 206, 208, and 210 as requested by Commission Staff and attaches Commission schedules I through V to reflects its decisions. The Commission granted the Department of Energy’s motion for rehearing requesting that finding of fact 198 be modified to reflect the applicable off-season for the schedulable intermittent pumping service. Finding of fact 198 is modified to reflect that the off-season is October through May. In its motion for rehearing, Entergy noted that findings of fact 17B and 17D should be modified to more accurately reflect the procedural history. The Commission modifies findings of fact 17B and 17D to state that Entergy agreed to extend time to provide the Commission sufficient time to consider the issues in this proceeding on two occasions—at the July 27 and August 30, 2012 open meetings.

I. Discussion A. Prepaid Pension Asset Balance Entergy included in rate base an approximately $56 million item named Unfunded Pension.3 This amount represents the accumulated difference between the annual pension costs calculated in accordance with the Statement of Financial Accounting Standards (SFAS) No. 87 and the actual contributions made by Entergy to the pension fund—Entergy contributed nearly $56 million more to its pension fund than the minimum required by SFAS No. 87.4 In Docket No. 33309, the Commission allowed a pension prepayment asset, excluding the portion of the asset that is capitalized to construction work in progress (CWIP), less accrued deferred federal income taxes (ADFIT) to be included in rate base.5 For the excluded portion, the Commission allowed the accrual of an allowance for funds used during construction

Proposal for Decision at 23 (July 6, 2012) (PFD).

PFD at 23-24.

Application of AEP Texas Central Company for Authority to Change Rates, Docket No. 33309, Order on Rehearing (March 4, 2008).

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(AFUDC).6 The ALJs concluded that this approach was sound and should be followed in this case.7 Thus, the ALJs recommended that the CWIP-related portion of Entergy’s prepaid pension asset ($25,311,236) should be excluded from the asset and should accrue AFUDC.8 However, the ALJs did not address ADFIT.

The Commission agrees that the CWIP-related portion of Entergy’s pension asset should be excluded from the asset and that this excluded portion should accrue AFUDC. However, the Commission also finds that the impact of this exclusion on Entergy’s ADFIT should be reflected.

When items are excluded from rate base, the related ADFIT should also be excluded. The adjusted ADFIT for the prepaid pension asset remaining in Entergy’s rate base should be reduced by $8,858,933, the deferred taxes related to the excluded $25 million. The Commission adds new finding of fact 28A to reflect this modification to Entergy’s ADFIT.

B. FIN 48 The Financial Accounting Standards Board’s Interpretation No. 48 (FIN 48) prescribes the way in which a company must analyze, quantify, and disclose the potential consequences of tax positions that the company has taken that are legally uncertain. Entergy reported that its uncertain tax positions totaled $5,916,461. FIN 48 requires that this amount be recorded on Entergy’s balance sheet as a tax liability. Entergy also reported that it made a cash deposit with the IRS in the amount of $1,294,683 associated with its FIN 48 liability.9 The ALJs concluded that Entergy’s FIN 48 liability should be included in its ADFIT balance, but the amount of the cash deposit made by Entergy to the IRS attributable to Entergy’s FIN 48 liability should not be included in Entergy’s ADFIT balance. Accordingly, the ALJs recommended that $4,621,778 (Entergy’s FIN 48 liability of $5,916,461 less the $1,294,683 cash deposit Entergy has already made with the IRS) be added to Entergy’s ADFIT balance and thus

Remand of Docket No. 33309 (Application of AEP Texas Central Company for Authority to Change Rates), Docket No. 38772, Order on Remand (Jan. 20, 2011).

PFD at 26.

Id. at 24-26.

PFD at 26-27 (citing Rebuttal Testimony of Roberts, Entergy Ex. 64 at 6), 29 (citing Rebuttal Testimony of Roberts, Entergy Ex. 64 at 8).

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be used to offset Entergy’s rate base.10 The ALJs did not recommend the addition of a deferred- tax-account rider because no party expressly advocated the addition of such a rider.11 The Commission adopts the proposal for decision regarding the adjustment to Entergy’s ADFIT for the amount attributable to Entergy’s FIN 48 liability. However, the Commission also follows its precedent regarding the creation of a deferred-tax-account tracker and modifies the proposal for decision on this point. In CenterPoint’s Electric Delivery Company’s last rate case, Docket No. 38339,12 the Commission found that tax schedule UTP—on which companies must describe, list, and rank each uncertain tax position—would provide the IRS auditors sufficient information to quickly determine which uncertain tax positions are of a magnitude worth investigating and that an IRS audit would be more likely to occur on some uncertain tax positions. If an IRS audit of a FIN 48 uncertain tax position results in an unfavorable outcome, the utility would not be able to earn a return on the amount paid to the IRS until the next rate case.

Accordingly, the Commission authorizes Entergy to establish a rider to track unfavorable FIN-48 rulings by the IRS. The rider will also allow Entergy to recover on a prospective basis an after-tax return of 8.27% on the amounts paid to the IRS that result from an unfavorable FIN- unfavorable-tax-position audit. The return will be applied prospectively to FIN-48 amounts disallowed by an IRS audit after such amounts are actually paid to the federal government. If Entergy subsequently prevails in an appeal of an unfavorable FIN-48 unfavorable-tax-position decision by the IRS, then any amounts collected under rider related to that overturned decision shall be credited back to ratepayers.

The Commission adds new finding of fact 40A and deletes finding of fact 41 consistent with its decision to authorize the deferred-tax-account tracker.

PFD at 29.

Id. at 29.

Application of CenterPoint Electric Delivery Company, LLC for Authority to Change Rates, Docket No. 38339, Order on Rehearing at 3-4 (June 23, 2011).

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C. Capitalized Incentive Compensation Entergy capitalized into plant-in-service accounts some of the incentive payments made to employees and sought to include those amounts in rate base. The ALJs determined that Entergy should not be able to recover its financially based incentive-compensation costs.13 Therefore, the portion of Entergy’s incentive-compensation costs capitalized during the period July 1, 2009 through June 30, 2010 that were financially based was excluded from Entergy’s rate base. The ALJs also determined that the actual percentages should be used to determine the amount that is financially based.14 In discussing Entergy’s incentive compensation as a component of operating expenses, the ALJs adopted the method advocated by Texas Industrial Energy Consumers (TIEC) for calculating the amount of the financially based incentive costs. This method uses the actual percentage reductions applicable to each of the annual incentive programs that included a component of financially-based costs.15 In its exceptions regarding capitalized incentive compensation, Entergy advocated for the use of TIEC’s methodology to also calculate the amount of capitalized incentive compensation that is financially based. Entergy also noted that the amount of the disallowance reflected in the schedules, $1,333,352, was calculated using a disallowance factor that included incentive compensation tied to cost-control measures, which the ALJs found to be recoverable in the operating-cost incentive-compensation calculation.16 When the TIEC methodology is applied to the capitalized incentive-compensation costs in rate base, the net result under TIEC’s methodology is that only $335,752.96 should be disallowed from capital costs.17 The Commission agrees that capitalized incentive compensation that is financially based should be excluded from rate base and that the exclusion only applies to incentive costs that Entergy capitalized during the period from July 1, 2009 through June 30, 2010. However, the Commission finds that a consistent methodology should be used to calculate the amount to be

PFD at 171.

Id. at 72.

Id. at 174; see also Entergy’s Exceptions to the Proposal for Decision at 25-26 (July 23, 2012).

Entergy’s Exceptions to the Proposal for Decision at 25-26.

Id. at 25-26.

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excluded and therefore that TIEC’s methodology should also be used for calculating the amount of capitalized financially based incentive-compensation costs that should be excluded from rate base. Accordingly, the total amount of capitalized incentive-compensation costs that should be disallowed from rate base is $335,752.96. Finding of fact 61 is modified to reflect this determination.

As noted by Commission Staff, this disallowance to plant-in-service alters the expense for ad valorem taxes. Accounting for this disallowance, the appropriate expense amount for ad valorem taxes is $24,921,022,18 an adjustment of $1,222,106 to Entergy’s test year amount.

Finding of fact 151 is modified to reflect this adjustment to property taxes.

D. Rate of Return and Cost of Capital The ALJs found the proper range of an acceptable return on equity for Entergy would be from 9.3 percent to 10.0 percent.19 The mid-point of the range is 9.65 percent. The ALJs found that the effect of unsettled economic conditions facing utilities on the appropriate return on equity should be taken into account and that the effect would be to move the ultimate return on equity towards the upper limits of the range that was determined to be reasonable.20 The ALJs found that the reasonable adjustment would be 15 basis points, moving the reasonable return on equity to 9.80 percent.21 The Commission must establish a reasonable return for a utility and must consider applicable factors.22 The Commission disagrees with the ALJs that a utility’s return on equity should be determined using an adder to reflect unsettled economic conditions facing utilities.

The Commission agrees with the ALJs, however, that a return on equity of 9.80 percent will allow Entergy a reasonable opportunity to earn a reasonable return on its invested capital, but finds this rate appropriate independent of the 15-point adder recommended by the ALJs. A return on equity of 9.80 percent is within the range of an acceptable return on equity found by

Commission Number-Run Memorandum at 2 (Aug. 28, 2012).

PFD at 94.

Id. Id. at 94.

PURA §§ 36.051, .052.

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the ALJs. Accordingly, the Commission adds new finding of fact 65A to reflect the Commission’s decision on this point.

E. Purchased-Power Capacity Expense The ALJs rejected Entergy’s request to recover $31 million more in purchased-power capacity costs than its actual test-year expenses because Entergy had failed to prove that the adjustment was known and measurable,23 and because the request violated the matching principle.24 Consequently, the ALJs recommended that Entergy’s test-year expenses of $245,432,884 be used to set rates in this docket.25 Entergy pointed to an additional $533,002 of purchased-power capacity expenses that were properly included in Entergy’s rate-filing package, but not provided for in the proposal for decision.26 The Commission finds that an additional $533,002 ($6,132 for test-year expenses for Southwest Power Pool fees, $654,082 for Toledo Bend hydro fixed-charges, and -$127,212 for an Entergy intra-system billing adjustment that were all recorded in FERC account 555) of purchased-power capacity costs were incurred during the test-year and should be added to the purchased-power capacity costs in Entergy’s revenue requirement. The Commission modifies findings of fact 72 and 86 to reflect the inclusion of the additional $533,002 of test-year purchased-power capacity costs, increasing the total amount to $245,965,886.

F. Labor Costs – Incentive Compensation The ALJs found that $6,196,037, representing Entergy’s financially-based incentives paid in the test-year, should be removed from Entergy’s O&M expenses.27 The ALJs agreed with Commission Staff and Cities that an additional reduction should be made to account for the FICA taxes that Entergy would have paid for those costs,28 but did not include this reduction in a finding of fact.

PFD at 108-09.

Id. at 109.

Id. Entergy’s Exceptions to the Proposal for Decision at 51.

PFD at 175.

Id. at 175-76.

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The Commission agrees with the ALJs, but modifies finding of fact 133 to specifically include the decision that an additional reduction should be made to account for the FICA taxes Entergy would have paid on the disallowed financially-based incentive compensation. The Commission notes that this reduction for FICA taxes is reflected in the schedules attached to this Order.29

G. Affiliate Transactions OPUC argued that Entergy’s sales and marketing expenses exclusively benefit the larger commercial and industrial customers, but the majority of the sales, marketing, and customer service expenses are allocated to the operating companies based on customer counts. Therefore, the majority of these expenses are allocated to residential and small business customers. OPUC argued that it is inappropriate for residential and small business customers to pay for these expenses.30 The ALJs did not adopt OPUC’s position on this issue.

The Commission agrees with OPUC and reverses the proposal for decision regarding allocation of Entergy’s sales and marketing expense and finds that $2.086 million of sales and marketing expense should be reallocated using direct assignment. The Commission has previously expressed its preference for direct assignment of affiliate expenses.31 The Commission finds that the following amounts should be allocated based on a total-number-of- customers basis: (1) $46,490 for Project E10PCR56224 – Sales and Marketing – EGSI Texas; (2) $17,013 for Project F3PCD10049 – Regulated Retail Systems O&M; and (3) $30,167 for Project F3PPMMALI2 – Middle Market Mkt. Development. The remainder, $1,992,475, should be assigned to (1) General Service, (2) Large General Service and (3) Large Industrial Power Service.32 The reallocation has the effect of increasing the revenue requirement allocated to the large business class customers and reduces the revenue requirement for small business and residential customers. New finding of fact 164A is added to reflect the proper allocation of these affiliate transactions.

See Commission Number Run-Memorandum at 3 (Aug. 28, 2012).

Direct Testimony of Carol Szerszen, OPUC Ex. 1 at 44-45.

Application of Central Power and Light Company for Authority to Change Rates, Docket No. 14965, Second Order on Rehearing at 87, COL 29 (Oct. 16, 1997).

Direct Testimony of Carol Szerszen, OPUC Ex. 1 at Schedule CAS-7.

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H. Fuel Reconciliation Entergy proposed to allocate costs for the fuel reconciliation to customers using a line- loss study performed in 1997. Entergy conducted a line-loss study for the year ending December 31, 2010, which falls in the middle of the two year fuel reconciliation period—July 2009 through June 2011—and therefore reflects the actual line losses experienced by the customer classes during the reconciliation period. Cities argued that the allocation of fuel costs incurred over the reconciliation period should reflect the current line-loss study performed by Entergy for this case and recommended approval on a going-forward basis. Fuel factors under P.U.C. SUBST.

R. 25.237(a)(3) are temporary rates subject to revision in a reconciliation proceeding described in P.U.C. SUBST. R. 25.236. P.U.C. SUBST. R. 25.236(d)(2) defines the scope of a fuel reconciliation proceeding to include any issue related to the reasonableness of a utility’s fuel expenses and whether the utility has over- or under-recovered its reasonable fuel expenses.33 Cities calculated a $3,981,271 reduction to the Texas retail fuel expenses incurred over the reconciliation period using the current line-losses. The ALJs rejected Cities’ proposed adjustment finding that the P.U.C. SUBST. R. 25.237(c)(2)(B) requires the use of Commission- approved line losses that were in effect at the time fuel costs were billed to customers in a fuel reconciliation.34 The Commission agrees with Cities and reverses the proposal for decision regarding which line-loss factors should be used in Entergy’s fuel reconciliation. Entergy used the 2010 study line-loss calculations to calculate the demand- and energy-related allocations in its cost of service analysis supporting its requested base rates. These same currently available line-loss factors should have been utilized in Entergy’s fuel reconciliation. The Commission finds that Entergy’s 2010 line-loss factors should be used to calculate Entergy’s fuel reconciliation over-recovery. As a result, Entergy’s fuel reconciliation over-recovery should be reduced by $3,981,271. Finding of fact 246A and conclusions of law 19A and 19B are added to reflect the Commission’s finding that the 2010 line-loss factors be used to reconcile Entergy’s fuel costs.

Cities’ Exceptions to the Proposal for Decision at 20-21 (July 23, 2012).

PFD at 327-328.

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I. MISO Transition Expenses During the Commission’s consideration of the proposal for decision, the parties that contested the amount of Entergy’s MISO transition expenses and how the transition expenses should be accounted for reached announced on the record that they had reached an agreement on these issues.35 Those parties agreed that the MISO transition expenses would not be deferred and that Entergy’s base rates should include $1.6 million for MISO transition expense.36 The Commission adopts the agreement of the parties and accordingly modifies finding of fact 251 and deletes finding of fact 252.

J. Purchased-Power Capacity Cost Baseline The Commission modified the amount of purchased-power capacity expense in the test-year to be $245,965,886 (see section E above). Finding of fact 255 is modified to reflect the change to the proper test-year purchased-power capacity expense.

K. Other Issues New findings of fact 17A, 17B, 17C, 17D, and 17 E are added to reflect procedural aspects of the case after issuance of the proposal for decision.

In addition, to reflect corrections recommended by the ALJs, findings of fact 116, 123, 192, 194, and 202 are modified; and new finding of fact 182A is added.

The Commission adopts the following findings of fact and conclusions of law:

II. Findings of Fact Procedural History 1. Entergy Texas, Inc. (ETI or the company) is an investor-owned electric utility with a retail service area located in southeastern Texas.

Open Meeting Tr. at 138 (Aug. 17, 2012).

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2. ETI serves retail and wholesale electric customers in Texas. As of June 30, 2011, ETI served approximately 412,000 Texas retail customers. The Federal Energy Regulatory Commission (FERC) regulates ETI’s wholesale electric operations.

3. On November 28, 2011, ETI filed an application requesting approval of: (1) a proposed increase in annual base rate revenues of approximately $111.8 million over adjusted test- year revenues; (2) a set of proposed tariff schedules presented in the Electric Utility Rate Filing Package for Generating Utilities (RFP) accompanying ETI’s application and including new riders for recovery of costs related to purchased-power capacity and renewable energy credit requirements; (3) a request for final reconciliation of ETI’s fuel and purchased-power costs for the reconciliation period from July 1, 2009 to June 30, 2011; and (4) certain waivers to the instructions in RFP Schedule V accompanying ETI’s application.

4. The 12-month test-year employed in ETI’s filing ended on June 30, 2011 (test-year).

5. ETI provided notice by publication for four consecutive weeks before the effective date of the proposed rate change in newspapers having general circulation in each county of ETI’s Texas service territory. ETI also mailed notice of its proposed rate change to all of its customers. Additionally, ETI timely served notice of its statement of intent to change rates on all municipalities retaining original jurisdiction over its rates and services.

6. The following parties were granted intervenor status in this docket: Office of Public Utility Counsel; the cities of Anahuac, Beaumont, Bridge City, Cleveland, Conroe, Dayton, Groves, Houston, Huntsville, Montgomery, Navasota, Nederland, Oak Ridge North, Orange, Pine Forest, Rose City, Pinehurst, Port Arthur, Port Neches, Shenandoah, Silsbee, Sour Lake, Splendora, Vidor, and West Orange (Cities), the Kroger Co. (Kroger); State Agencies; Texas Industrial Energy Consumers; East Texas Electric Cooperative, Inc.; the United States Department of Energy (DOE); and Wal-Mart Stores Texas, LLC, and Sam’s East, Inc. (Wal-Mart). The Staff (Staff) of the Public Utility Commission of Texas (Commission or PUC) was also a participant in this docket.

7. On November 29, 2011, the Commission referred this case to the State Office of Administrative Hearings (SOAH).

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8. On December 7, 2011, the Commission issued its order requesting briefing on threshold legal/policy issues.

9. On December 19, 2011, the Commission issued its Preliminary Order, identifying 31 issues to be addressed in this proceeding.

10. On December 20, 2011, the Administrative Law Judges (ALJs) issued SOAH Order No. 2, which approved an agreement among the parties to establish a June 30, 2012 effective date for the company’s new rates resulting from this case pursuant to certain agreed language and consolidate Application of Entergy Texas, Inc. for Authority to Defer Expenses Related to its Proposed Transition to Membership in the Midwest Independent System Operator, Docket No. 39741 (pending) into this proceeding. Although it did not agree, Staff did not oppose the consolidation.

11. On January 13, 2012, the ALJs issued SOAH Order No. 4 granting the motions for admission pro hac vice filed by Kurt J. Boehm and Jody M. Kyler to appear and participate as counsel for Kroger and the motion for admission pro hac vice filed by Rick D. Chamberlain to appear and participate as counsel for Wal-Mart.

12. On January 19, 2012, the Commission issued a supplemental preliminary order identifying two additional issues to be addressed in this case and concluding that the company’s proposed purchased-power capacity rider should not be addressed in this case and that such costs should be recovered through base rates.

13. ETI timely filed with the Commission petitions for review of the rate ordinances of the municipalities exercising original jurisdiction within its service territory. All such appeals were consolidated for determination in this proceeding.

14. On April 4, 2012, the ALJs issued SOAH Order No. 13 severing rate case expense issues into Application of Entergy Texas, Inc. for Rate Case Expenses Severed from PUC Docket No. 39896, Docket No. 40295 (pending).

15. On April 13, 2012, ETI adjusted its request for a proposed increase in annual base rate revenues to approximately $104.8 million over adjusted test-year revenues.

16. The hearing on the merits commenced on April 24 and concluded on May 4, 2012.

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17. Initial post-hearing briefs were filed on May 18 and reply briefs were filed on May 30, 2012.

17A. On August 7, 2012, the SOAH ALJs filed a letter with the Commission recommending changes to the PFD.

17B At the July 27, 2012 open meeting, ETI agreed to extend time to August 31, 2012 to provide the Commission sufficient time to consider the issues in this proceeding.

17C. The Commission considered the proposal for decision at the August 17, 2012 and August 30, 2012 open meetings.

17D. At the August 30, 2012 open meeting, ETI agreed to extend time to September 14, 2012 to provide the Commission sufficient time to consider the issues in this proceeding.

17E. At the August 17, 2012 open meeting, parties announced on the record a settlement of the amount of costs for the transition to MISO.

Rate Base 18. Capital additions that were closed to ETI’s plant-in-service between July 1, 2009 and June 30, 2011, are used and useful in providing service to the public and were prudently incurred.

19. ETI’s proposed Hurricane Rita regulatory asset was an issue resolved by the black-box settlement in Application of Entergy Texas, Inc. for Authority to Change Rates and Reconcile Fuel Costs, Docket No. 37744 (Dec. 13, 2010).

20. Accrual of carrying charges on the Hurricane Rita regulatory asset should have ceased when Docket No. 37744 concluded because the asset would have then begun earning a rate of return as part of rate base.

21. The appropriate calculation of the Hurricane Rita regulatory asset should begin with the amount claimed by ETI in Docket No. 37744, less amortization accruals to the end of the test-year in the present case, and less the amount of additional insurance proceeds received by ETI after the conclusion of Docket No. 37744.

22. A Test-Year-end balance of $15,175,563 for the Hurricane Rita regulatory asset should remain in rate base, applying a five-year amortization rate beginning August 15, 2010.

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23. The Hurricane Rita regulatory asset should not be moved to the storm damage insurance reserve.

24. The company requested in rate base its prepaid pension assets balance of $55,973,545, which represents the accumulated difference between the Statement of Financial Accounting Standards (SFAS) No. 87 calculated pension costs each year and the actual contributions made by the company to the pension fund.

25. The prepaid pension assets balance includes $25,311,236 capitalized to construction work in progress (CWIP).

26. It is not necessary to the financial integrity of ETI to include CWIP in rate base, and there was insufficient evidence showing that major projects under construction were efficiently and prudently managed.

27. The portion of the prepaid pension assets balance that is capitalized to CWIP should not be included in ETI’s rate base.

28. The remainder of the prepaid pension assets balance should be included in ETI’s rate base.

28A. When items are excluded from rate base, the related ADFIT should also be excluded.

The amount of ADFIT associated with the $25 million capitalized to CWIP and excluded from rate base is $8,858,933. The adjusted ADFIT for the prepaid pension asset remaining in Entergy’s rate base should be reduced by $8,858,933.

29. ETI should be permitted to accrue an allowance for funds used during construction on the portion of ETI’s Prepaid Pension Assets Balance capitalized to CWIP.

30. The Financial Accounting Standard Board (FASB) Financial Interpretation No. 48 (FIN 48), “Accounting for Uncertainty in Income Taxes,” requires ETI to identify each of its uncertain tax positions by evaluating the tax position on its technical merits to determine whether the position, and the corresponding deduction, is more-likely-than-not to be sustained by the Internal Revenue Service (IRS) if audited.

31. FIN 48 requires ETI to remove the amount of its uncertain tax positions from its Accumulated Deferred Federal Income Tax (ADFIT) balance for financial reporting PUC Docket No. 39896 Order on Rehearing Page 15 of 44 SOAH Docket No. XXX-XX-XXXX

purposes and record it as a potential liability with interest to better reflect the company’s financial condition.

32. At test-year-end, ETI had $5,916,461 in FIN 48 liabilities, meaning ETI has, thus far, avoided paying to the IRS $5,916,461 in tax dollars (the FIN 48 liability) in reliance upon tax positions that the company believes will not prevail in the event the positions are challenged, via an audit, by the IRS.

33. ETI has deposited $1,294,683 with the IRS in connection with the FIN 48 liability.

34. The IRS may never audit ETI as to its uncertain tax positions creating the FIN 48 liability.

35. Even if ETI is audited, ETI might prevail on its uncertain tax positions.

36. ETI may never have to pay the IRS the FIN 48 liability.

37. Other than the amount of its deposit with the IRS, ETI has current use of the FIN 48 liability funds.

38. Until actually paid to the IRS, the FIN 48 liability represents cost-free capital and should be deducted from rate base.

39. The amount of $4,621,778 (representing ETI’s full FIN 48 liability of $5,916,461 less the $1,294,683 cash deposit ETI has made with the IRS for the FIN 48 liability) should be added to ETI’s ADFIT and thus be used to reduce ETI’s rate base.

40. ETI’s application and proposed tariffs do not include a request for a tracking mechanism or rider to collect a return on the FIN 48 liability.

40A. It is appropriate for ETI to create a deferred-tax-account tracker in the form of a rider to recover on a prospective basis an after–tax return of 8.27% on the amounts paid to the IRS that result from an unfavorable FIN 48 audit. The rider will track unfavorable FIN rulings and the return will be applied prospectively to FIN 48 amounts disallowed by an IRS audit after such amounts are actually paid to the federal government. If ETI prevails in an appeal of a FIN 48 decision, then any amounts collected under the rider related to that decision should be credited back to ratepayers.

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41. Deleted.

42. Investor-owned electric utilities may include a reasonable allowance for cash working capital in rate base as determined by a lead-lag study conducted in accordance with the Commission’s rules.

43. Cash working capital represents the amount of working capital, not specifically addressed in other rate base items, that is necessary to fund the gap between the time expenditures are made and the time corresponding revenues are received.

44. The lead-lag study conducted by ETI considered the actual operations of ETI, adjusted for known and measurable changes, and is consistent with P.U.C. SUBST.

R. 25.231(c)(2)(B)(iii).

45. It is reasonable to establish ETI’s cash working capital requirement based on ETI’s lead- lag study as updated in Jay Joyce’s rebuttal testimony and on the cost of service approved for ETI in this case.

46. As a result of the black-box settlements in Application of Entergy Gulf States, Inc. for Authority to Change Rates and to Reconcile Fuel Costs, Docket No. 34800 (Nov. 7, 2008) and Docket No. 37744, the Commission did not approve ETI’s storm damage expenses since 1996 and its storm damage reserve balance.

47. ETI established a prima facie case concerning the prudence of its storm damage expenses incurred since 1996.

48. Adjustments to the storm damage reserve balance proposed by intervenors should be denied.

49. The Hurricane Rita regulatory asset should not be moved to the storm damage insurance reserve.

50. ETI’s appropriate Test-Year-end storm reserve balance was negative $59,799,744.

51. The amount of $9,846,037, representing the value of the average coal inventory maintained at ETI’s coal-burning facilities, is reasonable, necessary, and should be included in rate base.

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52. The Spindletop gas storage facility (Spindletop facility) is used and useful in providing reliable and flexible natural gas supplies to ETI’s Sabine Station and Lewis Creek generating plants.

53. The Spindletop facility is critical to the economic, reliable operation of the Sabine Station and Lewis Creek generating plants due to their geographic location in the far western region of the Entergy system.

54. It is reasonable and appropriate to include ETI’s share of the costs to operate the Spindletop facility in rate base.

55. Staff recommended updating ETI’s balance amounts for short-term assets to the 13- month period ending December 2011, which was the most recent information available.

Staff’s proposed adjustments should be incorporated into the calculation of ETI’s rate base.

56. The following short-term asset amounts should be included in rate base: prepayments at $8,134,351; materials and supplies at $29,285,421; and fuel inventory at $52,693,485.

57. The amount of $1,127,778, representing costs incurred by ETI when it acquired the Spindletop facility, represent actual costs incurred to process and close the acquisition, not mere mark-up costs.

58. ETI’s $1,127,778 in capitalized acquisition costs should be included in rate base because ETI incurred these costs in conjunction with the purchase of a viable asset that benefits its retail customers.

59. In its application, ETI capitalized into plant in service accounts some of the incentive payments ETI made to its employees. ETI seeks to include those amounts in rate base.

60. A portion of those capitalized incentive accounts represent payments made by ETI for incentive compensation tied to financial goals.

61. The portion of ETI’s incentive payments that are capitalized and that are financially- based should be excluded from ETI’s rate base because the benefits of such payments inure most immediately and predominantly to ETI’s shareholders, rather than its electric PUC Docket No. 39896 Order on Rehearing Page 18 of 44 SOAH Docket No. XXX-XX-XXXX

customers. ETI’s capitalized incentive compensation that is financially based is $335,752.96 and should be removed for rate base.

62. The test-year for ETI’s prior ratemaking proceeding ended on June 30, 2009, and the reasonableness of ETI’s capital costs (including capitalized incentive compensation) for that prior period was dealt with by the Commission in that proceeding and is not at issue in this proceeding.

63. In this proceeding, ETI’s capitalized incentive compensation that is financially-based should be excluded from rate base, but only for incentive costs that ETI capitalized during the period from July 1, 2009 (the end of the prior test-year) through June 30, 2010 (the commencement of the current test-year).

Rate of Return and Cost of Capital 64. A return on common equity (ROE) of 9.80 percent will allow ETI a reasonable opportunity to earn a reasonable return on its invested capital.

65. The results of the discounted cash flow model and risk premium approach support a ROE of 9.80 percent.

65A. It is not appropriate to add 15 points to the ROE due to unsettled economic conditions facing utilities.

66. A 9.80 percent ROE is consistent with ETI’s business and regulatory risk.

67. ETI’s proposed 6.74 percent embedded cost of debt is reasonable.

68. The appropriate capital structure for ETI is 50.08 percent long-term debt and 49.92 percent common equity.

69. A capital structure composed of 50.08 percent debt and 49.92 percent equity is reasonable in light of ETI’s business and regulatory risks.

70. A capital structure composed of 50.08 percent debt and 49.92 percent equity will help ETI attract capital from investors.

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71. ETI’s overall rate of return should be set as follows: CAPITAL WEIGHTED AVG COMPONENT STRUCTURE COST OF CAPITAL COST OF CAPITAL LONG-TERM DEBT 50.08% 6.74% 3.38% COMMON EQUITY 49.92% 9.80% 4.89% TOTAL 100.00% 8.27% Operating Expenses 72. ETI’s test-year purchased capacity expenses were $245,965,886.

73. ETI requested an upward adjustment of $30,809,355 as a post-test-year adjustment to its purchased capacity costs. This request was based on ETI’s projections of its purchased capacity expenses during a period beginning June 1, 2012 and ending May 31, 2013 (the rate-year).

74. ETI’s purchased capacity expense projections were based on estimates of rate-year expenses for: (a) reserve equalization payments under Schedule MSS-1; (b) payments under third-party capacity contracts; and (c) payments under affiliate contracts.

75. ETI’s projection of its rate-year reserve equalization payments under Schedule MSS-1 is based on numerous assumptions, including load growths for ETI and its affiliates, future capacity contracts for ETI and its affiliates, and future values of the generation assets of ETI and its affiliates.

76. There is substantial uncertainty with regard to ETI’s projection of its rate-year reserve equalization payments under Schedule MSS-1.

77. ETI’s projection of its rate-year third-party capacity contract payments includes numerous assumptions, one of which is that every single third-party supplier will perform at the maximum level under the contract, even though that assumption is inconsistent with ETI’s historical experience.

78. There is substantial uncertainty with regard to ETI’s projection of its rate-year third-party capacity-contract payments.

79. ETI’s estimates of its rate-year purchases under affiliate contracts are based on a mathematical formula set out in Schedule MSS-4.

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80. The MSS-4 formula for rate-year affiliate capacity payments reflects that these payments will be based on ratios and costs that cannot be determined until the month that the payments are to be made.

81. Over $11 million of ETI’s affiliate transactions were based on a 2013 contract (the EAI WBL Contract) that was not signed until April 11, 2012.

82. There is uncertainty about whether the EAI WBL Contract will ever go into effect.

83. ETI projects purchasing over 300 megawatts (MW) more in purchased capacity in the rate-year than it purchased in the test-year.

84. ETI experienced substantial load growth in the two years before the test-year, and it continues to project similar load growth in the future.

85. ETI did not meet its burden of proof to demonstrate that a known and measurable adjustment of $30,809,355 should be made to its test-year purchased capacity expenses.

86. ETI’s purchased capacity expense in this case should be based on the test-year level of $245,965,886.

87. ETI incurred $1,753,797 of transmission equalization expense during the test-year.

88. ETI proposed an upward adjustment of $8,942,785 for its transmission equalization expense. This request was based on ETI’s projections of its transmission equalization expenses during the rate-year.

89. The transmission equalization expense that ETI will pay in the rate-year will depend on future costs and loads for each of the Entergy operating companies.

90. ETI’s projection of its rate-year transmission equalization expenses is uncertain and speculative because it depends on a number of variables, including future transmission investments, deferred taxes, depreciation reserves, costs of capital, tax rates, operating expenses, and loads of each of the Entergy operating companies.

91. ETI seeks increased transmission equalization expenses for transmission projects that are not currently used and useful in providing electric service. ETI’s post-test-year adjustment is based on the assumption that certain planned transmission projects will go PUC Docket No. 39896 Order on Rehearing Page 21 of 44 SOAH Docket No. XXX-XX-XXXX

into service after the test-year. At the close of the hearing, none of the planned transmission projects had been fully completed and some were still in the planning phase.

92. It is not reasonable for ETI to charge its retail ratepayers for transmission equalization expenses related to projects that are not yet in-service.

93. ETI’s request for a post-test-year adjustment of $8,942,785 for rate-year transmission equalization expenses should be denied because those expenses are not known and measurable. ETI’s post-test-year adjustment does not with reasonable certainty reflect what ETI’s transmission equalization expense will be when rates are in effect.

94. ETI’s transmission equalization expense in this case should be based on the test-year level of $1,753,797.

95. P.U.C. SUBST. R. 25.231(c)(2)(ii) states that the reserve for depreciation is the accumulation of recognized allocations of original cost, representing the recovery of initial investment over the estimated useful life of the asset.

96. Except in the case of the amortization of the general plant deficiency, the use of the remaining life depreciation method to recover differences between theoretical and actual depreciation reserves is the most appropriate method and should be continued.

97. It is reasonable for ETI to calculate depreciation reserve allocations on a straight-line basis over the remaining, expected useful life of the item or facility.

98. Except as described below, the service lives and net salvage rates proposed by the company are reasonable, and these service lives and net salvage rates should be used in calculating depreciation rates for the company’s production, transmission, distribution, and general plant assets.

99. A 60-year life for Sabine Units 4 and 5 is reasonable for purposes of establishing production plant depreciation rates.

100. The retirement (actuarial) rate method, rather than the interim retirement method, should be used in the development of production plant depreciation rates.

101. Production plant net salvage is reasonably based on the negative five percent net salvage in existing rates.

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102. The net salvage rate of negative 10 percent for ETI’s transmission structures and improvements (FERC Account 352) is the most reasonable of those proposed and should be adopted.

103. The net salvage rate of negative 20 percent for ETI’s transmission station equipment (FERC Account 353) is the most reasonable of those proposed and should be adopted.

104. The net salvage rate of negative five percent for ETI’s transmission towers and fixtures (FERC Account 354) is the most reasonable of those proposed and should be adopted.

105. The net salvage rate of negative 30 percent for ETI’s transmission poles and fixtures (FERC Account 355) is the most reasonable of those proposed and should be adopted.

106. The net salvage rate of negative 30 percent for ETI’s transmission overhead conductors and devices (FERC Account 356) is the most reasonable of those proposed and should be adopted.

107. A service life of 65 years and a dispersion curve of R3 for ETI’s distribution structures and improvements (FERC Account 361) are the most reasonable of those proposed and should be approved.

108. A service life of 40 years and a dispersion curve of R1 for ETI’s distribution poles, towers, and fixtures (FERC Account 364) are the most reasonable of those proposed and should be approved.

109. A service life of 39 years and a dispersion curve of R0.5 for ETI’s distribution overhead conductors and devices (FERC Account 365) are the most reasonable of those proposed and should be approved.

110. A service life of 35 years and a dispersion curve of R1.5 for ETI’s distribution underground conductors and devices (FERC Account 367) are the most reasonable of those proposed and should be approved.

111. A service life of 33 years and a dispersion curve of L0.5 for ETI’s distribution line transformers (FERC Account 368) are the most reasonable of those proposed and should be approved.

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112. A service life of 26 years and a dispersion curve of L4 for ETI’s distribution overhead service (FERC Account 369.1) are the most reasonable of those proposed and should be approved.

113. The net salvage rate of negative five percent for ETI’s distribution structures and improvements (FERC Account 361) is the most reasonable of those proposed and should be adopted.

114. The net salvage rate of negative 10 percent for ETI’s distribution station equipment (FERC Account 362) is the most reasonable of those proposed and should be adopted.

115. The net salvage rate of negative seven percent for ETI’s distribution overhead conductors and devices (FERC Account 365) is the most reasonable of those proposed and should be adopted.

116. The net salvage rate of positive five percent for ETI’s distribution line transformers (FERC Account 368) is the most reasonable of those proposed and should be adopted.

117. The net salvage rate of negative 10 percent for ETI’s distribution overhead services (FERC Account 369.1) is the most reasonable of those proposed and should be adopted.

118. The net salvage rate of negative 10 percent for ETI’s distribution underground services (FERC Account 369.2) is the most reasonable of those proposed and should be adopted.

119. A service life of 45 years and a dispersion curve of R2 for ETI’s general structures and improvements (FERC Account 390) are the most reasonable of those proposed and should be approved.

120. The net salvage rate of negative 10 percent for ETI’s general structures and improvements (FERC Account 390) is the most reasonable of those proposed and should be adopted.

121. It is reasonable to convert the $21.3 million deficit that has developed over time in the reserve for general plant accounts to General Plant Amortization.

122. A ten-year amortization of the deficit in the reserve for general plant accounts is reasonable and should be adopted.

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123. FERC pronouncement AR-15 requires amortization over the same life as recommended based on standard life analysis. A standard life analysis determined that a five-year life was appropriate for general plant computer equipment (FERC Account 391.2).

Therefore, a five year amortization for this account is reasonable and should be adopted.

124. ETI proposed adjustments to its test-year payroll costs to reflect: (a) changes to employee headcount levels at ETI and Entergy Services, Inc. (ESI); and (b) approved wage increases set to go into effect after the end of the test-year.

125. The proposed payroll adjustments are reasonable but should be updated to reflect the most recent available information on headcount levels as proposed by Commission Staff.

In addition to adjusting payroll expense levels, the more recent headcount numbers should be used to adjust the level of payroll tax expense, benefits expense, and savings plan expense.

126. Staff has appropriately updated headcount levels to the most recent available data but errors made by Staff should be corrected. The corrections related to: (a) a double counting of three ETI and one ESI employee; (b) inadvertent use of the ETI benefits cost percentage in the calculation of ESI benefits costs; (c) an inappropriate reduction of savings plan costs when such costs were already included in the benefits percentage adjustments; and (d) corrections for full-time equivalents calculations. Staff’s ETI headcount adjustment (AG-7) overstated operation and maintenance (O&M) payroll reduction by $224,217, and ESI headcount adjustment (AG-7) understated O&M payroll increase by $37,531.

127. ETI included $14,187,744 for incentive compensation expenses in its cost of service.

128. The compensation packages that ETI offers its employees include a base payroll amount, annual incentive programs, and long-term incentive programs. The majority of the compensation is for operational measures, but some is for financial measures.

129. Incentive compensation that is based on financial measures is of more immediate and predominant benefit to shareholders, whereas incentive compensation based on operational measures is of more immediate and predominant benefit to ratepayers.

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130. Incentives to achieve operational measures are necessary and reasonable to provide utility services but those to achieve financial measures are not.

131. The $5,376,975 that was paid for long term incentive programs was tied to financial measures and, therefore, should not be included in ETI’s cost of service.

132. Of the amounts that were paid pursuant to the Executive Annual Incentive Plan, $819,062 was tied to financial measures and, therefore, should be disallowed.

133. In total, the amount of incentive compensation that should be disallowed is $6,196,037 because it was related to financial measures that are not reasonable and necessary for the provision of electric service. An additional reduction should be made to account for the FICA taxes ETI would have paid on the disallowed financially based incentive compensation.

134. The amount of incentive compensation that should be included in the cost of service is $7,991,707.

135. To attract and retain highly qualified employees, the Entergy companies provide a total package of compensation and benefits that is equivalent in scope and cost with what other comparable companies within the utility business and other industries provide for their employees.

136. When using a benchmark analysis to compare companies’ levels of compensation, it is reasonable to view the market level of compensation as a range rather than a precise, single point.

137. ETI’s base pay levels are at market.

138. ETI’s benefits plan levels are within a reasonable range of market levels.

139. ETI’s level of compensation and benefits expense is reasonable and necessary.

140. ETI provides non-qualified supplemental executive retirement plans for highly compensated individuals such as key managerial employees and executives that, because of limitations imposed under the Internal Revenue Code, would otherwise not receive retirement benefits on their annual compensation over $245,000 per year.

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141. ETI’s non-qualified supplemental executive retirement plans are discretionary costs designed to attract, retain, and reward highly compensated employees whose interests are more closely aligned with those of the shareholders than the customers.

142. ETI’s non-qualified executive retirement benefits in the amount of $2,114,931 are not reasonable or necessary to provide utility service to the public, not in the public interest, and should not be included in ETI’s cost of service.

143. For the employee market in which ETI operates, most peer companies offer moving assistance. Such assistance is expected by employees, and ETI would be placed at a competitive disadvantage if it did not offer relocation expenses.

144. ETI’s relocation expenses were reasonable and necessary.

145. The company’s requested operating expenses should be reduced by $40,620 to reflect the removal of certain executive prerequisites proposed by Staff.

146. Staff properly adjusted the company’s requested interest expense of $68,985 by removing $25,938 from FERC account 431 (using the interest rate of 0.12 percent for calendar year 2012), leaving a recommended interest expense of $43,047.

147. During the test-year, ETI’s property tax expense equaled $23,708,829.

148. ETI requested an upward pro forma adjustment of $2,592,420, to account for the property tax expenses ETI estimates it will pay in the rate-year.

149. ETI’s requested pro forma adjustment is not reasonable because it is based, in part, upon the prediction that ETI’s property tax rate will be increased in 2012, a change that is speculative is not known and measurable.

150. Staff’s recommendation to increase ETI’s test-year property tax expenses by $1,214,688 is based on the historical effective tax rate applied to the known test-year-end plant in service value, consistent with Commission precedent, and based upon known and measurable changes.

151. ETI’s test-year property tax burden should be adjusted upward by $1,222,106 for a total expense of $24,921,022.

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152. Staff recommended reducing ETI’s advertising, dues, and contributions expenses by $12,800. The recommendation, which no party contested, should be adopted.

153. The final cost of service should reflect changes to cost of service that affect other components of the revenue requirement such as the calculation of the Texas state gross receipts tax, the local gross receipts tax, the PUC Assessment Tax and the Uncollectible Expenses.

154. The company’s requested Federal income tax expense is reasonable and necessary.

155. ETI’s request for $2,019,000 to be included in its cost of service to account for the company’s annual decommissioning expenses associated with River Bend is not reasonable because it is not based upon “the most current information reasonably available regarding the cost of decommissioning” as required by P.U.C. SUBST.

R. 25.231(b)(1)(F)(i).

156. Based on the most current information reasonably available, the appropriate level of decommissioning costs to be included in ETI’s cost of service is $1,126,000.

157. ETI’s appropriate total annual self-insurance storm damage reserve expense is $8,270,000, comprised of an annual accrual of $4,400,000 to provide for average annual expected storm losses, plus an annual accrual of $3,870,000 for 20 years to restore the reserve from its current deficit.

158. ETI’s appropriate target self-insurance storm damage reserve is $17,595,000.

159. ETI should continue recording its annual storm damage reserve accrual until modified by a Commission order.

160. The operating costs of the Spindletop facility are reasonable and necessary.

161. The operating costs of the Spindletop facility paid to PB Energy Storage Services are eligible fuel expenses.

Affiliate Transactions 162. ETI affiliates charged ETI $78,998,777 for services during the test-year. The majority of these O&M expenses—$69,098,041—were charged to ETI by ESI. The remaining affiliate services were charged (or credited) to ETI by: Entergy Gulf States Louisiana, PUC Docket No. 39896 Order on Rehearing Page 28 of 44 SOAH Docket No. XXX-XX-XXXX

L.L.C.; Entergy Arkansas, Inc.; Entergy Louisiana, LLC; Entergy Mississippi, Inc.; Entergy Operations, Inc.; and non-regulated affiliates.

163. ESI follows a number of processes to ensure that affiliate charges are reasonable and necessary and that ETI and its affiliates are charged the same rate for similar services.

These processes include: (a) the use of service agreements to define the level of service required and the cost of those services; (b) direct billing of affiliate expenses where possible; (c) reasonable allocation methodologies for costs that cannot be directly billed; (d) budgeting processes and controls to provide budgeted costs that are reasonable and necessary to ensure appropriate levels of service to its customers; and (e) oversight controls by ETI’s Affiliate Accounting and Allocations Department.

164. Affiliates charged expenses to ETI through 1292 project codes during the test-year.

164A. The $2,086,145 in affiliate transactions related to sales and marketing expenses should be reallocated using direct assignment. The following amounts should be allocated to all retail classes in proportion to number of customers: (1) $46,490 for Project E10PCR56224 – Sales and Marketing – EGSI Texas; (2) $17,013 for Project F3PCD10049 – Regulated Retail Systems O&M; and (3) $30,167 for Project F3PPMMALI2 – Middle Market Mkt. Development. The remainder, $1,992,475, should be assigned to (1) General Service, (2) Large General Service and (3) Large Industrial Power Service.

165. ETI agreed to remove the following affiliate transactions from its application: (1) Project F3PPCASHCT (Contractual Alternative/Cashpo) in the amount of $2,553; (2) Project F3PCSPETEI (Entergy-Tulane Energy Institute) in the amount of $14,288; and (3) Project F5PPKATRPT (Storm Cost Processing & Review) in the amount of $929.

166. The $356,151 (which figure includes the $112,531 agreed to by ETI) of costs associated with Projects F5PCZUBENQ (Non-Qualified Post Retirement) and F5PPZNQBDU (Non Qual Pension/Benf Dom Utl) are costs that are not reasonable and necessary for the provision of electric utility service and are not in the public interest.

167. The $10,279 of costs associated with Project F3PPFXERSP (Evaluated Receipts Settlement) are not normally-recurring costs and should not be recoverable.

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168. The $19,714 of costs associated with Project F3PPEASTIN (Willard Eastin et al) are related to ESI’s operations, it is more immediately related to Entergy Louisiana, Inc. and Entergy New Orleans, Inc. As such, they are not recoverable from Texas ratepayers.

169. The $171,032 of costs associated with Project F3PPE9981S (Integrated Energy Management for ESI) are research and development costs related to energy efficiency programs. As such, they should be recovered through the energy efficiency cost recovery factor rather than base rates.

170. Except as noted in the above findings of fact Nos. 162-169, all remaining affiliate transactions were reasonable and necessary, were allowable, were charged to ETI at a price no higher than was charged by the supplying affiliate to other affiliates, and the rate charged is a reasonable approximation of the cost of providing service.

Jurisdictional Cost Allocation 171. ETI has one full or partial requirements wholesale customer – East Texas Electric Cooperative, Inc. 172. ETI proposes that 150 MW be set as the wholesale load for developing retail rates in this docket. Using 150 MW to set the wholesale load is reasonable. The 150 MW used to set the wholesale load results in a retail production demand allocation factor of 95.3838 percent.

173. The 12 Coincident Peak (12 CP) allocation method is consistent with the approach used by the FERC to allocate between jurisdictions.

174. Using 12CP methodology to allocate production costs between the wholesale and retail jurisdictions is the best method to reflect cost responsibility and is appropriate based on ETI’s reliance on capacity purchases.

Class Cost Allocation and Rate Design 175. There is no express statutory authorization for ETI’s proposed Renewable Energy Credits rider (REC rider).

176. REC rider constitutes improper piecemeal ratemaking and should be rejected.

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177. ETI’s test-year expense for renewable energy credits, $623,303, is reasonable and necessary and should be included in base rates.

178. Municipal Franchise Fees (MFF) is a rental expense paid by utilities for the right to use public rights-of-way to locate its facilities within municipal limits.

179. ETI is an integrated utility system. ETI’s facilities located within municipal limits benefit all customers, whether the customers are located inside or outside of the municipal limits.

180. Because all customers benefit from ETI’s rental of municipal right-of-way, municipal franchise fees should be charged to all customers in ETI’s service area, regardless of geographic location.

181. It is reasonable and consistent with the Public Utility Regulatory Act (PURA) § 33.008(b) that MFF be allocated to each customer class on the basis of in-city kilowatt hour (kWh) sales, without an adjustment for the MFF rate in the municipality in which a given kWh sale occurred.

182. The same reasons for allocating and collecting MFF as set out in Finding of Fact Nos. 178-181 also apply to the allocation and collection of Miscellaneous Gross Receipts Taxes. The company’s proposed allocation of these costs to all retail customer classes based on customer class revenues relative to total revenues is appropriate.

182A. ETI’s proposed gross plant-based allocator is an appropriate method for allocating the Texas franchise tax.

183. The Average and Excess (A&E) 4CP method for allocating capacity-related production costs, including reserve equalization payments, to the retail classes is a standard methodology and the most reasonable methodology.

184. The A&E 4CP method for allocating transmission costs to the retail classes is standard and the most reasonable methodology.

185. ETI appropriately followed the rate class revenue requirements from its cost of service study to allocate costs among customer classes. ETI’s revenue allocation properly sets rates at each class’s cost of service.

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186. It is reasonable for ETI to eliminate the service condition for Rate Groups A and C in Schedule SHL [Street and Highway Lighting Service] that charges a $50 fee for any replacement of a functioning light with a lower-wattage bulb.

187. It is appropriate to require ETI to prepare and file, as part of its next base rate case, a study regarding the feasibility of instituting LED-based rates and, if the study shows that such rates are feasible, ETI should file proposals for LED-based lighting and traffic signal rates in its next rate case.

188. An agreement was reached by the parties and approved by the Commission in Docket No. 37744 that directed ETI to exclude, in its next rate case, the life-of-contract demand ratchet for existing customers in the Large Industrial Power Service (LIPS), Large Industrial Power Service-Time of Day, General Service, General Service-Time of Day, Large General Service, and Large General Service-Time of Day rate schedules.

189. ETI’s proposed tariffs in this case did not remove the life-of-contract demand ratchet from these rate schedules consistent with the parties’ agreement in Docket No. 37744.

190. A perpetual billing obligation based on a life-of-contract demand ratchet, as ETI proposed, is not reasonable.

191. ETI’s proposed LIPS and LIPS Time of Day tariffs should be modified to reflect the agreement that was adopted by the Commission as just and reasonable in Docket No. 37744. Accordingly, these tariffs should be modified as set out in Findings of Fact No. 192-194.

192. ETI’s Schedule LIPS and LIPS Time of Day § VI should be changed to read: DETERMINATION OF BILLING LOAD The kW of Billing Load will be the greatest of the following: (A) The Customer’s maximum measured 30-minute demand during any 30-minute interval of the current billing month, subject to §§ III, IV and V above; or (B) 75% of Contract Power as defined in § VII; or (C) 2,500 kW.

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193. ETI’s Schedule LIPS and LIPS Time of Day § VII should be changed to read: DETERMINATION OF CONTRACT POWER Unless Company gives customer written notice to the contrary, Contract Power will be defined as below: Contract Power - the highest load established under § VI(A) above during the 12 months ending with the current month. For the initial 12 months of Customer’s service under the currently effective contract, the Contract Power shall be the kW specified in the currently effective contract unless exceeded in any month during the initial 12-month period.

194. The Large General Service, Large General Service-Time of Day, General Service, and General Service-Time of Day schedules should be similarly revised to eliminate ETI’s life-of-contract demand ratchet.

195. In its proposed rate design for the LIPS class, the company took a conservative approach and increased the current rates by an equal percentage. This minimized customer bill impacts while maintaining cost causation principles on a rate class basis.

196. It is a reasonable move towards cost of service to add a customer charge of $630 to the LIPS rate schedule with subsequent increases to be considered in subsequent base rate cases.

197. It is a reasonable move towards cost of service to slightly decrease the LIPS energy charges and increase the demand charges as proposed by Staff witness William B. Abbott.

198. DOE proposed a new Schedule LIPS rider—Schedule “Schedulable Intermittent Pumping Service” (SIPS) for load schedulable at least four weeks in advance, that occurs in the off-season (October through May), that can be cancelled at any time, and for load not lasting more than 80 hours in a year. For customers whose loads match these SIPS characteristics (for example, DOE’s Strategic Petroleum Reserve), the 12-month demand ratchet provision of Schedule LIPS does not apply to demands set under the provisions of the SIPS rider. The monthly demand set under the SIPS provisions would be applicable for billing purposes only in the month in which it occurred. In short, if a customer set a PUC Docket No. 39896 Order on Rehearing Page 33 of 44 SOAH Docket No. XXX-XX-XXXX

12-month ratchet demand in that month, it would be forgiven and not applicable in the succeeding 12 months.

199. DOE’s proposed Schedule SIPS is not restricted solely to the DOE and should be adopted. It more closely addresses specific customer characteristics and provides for cost-based rates, as does another ETI rider applicable to Pipeline Pumping Service.

200. Standby Maintenance Service (SMS) is available to customers who have their own generation equipment and who contract for this service from ETI.

201. P.U.C. SUBST. R. 25.242(k)(1) provides that rates for sales of standby and maintenance power to qualifying facilities should recognize system wide costing principles and should not be discriminatory.

202. It is reasonable to move Schedule SMS toward cost of service by: (a) adding a customer charge equivalent to that of the LIPS rate schedule only for SMS customers not purchasing supplementary power under another applicable rate; and (b) revising the tariff as follows: Distribution Transmission Charge (less than 69KV) (69KV and greater) Billing Load Charge ($/kW): Standby $2.46 $0.79 Maintenance $2.27 $0.60 Non-Fuel Energy Charge (¢/kWh) On-Peak 4.245¢ 4.074¢ Off-Peak 0.575¢ 0.552¢

203. ETI’s Additional Facilities Charge rider (Schedule AFC) prescribes the monthly rental charge paid by a customer when ETI installs facilities for that customer that would not normally be supplied, such as line extensions, transformers, or dual feeds.

204. ETI existing Schedule AFC provides two pricing options. Option A is a monthly charge.

Option B, which applies when a customer elects to amortize the directly-assigned facilities over a shorter term ranging from one to ten years, has a variable monthly charge. There is also a term charge that applies after the facility has been fully depreciated.

PUC Docket No. 39896 Order on Rehearing Page 34 of 44 SOAH Docket No. XXX-XX-XXXX

205. It is reasonable and cost-based to reduce the Schedule AFC Option A rate to 1.11 percent per month of the installed cost of all facilities included in the agreement for additional facilities.

206. It is reasonable and cost-based to reduce the Schedule AFC Option B monthly rate and the Post Term Recovery Charge as follows: Selected Recovery Term Recovery Term Charge Post Recovery Term Charge 1 9.52% 0.28% 2 5.14% 0.28% 3 3.68% 0.28% 4 2.95% 0.28% 5 2.52% 0.28% 6 2.23% 0.28% 7 2.03% 0.28% 8 1.88% 0.28% 9 1.76% 0.28% 10 1.67% 0.28%

207. The revisions in the above findings of fact to Schedule AFC rates reasonably reflect the costs of running, operating, and maintaining the directly-assigned facilities.

208. It is reasonable to modify the Large General Service rate schedule by increasing the demand charge from $8.56 to $11.43; decreasing the energy charge from $.00854 to $.00458; and reducing the customer charge to $260.00.

209. Staff’s proposed change to the General Service (GS) rate schedule to gradually move GS customers towards their cost of service by recommending a decrease in the customer charge from the current rate of $41.09 to $39.91, and a decrease in the energy charges is reasonable and should be adopted.

210. ETI’s Residential Service (RS) rate schedule is composed of two elements: a customer charge and a consumption-based energy charge. In the months November through April (winter), the rates are structured as a declining block, in which the price of each unit is reduced after a defined level of usage. ETI’s proposed increase in the RS customer charge to $6 per month is reasonable and should be adopted. For the RS summer rate and PUC Docket No. 39896 Order on Rehearing Page 35 of 44 SOAH Docket No. XXX-XX-XXXX

the first winter block rate, the 6.296¢ per kWh energy charge resulting from the increased revenue requirement for residential customers is reasonable and should be adopted.

211. ETI’s Schedule RS declining block rate structure is contrary to energy-efficiency efforts and the Legislature’s goal of reducing both energy demand and energy consumption in Texas, as stated in PURA § 39.905.

212. Schedule RS winter block rates should be modified consistent with the goal set out in PURA § 39.905, with the initial phase-in of a 20 percent reduction in the block differential proposed by ETI and subsequent reductions should be reviewed for consideration at the occurrence of each rate case filing.

213. Other elements of Schedule RS are just and reasonable.

Fuel Reconciliation 214. ETI incurred $616,248,686 in natural-gas expenses during the reconciliation period, which is from July 2009 through June 2011.

215. ETI purchased natural gas in the monthly and daily markets and pursuant to a long-term contract with Enbridge Inc. pipeline. ETI also transported gas on its own account and negotiated operational balancing agreements with various pipeline companies.

216. ETI employed a diversified portfolio of gas supply and transportation agreements to meet its natural-gas requirements, and ETI prudently managed its gas-supply contracts.

217. ETI’s natural gas expenses were reasonable and necessary expenses incurred to provide reliable electric service to retail customers.

218. ETI incurred $90,821,317 in coal expenses during the reconciliation period.

219. ETI prudently managed its coal and coal-related contracts during the reconciliation period.

220. ETI monitored and audited coal invoices from Louisiana Generating, LLC for coal burned at the Big Cajun II, Unit 3 facility.

221. ETI’s coal expenses were reasonable and necessary expenses incurred to provide reliable electric service to retail customers.

PUC Docket No. 39896 Order on Rehearing Page 36 of 44 SOAH Docket No. XXX-XX-XXXX

222. ETI incurred $990,041,434 in purchased-energy expenses during the reconciliation period.

223. The Entergy System’s planning and procurement processes for purchased-power produced a reasonable mix of purchased resources at a reasonable price.

224. During the reconciliation period, ETI took advantage of opportunities in the fuel and purchased-power markets to reduce costs and to mitigate against price volatility.

225. ETI’s purchased-energy expenses were reasonable and necessary expenses incurred to provide reliable electric service to retail customers.

226. ETI provided sufficient contemporaneous documentation to support the reasonableness of its purchased-power planning and procurement processes and its actual power purchases during the reconciliation period.

227. The Entergy system sold power off system when the revenues were expected to be more than the incremental cost of supplying generation for the sale, subject to maintaining adequate reserves.

228. The System Agreement is the tariff approved by the FERC that provides the basis for the operation and planning of the Entergy system, including the six operating companies.

The System Agreement governs the wholesale-power transactions among the operating companies by providing for joint operation and establishing the bases for equalization among the operating companies, including the costs associated with the construction, ownership, and operation of the Entergy system facilities.

229. Under the terms of the Entergy System Agreement, ETI was allocated its share of revenues and expenses from off-system sales.

230. During the reconciliation period, ETI recorded off-system sales revenue in the amount of $376,671,969 in FERC Account 447 and credited 100 percent of off-system sales revenues and margins from off-system sales to eligible fuel expenses.

231. ETI properly recorded revenues from off-system sales and credited those revenues to eligible fuel costs.

PUC Docket No. 39896 Order on Rehearing Page 37 of 44 SOAH Docket No. XXX-XX-XXXX

232. The Entergy system consists of six operating companies, including ETI, which are planned and operated as a single, integrated electric system under the terms of the System Agreement.

233. Service schedule MSS-1 of the System Agreement determines how the capability and ownership costs of reserves for the Entergy system are equalized among the operating companies. These inter-system “reserve equalization” payments are the result of a formula rate related to the Entergy system’s reserve capability that is applied on a monthly basis.

234. Reserve capability under service schedule MSS-1 is capability in excess of the Entergy system’s actual or planned load built or acquired to ensure the reliable, efficient operation of the electric system.

235. By approving service schedule MSS-1, the FERC has approved the method by which the operating companies share the cost of maintaining sufficient reserves to provide reliability for the Entergy system as a whole.

236. Service schedule MSS-3 of the System Agreement determines the pricing and exchange of energy among the operating companies. By approving service schedule MSS-3, the FERC has approved the method by which the operating companies are reimbursed for energy sold to the exchange energy pool and how that energy is purchased.

237. Service schedule MSS-4 of the System Agreement sets forth the method for determining the payment for unit power purchases between operating companies. By approving service schedule MSS-4, the FERC has approved the methodology for pricing inter-operating company unit power purchases.

238. The Entergy system is planned using multi-year, annual, seasonal, monthly, and next-day horizons. Once the planning process has identified the most economical resources that can be used to reliably meet the aggregate Entergy system demand, the next step is to procure the fuel necessary to operate the generating units as planned and acquire wholesale power from the market.

PUC Docket No. 39896 Order on Rehearing Page 38 of 44 SOAH Docket No. XXX-XX-XXXX

239. Once resources are procured to meet forecasted load, the Entergy system is operated during the current day using all the resources available to meet the total Entergy system demand.

240. After current-day operation, the System Agreement prescribes an accounting protocol to bill the costs of operating the system to the individual operating companies. This protocol is implemented via the intra-system bill to each operating company on a monthly basis.

241. ETI purchased power from affiliated operating companies per the terms of service schedule MSS-3 of the System Agreement. The payments made under Schedule MSS-3 to affiliated operating companies are reasonable and necessary, and the FERC has approved the pricing formula and the obligation to purchase the energy. ETI pays the same price per megawatt hour for energy under service schedule MSS-3 as does any other operating company purchasing energy under service schedule MSS-3 during the same hour.

242. The Spindletop facility is used primarily to ensure gas-supply reliability and guard against gas-supply curtailments that can occur as a result of extreme weather or other unusual events.

243. The Spindletop facility provides a secondary benefit of flexibility in gas supply. ETI can back down gas-fired generation to take advantage of more economical wholesale power, or use gas from storage to supplement gas-fired generation when load increases during the day and thereby avoid more expensive intra-day gas purchases.

244. ETI’s customers received benefits from the Spindletop facility during the reconciliation period through reliable gas supplies and ETI’s monthly and daily storage activity.

245. ETI prudently managed the Spindletop facility to provide reliability and flexibility of gas supply for the benefit of customers.

246. ETI proposed new loss factors, based on a December 2010 line-loss study, to be applied for the purpose of allocating its costs to its wholesale customers and retail customer classes.

PUC Docket No. 39896 Order on Rehearing Page 39 of 44 SOAH Docket No. XXX-XX-XXXX

246A. ETI’s 2010 line-loss factors should be used to reconcile ETI’s fuel costs. Therefore, ETI’s fuel reconciliation over-recovery should be reduced by $3,981,271.

247. ETI’s proposed loss factors are reasonable and shall be implemented on a prospective basis as a result of this final order.

248. ETI seeks a special-circumstances exception to recover $99,715 resulting from the FERC’s reallocation of rough production equalization costs in FERC Order No. 720-A, and to treat such costs as eligible fuel expense.

249. Special circumstances exist and it is appropriate for ETI to recover the rough production cost equalization costs reallocated to ETI as a result of the FERC’s decision in Order No. 720-A.

Other Issues 250. A deferred accounting of ETI’s Midwest Independent Transmission System Operator (MISO) transition expenses is not necessary to carry out any requirement of PURA.

251. ETI should include $1.6 million in base rates for MISO transition expense.

252. Deleted.

253. Transmission Cost Recovery Factor baseline values should be set during the compliance phase of this docket, after the Commission makes final rulings on the various contested issues that may affect this calculation.

254. Distribution Cost Recovery Factor baseline values should be set during the compliance phase of this docket, after the Commission makes final rulings on the various contested issues that may affect this calculation.

255. The appropriate amount for ETI’s purchased-power capacity expense to be included in base rates is $245,965,886.

256. The amount of ETI’s purchased-power capacity expense includes third-party contracts, legacy affiliate contracts, other affiliate contracts, and reserve equalization. Whether the amounts for all contracts should be included in the baseline for a purchased-capacity rider that may be approved in Project No. 39246 is an issue that should be decided in that project.

PUC Docket No. 39896 Order on Rehearing Page 40 of 44 SOAH Docket No. XXX-XX-XXXX

III. Conclusions of Law 1. ETI is a “public utility” as that term is defined in PURA § 11.004(1) and an “electric utility” as that term is defined in PURA § 31.002(6).

2. The Commission exercises regulatory authority over ETI and jurisdiction over the subject matter of this application pursuant to PURA §§ 14.001, 32.001, 32.101, 33.002, 33.051, 36.101–.111, and 36.203.

3. SOAH has jurisdiction over matters related to the conduct of the hearing and the preparation of a proposal for decision in this docket, pursuant to PURA § 14.053 and TEX. GOV’T CODE ANN. § 2003.049.

4. This docket was processed in accordance with the requirements of PURA and the Texas Administrative Procedure Act, Tex. Gov’t Code Ann. Chapter 2001.

5. ETI provided notice of its application in compliance with PURA § 36.103, P.U.C. PROC.

R. 22.51(a), and P.U.C. SUBST. R. 25.235(b)(1)-(3).

6. Pursuant to PURA § 33.001, each municipality in ETI’s service area that has not ceded jurisdiction to the Commission has jurisdiction over the company’s application, which seeks to change rates for distribution services within each municipality.

7. Pursuant to PURA § 33.051, the Commission has jurisdiction over an appeal from a municipality’s rate proceeding.

8. ETI has the burden of proving that the rate change it is requesting is just and reasonable pursuant to PURA § 36.006.

9. In compliance with PURA § 36.051, ETI’s overall revenues approved in this proceeding permit ETI a reasonable opportunity to earn a reasonable return on its invested capital used and useful in providing service to the public in excess of its reasonable and necessary operating expenses.

10. Consistent with PURA § 36.053, the rates approved in this proceeding are based on original cost, less depreciation, of property used and useful to ETI in providing service.

11. The ADFIT adjustments approved in this proceeding are consistent with PURA § 36.059 and P.U.C. SUBST. R. 25.231(c)(2)(C)(i).

PUC Docket No. 39896 Order on Rehearing Page 41 of 44 SOAH Docket No. XXX-XX-XXXX

12. Including the cash working capital approved in this proceeding in ETI’s rate base is consistent with P.U.C. SUBST. R. 25.231(c)(2)(B)(iii)(IV), which allows a reasonable allowance for cash working capital to be included in rate base.

13. The ROE and overall rate of return authorized in this proceeding are consistent with the requirements of PURA §§ 36.051 and 36.052.

14. The affiliate expenses approved in this proceeding and included in ETI’s rates meet the affiliate payment standards articulated in PURA §§ 36.051, 36.058, and Railroad Commission of Texas v. Rio Grande Valley Gas Co., 683 S.W.2d 783 (Tex. App.— Austin 1984, no writ).

15. The ADFIT adjustments approved in this proceeding are consistent with PURA § 36.059 and P.U.C. SUBST. R. 25.231(c)(2)(C)(i).

16. Pursuant to P.U.C. SUBST. R. 25.231(b)(1)(F), the decommissioning expense approved in this case is based on the most current information reasonably available regarding the cost of decommissioning, the balance of funds in the decommissioning trust, anticipated escalation rates, the anticipated return on the funds in the decommissioning trust, and other relevant factors.

17. ETI has demonstrated that its eligible fuel expenses during the reconciliation period were reasonable and necessary expenses incurred to provide reliable electric service to retail customers as required by P.U.C. SUBST. R. 25.236(d)(1)(A). ETI has properly accounted for the amount of fuel-related revenues collected pursuant to the fuel factor during the reconciliation period as required by P.U.C. SUBST. R. 25.236(d)(1)(C).

18. ETI prudently managed the dispatch, operations, and maintenance of its fossil plants during the reconciliation period.

19. The reconciliation period level operating and maintenance expenses for the Spindletop facility are eligible fuel expenses pursuant to P.U.C. SUBST. R. 25.236(a).

19A. Fuel factors under P.U.C. SUBST. R. 25.237(a)(3) are temporary rates subject to revision in a reconciliation proceeding.

PUC Docket No. 39896 Order on Rehearing Page 42 of 44 SOAH Docket No. XXX-XX-XXXX

19B. P.U.C. SUBST. R. 25.236(d)(2) defines the scope of a fuel reconciliation proceeding to include any issue related to the reasonableness of a utility’s fuel expenses and whether the utility has over- or under-recovered its reasonable fuel expenses. It is proper to use the new line-loss study to calculate Entergy’s fuel reconciliation and over-recovery.

20. Special circumstances are warranted pursuant to P.U.C. SUBST. R. 25.236(a)(6) to recover rough production equalization payments reallocated to ETI by the FERC.

21. ETI’s rates, as approved in this proceeding, are just and reasonable in accordance with PURA § 36.003.

IV. Ordering Paragraphs In accordance with these findings of fact and conclusions of law, the Commission issues the following orders: 1. The proposal for decision prepared by the SOAH ALJs is adopted to the extent consistent with this Order.

2. ETI’s application is granted to the extent consistent with this Order.

3. ETI shall file in Tariff Control No. 40742 Compliance Tariff Pursuant to Final Order in Docket No. 39896 (Application of Entergy Texas, Inc. for Authority to Change Rates, Reconcile Fuel Costs, and Obtain Deferred Accounting Treatment) tariffs consistent with this Order within 20 days of the date of this Order. No later than ten days after the date of the tariff filings, Staff shall file its comments recommending approval, modification, or rejection of the individual sheets of the tariff proposal. Responses to the Staff’s recommendation shall be filed no later than 15 days after the filing of the tariff. The Commission shall by letter approve, modify, or reject each tariff sheet, effective the date of the letter.

4. The tariff sheets shall be deemed approved and shall become effective on the expiration of 20 days from the date of filing, in the absence of written notification of modification or rejection by the Commission. If any sheets are modified or rejected, ETI shall file proposed revisions of those sheets in accordance with the Commission’s letter within ten PUC Docket No. 39896 Order on Rehearing Page 43 of 44 SOAH Docket No. XXX-XX-XXXX

days of the date of that letter, and the review procedure set out above shall apply to the revised sheets.

5. Copies of all tariff-related filings shall be served on all parties of record.

6. ETI shall prepare and file as part of its next base rate case a study regarding the feasibility of instituting LED-based rates and, if the study shows that such rates are feasible, ETI should file proposals for LED-based lighting and traffic signal rates in that case. If ETI has LED lighting customers taking service, the study shall include detailed information regarding differences in the cost of serving LED and non-LED lighting customers. ETI shall provide the results of this study to Cities and interested parties as soon as practicable, but no later than the filing of its next rate case.

7. All other motions, requests for entry of specific findings of fact and conclusions of law, and any other requests for general or specific relief, if not expressly granted, are denied.

PUC Docket No. 39896 Order on Rehearing Page 44 of 44 SOAH Docket No. XXX-XX-XXXX

SIGNED AT AUSTIN, TEXAS the ______ day of October 2012.

PUBLIC UTILITY COMMISSION OF TEXAS

______________________________________________ DONNA L. NELSON, CHAIRMAN

______________________________________________ ROLANDO PABLOS, COMMISSIONER I respectfully dissent regarding the utility- and executive-management-class affiliate transactions. To be consistent with Commission precedent in Docket No. 14965,37 the indirect costs of the management of Entergy’s ultimate parent should not be borne by Texas ratepayers.

Therefore, I would disallow the following: $173,867 for Project No. F3PCCPM001 (Corporate Performance Management); $372,919 for Project No. F3PCC31255 (Operations-Office of the CEO); and $74,485 for Project No. F3PPCOO001 (Chief Operating Officer). I join the Commission in all other respects for this Order.

______________________________________________ KENNETH W. ANDERSON, JR., COMMISSIONER

q:\cadm\orders\final\39000\39896o on reh.docx

Application of Central Power and Light Company for Authority to Change Rates, Docket No. 14965, Second Order on Rehearing (Oct. 16, 1997).

APPENDIX C District Court's Final Judgment DC BK1429S PG132 Filed In 'fh o· of Travis ~ •strict Cour:· ounty, Texas EM OCT 1~ tUlli CAUSE NO. D-l-GN-13-000121 At (/ .J.q. A AmaliaRodriguez-Mendoza, c;;~·

ENTERGY TEXAS, INC., § IN THE DISTRICT COURT OF Plaintiff § § v. § TRAVIS COUNTY, TEXAS § PUBLIC UTILITY COMMISSION, § Defendant § 353RD JUDICIAL DISTRICT

ORDER ON ADMINISTRATIVE APPEAL On July 22, 2014, the Court heard Plaintiffs appeal from Defendant's Order in PUC Docket No. 39896, SOAH Docket No. XXX-XX-XXXX. The administrative record was admitted into evidence, and the Court heard oral argument. Entergy, the Cities, and OPUC each asserted points of error challenging the Commission's order. Having considered the pleadings, the evidence and the arguments of counsel, the Court makes the following rulings:

l . Entergy's Point of Error No. 1 addressing the use of a current line loss study rather that a prior-approved line loss study in allocating line loss costs among classes of customers establishes that the Commission erred in applying the current study in violation of Commission rules found at 16 TAC §25.236(e)(3) and 16 TAC 25.237(a) and (c)(2)(B). Accordingly, the Court FINDS that the PUC's ruling was arbitrary and capricious and constitutes an error of law. The Court REVERSES such ruling and REMANDS this matter to the Commission for further proceedings consistent with this Court's Order.

2. All other points of error are DENIED, and the Commission' s Order is in all other respects AFFIRMED.

J APPENDIX D Commission's Final Order in Docket No. 37744 PUC DOCKET NO. 37744 SOAH DOCKET NO. XXX-XX-XXXX

APPLICATION OF ENTERGY TEXAS, § PUBLIC UTILITY COMMISSION INC. FOR AUTHORITY TO CHANGE § RATES AND RECONCILE FUEL § OF TEXAS COSTS §

ORDER

This Order addresses the application of Entergy Texas, Inc. (ETI) for authority to change rates and reconcile fuel costs. ETI, Commission Staff, the Office of Public Utility Counsel (OPUC), the Steering Committee of Cities Served by ETI (Cities),1 Texas Industrial Energy Consumers (TIEC), The Kroger Company (Kroger), and Wal-Mart Stores Texas, LLC and Sam’s East, Inc. (collectively Wal-Mart), through their duly authorized representatives entered into and filed a stipulation and settlement agreement that resolves all of the issues in this proceeding except the issues related to ETI’s proposal for competitive generation service.

Cottonwood Energy, L.P. and the State of Texas agencies and institutions of higher education (State Agencies) did not join but do not oppose the stipulation.

The Commission severed the competitive generation service issues into Docket No. 389512 in Order No. 14.

The Commission adopts the following findings of fact and conclusions of law:

Steering Committee of Cities is comprised of the Cities of Anahuac, Beaumont, Bridge City, Cleveland, Conroe, Groves, Houston, Huntsville, Montgomery, Navasota, Nederland, Oak Ridge North, Orange, Pine Forest, Pinehurst, Port Arthur, Port Neches, Rose City, Shenandoah, Silsbee, Sour Lake, Splendora, Vidor, and West Orange.

Application of Entergy Texas, Inc. for Approval of Competitive Generation Service Tariff (Issues Severed From Docket No. 37744), Docket No. 38951.

PUC Docket No. 37744 Order Page 2 of 15 SOAH Docket No. XXX-XX-XXXX

I. Findings of Fact Procedural History 1. On December 30, 2009, ETI filed an application requesting approval of (1) base rate tariffs and riders designed to collect an overall revenue requirement of $1,758.4 million, which includes a total non-fuel retail revenue requirement of $838.3 million (base rate revenues of $486 million plus revenue from riders of $352.3 million); (2) a set of proposed tariff schedules presented in the Electric Utility Rate Filing Package for Generating Utilities (RFP) accompanying ETI’s application; (3) a request for final reconciliation of ETI’s fuel and purchased power costs for the reconciliation period from April 1, 2007 to June 30, 2009; and (4) certain waivers to the instructions in RFP Schedule V accompanying ETI’s application.

2. The 12-month test year employed in ETI’s filing ended on June 30, 2009.

3. ETI provided notice by publication for four consecutive weeks before the effective date of the proposed rate change in newspapers having general circulation in each county of ETI’s Texas service territory. ETI also mailed notice of its proposed rate change to all of its customers. Additionally, ETI timely served notice of its statement of intent to change rates on all municipalities retaining original jurisdiction over its rates and services. ETI also published one-time supplemental notice by publication in newspapers and by bill insert.

4. The following parties were granted intervenor status in this docket: OPUC, Cities, Cottonwood, Kroger, State Agencies, TIEC, and Wal-Mart. Commission Staff was also a participant in this docket.

5. On January 4, 2010, the Commission referred this case to the State Office of Administrative Hearings (SOAH) for processing.

6. On February 19, 2010, the ALJs issued Order No. 3, which approved an agreement between ETI, Staff, Cities, State Agencies, OPUC, TIEC, Kroger, and Wal-Mart, to (1) establish an interim rate increase of $17.5 million annually above ETI’s then-existing base rates commencing with service rendered on and after May 1, 2010 subject to true-up and refund for service rendered prior to September 13, 2010 to the extent final PUC Docket No. 37744 Order Page 3 of 15 SOAH Docket No. XXX-XX-XXXX

overall rates established by the Commission amounted to less than a $17.5 million rate increase; (2) extend the jurisdictional deadline by which the Commission must issue a final order on the Company’s rate request from July 5, 2010 to November 1, 2010; (3) establish a September 13, 2010 effective date for rates such that, notwithstanding the extension of the jurisdictional deadline, the final overall rates established by the Commission would relate back to service rendered on and after September 13, 2010; (4) require ETI to publish supplemental notice, once in newspapers and by a bill insert, setting forth the effect of its proposed rate change in terms of the percentage increase in non-fuel revenues; and (5) establish a procedural schedule and discovery deadlines for this proceeding. Order No. 3 also granted Mr. Kurt Boehm’s motion for admission pro hac vice as counsel for Kroger and ETI’s February 3 and February 11, 2010 petitions for review of cities’ ordinances and motions to consolidate with respect to the rate decisions adopted by the Cities of Ames, Anderson, Bedias, Bevil Oaks, Bremond, Caldwell, Calvert, Chester, China, Colmesneil, Corrigan, Cut and Shoot, Daisetta, Dayton, Devers, Franklin, Groveton, Hardin, Hearne, Iola, Kosse, Kountze, Liberty, Lumberton, Madisonville, Midway, New Waverly, Normangee, Nome, Patton Village, Plum Grove, Riverside, Rose Hill Acres, Somerville, Taylor Landing, Todd Mission, Trinity, and Woodville.

7. On June 14, 2010, the ALJs issued Order No. 6 granting Staff’s June 1, 2010 motion and severing rate case expense issues to Docket No. 38346.3 Through Order No. 6, the ALJs also granted ETI’s March 12, April 29, and May 17 petitions for review and motions to consolidate with respect to the rate decisions adopted by the Cities of Anahuac, Beaumont, Bridge City, Cleveland, Conroe, Groves, Houston, Huntsville, Montgomery, Navasota, Nederland, Oak Ridge North, Orange, Panorama Village, Pine Forest, Pinehurst, Port Arthur, Port Neches, Roman Forest, Rose City, Shenandoah, Shepard, Silsbee, Sour Lake, Splendora, Vidor, West Orange, Willis, Woodbranch Village, and Woodloch.

Application of Entergy Texas, Inc. for Rate Case Expenses Severed from PUC Docket No. 37744, Docket No. 38346.

PUC Docket No. 37744 Order Page 4 of 15 SOAH Docket No. XXX-XX-XXXX

8. The hearing on the merits commenced on July 13, 2010 and was immediately recessed in order to facilitate settlement negotiations. The hearing was again convened on July 15, 2010, at which time the signatories announced their intent to continue settlement discussions to resolve all issues related to the Company’s application with the exception of those related to ETI’s proposal for competitive generation service (CGS) and associated riders.

9. On August 6, 2010, the signatories submitted the stipulation resolving all outstanding issues regarding the Company’s application with the exception of those related to ETI’s CGS proposal. Under the stipulation, ETI will be allowed to implement base rate tariffs and riders designed to collect an overall revenue requirement of $1,614.9 million,4 which includes a total non-fuel retail revenue requirement of $694.9 million (base rate revenues of $599 million plus revenue from riders of $95.9 million). The signatories also submitted, on August 6, 2010, an agreed motion to revise interim rates and to consolidate the severed rate-case expense docket. The interim rates requested in the agreed motion mirrored the final rates proposed for Commission approval in the stipulation. The agreed motion further requested that the ALJs consolidate with the instant proceeding Docket No. 38346, related to severed Docket No. 37744 rate case expense issues, and admit the parties’ pre-filed exhibits into evidence.

10. On July 16 and July 20, 2010, the ALJs held the hearing on the merits with respect to ETI’s CGS proposal.

11. On August 9, 2010, the ALJs issued Order No. 12, granting approval of revised interim rates for usage on and after August 15, 2010.

12. On October 5, 2010, the ALJs issued a proposal for decision regarding issues related to ETI’s CGS proposal.

13. On October 5, 2010, the ALJs issued Order No. 13, ordering the consolidation of Docket No. 38346, related to severed rate-case expense issues, into the instant proceeding,

This figure includes fuel at test year prices. If current fuel prices are substituted for test year fuel prices, the overall revenue requirement figure would be $1,504.0 million.

PUC Docket No. 37744 Order Page 5 of 15 SOAH Docket No. XXX-XX-XXXX

admitting evidence, and returning this docket to the Commission consistent with the agreed motion filed on August 6, 2010.

14. The Commission considered this Docket at the November 10, 2010 and December 1, 2010 open meetings.

15. On November 30, 2010 ETI filed an unopposed motion to sever the competitive CGS issues from the settled issues in this docket. The Commission granted the motion at the December 1, 2010 open meeting and the Commission’s decision was memorialized in Order No. 14 issued on December 3, 2010. The CGS issues were severed into Docket No. 38951 in Order No. 14.

Description of the stipulation and Settlement Agreement 16. The signatories to the settlement stipulated that ETI should be allowed to implement an initial overall increase in base-rate revenues of $59 million for usage on and after August 15, 2010. The signatories further stipulated that they would request approval of interim rates by the ALJs presiding or by the Commission, as necessary, to ensure timely implementation of this initial rate increase. The signatories further stipulated that ETI should be allowed to implement an additional overall increase in base-rate revenues of $9 million on an annualized basis effective for bills rendered on and after May 2, 2011, the first billing cycle for the revenue month of May.

17. The signatories agreed that ETI’s authorized return on equity shall be 10.125% and its weighted average cost of capital shall be 8.5209%.

18. The signatories stipulated that the amount of rate increase authorized under finding of fact 16 includes rate-case expenses and contemplates their full amortization in 2010, and that this amount constitutes the full and final recovery of all rate-case expenses relating to Docket No. 37744.

19. The signatories stipulated to the amount of transmission and distribution invested capital by function as of June 30, 2009 as set out in attachment 1 to the stipulation.

PUC Docket No. 37744 Order Page 6 of 15 SOAH Docket No. XXX-XX-XXXX

20. The signatories stipulated that the Company’s proposed purchased-power recovery rider will not be approved in this docket, and purchased capacity costs will be included in base rates.

21. The signatories stipulated that the Company’s proposed transmission cost recovery factor (TCRF) will not be approved in this docket. The signatories stipulated to the baseline values as shown in attachment 2 to the stipulation to be used in the Company’s request, if any, for a TCRF in a separate proceeding.

22. The signatories agreed that ETI’s proposed cost-of-service adjustment rider and formula rate plan will not be approved in this docket.

23. The signatories stipulated that the Company’s proposed renewable-energy-credit rider will not be approved in this docket, and the Company’s renewable-energy-credit costs shall be recovered in base rates. The signatories further stipulated that a transmission customer that opts out pursuant to P.U.C. SUBST. R. 25.173(j) shall receive a credit that offsets the amount of renewable-energy-credit costs that are recovered in base rates from the transmission customer.

24. The signatories agreed that ETI’s proposed remote-communications-link rider should be approved as filed by the Company.

25. The signatories agreed that ETI’s proposed market-valued-energy-reduction service rider will not be approved in this docket.

26. The signatories reached the following specific agreements regarding rate design as a part of the overall resolution of this docket: a. Rate Schedule IS. Rate Schedule IS will be opened to new business. In the Company’s next base-rate case, the amount of interruptible credits recoverable from Texas retail customers shall be limited to an increase of $1 million more than the amount requested in this docket (or a total of $6.8 million); provided, however, that in the next rate case, the Company may request an exception to this limitation upon a showing that the test-year credit amount in excess of the $6.8 million cap is both cost effective and necessary to meet the Company’s generation reserve margin requirement. The signatories further agreed that the PUC Docket No. 37744 Order Page 7 of 15 SOAH Docket No. XXX-XX-XXXX

Company will not offer additional interruptible service if the availability of total interruptible service supplied by the Company under all interruptible service riders exceeds 5% of the projected aggregate Company peak demand unless the additional level of interruptible service offered in excess of the 5% cap is both cost effective and necessary to meet the Company’s generation reserve margin requirement. To the extent that the credit amount or participation level exceeds the limitations described in this paragraph and the Company includes test-year credits over the $6.8 million credit-amount cap or additional participation in excess of the 5% participation-level cap in its next rate case, the Company shall have the burden to prove whether those test-year credits or participation levels meet the standards established in this paragraph for inclusion in the test year. The standards in this paragraph are in addition to any requirements in PURA for inclusion of costs in rates. The signatories further agreed to the Schedule IS revisions shown on attachment 3 to the stipulation.

b. Rate Schedule IHE. The signatories agreed that no change shall be made to rate schedule IHE in this docket.

c. Lighting Class Rates. The signatories stipulated that the language under the paragraph relating to rate group C in rate schedule SHL will be revised to reflect that, where the Company agrees to install facilities other than its standard street light fixture and lamp as provided under Rate Group A, a lump sum payment will be required, based upon the installed cost of all facilities excluding the cost of the standard street light fixture and lamp, and the customer will be billed under rate group A.

e. Electric Extension Policy. The signatories agreed to the line-extension terms and conditions as reflected in attachment 4 to the stipulation.

f. Life-of-Contract Demand Ratchet. The signatories agreed that the life-of-contract demand ratchet provision in rate schedules Large Industrial Power Service, Large Industrial Power Service-Time of Day, General Service, General Service-Time of Day, Large General Service, and Large General Service-Time of PUC Docket No. 37744 Order Page 8 of 15 SOAH Docket No. XXX-XX-XXXX

Day shall be excluded from rate schedules in ETI’s next rate case. The signatories further stipulated that the foregoing rate schedules will be revised so that the life-of-contract demand ratchet provision shall not be applicable to new customers and shall not exceed the level in effect on August 15, 2010 for existing customers.

g. Residential Customer Charge. The signatories agreed that the residential customer charge shall be increased to $5.00.

h. Non-Sufficient Funds Charge. The signatories agreed that the non-sufficient funds charge shall be increased to $15.00.

27. The signatories agreed to the class cost allocation set forth in attachment 5 to the stipulation.

28. The signatories stipulated that the appropriate allocation between ETI’s wholesale and retail jurisdictions of baseline values and costs to be included in a TCRF is to be addressed in the proceeding, if any, in which ETI seeks approval of a TCRF.

29. The signatories stipulated that no party waives its right to address in any subsequent proceeding the appropriate treatment for Texas retail ratemaking purposes of power sales between ETI and Entergy Gulf States Louisiana, L.L.C. 30. The signatories reached the following specific agreements regarding fuel-related issues as part of the overall resolution of this docket: a. Agreed Fuel Disallowance. The Company stipulated to a fuel disallowance of $3.25 million not associated with any particular issue raised by the signatories.

The disallowance will be allocated pro rata with interest over each month of the reconciliation period and reflected in the refund in Docket No. 38403.5 The signatories stipulated that the Company’s fuel costs shall be finally reconciled for the reconciliation period of April 1, 2007 through June 30, 2009.

b. Rider IPCR. The signatories agreed that ETI’s eligible Rider IPCR costs for the

Application of Entergy Texas, Inc. to Implement an Interim Fuel Refund, Docket No. 38403, Order (Sept. 16, 2010).

PUC Docket No. 37744 Order Page 9 of 15 SOAH Docket No. XXX-XX-XXXX

period April 1, 2007 through the date the rider terminated shall be finally reconciled with a disallowance of $300,000. The signatories further agreed that the under-recovered balance of Rider IPCR costs shall be booked as fuel expense in the month in which the Commission issues an order adopting the stipulation; provided, however, that the under-recovered balance shall be allocated to customer classes using A&E4CP.

c. Rough Production Cost Equalization (RPCE) Payments. The signatories agreed that ETI will credit an additional $18.6 million to Texas fuel-factor customers, which the signatories stipulated represents the remaining portion of RPCE payments ETI received in 2007 that were at issue in Docket No. 35269.6 The RPCE credit shall be allocated to rate classes based on loss-adjusted kilowatt hours at plant for calendar year 2006. For customers in the Large Industrial Power Service rate class, the credit will be refunded based on the customer’s actual kWh usage during the billing months of January 2006 through December 2006. Upon issuance of a final order approving the stipulation, the RPCEs shall be credited to customers as a separate one-month bill credit in the same form as the RPCEA Rider last approved in Docket No. 38098.7 ETI agreed that it will terminate all appeals related to Docket No. 35269.

31. The signatories agreed that ETI will continue its accrual of storm-cost reserves at the level of $3.65 million annually and that this amount shall be subsumed in the base-rate revenue increase described in finding of fact 16 above.

32. The signatories agreed that ETI shall maintain River Bend depreciation rates at current levels, i.e., based on a 60-year life. River Bend decommissioning costs will be set at $2,019,000 annually, which is based upon a labor-factor escalation rate of 1.67%, an energy-factor escalation rate of 0.25%, and a waste-burial-factor-escalation rate of

Compliance Filing of Entergy Texas, Inc. Regarding Jurisdictional Allocation of 2007 System Agreement Payments, Docket No. 35269, Order (Jan. 7, 2009).

Application of Entergy Texas, Inc. for Authority to Implement New RPCEA Rate, Docket No. 38098, Order (July 1, 2010).

PUC Docket No. 37744 Order Page 10 of 15 SOAH Docket No. XXX-XX-XXXX

1.71%, resulting in an overall escalation rate of 3.62%, and net investment yields as follows: Nuclear-Decommissioning-Trust Projected Returns Tax-Qualified Non-Tax-Qualified Investments Investment 2010 5.475% 5.057% 2011 5.837% 5.236% 2012 6.306% 5.567% 2013 6.304% 5.607% 2014 6.481% 5.896% 2015 6.493% 5.909% 2016 6.412% 5.826% 2017 6.412% 5.830% 2018 6.364% 5.790% 2019 6.316% 5.748% 2020 6.268% 5.712% 2021 6.220% 5.670% 2022 2.503% 5.458% 2023 5.817% 5.055% 2024 5.382% 4.628% 2025 5.036% 4.516% 2026-2034 4.920% 4.409% 33. The signatories stipulated that the Company’s depreciation rates for non-River Bend production plant, transmission, distribution, and general plant will remain at current levels and the Company will maintain its accounting records on a prospective basis for purposes of depreciation accrual, depreciation reserve, retirements, additions, salvage, and cost of removal by FERC account.

Consistency of the Agreement with PURA and the Commission Requirements 34. Considered in light of (1) the pre-filed testimony by the parties entered into evidence and (2) the additional evidence and testimony admitted during the course of the hearing on the merits on the Company’s application, the stipulation is the result of compromise from each signatory, and these efforts, as well as the overall result of the stipulation viewed in light of the record evidence as a whole, support the reasonableness and benefits of the terms of the stipulation.

PUC Docket No. 37744 Order Page 11 of 15 SOAH Docket No. XXX-XX-XXXX

35. The evidence addressed in finding of fact 34 demonstrates that the rates, terms, and conditions resulting from the stipulation are just and reasonable and consistent with the public interest.

36. The total level of the Texas retail revenue requirement contemplated by the stipulation will allow ETI the opportunity to earn a reasonable return over and above its reasonable and necessary operating expense.

37. The stipulated revenue requirement is consistent with applicable provisions of PURA chapter 36 and the Commission’s rules.

38. To the extent that affiliate costs are included in the stipulated revenue requirement and fuel expense, they are reasonable and necessary for each class of affiliate costs presented in ETI’s application.

39. To the extent that affiliate costs are included in the stipulated revenue requirement and fuel expense, the price charged to ETI is not higher than the prices charged by the supplying affiliate for the same item or class of items to its other affiliates or divisions, or a non-affiliated person within the same market area or having the same market conditions.

40. The retail revenue requirement in the stipulation does not include any expenses prohibited from recovery under PURA.

41. A return on equity of 10.125% and a weighted average cost of capital of 8.5209% for ETI should be adopted consistent with the stipulation.

42. The agreed rate-design provisions and terms and conditions of service included in the stipulation are just and reasonable.

43. The treatment of rate-case expenses described in the stipulation is reasonable.

44. The Company’s proposed remote-communications-link rider as filed by the Company is reasonable.

45. The depreciation rates agreed to in the stipulation are just and reasonable.

PUC Docket No. 37744 Order Page 12 of 15 SOAH Docket No. XXX-XX-XXXX

46. The recovery of $2,019,000 annually for decommissioning costs of nuclear production assets based on the factors agreed to in the stipulation is reasonable.

47. A $3.65 million annual storm cost accrual is reasonable.

48. The class allocation methodologies described in the stipulation are just and reasonable.

49. The fuel and IPCR-related provisions of the stipulation are reasonable.

II. Conclusions of Law 1. ETI is a public utility as that term is defined in PURA § 11.004(1) and an electric utility as that term is defined in PURA § 31.002(6).

2. The Commission exercises regulatory authority over ETI and jurisdiction over the subject matter of this application pursuant to PURA §§ 14.001, 32.001, 32.101, 33.002, 33.051, 36.001–.111, 36.203, 39.452, and 39.455.

3. SOAH has jurisdiction over matters related to the conduct of the hearing and the preparation of a proposal for decision in this docket, pursuant to PURA § 14.053 and TEX. GOV’T CODE ANN. § 2003.049.

4. This docket was processed in accordance with the requirements of PURA, the Texas Administrative Procedure Act,8 and Commission rules.

5. ETI provided notice of its application in compliance with PURA § 36.103, P.U.C. PROC.

R. 22.51(a), and P.U.C. SUBST. R. 25.235(b)(1)-(3).

6. This docket contains no remaining contested issues of fact or law.

7. The stipulation, taken as a whole, is a just and reasonable resolution of all issues it addresses; results in just and reasonable rates, terms, and conditions; is supported by a preponderance of the credible evidence in the record; is consistent with the relevant provisions of PURA; and is consistent with the public interest.

8. ETI has properly accounted for the amount of fuel and IPCR-related revenues collected pursuant to the fuel factor and Rider IPCR.

TEX. GOV’T CODE ANN. Chapter 2001 (Vernon 2007 and Supp. 2009).

PUC Docket No. 37744 Order Page 13 of 15 SOAH Docket No. XXX-XX-XXXX

9. The revenue requirement, cost allocation, revenue distribution, and rate design implementing the stipulation result in rates that are just and reasonable, comply with the ratemaking provisions in PURA, and are not unreasonably discriminatory, preferential, or prejudicial.

10. Based on the evidence in this docket, the overall total invested capital through the end of the test year meets the requirement in PURA § 36.053(a) that electric utility rates be based on the original cost, less depreciation, of property used by and useful to the utility in providing service.

11. ETI has met its burden of proof in demonstrating that it is entitled to the level of retail base rate and rider revenue set out in the stipulation.

12. ETI has met its burden of proof in demonstrating that the rates resulting from the stipulation are just and reasonable, and consistent with PURA.

III. Ordering Paragraphs 1. ETI’s application seeking authority to change its rates; reconcile its fuel and purchased power costs for the Reconciliation Period from April 1, 2007 to June 30, 2009; and for other related relief is approved consistent with the above findings of fact and conclusions of law.

2. Rates, terms, and conditions consistent with the stipulation are approved.

3. The tariffs and riders consistent with the stipulation are approved for the initial and second step rate increases.

4. ETI’s request for waivers of RFP instructions (RFP Schedule V) is granted.

5. ETI shall adjust decommissioning expense related to the River Bend Nuclear Generating Station consistent with the terms of this Order.

6. Neither the stipulation and settlement agreement nor this Order constitutes the Commission's agreement with, or consent to, the manner in which ETI, or any entity affiliated with ETI, has interacted with any decommissioning trust to which ETI or its ratepayers have made contributions or provided funds. Furthermore, this Order in no PUC Docket No. 37744 Order Page 14 of 15 SOAH Docket No. XXX-XX-XXXX

way constitutes a waiver or release of any conduct, whether or not such conduct occurred before the date of this Order, that may constitute a violation of any provision of state law, including, without limitation, the rules and regulations of this Commission relating to nuclear decommissioning trust funds; or prevents the Staff of the Commission from opening an investigation and taking enforcement action relating to violations of such rules and regulations.

7. Nothing contained in this Order constitutes the consent or approval, explicit or implied, of any modification, amendment or clarification of any power purchase agreement between ETI and any other Entergy entity relating to the River Bend Station. Without limiting the foregoing, nothing contained in this Order shall constitute the consent or approval of any modification, amendment, or clarification of any power purchase agreement between ETI and any other Entergy entity relating to the River Bend Station, which is made to address any concerns raised by the NRC in its Request for Additional Information regarding the River Bend Station dated March 11, 2010.

8. The Rider IPCR costs and eligible fuel costs requested by ETI are, consistent with this Order, reconciled through June 30, 2009, and are approved consistent with the stipulation.

9. ETI shall adjust its fuel over/under recovery balance consistent with the findings in this Order.

10. ETI shall file an RPCEA Rider consistent with the above findings of fact and conclusions of law to be effective with the first billing cycle of the billing month immediately following the effective date of this Order.

11. Because the final approved rates are equal to or higher than the interim rates adopted in Order No. 3, no refund of the interim rates authorized by Order No. 3 is necessary.

12. The interim rates approved in Order No. 12 are herby approved for the initial step rate increase contemplated by the stipulation, and ETI shall implement the second step rates for bills rendered on and after May 2, 2011, the first billing cycle for the revenue month of May.

PUC Docket No. 37744 Order Page 15 of 15 SOAH Docket No. XXX-XX-XXXX

13. Within 30 days of the date of this Order, ETI shall file a clean copy of all of the tariffs and schedules approved in this docket and a clean copy of the attachments to the stipulation.

14. The entry of this Order consistent with the stipulation does not indicate the Commission’s endorsement of any principle or method that may underlie the stipulation. Neither should entry of this Order be regarded as a precedent as to the appropriateness of any principle or methodology underlying the stipulation.

15. All other motions, requests for entry of specific findings of fact, conclusions of law, and ordering paragraphs, and any other requests for general or specific relief, if not expressly granted in this order, are hereby denied.

SIGNED AT AUSTIN, TEXAS the ______ day of December 2010

PUBLIC UTILITY COMMISSION OF TEXAS

BARRY T. SMITHERMAN, CHAIRMAN

DONNA L. NELSON, COMMISSIONER

KENNETH W. ANDERSON, JR., COMMISSIONER

q:\cadm\orders\final\37000\37744fo.docx Page 1 (Pages 1-4) Page i Page iii · · · · · · · ··SOAH DOCKET NO. XXX-XX-XXXX ·1· ·1· · · · · · · · ·TABLE OF CONTENTS (CONTINUED) ··· ·2· · · · · · · · · · · · · · · · · · · · · · · · · · · ·PAGE · · · · · · · · · ·PUC DOCKET NO. 39896 ·2· ··· ·3· ·PRESENTATION ON BEHALF OF · ·3· ··ENTERGY · TEXAS, INC. (CONTINUED) ··· ·APPLICATION OF ENTERGY· ··)· ·STATE OFFICE OF ·4· ·4· · ··TEXAS, · INC., FOR· · · · ··) ·AUTHORITY TO CHANGE RATES ) ·5· ···· ··CHRIS E. BARRILLEAUX ··AND · RECONCILE FUEL COSTS, ) ·5· · · · · · ·- Direct (Olson)· · · · · · · · · · · · · ·149 ·AND OBTAIN DEFERRED· · · ·) ·6· ··ACCOUNTING · TREATMENT· · ··) ADMINISTRATIVE HEARINGS ···· · · · ·- Cross (Lawton)· · · · · · · · · · · · · ·151 · ·7· ·6· · · · · · ·- Cross (Griffiths)· · · · · · · · · · · ··167 ··· · ·8· ···· · · · ·- Redirect (Olson)· · · · · · · · · · · · ·187 ··· ·7· · · · · · ·- Recross (Lawton)· · · · · · · · · · · · ·198 · ·9· ··· ·8· · · ··SAMUEL C. HADAWAY · 10· ···· · · · ·- Direct (Williams)· · · · · · · · · · · ··199 ··· · · · · · · · · · ·HEARING ON THE MERITS 11· ·9· · · · · · ·- Cross (Lawton)· · · · · · · · · · · · · ·201 ··· · · · · · · · ··Wednesday, April 25, 2012 12· ···· · · · ·- Cross (Griffiths)· · · · · · · · · · · ··212 ··· 10· · · · · · ·- Cross (Kelley)· · · · · · · · · · · · · ·230 · 13· ··· ···· · · · ·- Redirect (Williams)· · · · · · · · · · ··231 · 14· 11· · · · · · ·- Recross (Griffiths)· · · · · · · · · · ··239 ··· · · · · · · · · · ··TABLE OF CONTENTS 15· 12· ·PROCEEDINGS RECESSED· · · · · · · · · · · · · · · · ·246 ··· 13· · · · · · · · ·(Volume 2, Pages i through xxiv) 16· ··· 14· · · 17· 15· · ··· · 18· 16· · ··· · 19· 17· · ··· 18· · · 20· ··· 19· · · 21· 20· · ··· · 22· 21· · ··· 22· · · 23· ··· 23· · · 24· 24· · ··· · 25· 25· · Page ii Page iv ·1· · · · · · · · ·TABLE OF CONTENTS ·1· · · · · · · · · ··TABLE OF CONTENTS ··· ·2· · · · · · · · · · · · · · · · · · · · · · · · · · · ·PAGE ·2· · · · · · · · · · · · · · · · · · · · · · · · · · · ·PAGE ·3· ·PROCEEDINGS, WEDNESDAY, APRIL 25, 2012 - VOLUME 2· ··248 ··· ·4· ·PRESENTATION ON BEHALF OF ·3· ·PROCEEDINGS, TUESDAY, APRIL 24, 2012 - VOL. 1· · · · ··5 ··ENTERGY · TEXAS, INC. (CONTINUED)· · · · · · · · · · ··250 ··· ·4· ·OPENING STATEMENT ON BEHALF OF ·5· · ··ENTERGY · TEXAS, INC. (Neinast)· · · · · · · · · · · · ·16 ···· ··ROBERT D. SLOAN ·5· · ·6· · · · · · ·- Direct (Cyr)· · · · · · · · · · · · · · ·250 ··OPENING · STATEMENT ON BEHALF OF ···· · · · ·- Cross (Kelley)· · · · · · · · · · · · · ·253 ·6· ·ENTERGY TEXAS, INC. (Wren)· · · · · · · · · · · · · ··22 ·7· · · · · · ·- Cross (Ferris)· · · · · · · · · · · · · ·258 ··· ···· · · · ·- Redirect (Cyr)· · · · · · · · · · · · · ·285 ·7· ·OPENING STATEMENT ON BEHALF OF ·8· · · · · · ·- Recross (Ferris)· · · · · · · · · · · · ·295 ··CITIES · (Lawton)· · · · · · · · · · · · · · · · · · · ·37 ·9· · · ··H. VERNON PIERCE, JR. ·8· · ···· · · · ·- Direct (Cyr)· · · · · · · · · · · · · · ·303 ··OPENING · STATEMENT ON BEHALF OF ·9· ·TEXAS INDUSTRIAL ENERGY CONSUMERS (VanMiddlesworth)· ·41 10· · · · · · ·- Cross (Mack)· · · · · · · · · · · · · · ·305 ··· ···· · · · ·- Cross (Younger)· · · · · · · · · · · · ··315 10· ·OPENING STATEMENT ON BEHALF OF 11· · ··OFFICE · OF PUBLIC UTILITY COUNSEL (Ferris)· · · · · · ·49 ···· ··MICHAEL P. CONSIDINE 11· · 12· · · · · · ·- Direct (Neinast)· · · · · · · · · · · · ·317 ··OPENING · STATEMENT ON BEHALF OF ···· · · · ·- Cross (Lawton)· · · · · · · · · · · · · ·318 12· ·STAFF (Smyth)· · · · · · · · · · · · · · · · · · · · ·52 13· · · · · · ·- Cross (Griffiths)· · · · · · · · · · · ··352 ··· ···· · · · ·- Cross (Kelley)· · · · · · · · · · · · · ·355 13· ·OPENING STATEMENT ON BEHALF OF ··THE · UNITED STATES DEPARTMENT OF ENERGY (Porter)· · · ·54 14· · · · · · ·- Redirect (Neinast)· · · · · · · · · · · ·358 14· · ···· · · · ·- Recross (Lawton)· · · · · · · · · · · · ·362 ··· 15· · 15· ·PRESENTATION ON BEHALF OF ··AFTERNOON · SESSION· · · · · · · · · · · · · · · · · ··365 ··ENTERGY · TEXAS, INC.· · · · · · · · · · · · · · · · · ·60 16· · 16· · ··PRESENTATION · ON BEHALF OF ···· ··JOSEPH DOMINO 17· ·ENTERGY TEXAS, INC. (CONTINUED)· · · · · · · · · · ··366 17· · · · · · ·- Direct (Wren)· · · · · · · · · · · · · · ·60 18· · · ··WALTER C. FERGUSON ···· · · · ·- Cross (Lawton)· · · · · · · · · · · · · ··62 ···· · · · ·- Direct (McNally)· · · · · · · · · · · · ·366 18· · ··AFTERNOON · SESSION· · · · · · · · · · · · · · · · · ··103 19· · · · · · ·- Cross (Ferris)· · · · · · · · · · · · · ·367 19· · ···· · · · ·- Redirect (McNally)· · · · · · · · · · · ·369 ··PRESENTATION · ON BEHALF OF 20· · · · · · ·- Recross (Ferris)· · · · · · · · · · · · ·372 20· ·ENTERGY TEXAS, INC. (CONTINUED) ···· · · · ·- Further Redirect (McNally)· · · · · · · ·374 ··· 21· · 21· · · ··JOSEPH DOMINO ···· ··DANE A. WATSON ···· · · · ·- Cross (Lawton - Continued)· · · · · · · ·103 22· · · · · · ·- Direct (Williams)· · · · · · · · · · · ··376 22· · · · · · ·- Cross (VanMiddlesworth)· · · · · · · · ··115 ···· · · · ·- Cross (Lawton)· · · · · · · · · · · · · ·380 ···· · · · ·- Cross (Kelley)· · · · · · · · · · · · · ·131 23· · · · · · ·- Redirect (Wren)· · · · · · · · · · · · ··139 23· · · · · · ·- Cross (Lawler)· · · · · · · · · · · · · ·397 ···· · · · ·- Recross (Lawton)· · · · · · · · · · · · ·143 ···· · · · ·- Redirect (Williams)· · · · · · · · · · ··403 24· · · · · · ·- Recross (VanMiddlesworth)· · · · · · · ··144 24· · · · · · ·- Recross (Lawton)· · · · · · · · · · · · ·410 ··· ···· · · · ·- Recross (Lawler)· · · · · · · · · · · · ·414 25· · 25· ·

KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 51 (Pages 447-450) Page 447 Page 449 ·1·· ·understand your term of human resource costs, to the ·1·· · · ·A· ··It's my rebuttal testimony and exhibits. ·2·· ·extent that there were labor dollars applied to a ·2·· · · ·Q· ··Okay.··Was your direct testimony, rebuttal ·3·· ·project, and my schedule will often have the impact ·3·· ·testimony, and exhibits prepared by you or under your ·4·· ·through the loading of benefits.··And so through that ·4·· ·supervision? ·5·· ·mechanism, I see that, but I couldn't tell you that it ·5·· · · ·A· ··Yes, it was. ·6·· ·had to do with human resource costs in the sense of work ·6·· · · ·Q· ··Do you have any corrections you need to make to ·7·· ·that I would do or anybody on my staff. ·7·· ·your testimony? ·8·· · · ·Q· ··I understand.··But it's in the human resources ·8·· · · ·A· ··No. ·9·· ·class on your exhibit. ·9·· · · ·Q· ··If I were to ask you the same questions today 10·· · · ·A· ··Ma'am, I understand. 10·· ·that were asked in your written testimony, would your 11·· · · ·Q· ··Yes. 11·· ·answers be the same?

12·· · · · · · · · ·MS. KELLEY:··I have no further questions, 12·· · · ·A· ··Yes.

13·· ·and I would offer State Agency Exhibit No. 3. 13·· · · · · · · · ·MR. OLSON:··All right.··Your Honor, at 14·· · · · · · · · ·JUDGE WALSTON:··Any objection? 14·· ·this time, we move for the admission of ETI 32 and 59.

15·· · · · · · · · ·MR. BRITT:··Just with the caveat that it's 15·· · · · · · · · ·JUDGE WALSTON:··Okay.··ETI Exhibits 32 and 16·· ·subject to check and verification. 16·· ·59 are admitted.

17·· · · · · · · · ·JUDGE WALSTON:··Subject to verification, 17·· · · · · · · · ·(Exhibit ETI Nos. 32 and 59 admitted) 18·· ·State's Exhibit 3 is admitted. 18·· · · · · · · · ·MR. OLSON:··All right.··At this time, I 19·· · · · · · · · ·(Exhibit State No. 3 admitted) 19·· ·offer the witness for cross-examination.

20·· · · · · · · · ·JUDGE WALSTON:··Public Utility Counsel? 20·· · · · · · · · ·JUDGE WALSTON:··Cities?

21·· · · · · · · · ·MS. FERRIS:··No questions, Your Honor. 21·· · · · · · · · ·MR. MACK:··No questions.

22·· · · · · · · · ·JUDGE WALSTON:··Okay.··Staff? 22·· · · · · · · · ·JUDGE WALSTON:··TIEC?

23·· · · · · · · · ·MR. SMYTH:··No questions. 23·· · · · · · · · ·MS. GRIFFITHS:··Yes, Your Honor.

24·· · · · · · · · ·JUDGE WALSTON:··Redirect? 24·· · 25·· · · · · · · · ·MR. BRITT:··No questions, Your Honor. 25·· · Page 448 Page 450 ·1·· · · · · · · · ·JUDGE WALSTON:··Okay.··Thank you, ·1·· · · · · · · · · · · ·CROSS-EXAMINATION ·2·· ·Mr. Gardner. ·2·· ·BY MS. GRIFFITHS: ·3·· · · · · · · · ·WITNESS GARDNER:··Thank you. ·3·· · · ·Q· ··Good afternoon, Mr. McCulla.··You're here today ·4·· · · · · · · · ·JUDGE WALSTON:··Will you raise your right ·4·· ·for your direct and your rebuttal testimony.··Correct? ·5·· ·hand? ·5·· · · ·A· ··That's correct. ·6·· · · · · · · · ·(Witness McCulla sworn) ·6·· · · ·Q· ··All right.··And what was your title again, ·7·· · · · · · · · ·JUDGE WALSTON:··State your full name. ·7·· ·Mr. McCulla? ·8·· · · · · · · · ·WITNESS McCULLA:··Mark F. McCulla. ·8·· · · ·A· ··Vice president of transmission regulatory ·9·· · · · · · · · ·JUDGE WALSTON:··Thank you. ·9·· ·compliance.

10·· · · · · · · · · · · ·MARK F. McCULLA, 10·· · · ·Q· ··Okay.··And as vice president of transmission 11·· ·having been first duly sworn, testified as follows: 11·· ·and regulatory compliance, you know what MSS-2 means, do 12·· · · · · · · · · · ··DIRECT EXAMINATION 12·· ·you not?

13·· ·BY MR. OLSON: 13·· · · ·A· ··Yes.

14·· · · ·Q· ··Mr. McCulla, you just stated your name.··Please 14·· · · ·Q· ··Okay.··What is MSS-2?

15·· ·state your title and position with the Company. 15·· · · ·A· ··It's schedule that's used for transmission 16·· · · ·A· ··I'm the vice president of transmission 16·· ·facilities, but certain qualifications are equalized 17·· ·regulatory compliance. 17·· ·because they lend themselves to serving the needs of the 18·· · · ·Q· ··Okay.··You have in front of you what has been 18·· ·entire system.

19·· ·marked ETI Exhibit 32.··Do you see that? 19·· · · ·Q· ··Okay.··So MSS-2 is part of the Entergy system 20·· · · ·A· ··I do. 20·· ·agreement which is a FERC-approved schedule.··Correct?

21·· · · ·Q· ··Can you please identify that exhibit? 21·· · · ·A· ··That's correct.

22·· · · ·A· ··It's my direct testimony and exhibits. 22·· · · ·Q· ··All right.··And is it fair to say that what 23·· · · ·Q· ··Okay.··And you also have before you ETI 59. 23·· ·MSS-2 does is it equalizes the costs of transmission 24·· · · ·A· ··I do. 24·· ·investment across the Entergy system for particular 25·· · · ·Q· ··Can you identify that, please? 25·· ·transmission projects that I believe are at 230-kV and

KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 52 (Pages 451-454) Page 451 Page 453 ·1·· ·above?··Is that accurate? ·1·· ·don't know if this is the right word or the right way to ·2·· · · ·A· ··230 and above and other qualifications, tie ·2·· ·phrase it -- but essentially embodied in this number ·3·· ·lines and other things like that.··But generally 230 and ·3·· ·that the Company is requesting as an increase in its ·4·· ·above is correct. ·4·· ·MSS-2 expense.··Is that correct? ·5·· · · ·Q· ··Okay.··And an issue in this case is the amount ·5·· · · ·A· ··Yes, that's correct. ·6·· ·of MSS-2 expense that the Company is entitled to.··Is ·6·· · · ·Q· ··All right.··Now, you have some familiarity with ·7·· ·that fair to say? ·7·· ·the MSS-2 service schedule? ·8·· · · ·A· ··That's one of the issues, yes. ·8·· · · ·A· ··Some familiarity. ·9·· · · ·Q· ··All right.··And the Company is requesting, as ·9·· · · ·Q· ··All right.··Is it accurate that MSS-2 -- that 10·· ·part of its rate request here -- as part of the about 10·· ·there are various inputs to the MSS-2 calculation?··In 11·· ·104 or $10 million -- whatever it is -- rate request -- 11·· ·that I mean that there are various inputs to how much 12·· ·approximately $10.6 million in MSS-2 expense.··Correct? 12·· ·each operating company must pay to figure out what their 13·· · · ·A· ··That's correct. 13·· ·MSS-2 expense is going to be.

14·· · · ·Q· ··And you offer rebuttal testimony on that issue. 14·· · · ·A· ··I wouldn't say I'm very familiar with the 15·· ·Yes? 15·· ·calculation that takes place.··I'm familiar with the 16·· · · ·A· ··Yes, I do. 16·· ·assets -- the transmission assets and what -- what I'm 17·· · · ·Q· ··Okay.··So earlier today -- and I'm not sure if 17·· ·familiar with is whether they're determined to be 18·· ·you were here with -- when this testimony was given, but 18·· ·qualified as equalizable or not.··But as far as the 19·· ·Mr. Lawton with the Cities went over the post test year 19·· ·calculation and how it goes into the rates, I'm not as 20·· ·adjustment that the Company did for MSS-2 expense.··Were 20·· ·familiar with that.

21·· ·you here for that? 21·· · · ·Q· ··Okay.··I understand.··And I don't want to test 22·· · · ·A· ··I was not. 22·· ·your knowledge or give you a test on the FERC schedule, 23·· · · ·Q· ··Okay.··I believe what you have in front of 23·· ·because I counted the pages of the FERC schedule, and 24·· ·you -- it should have been passed out -- is a document 24·· ·it's about a seven-page calculation.

25·· ·that I'm not going to be admitting into the record, but 25·· · · ·A· ··Okay.··Thanks.

Page 452 Page 454 ·1·· ·it is labeled at the bottom WP/PAJ-23.1. ·1·· · · ·Q· ··But do you agree that that calculation does ·2·· · · ·A· ··Okay.··I have it in front of me. ·2·· ·look at various variables, and one of those variables ·3·· · · ·Q· ··All right.··And that is a workpaper that is a ·3·· ·will be the -- basically the inter-transmission ·4·· ·backup to Mr. Considine's testimony, because ·4·· ·investment on the system? ·5·· ·Mr. Considine also sponsored that post test year ·5·· · · ·A· ··Correct.··Yes. ·6·· ·adjustment for MSS-2 expense. ·6·· · · ·Q· ··All right.··And another variable will be the ·7·· · · · · · · · ·If you turn to Page 23.2 at the bottom -- ·7·· ·ownership or operating costs of a particular company. ·8·· ·just flip it over. ·8·· ·Correct? ·9·· · · ·A· ··Okay. ·9·· · · ·A· ··The -- 10·· · · ·Q· ··All right.··You'll see adjusted total, and 10·· · · ·Q· ··The ownership or operating costs?

11·· ·under that is approximately $10.7 million.··Correct? 11·· · · ·A· ··I'm not sure how that goes into it, but -- 12·· · · ·A· ··Yes.··Correct. 12·· · · ·Q· ··Okay.··Fair enough.··Do you know what the term 13·· · · ·Q· ··Okay.··And that correlates to the amount of 13·· ·"responsibility ratio" means?

14·· ·MSS-2 expense that the Company is requesting? 14·· · · ·A· ··I'm not familiar with how it's used.

15·· · · ·A· ··Okay. 15·· · · ·Q· ··Okay.··Do you understand that each particular 16·· · · ·Q· ··Is that accurate? 16·· ·operating company makes -- makes or receives MSS-2 -- 17·· · · ·A· ··Correct. 17·· · · ·A· ··Okay.

18·· · · ·Q· ··Okay.··And that is not a test year number, but 18·· · · ·Q· ··-- costs based -- 19·· ·it is a projected rate year number for MSS-2 expense. 19·· · · ·A· ··Yes.

20·· ·Correct? 20·· · · ·Q· ··-- on its particular responsibility ratio?

21·· · · ·A· ··That's my understanding.··What my rebuttal 21·· · · ·A· ··Okay.··Yes, I'm familiar with that.

22·· ·testimony was reflecting was the transmission projects 22·· · · ·Q· ··Okay.··So if an operating company has -- I know 23·· ·and their status and expected completion. 23·· ·it's all relative, but a higher responsibility ratio, 24·· · · ·Q· ··Okay.··But you understand that the projects 24·· ·its MSS-2 expense may go up depending upon its actual 25·· ·that you discussed in your rebuttal testimony were -- I 25·· ·costs?

KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 1 (Pages 1-4) Page i Page iii · · · · · · · ··SOAH DOCKET NO. XXX-XX-XXXX ·1· ·1· · · · · · · · ·TABLE OF CONTENTS (CONTINUED) ··· ·2· · · · · · · · · · · · · · · · · · · · · · · · · · · ·PAGE · · · · · · · · · ·PUC DOCKET NO. 39896 ·2· ··· ·3· ·PRESENTATION ON BEHALF OF · ·3· ··ENTERGY · TEXAS, INC. (CONTINUED) ··· ·APPLICATION OF ENTERGY· ··)· ·STATE OFFICE OF ·4· ·4· · ··TEXAS, · INC., FOR· · · · ··) ·AUTHORITY TO CHANGE RATES ) ·5· ···· ··CHRIS E. BARRILLEAUX ··AND · RECONCILE FUEL COSTS, ) ·5· · · · · · ·- Direct (Olson)· · · · · · · · · · · · · ·149 ·AND OBTAIN DEFERRED· · · ·) ·6· ··ACCOUNTING · TREATMENT· · ··) ADMINISTRATIVE HEARINGS ···· · · · ·- Cross (Lawton)· · · · · · · · · · · · · ·151 · ·7· ·6· · · · · · ·- Cross (Griffiths)· · · · · · · · · · · ··167 ··· · ·8· ···· · · · ·- Redirect (Olson)· · · · · · · · · · · · ·187 ··· ·7· · · · · · ·- Recross (Lawton)· · · · · · · · · · · · ·198 · ·9· ··· ·8· · · ··SAMUEL C. HADAWAY · 10· ···· · · · ·- Direct (Williams)· · · · · · · · · · · ··199 ··· · · · · · · · · · ·HEARING ON THE MERITS 11· ·9· · · · · · ·- Cross (Lawton)· · · · · · · · · · · · · ·201 ··· · · · · · · · · ·Thursday, April 26, 2012 12· ···· · · · ·- Cross (Griffiths)· · · · · · · · · · · ··212 ··· 10· · · · · · ·- Cross (Kelley)· · · · · · · · · · · · · ·230 · 13· ··· ···· · · · ·- Redirect (Williams)· · · · · · · · · · ··231 · 14· 11· · · · · · ·- Recross (Griffiths)· · · · · · · · · · ··239 ··· · · · · · · · · · ··TABLE OF CONTENTS 15· 12· ·PROCEEDINGS RECESSED· · · · · · · · · · · · · · · · ·246 ··· 13· · · · · ·(Volumes 1 through 3, Pages i through xxviii) 16· ··· 14· · · 17· 15· · ··· · 18· 16· · ··· · 19· 17· · ··· 18· · · 20· ··· 19· · · 21· 20· · ··· · 22· 21· · ··· 22· · · 23· ··· 23· · · 24· 24· · ··· · 25· 25· · Page ii Page iv ·1· · · · · · · · ·TABLE OF CONTENTS ·1· · · · · · · · · ··TABLE OF CONTENTS ·2· · · · · · · · · · · · · · · · · · · · · · · · · · · ·PAGE ·2· · · · · · · · · · · · · · · · · · · · · · · · · · · ·PAGE ·3· ·PROCEEDINGS, TUESDAY, APRIL 24, 2012 - VOL. 1· · · · ··5 ·3· ·PROCEEDINGS, WEDNESDAY, APRIL 25, 2012 - VOLUME 2· ··248 ·4· ·OPENING STATEMENT ON BEHALF OF ·4· ·PRESENTATION ON BEHALF OF ··ENTERGY · TEXAS, INC. (Neinast)· · · · · · · · · · · · ·16 ··ENTERGY · TEXAS, INC. (CONTINUED)· · · · · · · · · · ··250 ·5· · ·5· · ···· ··ROBERT D. SLOAN ··OPENING · STATEMENT ON BEHALF OF ·6· · · · · · ·- Direct (Cyr)· · · · · · · · · · · · · · ·250 ·6· ·ENTERGY TEXAS, INC. (Wren)· · · · · · · · · · · · · ··22 ···· · · · ·- Cross (Kelley)· · · · · · · · · · · · · ·253 ·7· ·OPENING STATEMENT ON BEHALF OF ·7· · · · · · ·- Cross (Ferris)· · · · · · · · · · · · · ·258 ··CITIES · (Lawton)· · · · · · · · · · · · · · · · · · · ·37 ···· · · · ·- Redirect (Cyr)· · · · · · · · · · · · · ·285 ·8· · ·8· · · · · · ·- Recross (Ferris)· · · · · · · · · · · · ·295 ··OPENING · STATEMENT ON BEHALF OF ·9· · · ··H. VERNON PIERCE, JR. ·9· ·TEXAS INDUSTRIAL ENERGY CONSUMERS (VanMiddlesworth)· ·41 ···· · · · ·- Direct (Cyr)· · · · · · · · · · · · · · ·303 10· ·OPENING STATEMENT ON BEHALF OF 10· · · · · · ·- Cross (Mack)· · · · · · · · · · · · · · ·305 ··OFFICE · OF PUBLIC UTILITY COUNSEL (Ferris)· · · · · · ·49 ···· · · · ·- Cross (Younger)· · · · · · · · · · · · ··315 11· · 11· · ···· ··MICHAEL P. CONSIDINE ··OPENING · STATEMENT ON BEHALF OF 12· · · · · · ·- Direct (Neinast)· · · · · · · · · · · · ·317 12· ·STAFF (Smyth)· · · · · · · · · · · · · · · · · · · · ·52 ···· · · · ·- Cross (Lawton)· · · · · · · · · · · · · ·318 13· ·OPENING STATEMENT ON BEHALF OF 13· · · · · · ·- Cross (Griffiths)· · · · · · · · · · · ··352 ··THE · UNITED STATES DEPARTMENT OF ENERGY (Porter)· · · ·54 ···· · · · ·- Cross (Kelley)· · · · · · · · · · · · · ·355 14· · 14· · · · · · ·- Redirect (Neinast)· · · · · · · · · · · ·358 15· ·PRESENTATION ON BEHALF OF ···· · · · ·- Recross (Lawton)· · · · · · · · · · · · ·362 ··ENTERGY · TEXAS, INC.· · · · · · · · · · · · · · · · · ·60 15· · 16· · ··AFTERNOON · SESSION· · · · · · · · · · · · · · · · · ··365 ···· ··JOSEPH DOMINO 16· · ··PRESENTATION · ON BEHALF OF 17· · · · · · ·- Direct (Wren)· · · · · · · · · · · · · · ·60 17· ·ENTERGY TEXAS, INC. (CONTINUED)· · · · · · · · · · ··366 ···· · · · ·- Cross (Lawton)· · · · · · · · · · · · · ··62 18· · · ··WALTER C. FERGUSON 18· · ···· · · · ·- Direct (McNally)· · · · · · · · · · · · ·366 ··AFTERNOON · SESSION· · · · · · · · · · · · · · · · · ··103 19· · · · · · ·- Cross (Ferris)· · · · · · · · · · · · · ·367 19· · ···· · · · ·- Redirect (McNally)· · · · · · · · · · · ·369 ··PRESENTATION · ON BEHALF OF 20· · · · · · ·- Recross (Ferris)· · · · · · · · · · · · ·372 20· ·ENTERGY TEXAS, INC. (CONTINUED) ···· · · · ·- Further Redirect (McNally)· · · · · · · ·374 21· · · ··JOSEPH DOMINO 21· · ···· · · · ·- Cross (Lawton - Continued)· · · · · · · ·103 ···· ··DANE A. WATSON 22· · · · · · ·- Direct (Williams)· · · · · · · · · · · ··376 22· · · · · · ·- Cross (VanMiddlesworth)· · · · · · · · ··115 ···· · · · ·- Cross (Lawton)· · · · · · · · · · · · · ·380 ···· · · · ·- Cross (Kelley)· · · · · · · · · · · · · ·131 23· · · · · · ·- Cross (Lawler)· · · · · · · · · · · · · ·397 23· · · · · · ·- Redirect (Wren)· · · · · · · · · · · · ··139 ···· · · · ·- Redirect (Williams)· · · · · · · · · · ··403 ···· · · · ·- Recross (Lawton)· · · · · · · · · · · · ·143 24· · · · · · ·- Recross (Lawton)· · · · · · · · · · · · ·410 24· · · · · · ·- Recross (VanMiddlesworth)· · · · · · · ··144 ···· · · · ·- Recross (Lawler)· · · · · · · · · · · · ·414 25· · 25· ·

KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 43 (Pages 681-684) Page 681 Page 683 ·1·· ·here showed a cost of $1,100, an increase of $100 over ·1·· · · · · · · · ·MR. VanMIDDLESWORTH:··Objection, as ·2·· ·Year 1 -- Year 1 to Year 3.··Do you see that? ·2·· ·leading.··I move to strike. ·3·· · · ·A· ··Yes. ·3·· · · · · · · · ·JUDGE BURKHALTER:··Sustained. ·4·· · · ·Q· ··Now, this is not rocket science.··Nobody will ·4·· · · ·Q· ··BY MR. WESTERBURG)··Let me ask you this, ·5·· ·be surprised by the simplicity of this.··But if it's ·5·· ·Mr. Cooper:··If you would clarify the record, what are ·6·· ·more, if the increase in capacity is actually greater ·6·· ·the costs based on that appear in this chart? ·7·· ·than $1,100 -- say $1,300 -- because of the increase in ·7·· · · ·A· ··The costs are based on the contracts between ·8·· ·capacity cost in Year 3, then under the chart that's ·8·· ·ETI and the counter-parties and the rates that are ·9·· ·been developed by Mr. VanMiddlesworth, does the revenue ·9·· ·established in those contracts.··So these would be 10·· ·of $1,100 cover the capacity cost? 10·· ·capacity costs associated with those contracts.··Reserve 11·· · · ·A· ··Not at that rate, no. 11·· ·equalization is also a part of the system agreement 12·· · · ·Q· ··All right.··I would like to also ask you -- 12·· ·contract, and those costs will be incurred as part of 13·· ·maybe turn to the chart.··It's a pretty popular item -- 13·· ·the system agreement expense.

14·· ·but I would like to ask you some questions about the 14·· · · ·Q· ··Does the calculation of the reserve 15·· ·Exhibit -- let's see.··I think it's TIEC Exhibit No. 15·· ·equalization have a load growth component?

16·· ·34 -- I think it's 34A.··It's the blow-up version -- 16·· · · ·A· ··No, not really.··The reserve equalization 17·· · · · · · · · ·MR. WESTERBURG:··Is this 34 or 34A?··34A. 17·· ·includes a number of different elements associated with 18·· ·Excuse me.··I need to get my numbering straight for the 18·· ·it.··The two main elements are the amount of capability 19·· ·record here, Your Honor. 19·· ·each company brings to the system's load.··And the other 20·· · · ·Q· ··(BY MR. WESTERBURG)··I'm talking about the 20·· ·main ingredient is each company's responsibility ratio, 21·· ·blown-up version -- Mr. Cooper, you can look at the 21·· ·so the responsibility ratio as a percentage of the 22·· ·actual size document or you can look at the larger 22·· ·system peak that each company shares.··And the extent 23·· ·document, which actually I find easier to look at, too, 23·· ·that a company is short -- in other words, they do not 24·· ·that Mr. VanMiddlesworth provided for us. 24·· ·have enough capability to meet their requirements -- 25·· · · ·A· ··I have it. 25·· ·then they would pay their responsibility ratio share of Page 682 Page 684 ·1·· · · ·Q· ··And explain to us what this is.··What is this ·1·· ·the excess from the long companies. ·2·· ·document? ·2·· · · ·Q· ··Now, the responsibility ratio that is the basis ·3·· · · ·A· ··This is a listing of contracts that ETI has ·3·· ·of the reserve equalization on Line 25 -- ·4·· ·entered into for the rate year, and it's divided up into ·4·· · · ·A· ··Yes. ·5·· ·third-party contracts and Legacy affiliate contracts, ·5·· · · ·Q· ··-- is that a projected responsibility ratio? ·6·· ·other affiliate contracts.··And then the last line item ·6·· · · ·A· ··Yes, it is.··It's based on the projected loads ·7·· ·is reserve equalization.··These are contracts that have ·7·· ·of all of the system companies during the rate year. ·8·· ·either been in place or will be coming on-line or new ·8·· · · ·Q· ··Okay.··Now, are there any other numbers on this ·9·· ·contracts that have been entered into for the rate year. ·9·· ·chart that are affected by a projected load?

10·· · · ·Q· ··Okay.··And I would like to ask you, Mr. Cooper, 10·· · · ·A· ··No, not that I'm aware of.

11·· ·these are capacity costs associated with those 11·· · · ·Q· ··With respect to the reserve equalization, do 12·· ·contracts.··Is that right? 12·· ·you know what the result would be if, in fact, the 13·· · · ·A· ··Yes, that's correct. 13·· ·projected load you have in this exhibit were held 14·· · · ·Q· ··Now, are the costs that we're looking at here 14·· ·constant from the test year?

15·· ·projections or are they contractually based? 15·· · · ·A· ··If we looked at the responsibility ratios of 16·· · · ·A· ··Well, they are contractually based projections 16·· ·each of the companies during the test year and we 17·· ·of what the costs will be.··So, you know, there are 17·· ·applied it to these contracts and rates, the reserve 18·· ·terms and conditions associated with delivery on these 18·· ·equalization would be about four and a half million 19·· ·contracts that, you know, if someone fails to deliver, 19·· ·dollars less for ETI.

20·· ·there may be penalties associated with the third-party 20·· · · ·Q· ··Now, there was a lot of talk about the EAI WBL, 21·· ·contracts.··But in general, they are contractually 21·· ·and that contract is reflected on Line 19.

22·· ·based. 22·· · · ·A· ··Yes.

23·· · · ·Q· ··Right.··In other words, they are charges that 23·· · · ·Q· ··To clarify for the Judges -- to the extent they 24·· ·the company will have to pay? 24·· ·may need it; they may not -- but for the record, the 25·· · · ·A· ··Yes. 25·· ·discussion about the operating committee minutes for

KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 44 (Pages 685-688) Page 685 Page 687 ·1·· ·what may have been referred to as a new WBL contract, ·1·· · · ·A· ··Yes. ·2·· ·when does that contract that is made the discussion of ·2·· · · ·Q· ··Mr. Cooper, now the chart we're looking at ·3·· ·the operating committee minutes, when does that contract ·3·· ·here, this is a revision.··Is that correct? ·4·· ·begin?··And if you could refer us to the chart. ·4·· · · ·A· ··Yes, it is. ·5·· · · ·A· ··The contract that was approved by the operating ·5·· · · ·Q· ··Okay.··And was the revision for the purpose of ·6·· ·committee in mid-March actually goes into effect in ·6·· ·reflecting the new WBL contract in January 2013? ·7·· ·January of 2013. ·7·· · · ·A· ··Yes, it was. ·8·· · · ·Q· ··Okay.··So what do we have represented for the ·8·· · · ·Q· ··Now, in the lower right-hand corner, the number ·9·· ·EAI WBL on Line 19, prior to January 13? ·9·· ·that is $275,800,000 and some additional dollars, I 10·· · · ·A· ··That's the existing EAI WBL contract. 10·· ·believe that's the total capacity charges that's 11·· · · ·Q· ··Okay.··Do you recall when the case was filed in 11·· ·indicated on the chart.··Does that represent a total of 12·· ·this docket, Mr. Cooper?··I'm just asking. 12·· ·all the charges on this chart?

13·· · · ·A· ··In November. 13·· · · ·A· ··Yes.

14·· · · ·Q· ··Right.··November.··And I see here that the 14·· · · ·Q· ··Okay.··Now, can you tell us whether or not that 15·· ·first date entry or the first month entry for this chart 15·· ·number that appears on your revised RRC-1 is higher or 16·· ·is June 12.··Do you see that? 16·· ·lower than the number that was there prior to the 17·· · · ·A· ··Yes, I do. 17·· ·revision?

18·· · · ·Q· ··Is it your understanding that that's the 18·· · · ·A· ··It's lower by about $400,000.

19·· ·beginning of what we refer to as the rate year? 19·· · · ·Q· ··Now, was that -- 20·· · · ·A· ··Yes, that is. 20·· · · · · · · · ·JUDGE ARNOLD:··Mr. Westerburg, you're 21·· · · ·Q· ··So was the company -- and were you, Mr. Cooper, 21·· ·getting into specific numbers.··Are those highly 22·· ·when you prepared this chart, projecting future cost? 22·· ·sensitive?

23·· · · · · · · · ·JUDGE BURKHALTER:··For what time period? 23·· · · · · · · · ·MR. WESTERBURG:··The totals, Your Honor, 24·· · · · · · · · ·MR. WESTERBURG:··Thank you. 24·· ·are not.··But I appreciate the warning.··Thank you.

25·· · · ·Q· ··(BY MR. WESTERBURG)··For the rate year. 25·· · · ·Q· ··(BY MR. WESTERBURG)··And can you tell us, Page 686 Page 688 ·1·· · · ·A· ··The EAI WBL, the contract that existed, that ·1·· ·Mr. Cooper, if that is attributable in part or in whole ·2·· ·was a projection of the MSS-4 costs associated with the ·2·· ·to the new WBL contract? ·3·· ·existing contract, yes. ·3·· · · ·A· ··That's the $400,000? ·4·· · · ·Q· ··How does the projection of the capacity cost ·4·· · · ·Q· ··Yes, the reduction in cost. ·5·· ·for your RRC-1, for the EAI WBL, how does that compare ·5·· · · ·A· ··Yes, that would be attributable to the change ·6·· ·to the projection of cost beginning in January '13 for ·6·· ·in the WBL contract. ·7·· ·the EAI WBL, in terms of the way that it was developed? ·7·· · · ·Q· ··What are the megawatts associated with the new ·8·· · · ·A· ··The way it was developed was similar.··We used ·8·· ·contract, beginning in January 2013? ·9·· ·a similar process to develop that.··The resources that ·9·· · · ·A· ··It's 186 megawatts.

10·· ·make up the new contract do not include two of the 10·· · · ·Q· ··And what were the megawatts associated with the 11·· ·nuclear units that Arkansas has. 11·· ·existing contract that runs through the end of this 12·· · · · · · · · ·So we eliminated those two resources from 12·· ·year?

13·· ·the WBL, and we then changed the megawatt amount, 13·· · · ·A· ··I believe it was 110 megawatts.

14·· ·because the total megawatts that ETI is going to be 14·· · · ·Q· ··As a result of the new WBL, is the company and 15·· ·receiving from this new contract has increased from 15·· ·customers receiving greater megawatts at a lesser cost?

16·· ·110 megawatts to 186 megawatts.··So we applied the new 16·· · · ·A· ··Yes, they are.

17·· ·megawatts and the rates that were the same from the 17·· · · ·Q· ··Are you aware of any -- back up, lay a 18·· ·existing contract, to the resources that are part of the 18·· ·predicate.··Have you reviewed the intervenors' testimony 19·· ·new WBL contract. 19·· ·on the issue of the EAI WBL?

20·· · · ·Q· ··Did the projections prior to January of 2013, 20·· · · ·A· ··Yes, I have.

21·· ·were they based on the MSS-4 rate of the system 21·· · · ·Q· ··Are you aware of any objections to the 22·· ·agreement? 22·· ·projected cost of the existing EAI WBL?

23·· · · ·A· ··Yes. 23·· · · ·A· ··No, I'm not.

24·· · · ·Q· ··The projections after January of 2013, were 24·· · · · · · · · ·JUDGE BURKHALTER:··When you say 25·· ·they based on the MMS-4 of the system agreement? 25·· ·"existing," are you talking about the original one?··I'm

KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 45 (Pages 689-692) Page 689 Page 691 ·1·· ·not sure I'm following you. ·1·· ·operating committee minutes.··Do you recall that? ·2·· · · · · · · · ·MR. WESTERBURG:··I'll ask the witness, ·2·· · · ·A· ··Yes, I do. ·3·· ·Your Honor. ·3·· · · ·Q· ··And my questions will be directed toward the ·4·· · · ·Q· ··(BY MR. WESTERBURG)··Can you clarify for us the ·4·· ·February operating committee minutes.··And you ·5·· ·meaning of "existing"? ·5·· ·understand the distinction? ·6·· · · ·A· ··The existing contract that goes through the end ·6·· · · ·A· ··Yes. ·7·· ·of 2012. ·7·· · · ·Q· ··Are you familiar with the processes of the ·8·· · · ·Q· ··And, Mr. Cooper, is that the contract ·8·· ·operating committee? ·9·· ·associated with the numbers -- well, let me just ask ·9·· · · ·A· ··I'm somewhat familiar with the processes, not 10·· ·you:··What numbers on this chart are associated with 10·· ·intimately familiar.

11·· ·what we refer to as the existing EAI WBL? 11·· · · ·Q· ··Have you had an experience with there being 12·· · · ·A· ··Those would be Line 19, June through December 12·· ·delays of the finality of presentations with operating 13·· ·of 2012. 13·· ·committee minutes?

14·· · · ·Q· ··Now, this MSS-4 tariff, do you know whether 14·· · · ·A· ··Yes.··As I mentioned, it typically takes at 15·· ·that is part of what's referred to as the Energy System 15·· ·least a month to get the minutes from the operating 16·· ·Agreement? 16·· ·committee subsequent to the actual meeting.

17·· · · ·A· ··Yes.··MSS-4 is a schedule in the system 17·· · · ·Q· ··Do you know whether or not the operating 18·· ·agreement. 18·· ·committee sometimes requests changes to those 19·· · · ·Q· ··Does the company have any discretion in the way 19·· ·presentations?

20·· ·it bills under that tariff? 20·· · · ·A· ··No, I do not.

21·· · · ·A· ··No.··That's a FERC-regulated tariff that the 21·· · · ·Q· ··Do you know -- I'm looking for the contract.

22·· ·company really has no discretion in how it bills. 22·· ·And I'm going to refer to the exhibit marked as TIEC 23·· · · ·Q· ··Do you know if there have been changes to that 23·· ·Exhibit No. 21.

24·· ·tariff -- scratch that and start again.··Do you know 24·· · · ·A· ··Yes, I have it.

25·· ·whether there will be changes to that tariff between now 25·· · · ·Q· ··Right now, is this also an exhibit that's made Page 690 Page 692 ·1·· ·and the time that the company implements the new WBL ·1·· ·an exhibit to your rebuttal testimony? ·2·· ·contract in January 2013? ·2·· · · ·A· ··Yes, it is. ·3·· · · ·A· ··No, I'm unaware of any changes. ·3·· · · ·Q· ··And what is it that we're looking at here, ·4·· · · ·Q· ··There was a discussion about the volatility of ·4·· ·Exhibit 21? ·5·· ·fuel cost, Mr. Cooper.··Is it your experience that the ·5·· · · ·A· ··This is the agreement between ETI and EAI for ·6·· ·cost of gas is volatile? ·6·· ·the WBL contract that begins in 2013. ·7·· · · ·A· ··Yes.··The cost of gas, as recently as several ·7·· · · ·Q· ··Do you have any knowledge, Mr. Cooper, ·8·· ·years ago, was $14 a million Btu.··And, you know, in ·8·· ·regarding whether there are or are not negotiations ·9·· ·recent weeks it's been two dollars a million Btu.··It ·9·· ·related to the signing of these kinds of agreements?

10·· ·goes up; it goes down. 10·· · · ·A· ··No, I do not.

11·· · · ·Q· ··Has it been your experience that it has gone up 11·· · · ·Q· ··Let me take you to Page 2 of the agreement.

12·· ·and down over relatively short periods of time? 12·· ·There is a page number in the lower right-hand corner 13·· · · ·A· ··It has gone up and down over short periods of 13·· ·that is 25.

14·· ·time, too. 14·· · · ·A· ··Yes, I'm there.

15·· · · ·Q· ··How does the volatility of gas cost compare to 15·· · · ·Q· ··Now, would you read Section 6.

16·· ·the volatility of cost associated with the resources in 16·· · · ·A· ··Yes.··"Condition Precedent.··This Agreement 17·· ·the new WBL contract? 17·· ·shall be conditioned upon Buyer receiving all regulatory 18·· · · ·A· ··Well, gas historically has been much more 18·· ·approvals required by Buyer for this Agreement no later 19·· ·volatile than coal and nuclear fuel.··Nuclear fuel is 19·· ·than August 1, 2012."

20·· ·typically procured on long-term contracts; coal is also 20·· · · ·Q· ··And who is the buyer here?

21·· ·typically procured on long-term contracts.··And so the 21·· · · ·A· ··That would be Entergy Texas.

22·· ·price of those two fuels has been relatively stable over 22·· · · ·Q· ··Okay.··Do you know whether the operating 23·· ·the past. 23·· ·committee has made any indication of whether this 24·· · · ·Q· ··Now, there was some discussion also, 24·· ·contract will go forward for Entergy Texas if, in fact, 25·· ·Mr. Cooper, about the timing of the production of the 25·· ·it turns out that the Commission did not approve the

KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 46 (Pages 693-696) Page 693 Page 695 ·1·· ·contract? ·1·· ·understanding of what is before the Commission that is ·2·· · · ·A· ··No, I'm not aware. ·2· ·available for the review of the operating committee's · ·3·· · · ·Q· ··There was a discussion about hedging, ·3·· ·decision regarding the EAI WBL in this case? ·4·· ·Mr. Cooper.··Rather than to try to capture what ·4·· · · ·A· ··The operating committee minutes and the ·5·· ·you said -- and I don't think I'll do a good job of ·5·· ·presentations associated with it and the contract ·6·· ·it -- would you state again your understanding of the ·6·· ·associated with the new WBL. ·7·· ·practice or the opportunities for hedging as they may be ·7·· · · ·Q· ··In Mr. VanMiddlesworth's cross-examination of ·8·· ·exercised by Entergy Services on behalf of the operating ·8·· ·you on that? ·9·· ·companies and the Texas Commission, the PUCT's position, ·9·· · · ·A· ··Yes.

10·· ·your understanding of that. 10·· · · ·Q· ··To clarify a timing issue, if you could look at 11·· · · ·A· ··Yes.··I know that in the State of Louisiana and 11·· ·the exhibit that is the MSS-4 contract.

12·· ·the State of Mississippi, the utilities there practice a 12·· · · ·A· ··Yes, I have it here.

13·· ·gas hedging program where they fix forward a portion of 13·· · · ·Q· ··Now, what is the date at the top of the 14·· ·their projected requirements in order to reduce the 14·· ·contract that the contract is dated?

15·· ·volatility of gas supply costs.··And it was my 15·· · · ·A· ··This agreement is dated as of April 11, 2012.

16·· ·understanding that we have proposed a similar hedging 16·· · · ·Q· ··Okay.··And it will be obvious from the record, 17·· ·program in Texas, and it was denied. 17·· ·but do you recall whether or not the operating 18·· · · ·Q· ··Are you aware of any intervenors proposing 18·· ·committee's decision approving this contract was 19·· ·hedging in this case? 19·· ·provided in this case prior to this date?

20·· · · ·A· ··No. 20·· · · ·A· ··Yes, that's my understanding.

21·· · · ·Q· ··You mentioned your knowledge or your belief 21·· · · ·Q· ··Okay.··Mr. Cooper, with regard to 22·· ·that there was a proposal by the company.··Do you know 22·· ·Mr. VanMiddlesworth's chart up here, is it your 23·· ·whether or not either the Staff or any intervening party 23·· ·understanding that only capacity charges are reflected?

24·· ·has ever proposed hedging for Texas? 24·· ·Is there an energy cost reflected?

25·· · · ·A· ··No, I'm not aware. 25·· · · ·A· ··The only charges that Mr. VanMiddlesworth Page 694 Page 696 ·1·· · · ·Q· ··Back to EAI WBL -- sorry for jumping around -- ·1·· ·reflects are capacity charges, and then he tries to ·2·· ·but there is an existing EAI WBL in place.··Correct? ·2·· ·allocate those across Entergy.··And, you know, as ·3·· · · ·A· ··Yes, that's correct. ·3·· ·associated with these contracts, you know, many of these ·4·· · · ·Q· ··And do you know how long the term is of that ·4·· ·contracts are actually going to provide lower cost ·5·· ·one -- not when it ends.··I know it ends in December. ·5·· ·energy than would be available from existing resources ·6·· ·We saw that. ·6·· ·or if they were just to rely on the resources of the ·7·· · · ·A· ··Yes.··I believe that was a three-year ·7·· ·reserves of the Entergy system. ·8·· ·agreement. ·8·· · · · · · · · ·In addition, these capacity charges assume ·9·· · · ·Q· ··Okay.··Was there an EAI WBL in place under ·9·· ·that they are incremental.··And in the case of ETI being 10·· ·which Texas received or Entergy Texas or its predecessor 10·· ·a short company, we're not even getting ETI up to their 11·· ·received capacity prior to that? 11·· ·capacity needs.··And so, you know, I don't even consider 12·· · · ·A· ··I don't recall. 12·· ·these capacity charges incremental.··They're just, you 13·· · · · · · · · ·(Brief pause) 13·· ·know, trying to bring them up to the level that they 14·· · · · · · · · ·MR. WESTERBURG:··Your Honor, I'm trying to 14·· ·need to be, because they're short on resources.

15·· ·weed out questions, so if you'll bear with me. 15·· · · ·Q· ··Let me ask you about that, Mr. Cooper.··If you 16·· · · · · · · · ·JUDGE BURKHALTER:··Thank you.··I 16·· ·would go back to your RRC-1 -- 17·· ·appreciate it. 17·· · · ·A· ··Yes.

18·· · · ·Q· ··(BY MR. WESTERBURG)··Mr. Cooper, I think toward 18·· · · ·Q· ··-- now, are there new third-party contracts 19·· ·the end of Mr. VanMiddlesworth's cross-examination, you 19·· ·that are in place for the rate year that were not in 20·· ·made a reference to all files regarding the EAI WBL as 20·· ·place for the test year?

21·· ·being the basis -- being available for the 21·· · · ·A· ··Yes.

22·· ·Commission's review.··Do you remember your comment on 22·· · · ·Q· ··And which ones are those?

23·· ·files? 23·· · · ·A· ··Well, we have Calpine-Carville and SRMPA.

24·· · · ·A· ··No. 24·· · · ·Q· ··And if you could tell us the line number, just 25·· · · ·Q· ··I may be remembering wrong.··What is your 25·· ·so we --

KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 49 (Pages 705-708) Page 705 Page 707 ·1·· ·has various provisions for required availability rates ·1·· · · ·A· ··I don't know. ·2·· ·and other things that affect what gets actually paid. ·2·· · · ·Q· ··Did ETI experience load growth in the two years ·3·· ·Correct? ·3·· ·between the last test year and this test year? ·4·· · · ·A· ··That's correct, yes. ·4·· · · ·A· ··I don't know. ·5·· · · ·Q· ··And what do you assume for disallowances for ·5·· · · ·Q· ··Were you here for Mr. Domino's testimony the ·6·· ·availability factor adjustments in this? ·6·· ·other day? ·7·· · · ·A· ··We did not assume anything. ·7·· · · ·A· ··No, I wasn't. ·8·· · · ·Q· ··But there have been adjustments in the past ·8·· · · ·Q· ··So this no-load-growth scenario that results in ·9·· ·years for availability, haven't there? ·9·· ·an underrecovery, that's not what ETI is projecting, is 10·· · · ·A· ··Yes, there have, and they have been relatively 10·· ·it?

11·· ·minor. 11·· · · ·A· ··No. 12·· · · ·Q· ··And for the -- well, let's pick another one. 12·· · · ·Q· ··Now let me refer you to Exhibit 19.··I wanted 13·· ·For the ConocoPhillips -- I guess that's the SRW 13·· ·to clarify some things that Mr. Westerburg asked.

14·· ·contract -- that also has various provisions for 14·· ·Exhibit 19A is this sensitive material.··Do you have 15·· ·performance and for reducing the payment based on that. 15·· ·that?

16·· ·Correct? 16·· · · · · · · · ·MR. WESTERBURG:··I'm sorry.··Exhibit 19A, 17·· · · ·A· ··Yes, that's correct. 17·· ·which one is that, so I can look it up?

18·· · · ·Q· ··And in the Line 1, you didn't assume that the 18·· · · · · · · · ·MR. VanMIDDLESWORTH:··That's the March 23, 19·· ·payment would be reduced at all for that? 19·· ·2012 copy of the February 17 operating committee meeting 20·· · · ·A· ··Yes, that's correct. 20·· ·minutes.

21·· · · ·Q· ··Okay.··And we won't know until the actual year 21·· · · · · · · · ·MR. WESTERBURG:··Got it.

22·· ·comes and goes.··Right? 22·· · · · · · · · ·JUDGE BURKHALTER:··And are you intending 23·· · · ·A· ··Yes, sir. 23·· ·to go into highly sensitive?

24·· · · ·Q· ··You talked about lower fuel costs associated 24·· · · · · · · · ·MR. VanMIDDLESWORTH:··I'm not.

25·· ·with some of these contracts.··The fuel costs flow 25·· · · · · · · · ·JUDGE BURKHALTER:··Okay.

Page 706 Page 708 ·1·· ·through the fuel factor.··Isn't that right? ·1·· · · ·A· ··Yes, sir, I have it. ·2·· · · ·A· ··Yes, sir. ·2·· · · ·Q· ··(BY MR. VanMIDDLESWORTH)··All right.··Now, ·3·· · · ·Q· ··And Entergy receives its actual reasonable fuel ·3·· ·first of all, turning to the page that's marked TH794. ·4·· ·costs from ratepayers -- no more, no less.··Correct? ·4·· ·Do you see that?··Under "Item 3 -- 2013 EAI Wholesale ·5·· · · ·A· ··It's subject to reconciliation in Texas, yes. ·5·· ·Baseload, (Attachment C)"? ·6·· · · ·Q· ··And are you suggesting that you ought to ·6·· · · ·A· ··I'm afraid my pages got messed up here. ·7·· ·overrecover your actual capacity charges if you lower ·7·· · · · · · · · ·MR. VanMIDDLESWORTH:··May I approach the ·8·· ·fuel costs? ·8·· ·witness, Your Honor? ·9·· · · ·A· ··No, I'm not. ·9·· · · · · · · · ·JUDGE BURKHALTER:··Yes.

10·· · · ·Q· ··So you're still believing you should only 10·· · · ·Q· ··(BY MR. VanMIDDLESWORTH)··You can look at mine.

11·· ·recover your actual capacity charge? 11·· · · ·A· ··Is that it, 794?

12·· · · ·A· ··I'm suggesting we should recover the costs that 12·· · · ·Q· ··Yes.

13·· ·we incur for our capacity transactions. 13·· · · ·A· ··Okay.

14·· · · ·Q· ··All right.··And even if they reduce fuel costs, 14·· · · ·Q· ··You see Item 3 refers to 2013 EAI wholesale 15·· ·you don't get more than your actual costs.··Right? 15·· ·baseload?··And it says Attachment C?

16·· · · ·A· ··I'm sorry.··I don't understand that question. 16·· · · ·A· ··Yes.

17·· · · ·Q· ··Well, it's probably my fault.··Let me ask about 17·· · · ·Q· ··And then the next line says Charles DeGeorge 18·· ·this chart, ETI Exhibit 7, for you.··You were asked what 18·· ·provided the Committee members with a wholesale baseload 19·· ·would happen if there were no load growth between Year 1 19·· ·sales analysis?

20·· ·and Year 3 here.··Do you recall that? 20·· · · ·A· ··Yes.

21·· · · ·A· ··Yes. 21·· · · ·Q· ··Now, let me ask you to turn to Page 858 of TIEC 22·· · · ·Q· ··Does ETI project load growth between the test 22·· ·Exhibit 19A.

23·· ·year and the rate year? 23·· · · ·A· ··It's stuck in here.

24·· · · ·A· ··Yes, they do. 24·· · · ·Q· ··All right.··Let me show you mine.··I refer you 25·· · · ·Q· ··How much? 25·· ·to Page 858 --

KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 1 (Pages 1-4) Page i Page iii · · · · · · · ··SOAH DOCKET NO. XXX-XX-XXXX ·1· ·1· · · · · · · · ·TABLE OF CONTENTS (CONTINUED) ··· ·2· · · · · · · · · · · · · · · · · · · · · · · · · · · ·PAGE · · · · · · · · · ·PUC DOCKET NO. 39896 ·2· ··· ·3· ·PRESENTATION ON BEHALF OF · ·3· ··ENTERGY · TEXAS, INC. (CONTINUED) ··· ·APPLICATION OF ENTERGY· ··)· ·STATE OFFICE OF ·4· ·4· · ··TEXAS, · INC., FOR· · · · ··) ·AUTHORITY TO CHANGE RATES ) ·5· ···· ··CHRIS E. BARRILLEAUX ··AND · RECONCILE FUEL COSTS, ) ·5· · · · · · ·- Direct (Olson)· · · · · · · · · · · · · ·149 ·AND OBTAIN DEFERRED· · · ·) ·6· ··ACCOUNTING · TREATMENT· · ··) ADMINISTRATIVE HEARINGS ···· · · · ·- Cross (Lawton)· · · · · · · · · · · · · ·151 · ·7· ·6· · · · · · ·- Cross (Griffiths)· · · · · · · · · · · ··167 ··· · ·8· ···· · · · ·- Redirect (Olson)· · · · · · · · · · · · ·187 ··· ·7· · · · · · ·- Recross (Lawton)· · · · · · · · · · · · ·198 · ·9· ··· ·8· · · ··SAMUEL C. HADAWAY · 10· ···· · · · ·- Direct (Williams)· · · · · · · · · · · ··199 ··· · · · · · · · · · ·HEARING ON THE MERITS 11· ·9· · · · · · ·- Cross (Lawton)· · · · · · · · · · · · · ·201 ··· · · · · · · · · ··Friday, April 27, 2012 12· ···· · · · ·- Cross (Griffiths)· · · · · · · · · · · ··212 ··· 10· · · · · · ·- Cross (Kelley)· · · · · · · · · · · · · ·230 · 13· ··· ···· · · · ·- Redirect (Williams)· · · · · · · · · · ··231 · 14· 11· · · · · · ·- Recross (Griffiths)· · · · · · · · · · ··239 ··· · · · · · · · · · ··TABLE OF CONTENTS 15· 12· ·PROCEEDINGS RECESSED· · · · · · · · · · · · · · · · ·246 ··· 13· · · · · ·(Volumes 1 through 4, Pages i through xxxii) 16· ··· 14· · · 17· 15· · ··· · 18· 16· · ··· · 19· 17· · ··· 18· · · 20· ··· 19· · · 21· 20· · ··· · 22· 21· · ··· 22· · · 23· ··· 23· · · 24· 24· · ··· · 25· 25· · Page ii Page iv ·1· · · · · · · · ·TABLE OF CONTENTS ·1· · · · · · · · · ··TABLE OF CONTENTS ·2· · · · · · · · · · · · · · · · · · · · · · · · · · · ·PAGE ·2· · · · · · · · · · · · · · · · · · · · · · · · · · · ·PAGE ·3· ·PROCEEDINGS, TUESDAY, APRIL 24, 2012 - VOL. 1· · · · ··5 ·3· ·PROCEEDINGS, WEDNESDAY, APRIL 25, 2012 - VOLUME 2· ··248 ·4· ·OPENING STATEMENT ON BEHALF OF ·4· ·PRESENTATION ON BEHALF OF ··ENTERGY · TEXAS, INC. (Neinast)· · · · · · · · · · · · ·16 ··ENTERGY · TEXAS, INC. (CONTINUED)· · · · · · · · · · ··250 ·5· · ·5· · ···· ··ROBERT D. SLOAN ··OPENING · STATEMENT ON BEHALF OF ·6· · · · · · ·- Direct (Cyr)· · · · · · · · · · · · · · ·250 ·6· ·ENTERGY TEXAS, INC. (Wren)· · · · · · · · · · · · · ··22 ···· · · · ·- Cross (Kelley)· · · · · · · · · · · · · ·253 ·7· ·OPENING STATEMENT ON BEHALF OF ·7· · · · · · ·- Cross (Ferris)· · · · · · · · · · · · · ·258 ··CITIES · (Lawton)· · · · · · · · · · · · · · · · · · · ·37 ···· · · · ·- Redirect (Cyr)· · · · · · · · · · · · · ·285 ·8· · ·8· · · · · · ·- Recross (Ferris)· · · · · · · · · · · · ·295 ··OPENING · STATEMENT ON BEHALF OF ·9· · · ··H. VERNON PIERCE, JR. ·9· ·TEXAS INDUSTRIAL ENERGY CONSUMERS (VanMiddlesworth)· ·41 ···· · · · ·- Direct (Cyr)· · · · · · · · · · · · · · ·303 10· ·OPENING STATEMENT ON BEHALF OF 10· · · · · · ·- Cross (Mack)· · · · · · · · · · · · · · ·305 ··OFFICE · OF PUBLIC UTILITY COUNSEL (Ferris)· · · · · · ·49 ···· · · · ·- Cross (Younger)· · · · · · · · · · · · ··315 11· · 11· · ···· ··MICHAEL P. CONSIDINE ··OPENING · STATEMENT ON BEHALF OF 12· · · · · · ·- Direct (Neinast)· · · · · · · · · · · · ·317 12· ·STAFF (Smyth)· · · · · · · · · · · · · · · · · · · · ·52 ···· · · · ·- Cross (Lawton)· · · · · · · · · · · · · ·318 13· ·OPENING STATEMENT ON BEHALF OF 13· · · · · · ·- Cross (Griffiths)· · · · · · · · · · · ··352 ··THE · UNITED STATES DEPARTMENT OF ENERGY (Porter)· · · ·54 ···· · · · ·- Cross (Kelley)· · · · · · · · · · · · · ·355 14· · 14· · · · · · ·- Redirect (Neinast)· · · · · · · · · · · ·358 15· ·PRESENTATION ON BEHALF OF ···· · · · ·- Recross (Lawton)· · · · · · · · · · · · ·362 ··ENTERGY · TEXAS, INC.· · · · · · · · · · · · · · · · · ·60 15· · 16· · ··AFTERNOON · SESSION· · · · · · · · · · · · · · · · · ··365 ···· ··JOSEPH DOMINO 16· · ··PRESENTATION · ON BEHALF OF 17· · · · · · ·- Direct (Wren)· · · · · · · · · · · · · · ·60 17· ·ENTERGY TEXAS, INC. (CONTINUED)· · · · · · · · · · ··366 ···· · · · ·- Cross (Lawton)· · · · · · · · · · · · · ··62 18· · · ··WALTER C. FERGUSON 18· · ···· · · · ·- Direct (McNally)· · · · · · · · · · · · ·366 ··AFTERNOON · SESSION· · · · · · · · · · · · · · · · · ··103 19· · · · · · ·- Cross (Ferris)· · · · · · · · · · · · · ·367 19· · ···· · · · ·- Redirect (McNally)· · · · · · · · · · · ·369 ··PRESENTATION · ON BEHALF OF 20· · · · · · ·- Recross (Ferris)· · · · · · · · · · · · ·372 20· ·ENTERGY TEXAS, INC. (CONTINUED) ···· · · · ·- Further Redirect (McNally)· · · · · · · ·374 21· · · ··JOSEPH DOMINO 21· · ···· · · · ·- Cross (Lawton - Continued)· · · · · · · ·103 ···· ··DANE A. WATSON 22· · · · · · ·- Direct (Williams)· · · · · · · · · · · ··376 22· · · · · · ·- Cross (VanMiddlesworth)· · · · · · · · ··115 ···· · · · ·- Cross (Lawton)· · · · · · · · · · · · · ·380 ···· · · · ·- Cross (Kelley)· · · · · · · · · · · · · ·131 23· · · · · · ·- Cross (Lawler)· · · · · · · · · · · · · ·397 23· · · · · · ·- Redirect (Wren)· · · · · · · · · · · · ··139 ···· · · · ·- Redirect (Williams)· · · · · · · · · · ··403 ···· · · · ·- Recross (Lawton)· · · · · · · · · · · · ·143 24· · · · · · ·- Recross (Lawton)· · · · · · · · · · · · ·410 24· · · · · · ·- Recross (VanMiddlesworth)· · · · · · · ··144 ···· · · · ·- Recross (Lawler)· · · · · · · · · · · · ·414 25· · 25· ·

KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 2 (Pages 723-726) Page 723 Page 725 ·1·· ·subject to the prior ruling on objections to ETI Exhibit ·1·· ·sorry -- other -- let me rephrase that.··Too many MSSs. ·2·· ·No. 39, it is admitted. ·2·· · · · · · · · ·You also support the system agreement ·3·· · · · · · · · ·(Exhibit ETI No. 39 admitted) ·3·· ·costs in the fuel reconciliation period to the extent ·4·· · · · · · · · ·MR. WESTERBURG:··Your Honor, ETI tenders ·4·· ·they're included there? ·5·· ·the witness for cross. ·5·· · · ·A· ··Yes, I support the other service schedule ·6·· · · · · · · · ·JUDGE WALSTON:··All right.··Cities? ·6·· ·costs, whether they're in the fuel part or in base rates ·7·· · · · · · · · ·MR. LAWTON:··Yes, Your Honor.··May I ·7·· ·in this case. ·8·· ·begin? ·8·· · · ·Q· ··But to be clear, you support the test year ·9·· · · · · · · · ·JUDGE WALSTON:··Yes. ·9·· ·costs, whatever they were, about 1.7 million.··Correct?

10·· · · · · · · · ·MR. LAWTON:··Thank you. 10·· · · ·A· ··Are we talking about my direct testimony or are 11·· · · · · · · · · · · ·CROSS-EXAMINATION 11·· ·we talking about my rebuttal testimony in this?

12·· ·BY MR. LAWTON: 12·· · · ·Q· ··It's my understanding you're only here for 13·· · · ·Q· ··Good morning, Mr. Cicio.··How are you, sir? 13·· ·direct today.

14·· · · ·A· ··Good morning, Mr. Lawton.··Just fine. 14·· · · ·A· ··Okay.··In this particular case, Mr. Considine 15·· · · ·Q· ··Okay.··Start off with Page 3, Line 20 of your 15·· ·supported the pro forma to the test year MSS-2 costs in 16·· ·testimony, which is, I think -- ETI Exhibit 39, Is it? 16·· ·this case.

17·· · · ·A· ··Page 3 -- 17·· · · ·Q· ··Okay.··He supported a 9 million-dollar pro 18·· · · ·Q· ··Line 20. 18·· ·forma in MSS-2 costs.··Correct?

19·· · · ·A· ··-- Line 20.··Okay. 19·· · · ·A· ··The total was 10.7 million for the pro forma, 20·· · · ·Q· ··Okay.··Now, I want to understand the purpose of 20·· ·as I recall.

21·· ·your testimony and exactly what you do. 21·· · · ·Q· ··And when I asked him about the basis for that 22·· · · · · · · · ·The first thing I see there is you support 22·· ·9 million-dollar adjustment the other day, Mr. Considine 23·· ·the costs and revenues associated with ETI's 23·· ·told me he got it from, I think, your group.

24·· ·participation in the Entergy service agreement during 24·· · · ·A· ··Okay.··That's what he testified.··I haven't 25·· ·the test year, July 1, 2010 to June 30, 2011.··Correct? 25·· ·read Mr. Considine's testimony.

Page 724 Page 726 ·1·· · · ·A· ··It's the Entergy system agreement, yes. ·1·· · · ·Q· ··He got it from some accounting group that does ·2·· · · ·Q· ··Okay.··And so when you say you support the ·2·· ·this work, MSS-2.··Would that be your group or can you ·3·· ·costs and revenues associated with the service ·3·· ·think of somebody else? ·4·· ·agreement, what costs and revenues are you talking ·4·· · · ·A· ··He got that information from a combination of ·5·· ·about? ·5·· ·sources.··I think it was looked at by my group as well. ·6·· · · ·A· ··I think I go through and list those in my ·6·· · · ·Q· ··Well, I'm wondering, who do I ask questions ·7·· ·testimony, but generally speaking, it's the MSS-1 ·7·· ·about the 10.6 million calculation? ·8·· ·service -- Schedule MSS-1, MSS-2, MSS-3, MSS-5 and I ·8·· · · · · · · · ·In this direct case, I've asked ·9·· ·think that's it -- and MSS-4.··I think I forgot that. ·9·· ·Mr. Considine about it, and now I'm asking you about it.

10·· · · ·Q· ··Okay.··And if we -- and we're going to focus a 10·· ·And you don't testify to the 10.6 million.··Who in this 11·· ·bit today on what's called MSS-2. 11·· ·case testifies to the 10.6 million of MSS-2 costs the 12·· · · · · · · · ·So would you tell us what MSS-2 is? 12·· ·company is requesting in this direct case?

13·· · · ·A· ··Generally speaking, MSS-2 is the service 13·· · · · · · · · ·Who does it?··Who do I ask?

14·· ·schedule by which certain transmissions costs are 14·· · · ·A· ··It depends on what component of the 15·· ·equalized among the operating companies, and it's the 15·· ·calculations you're talking about.··The investment, I 16·· ·ownership costs of those transmission assets. 16·· ·believe, was sponsored -- or was supported by 17·· · · ·Q· ··And as I understand it, you support the test 17·· ·Mr. McCulla's organization.··The calculation was done in 18·· ·year cost of MSS-2? 18·· ·another group, but, you know, my group reviewed that.

19·· · · ·A· ··In my testimony, I support the test year cost 19·· ·So I feel comfortable talking about the calculation.

20·· ·of MSS-2. 20·· · · ·Q· ··Okay.··You're comfortable talking about how we 21·· · · ·Q· ··And exactly what is the amount of those costs 21·· ·get to 10.6 million?

22·· ·in the test year? 22·· · · ·A· ··Generally speaking, I can generally talk about 23·· · · ·A· ··I believe the test year costs are $1.7 million. 23·· ·it, yes.··But it came from Mr. Considine's thing, but I 24·· · · ·Q· ··And you also support the MSS-2 costs in the 24·· ·can talk about it.

25·· ·reconciliation period, or the other MSS costs?··I'm 25·· · · ·Q· ··Okay.··Fair enough.··Now, if we turn to your

KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 4 (Pages 731-734) Page 731 Page 733 ·1·· · · ·Q· ··Under the system agreement, the operating ·1·· · · · · · · · ·admitted) ·2·· ·companies that we've talked about are to equalize their ·2·· · · ·Q· ··(BY MR. LAWTON)··What I want to focus on, ·3·· ·cost of transmission.··Is that correct? ·3·· ·Mr. Cicio, is last page of Cities 28.··Are you there, ·4·· · · ·A· ··Of certain transmission.··It's not all ·4·· ·sir?··It's a table.··Do you see that table? ·5·· ·transmission.··There are certain guidelines within the ·5·· · · ·A· ··Yes, I see the table. ·6·· ·service schedule that govern what transmissions are ·6·· · · ·Q· ··This is the response to Cities 3-3 g.··Correct? ·7·· ·equalized. ·7·· · · ·A· ··That's correct. ·8·· · · ·Q· ··And generally speaking, would you agree that ·8·· · · ·Q· ··Now, what we have here on this table on the ·9·· ·it's all transmission assets at 230 kV and above? ·9·· ·left-hand side is the year from 2006 to 2011, along with 10·· · · ·A· ··I think that's generally the case. 10·· ·a grand total.··Do you see that?

11·· · · ·Q· ··Okay.··So if a utility has a lot of 11·· · · ·A· ··Yes, I see that.

12·· ·transmission relative to the other operating companies 12·· · · ·Q· ··And then across the top of the table, we have 13·· ·and its responsibility ratio reflects it, it may get 13·· ·EAI.··That would be the Arkansas company -- 14·· ·paid MSS-2 dollars -- correct -- from the other 14·· · · ·A· ··That's correct.

15·· ·operating companies? 15·· · · ·Q· ··-- and EGSI.··Which company is that, the 16·· · · ·A· ··I'm not sure I would characterize it exactly 16·· ·Louisiana Texas -- I mean, Louisiana Gulf States?

17·· ·that way. 17·· · · ·A· ··That is both companies, ETI and EGSL.··That was 18·· · · ·Q· ··Okay.··Well, would you agree with this 18·· ·prior to the jurisdictional separation of those two 19·· ·statement:··Some of the operating companies are paid on 19·· ·companies.

20·· ·a monthly basis for transmission and others pay the 20·· · · ·Q· ··Fair enough.··And then you have -- and so what 21·· ·cost? 21·· ·happened is on January 1st, 2008, Texas and Louisiana 22·· · · ·A· ··And there are long companies and there are 22·· ·separated.··Correct?

23·· ·short companies, as it relates to equalizable 23·· · · ·A· ··I think that's the case.

24·· ·transmission investment. 24·· · · ·Q· ··Okay.··And then the next company is ELL.··Which 25·· · · ·Q· ··Okay.··I've put some -- had Ms. Mayhall put 25·· ·one is that?··That's another operating company?

Page 732 Page 734 ·1·· ·some exhibits in front of you, and the first one I want ·1·· · · ·A· ··That's Entergy Louisiana. ·2·· ·to look at is what has been marked as Cities Exhibit 28. ·2·· · · ·Q· ··And EGSL, that's the Louisiana version that ·3·· · · ·A· ··I have it.··Yes, I have it.··Okay.··Cities ·3·· ·separated.··Correct? ·4·· ·Exhibit 28 is the response to Cities 3-3? ·4·· · · ·A· ··Right.··That's the Louisiana portion of what ·5·· · · ·Q· ··Yes.··You're getting ahead of me, sir. ·5·· ·used to be EGSI. ·6·· · · ·A· ··Okay. ·6·· · · ·Q· ··And EMI would be the Mississippi company I ·7·· · · ·Q· ··Would you agree that Cities Exhibit 28 is a ·7·· ·forgot before.··Right? ·8·· ·discovery response to Cities 3-3? ·8·· · · ·A· ··Entergy Mississippi, correct. ·9·· · · ·A· ··Yes, I would agree with that. ·9·· · · ·Q· ··And ENOI, that would be the New Orleans 10·· · · ·Q· ··And would you agree with me that you are the 10·· ·operations?

11·· ·sponsoring witness for Subparts g. and h.? 11·· · · ·A· ··That would be Entergy New Orleans, Inc. 12·· · · ·A· ··I am the sponsoring witness for g. and h. 12·· · · ·Q· ··And ETI at the far right would be the company 13·· · · ·Q· ··And you've seen this document before, haven't 13·· ·we're here about today, Entergy Texas, Inc.··Correct?

14·· ·you, sir? 14·· · · ·A· ··That's correct.

15·· · · ·A· ··I have seen it. 15·· · · ·Q· ··And let's look at ETI for a second starting in 16·· · · ·Q· ··Okay.··And it's true and correct to the best of 16·· ·2008.··You have a number that says a negative 17·· ·your knowledge.··Correct? 17·· ·$2,660,494.··Do you see that?

18·· · · ·A· ··That's correct. 18·· · · ·A· ··Yes, I do.

19·· · · · · · · · ·MR. LAWTON:··Your Honor, I would offer, at 19·· · · ·Q· ··And what does that number mean?

20·· ·this time, Cities 28. 20·· · · ·A· ··That means for the year -- calendar year 21·· · · · · · · · ·JUDGE WALSTON:··Any objection? 21·· ·2008 that Entergy Texas received MSS-2 payments in the 22·· · · · · · · · ·MR. WESTERBURG:··No, Your Honor. 22·· ·amount of $2.6 million.

23·· · · · · · · · ·JUDGE WALSTON:··Cities Exhibit 28 is 23·· · · ·Q· ··So the other operating companies had to pay 24·· ·admitted. 24·· ·Entergy Texas transmission dollars for equalization in 25·· · · · · · · · ·(Exhibit Cities··No. 28 marked and 25·· ·2008.··Correct?

KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 5 (Pages 735-738) Page 735 Page 737 ·1·· · · ·A· ··On a net basis -- net for the year. ·1·· · · ·Q· ··Okay.··Well, I just want to make sure what it ·2·· · · ·Q· ··On a net basis? ·2·· ·is because we said the test year was 1.7.··I'm trying to ·3·· · · ·A· ··Month-to-month it could have been different. ·3·· ·distinguish it. ·4·· · · ·Q· ··Okay.··Well, if we look -- let's stay on ·4·· · · ·A· ··Okay. ·5·· ·2008 for a moment.··Okay? ·5·· · · ·Q· ··Now, if we go to the bottom of that graph, ·6·· · · · · · · · ·If we look across all the 2008 numbers and ·6·· ·below it, you -- it looks like what appears to be the ·7·· ·if we were to add, for example, the EAI number for 2008, ·7·· ·test year numbers.··Is that correct, sir? ·8·· ·that's a negative 1.4 million.··Do you see that? ·8·· · · ·A· ··That's what it looks like, yes. ·9·· · · ·A· ··Yes. ·9·· · · ·Q· ··It says -- its starts off July 2010-June 6th -- 10·· · · ·Q· ··And that means they got paid.··Correct? 10·· ·June 2011.··Correct?

11·· · · ·A· ··Again; for the year, yes. 11·· · · ·A· ··That's right.

12·· · · ·Q· ··Right.··And then we see the ELL number is 12·· · · ·Q· ··Okay.··And so these are the actual numbers in 13·· ·something like 7.8 million for 2008.··Do you see that? 13·· ·the test year.··Right?

14·· · · ·A· ··Yes, I do. 14·· · · ·A· ··These are the actual amounts recorded for MSS-2 15·· · · ·Q· ··And they were paid 7.8 million.··Right? 15·· ·during the test year.

16·· · · ·A· ··Yes. 16·· · · ·Q· ··And Entergy Texas ended up paying the other 17·· · · ·Q· ··And EGSL had to pay.··It's a positive number. 17·· ·operating companies roughly 1.7 million.··Correct?

18·· ·That means they had to pay some money.··Correct? 18·· · · ·A· ··Yes.··They paid 1.7 million on a net basis for 19·· · · ·A· ··That's right. 19·· ·the year.

20·· · · ·Q· ··If we added the numbers across in any year, 20·· · · ·Q· ··On a net basis.··And if we added the test year 21·· ·would they equal zero? 21·· ·numbers across, it would, again, equal zero on a system 22·· · · ·A· ··They should equal zero. 22·· ·basis.··Right?

23·· · · ·Q· ··And the reason they equal zero is basically the 23·· · · ·A· ··That's correct.

24·· ·short companies have to pay the long companies. 24·· · · ·Q· ··Fair enough.··And it's that 1.7 million -- 25·· ·Correct? 25·· ·1,753,797 that you sponsor?

Page 736 Page 738 ·1·· · · ·A· ··It's a system, so we're equalizing the cost ·1·· · · ·A· ··Yes, that's what I sponsor in my testimony. ·2·· ·among the system.··So for the system, it would equal -- ·2·· · · ·Q· ··Fair enough.··But to be clear -- just go back ·3·· ·should equal zero. ·3·· ·there a second -- what you're asking for in this case -- ·4·· · · ·Q· ··Fair enough.··Now, in -- if we look at ETI, we ·4·· ·I'm sorry. ·5·· ·see in 2000 -- I think it's 2010, we have a positive ·5·· · · · · · · · ·What the company is asking for in this ·6·· ·number of 559,000.··Do you see that? ·6·· ·case is roughly not the 1.7 million test year number. ·7·· · · ·A· ··Yes, I do. ·7·· ·They're asking for a number of 10.6 million.··Correct? ·8·· · · ·Q· ··That means on the year, Entergy Texas, Inc., ·8·· · · ·A· ··They're asking for 10.6 million because, you ·9·· ·had to pay money to the operating companies -- other ·9·· ·know, the way the calculation works, if there's added 10·· ·operating companies.··Correct? 10·· ·investment across the companies, which you see here -- 11·· · · ·A· ··That's correct. 11·· ·there are changes in transmission investment year to 12·· · · ·Q· ··Okay.··And then in the following year, 2011, 12·· ·year, and so as those transmission projects are put in 13·· ·they had to pay -- "they" being ETI, Entergy Texas -- 13·· ·service, the balance will shift between the different 14·· ·had to pay roughly 1.3 million.··Correct? 14·· ·companies, depending on their transmission 15·· · · ·A· ··That's correct. 15·· ·responsibility relative to their investment.

16·· · · ·Q· ··But on a grand total basis, you just added 16·· · · ·Q· ··Fair enough.··Now, sir, I've had -- I want to 17·· ·those numbers up and said, on a net basis, Entergy 17·· ·go through that calculation for a moment so we all 18·· ·Texas, Inc., got paid 1.7 million.··Correct? 18·· ·understand how it's done.

19·· · · ·A· ··I think if you added up Entergy -- add all the 19·· · · · · · · · ·I've had a two-page demonstrative put in 20·· ·years for Entergy Texas, they would have received 20·· ·front of you, and the first page is just a. through w.

21·· ·1.7 million. 21·· ·You'll see those lines.··And the second page is a sheet 22·· · · ·Q· ··Fair enough. 22·· ·that has a bunch of numbers.··Okay, sir?··Do you see 23·· · · ·A· ··We're just saying for four years, you know, 23·· ·that?

24·· ·they got a net payment.··It's not -- that's just a 24·· · · ·A· ··I have this in front of me, yes.

25·· ·total. 25·· · · ·Q· ··And I just wanted you to assist us on how this

KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 11 (Pages 759-762) Page 759 Page 761 ·1·· · · ·Q· ··Okay.··Fair enough.··Fair enough. ·1·· · · · · · · · ·MR. LAWTON:··Thank you. ·2·· · · · · · · · ·Now, you said, when we started this ·2·· · · ·Q· ··(BY MR. LAWTON)··What's the rate year, sir, in ·3·· ·examination this morning, that you could talk about the ·3·· ·this case?··Do you know? ·4·· ·$10.6 million request. ·4·· · · ·A· ··I believe it begins June of '12 and ends May of ·5·· · · · · · · · ·JUDGE WALSTON:··Can I ask one clarifying ·5·· ·'13. ·6·· ·question just to make sure I'm clear? ·6·· · · ·Q· ··So June 2012 to May 2013.··That's your rate ·7·· · · · · · · · ·MR. LAWTON:··Yes, sir. ·7·· ·year, and you would agree that's a forecast period. ·8·· · · · · · · · ·JUDGE WALSTON:··You said some were removed ·8·· ·Correct? ·9·· ·due to an adjustment.··Is that -- do I understand some ·9·· · · ·A· ··I believe that's -- I'm not exactly sure that 10·· ·assets were included that should not have been included 10·· ·those are the 12 months, but I believe it's generally -- 11·· ·and then removed, or why were they removed?··I didn't 11·· · · ·Q· ··I think you got it right.

12·· ·follow that. 12·· · · ·A· ··Okay.

13·· · · · · · · · ·THE WITNESS:··Each month we -- being my 13·· · · ·Q· ··I think it's right.

14·· ·group -- receives the equalizable transmission 14·· · · ·A· ··Okay.

15·· ·investment from the transmission organization, who, I'm 15·· · · ·Q· ··So your 10.6 dollar-million estimate in this 16·· ·assuming, get it from the property accounting records. 16·· ·case is based upon MSS-2 costs for this time period, 17·· · · · · · · · ·So they look at the investment in 17·· ·June 2012 to May 2013.··Correct, sir?

18·· ·transmission month to month, and, say, based on the 18·· · · ·A· ··It's based on the expected investment, the 19·· ·rules of MSS-2, what should be determined to be 19·· ·changes in responsibility ratio for that 12-month 20·· ·equalizable investment. 20·· ·period.

21·· · · · · · · · ·They review that as they provide it, and 21·· · · ·Q· ··Okay.··And do you have Cities Exhibit 39 there, 22·· ·in that particular month, there was an adjustment where 22·· ·sir?··That's the demonstrative with all the numbers.

23·· ·they said that the investment that was there the month 23·· · · ·A· ··Yes, I have that in front of me. 24·· ·before -- a portion of that was no longer equalizable 24·· · · ·Q· ··Okay.··For that time period that we just 25·· ·and shouldn't have been equalizable.··So it was adjusted 25·· ·discussed, June 2012 to May 2013, you had to get an Page 760 Page 762 ·1·· ·out.··The investment is still there.··It's just not ·1·· ·estimate of all the plant costs on Lines a. through d. ·2·· ·determined to be equalizable investment. ·2·· ·Correct? ·3·· · · · · · · · ·JUDGE BURKHALTER:··Meaning it's not 230 kV ·3·· · · ·A· ··That's correct.··We would had to have a point ·4·· ·or above? ·4·· ·of view on the expected transmission investment. ·5·· · · · · · · · ·THE WITNESS:··Generally, yes, that's ·5·· · · ·Q· ··Somebody had to forecast all that stuff. ·6·· ·correct. ·6·· ·Right? ·7·· · · ·Q· ··(BY MR. LAWTON)··Now, sir -- ·7·· · · ·A· ··They had to forecast, or they looked at what ·8·· · · · · · · · ·MR. LAWTON:··I'm sorry.··I don't want to ·8·· ·projects were already being built that they thought were ·9·· ·interrupt again. ·9·· ·going to be completed, so a forecast based on existing 10·· · · · · · · · ·JUDGE WALSTON:··Okay. 10·· ·projects and forecasted projects.

11·· · · ·Q· ··(BY MR. LAWTON)··Now, the company has, in fact, 11·· · · ·Q· ··Okay.··And then if we look under the category 12·· ·forecast a 10.6 million-dollar number for this MSS-2 12·· ·cost of capital; debt ratio, bond costs, all the way 13·· ·category.··Correct? 13·· ·down to Item e., did you get a forecast for all those 14·· · · ·A· ··It's 10.696, I think. 14·· ·numbers?

15·· · · ·Q· ··You've got more decimal places than I, sir. 15·· · · ·A· ··I don't think those numbers were updated for 16·· · · · · · · · ·But this $10.6 million is roughly a 16·· ·that period.

17·· ·9 million-dollar increase, and it's included in the 17·· · · ·Q· ··They weren't?

18·· ·111 million request the company originally made.··Right? 18·· · · ·A· ··I don't -- I don't know, to be honest.

19·· · · ·A· ··It's a -- yes.··The $10.69 million is the rate 19·· · · ·Q· ··You don't know?

20·· ·year -- expected rate year MSS-2 expense. 20·· · · ·A· ··No, I don't.

21·· · · ·Q· ··All right.··Fair enough.··Now, go back, for a 21·· · · ·Q· ··Who knows?

22·· ·moment, to the demonstrative for Cities, Exhibit 39. 22·· · · ·A· ··Somebody that -- the gentlemen or gentleman 23·· · · · · · · · ·MR. LAWTON:··Your Honor, may I use this a 23·· ·that reviewed that.··I don't -- I don't know personally.

24·· ·second? 24·· · · ·Q· ··But I thought you reviewed it.

25·· · · · · · · · ·JUDGE WALSTON:··Yes. 25·· · · ·A· ··I reviewed it, but I don't remember whether

KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 12 (Pages 763-766) Page 763 Page 765 ·1·· ·those changed or not.··I just don't remember that. ·1·· · · ·Q· ··When they did the load forecast for Entergy ·2·· · · ·Q· ··Let's go to the tax rate.··Do you think that ·2·· ·Texas, did they have an increase in load for Entergy ·3·· ·changed? ·3·· ·Texas, sir?··Do you know? ·4·· · · ·A· ··I don't -- the factors I'm not sure of. ·4·· · · ·A· ··I don't know. ·5·· · · ·Q· ··Okay.··Well, would that include the factors ·5·· · · ·Q· ··Is the -- okay. ·6·· ·under O&M expenses, too? ·6·· · · · · · · · ·The last area that I want to ask you about ·7·· · · ·A· ··Everything from cost of capital through, you ·7·· ·is I think on your -- I have passed out this morning -- ·8·· ·know, the net investment ratio.··Those numbers, I just ·8·· ·is copy of Cities Exhibit 7.··It's part of 10-K.··It's ·9·· ·don't know if the financial factors were updated. ·9·· ·already into the record.··I just wanted to ask you a 10·· · · ·Q· ··Is there somebody in this case I can ask about 10·· ·little bit about the 10-K.

11·· ·it? 11·· · · ·A· ··Okay.

12·· · · ·A· ··I don't know, Mr. Lawton. 12·· · · ·Q· ··Go to Page 364 of the 10-K, sir.

13·· · · ·Q· ··Okay.··What about all the other numbers, net 13·· · · ·A· ··Okay.··I'm there.

14·· ·investment ratio, and all that, was that -- 14·· · · ·Q· ··Under "Other income statement variances" -- do 15·· · · ·A· ··Those are calculations, so those are embedded 15·· ·you see that in bold?

16·· ·in -- if you update, you know, the net transmission 16·· · · ·A· ··Yes, I see that.

17·· ·investment, then you update, you know, the ratio -- that 17·· · · ·Q· ··Go to the first bullet point and read that to 18·· ·ratio anyway. 18·· ·yourself.

19·· · · ·Q· ··Would you agree with me, sir -- we went through 19·· · · ·A· ··To myself?

20·· ·this -- that the cost of capital and all these O&M 20·· · · ·Q· ··Yes.

21·· ·factors are important parts of the calculation as well? 21·· · · · · · · · ·(Brief pause) 22·· · · ·A· ··Yes.··They're important parts of the 22·· · · ·A· ··Okay.··I've read it.

23·· ·calculation, but they don't typically vary a great deal. 23·· · · ·Q· ··(BY MR. LAWTON)··All right.··What I understand 24·· ·I mean, the significant change that generated the 24·· ·the 10-K -- the company, Entergy Corp., is reporting 25·· ·10.6 million was the change in the investment. 25·· ·that Entergy Texas, Inc., had some billing adjustments Page 764 Page 766 ·1·· · · ·Q· ··Well, let's talk about the load responsibility ·1·· ·to make in its MSS-2 expenditures.··Is that a fair ·2·· ·ratio.··Isn't that line -- what line is that, sir? ·2·· ·characterization creation of that statement? ·3·· · · ·A· ··On the demonstrative exhibit, it's Line s. ·3·· · · ·A· ··As it reads here, there was a transmission -- a ·4·· · · ·Q· ··Line s.··And isn't that load responsibility ·4·· ·change of 2011 -- down to year 2011 over calendar year ·5·· ·ratio based upon the forecast of loads in your example ·5·· ·2010.··There was a variance in transmission expenses of ·6·· ·here in your estimate? ·6·· ·roughly 8 and a half million dollars. ·7·· · · ·A· ··Are we talking about the rate year? ·7·· · · ·Q· ··Okay.··Would those be -- that 8 and a half ·8·· · · ·Q· ··Yes, sir.··Did somebody forecast the load ·8·· ·million referred to MSS-2 payments? ·9·· ·responsibility for the rate year to get 10.6 million? ·9·· · · ·A· ··The 8 and a half million appears to be due to a 10·· · · ·A· ··Yes, they updated -- that they did update, but 10·· ·change in the MSS-2 expenses from 2011 to 2010, a 11·· ·it's a very small percentage.··I mean, basically out of 11·· ·portion of that, and it's not a large portion of that, 12·· ·10.6, you know, that was less than 15 percent of the 12·· ·was related to that 16-year period from 1996 to 2011, 13·· ·adjustment. 13·· ·the billing adjustment for that period.

14·· · · ·Q· ··Based on your calculations.··Correct? 14·· · · ·Q· ··Okay.··So would it fair to say that the 15·· · · ·A· ··Based on my calculations.··Correct. 15·· ·company, Entergy Texas, Inc., or one of the groups 16·· · · ·Q· ··In rebuttal testimony, and we're going to talk 16·· ·there, did an audit for that time period, 1996 to 2011?

17·· ·about it at another time.··Right? 17·· ·Fair?

18·· · · ·A· ··It was calculated, you know, under my 18·· · · ·A· ··There was a review of the MSS-2 balances for 19·· ·supervision, and it's included in my rebuttal testimony. 19·· ·that period, 1996 to 2011, that resulted in a change in 20·· · · ·Q· ··Okay. 20·· ·the MSS-2 payments for -- over that 16-year period, and 21·· · · ·A· ··It's a very small percentage of the total. 21·· ·when you look at 2011 versus 2010, the variance is 8 and 22·· · · ·Q· ··Who did the load forecast, sir? 22·· ·a half million dollars for that period, but only a 23·· · · ·A· ··I believe the load forecast was generated out 23·· ·small -- less than half of that really related to that 24·· ·of one of the groups in our system planning 24·· ·adjustment.

25·· ·organization. 25·· · · · · · · · ·It could be other changes in transmission

KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 16 (Pages 779-782) Page 779 Page 781 ·1·· ·know whether he's also appeared for cross-examination in ·1·· ·Attachment 5 of the inter-system bill. ·2·· ·this proceeding? ·2·· · · ·Q· ··And has the company provided the inter-system ·3·· · · ·A· ··Yes, he's already appeared. ·3·· ·bill for a period of time in this case? ·4·· · · ·Q· ··And, now, what does -- does Mr. Considine ·4·· · · ·A· ··I believe in Cities 5-1, it's provided these ·5·· ·support the pro forma for MSS-2? ·5·· ·attachments, I believe, through February of 2011 -- ·6·· · · ·A· ··Mr. Considine also supports the pro forma for ·6·· ·2012.··I'm sorry. ·7·· ·MSS-2. ·7·· · · ·Q· ··And that is an attachment to 5-1? ·8·· · · ·Q· ··And what is the nature of his support for that? ·8·· · · ·A· ··Yes. ·9·· · · ·A· ··Mr. Considine looks -- took all the changes to ·9·· · · ·Q· ··And I think that is Cities Exhibit 29, so let's 10·· ·the test year that were perceived to be known and 10·· ·turn to that.

11·· ·measurable changes to the test year and adjusted the 11·· · · ·A· ··Okay.

12·· ·test year expenses by those known and measurable 12·· · · ·Q· ··Now, would we find Page 2 of Cities Exhibit 39 13·· ·adjustments. 13·· ·in the documents attached to -- or in the attachments to 14·· · · ·Q· ··Do you know whether Mr. Considine has already 14·· ·Cities Exhibit 29?

15·· ·appeared for cross-examination in this proceeding? 15·· · · ·A· ··Attachment 5 is -- which is the second page of 16·· · · ·A· ··Yes, he has already appeared. 16·· ·the Cities exhibit, is found as an attachment to Cities 17·· · · ·Q· ··I would like to turn to Mr. Lawton's 17·· ·5-1.

18·· ·demonstrable exhibit. 18·· · · ·Q· ··Right.··And, I mean, this -- what I'm talking 19·· · · · · · · · ·MR. WESTERBURG:··Was that Exhibit 37? 19·· ·about is the very specific month that -- could we turn 20·· · · · · · · · ·JUDGE WALSTON:··39. 20·· ·to that?

21·· · · · · · · · ·MR. WESTERBURG:··39.··Excuse me. 21·· · · · · · · · ·JUDGE WALSTON:··Which page are we turning 22·· ·Exhibit 39. 22·· ·to?

23·· · · ·Q· ··(BY MR. WESTERBURG)··Mr. Lawton took you 23·· · · · · · · · ·MR. WESTERBURG:··What I'm trying to do, 24·· ·through a discussion of the numbers and the columns and 24·· ·Your Honor, is find, in Cities Exhibit 29, 5-1, which is 25·· ·the lines that appear on Page 2 here.··You recall that? 25·· ·a number of Attachment 5 to the inter-system bill.··I'm Page 780 Page 782 ·1·· · · ·A· ··Yes, I do. ·1·· ·trying to find this specific page that is Page 2 of ·2·· · · ·Q· ··Do you have a sense, or do you have an opinion, ·2·· ·Cities 39.··So I'm dealing with both 39 and 29. ·3·· ·Mr. Cicio, about -- with respect to the number in the ·3·· · · ·A· ··If you go to Page 22 of Cities 5-1, you'll find ·4·· ·bottom right-hand corner, which on Exhibit 39, it shows ·4·· ·the July 2011 MSS-2 calculation, which is the same page ·5·· ·an MSS-2 payment for ETI -- with respect to that number, ·5·· ·as -- second page of the Cities demonstrative exhibit. ·6·· ·do you know, or would you have an opinion as to which ·6·· · · ·Q· ··(BY MR. WESTERBURG)··Okay.··Thank you, ·7·· ·numbers or groups of numbers change more than others to ·7·· ·Mr. Cicio.··And can you verify whether all of the ·8·· ·affect that number? ·8·· ·attachments to Cities 5-1, the -- sounds strange, but ·9·· · · ·A· ··I mean, the majority of this calculation is -- ·9·· ·I'm referring to them as the Attachment 5s -- with an 10·· ·a large percent of the calculation turns on the change 10·· ·"S" on the end of it.

11·· ·in total investment and net transmission investment. 11·· · · ·A· ··Okay.

12·· ·Generally speaking, the rest of the components, the cost 12·· · · ·Q· ··All of those are historical.··Is that correct?

13·· ·rates, the responsibility ratios don't change typically, 13·· · · ·A· ··Yes, these are historical periods.··I think the 14·· ·you know, much year over year. 14·· ·last month is February of 2012.

15·· · · ·Q· ··And, now, this document we're looking at, at 15·· · · ·Q· ··And does that mean that the information 16·· ·Page 2 of exhibit -- Cities Exhibit 39, this same form 16·· ·contained on these Attachment 5s reflect actual data and 17·· ·of document -- well, let me ask you, is -- this is a 17·· ·recordings return?

18·· ·page in an attachment to what's referred to as the 18·· · · ·A· ··These are based on the actual inter-system 19·· ·inter-system bill.··Is that correct? 19·· ·bills for those representative months.

20·· · · ·A· ··Yes, that's correct. 20·· · · ·Q· ··Okay.··And can we turn to the very last page of 21·· · · ·Q· ··And just for the sake of the way the transcript 21·· ·Attachment 5, which would be Page 29?

22·· ·might read, what page is this to the inter-system bill 22·· · · ·A· ··Yes, I'm there.

23·· ·in terms of -- you know, what part of the inter-system 23·· · · ·Q· ··And what is this?

24·· ·bill would this be a page of? 24·· · · ·A· ··This is the Attachment 5 for February of 2012.

25·· · · ·A· ··This is -- the MSS-2 calculation is found on 25·· · · ·Q· ··Just -- do you know why -- we're sitting here

KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 17 (Pages 783-786) Page 783 Page 785 ·1·· ·today in April.··Do you know why we don't have March ·1·· · · ·Q· ··Now, there was also discussion with Mr. Lawton ·2·· ·attached to attachment -- Cities Exhibit 29? ·2·· ·about an adjustment to MSS-2.··Do you recall that? ·3·· · · ·A· ··Yes.··The inter-system bill is prepared twice a ·3·· · · ·A· ··Yes, I do. ·4·· ·month.··It's prepared on the second work day of a month, ·4·· · · ·Q· ··Now, does -- the adjustment that's been ·5·· ·and the actual bill is rendered about 30 days after the ·5·· ·discussed, does that play a part in the increase in the ·6·· ·conclusion of the preceding month.··So the actual March ·6·· ·MSS-2 expense from the test year to what we see here on ·7·· ·bill was actually prepared this week -- was issued this ·7·· ·Page 29 of Exhibit 29? ·8·· ·week.··And so it's not yet -- it will be provided once ·8·· · · ·A· ··By -- what you're saying is, "does it play a ·9·· ·it was complete, which is, I think, mid-week or early ·9·· ·part."··To the extent there were changes in the 10·· ·part of this week. 10·· ·investment balance resulting from that review from '96 11·· · · ·Q· ··Okay.··So February was the latest available? 11·· ·to 2011, this calculation is based on cumulative 12·· · · ·A· ··Yes, February was the latest available. 12·· ·balances of transmission investment.

13·· · · ·Q· ··Okay.··And what's the number in the lower 13·· · · · · · · · ·So to the extent there was any change, it 14·· ·right-hand corner under payments for ETI for February, 14·· ·would have had some effect on those balances, but the 15·· ·which is Page 29? 15·· ·majority of this has been -- has occurred post that 16·· · · ·A· ··For February of 2012, ETI had an MSS-2 payment 16·· ·adjustment -- the change in transmission investment, the 17·· ·of $698,289.82. 17·· ·majority of which has been just new investment that's 18·· · · ·Q· ··And those are based on -- that is based on 18·· ·been put in service.

19·· ·actual investment and transmission of the operating 19·· · · ·Q· ··Maybe this is a cleaner question.··Does the 20·· ·companies.··Is that right? 20·· ·February Attachment 5 on Page 29 reflect the adjustment 21·· · · ·A· ··That's correct. 21·· ·and equalizable investment that you discussed with 22·· · · ·Q· ··There's no projections on this page? 22·· ·Mr. Lawton?

23·· · · ·A· ··There are no projections on this page. 23·· · · ·A· ··Does it reflect the equalizable -- 24·· · · ·Q· ··Do you know, Mr. Cicio, what -- or if you have 24·· · · ·Q· ··The adjustment in equalizable investment you 25·· ·it, I think it's a simple calculation. 25·· ·discussed with Mr. Lawton.

Page 784 Page 786 ·1·· · · · · · · · ·Do you know what, you know, 12 times ·1·· · · ·A· ··It reflects the balance -- the changes in the ·2·· ·698,000 would be? ·2·· ·balances. ·3·· · · ·A· ··No, I don't have a calculator on me, but if I ·3·· · · ·Q· ··Well, let me ask for clarification.··What was ·4·· ·rounded it to 700,000, it would be about $8.4 million. ·4·· ·the adjustment?··What was adjusted? ·5·· · · ·Q· ··8.4.··And what was the amount of test year ·5·· · · ·A· ··What was adjusted during that -- from '96 to ·6·· ·MSS-2 expenses? ·6·· ·2011, there were changes in the investment balances ·7·· · · ·A· ··The test year amount was 1.7 million. ·7·· ·across the different companies. ·8·· · · ·Q· ··Do you know whether the MSS-2 payments, as ·8·· · · ·Q· ··The equalizable investment? ·9·· ·reflected in this Cities 29 since the test year, have ·9·· · · ·A· ··The equalizable investment.

10·· ·been increasing or decreasing? 10·· · · ·Q· ··Okay.··Are those changes reflected in Page 29 11·· · · ·A· ··To get to -- I mean, if I looked at the test 11·· ·of Exhibit 29?

12·· ·year payments and receipts -- and since the test year, 12·· · · ·A· ··Yes.··Yes, they are reflected.

13·· ·they've been all payments, and they've been increasing 13·· · · ·Q· ··Do you know whether those changes will continue 14·· ·since the end of the test year. 14·· ·to be reflected going forward in the MSS-2 payments?

15·· · · · · · · · ·I mean, I'm going back, you know, since 15·· · · ·A· ··It's a cumulative balance, so to the extent 16·· ·the test year.··I think there was a slight dip in the -- 16·· ·those changes in -- those assets are still part of the 17·· ·in the month of January, it went from 620 to 596, but 17·· ·net investment, yes, they will continue to be included.

18·· ·generally above the test year monthly levels. 18·· · · ·Q· ··Mr. Lawton asked you about certain operating 19·· · · ·Q· ··And do you know why that has occurred? 19·· ·companies leaving the system agreement or having given 20·· · · ·A· ··There's been, as we talked about, you know, a 20·· ·notice to leave the system agreement.··Do you recall 21·· ·major factor in the change in how the payments and 21·· ·that?

22·· ·receipts for MSS-2 are generated by transmission 22·· · · ·A· ··Yes, I do.

23·· ·investment across the system.··And so there's been a 23·· · · ·Q· ··And those operating companies are Entergy 24·· ·fair amount of transmission investment built and placed 24·· ·Mississippi and Entergy Arkansas?

25·· ·in service across the system during this period. 25·· · · ·A· ··That's correct.

KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 19 (Pages 791-794) Page 791 Page 793 ·1·· ·Do you see that? ·1·· ·projects that are in service or in service early or ·2·· · · ·A· ··Yes.··I think it's Line s. on the -- ·2·· ·projected to be in service, and there's a construction ·3·· · · ·Q· ··And that's what you just explained.··Correct? ·3·· ·amount associated with each of those projects.··So ·4·· · · ·A· ··I explained coincident peak.··Responsibility ·4·· ·they're measurable by that aspect of it. ·5·· ·ratio is the average of the 12 -- preceding 12 months. ·5·· · · ·Q· ··What value does ETI receive for its MSS-2 ·6·· · · ·Q· ··Twelve months what, coincident peak? ·6·· ·payments? ·7·· · · ·A· ··Twelve months coincident peak. ·7·· · · ·A· ··What ETI receives as a benefit from its MSS-2 ·8·· · · ·Q· ··Okay.··Now, is there any other calculation on ·8·· ·payments is the ability to have resources available to ·9·· ·this page that reflects the concept of load, other than ·9·· ·them through the use of the system's bulk electric power 10·· ·responsibility ratio? 10·· ·system.··So if there are resources that are in a 11·· · · ·A· ··No, there's not. 11·· ·different area outside of Texas, by use of that system, 12·· · · ·Q· ··Now, I think Mr. Lawton established that for 12·· ·they have available to them purchased power 13·· ·the purpose of the projections into the rate year of 13·· ·opportunities, other generation from the system that 14·· ·MSS-2, there needed to be a projection of the 14·· ·would benefit customers in terms of lower fuel costs.

15·· ·responsibility ratio.··Is that correct? 15·· · · · · · · · ·So it's part of the coordinated dispatch 16·· · · ·A· ··Yes, that's correct. 16·· ·of the system.··So if you have a coordinated dispatch, 17·· · · ·Q· ··Does that mean that the -- there was a 17·· ·you have to rely on a system to move that power.··That 18·· ·projection of load in order to make that calculation? 18·· ·would be the bulk electric power system.

19·· · · ·A· ··For purposes of the rate year calculation, 19·· · · · · · · · ·MR. WESTERBURG:··I believe I'm finished.

20·· ·there was a forecasted load, which generated a forecast 20·· ·Can I have a 60-second break?

21·· ·of responsibility ratios that was included as part of 21·· · · · · · · · ·JUDGE WALSTON:··Yeah.

22·· ·that. 22·· · · · · · · · ·(Brief pause) 23·· · · ·Q· ··Okay.··Have you made a calculation of what the 23·· · · · · · · · ·MR. WESTERBURG:··No more questions, Your 24·· ·rate year MSS-2 cost would be if you held the load and 24·· ·Honor.

25·· ·responsibility ratio constant from the test year? 25·· · · · · · · · ·JUDGE WALSTON:··Do the Cities have Page 792 Page 794 ·1·· · · ·A· ··Yes, I have. ·1·· ·recross? ·2·· · · ·Q· ··And what is that? ·2·· · · · · · · · ·MR. LAWTON:··Just a bit, Your Honor. ·3·· · · ·A· ··That number was 86 percent of the total.··I ·3·· ·Thank you. ·4·· ·think the adjustment was around $9.4 million, I believe. ·4·· · · · · · · · · · ··RECROSS-EXAMINATION ·5·· · · ·Q· ··That's what the adjustment would be in the rate ·5·· ·BY MR. LAWTON: ·6·· ·year if you held it? ·6·· · · ·Q· ··Mr. Cicio, counsel asked you about your ·7·· · · ·A· ··Yes, the total.··I think the adjustment is ·7·· ·testimony I crossed you about regarding your support for ·8·· ·7-something. ·8·· ·the test year.··You support the test year number. ·9·· · · ·Q· ··Excuse me.··Thank you.··And you address that in ·9·· ·Correct?

10·· ·your rebuttal? 10·· · · ·A· ··That's correct.

11·· · · ·A· ··It's all -- yeah, the actual numbers are 11·· · · ·Q· ··And he also asked you that -- whether you 12·· ·contained in my rebuttal testimony. 12·· ·supported the 9 million pro forma.··Correct?··And you 13·· · · ·Q· ··What is your opinion of whether the rate year 13·· ·do.··Right?

14·· ·change in transmission investment is known? 14·· · · ·A· ··Yes, I support the calculation.

15·· · · ·A· ··I relied on Mr. McCulla's assessment of the 15·· · · ·Q· ··Right.··And you've reviewed the calculations, 16·· ·known and measurable aspect of the MSS-2 -- MSS-2 inputs 16·· ·but you didn't do the calculations?

17·· ·of transmission investment that -- Mr. McCulla believes 17·· · · ·A· ··I have looked at the calculations, that's 18·· ·those are known and measurable changes, then they were 18·· ·correct.

19·· ·known and measurable changes and they were included in 19·· · · ·Q· ··Okay.··And you still don't know who did all the 20·· ·the pro forma adjustment. 20·· ·calculations for the load forecast.··Correct?

21·· · · ·Q· ··My next question for you I think you just 21·· · · ·A· ··I don't know the specific individual.

22·· ·answered, but what is your opinion of whether the change 22·· · · ·Q· ··Okay.··And then you also said that 23·· ·in investment -- excuse me -- the change in the 23·· ·Mr. Considine also supports the 9 million pro forma.

24·· ·investment dollars is measurable? 24·· ·Correct?

25·· · · ·A· ··They are measurable if they were based on 25·· · · ·A· ··Yes, that's correct.

KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 1 (Pages 1-4) Page i Page iii · · · · · · · ··SOAH DOCKET NO. XXX-XX-XXXX ·1· ·1· · · · · · · · ·TABLE OF CONTENTS (CONTINUED) ··· ·2· · · · · · · · · · · · · · · · · · · · · · · · · · · ·PAGE · · · · · · · · · ·PUC DOCKET NO. 39896 ·2· ··· ·3· ·PRESENTATION ON BEHALF OF · ·3· ··ENTERGY · TEXAS, INC. (CONTINUED) ··· ·APPLICATION OF ENTERGY· ··)· ·STATE OFFICE OF ·4· ·4· · ··TEXAS, · INC., FOR· · · · ··) ·AUTHORITY TO CHANGE RATES ) ·5· ···· ··CHRIS E. BARRILLEAUX ··AND · RECONCILE FUEL COSTS, ) ·5· · · · · · ·- Direct (Olson)· · · · · · · · · · · · · ·149 ·AND OBTAIN DEFERRED· · · ·) ·6· ··ACCOUNTING · TREATMENT· · ··) ADMINISTRATIVE HEARINGS ···· · · · ·- Cross (Lawton)· · · · · · · · · · · · · ·151 · ·7· ·6· · · · · · ·- Cross (Griffiths)· · · · · · · · · · · ··167 ··· · ·8· ···· · · · ·- Redirect (Olson)· · · · · · · · · · · · ·187 ··· ·7· · · · · · ·- Recross (Lawton)· · · · · · · · · · · · ·198 · ·9· ··· ·8· · · ··SAMUEL C. HADAWAY · 10· ···· · · · ·- Direct (Williams)· · · · · · · · · · · ··199 ··· · · · · · · · · · ·HEARING ON THE MERITS 11· ·9· · · · · · ·- Cross (Lawton)· · · · · · · · · · · · · ·201 ··· · · · · · · · · ··Wednesday, May 2, 2012 12· ···· · · · ·- Cross (Griffiths)· · · · · · · · · · · ··212 ··· 10· · · · · · ·- Cross (Kelley)· · · · · · · · · · · · · ·230 · 13· ··· ···· · · · ·- Redirect (Williams)· · · · · · · · · · ··231 · 14· 11· · · · · · ·- Recross (Griffiths)· · · · · · · · · · ··239 ··· · · · · · · · · · ··TABLE OF CONTENTS 15· 12· ·PROCEEDINGS RECESSED· · · · · · · · · · · · · · · · ·246 ··· 13· · · · · ·(Volumes 1 through 7, Pages i through xlviii) 16· ··· 14· · · 17· 15· · ··· · 18· 16· · ··· · 19· 17· · ··· 18· · · 20· ··· 19· · · 21· 20· · ··· · 22· 21· · ··· 22· · · 23· ··· 23· · · 24· 24· · ··· · 25· 25· · Page ii Page iv ·1· · · · · · · · · · · ·TABLE OF CONTENTS ·1· · · · · · · · · ··TABLE OF CONTENTS ·2· · · · · · · · · · · · · · · · · · · · · · · · · · · ·PAGE ·2· · · · · · · · · · · · · · · · · · · · · · · · · · · ·PAGE ·3· ·PROCEEDINGS, TUESDAY, APRIL 24, 2012 - VOL. 1· · · · ··5 ·3· ·PROCEEDINGS, WEDNESDAY, APRIL 25, 2012 - VOLUME 2· ··248 ·4· ·OPENING STATEMENT ON BEHALF OF ·4· ·PRESENTATION ON BEHALF OF ··ENTERGY · TEXAS, INC. (Neinast)· · · · · · · · · · · · ·16 ··ENTERGY · TEXAS, INC. (CONTINUED)· · · · · · · · · · ··250 ·5· · ·5· · ···· ··ROBERT D. SLOAN ··OPENING · STATEMENT ON BEHALF OF ·6· · · · · · ·- Direct (Cyr)· · · · · · · · · · · · · · ·250 ·6· ·ENTERGY TEXAS, INC. (Wren)· · · · · · · · · · · · · ··22 ···· · · · ·- Cross (Kelley)· · · · · · · · · · · · · ·253 ·7· ·OPENING STATEMENT ON BEHALF OF ·7· · · · · · ·- Cross (Ferris)· · · · · · · · · · · · · ·258 ··CITIES · (Lawton)· · · · · · · · · · · · · · · · · · · ·37 ···· · · · ·- Redirect (Cyr)· · · · · · · · · · · · · ·285 ·8· · ·8· · · · · · ·- Recross (Ferris)· · · · · · · · · · · · ·295 ··OPENING · STATEMENT ON BEHALF OF ·9· · · ··H. VERNON PIERCE, JR. ·9· ·TEXAS INDUSTRIAL ENERGY CONSUMERS (VanMiddlesworth)· ·41 ···· · · · ·- Direct (Cyr)· · · · · · · · · · · · · · ·303 10· ·OPENING STATEMENT ON BEHALF OF 10· · · · · · ·- Cross (Mack)· · · · · · · · · · · · · · ·305 ··OFFICE · OF PUBLIC UTILITY COUNSEL (Ferris)· · · · · · ·49 ···· · · · ·- Cross (Younger)· · · · · · · · · · · · ··315 11· · 11· · ···· ··MICHAEL P. CONSIDINE ··OPENING · STATEMENT ON BEHALF OF 12· · · · · · ·- Direct (Neinast)· · · · · · · · · · · · ·317 12· ·STAFF (Smyth)· · · · · · · · · · · · · · · · · · · · ·52 ···· · · · ·- Cross (Lawton)· · · · · · · · · · · · · ·318 13· ·OPENING STATEMENT ON BEHALF OF 13· · · · · · ·- Cross (Griffiths)· · · · · · · · · · · ··352 ··THE · UNITED STATES DEPARTMENT OF ENERGY (Porter)· · · ·54 ···· · · · ·- Cross (Kelley)· · · · · · · · · · · · · ·355 14· · 14· · · · · · ·- Redirect (Neinast)· · · · · · · · · · · ·358 15· ·PRESENTATION ON BEHALF OF ···· · · · ·- Recross (Lawton)· · · · · · · · · · · · ·362 ··ENTERGY · TEXAS, INC.· · · · · · · · · · · · · · · · · ·60 15· · 16· · ··AFTERNOON · SESSION· · · · · · · · · · · · · · · · · ··365 ···· ··JOSEPH DOMINO 16· · ··PRESENTATION · ON BEHALF OF 17· · · · · · ·- Direct (Wren)· · · · · · · · · · · · · · ·60 17· ·ENTERGY TEXAS, INC. (CONTINUED)· · · · · · · · · · ··366 ···· · · · ·- Cross (Lawton)· · · · · · · · · · · · · ··62 18· · · ··WALTER C. FERGUSON 18· · ···· · · · ·- Direct (McNally)· · · · · · · · · · · · ·366 ··AFTERNOON · SESSION· · · · · · · · · · · · · · · · · ··103 19· · · · · · ·- Cross (Ferris)· · · · · · · · · · · · · ·367 19· · ···· · · · ·- Redirect (McNally)· · · · · · · · · · · ·369 ··PRESENTATION · ON BEHALF OF 20· · · · · · ·- Recross (Ferris)· · · · · · · · · · · · ·372 20· ·ENTERGY TEXAS, INC. (CONTINUED) ···· · · · ·- Further Redirect (McNally)· · · · · · · ·374 21· · · ··JOSEPH DOMINO 21· · ···· · · · ·- Cross (Lawton - Continued)· · · · · · · ·103 ···· ··DANE A. WATSON 22· · · · · · ·- Direct (Williams)· · · · · · · · · · · ··376 22· · · · · · ·- Cross (VanMiddlesworth)· · · · · · · · ··115 ···· · · · ·- Cross (Lawton)· · · · · · · · · · · · · ·380 ···· · · · ·- Cross (Kelley)· · · · · · · · · · · · · ·131 23· · · · · · ·- Cross (Lawler)· · · · · · · · · · · · · ·397 23· · · · · · ·- Redirect (Wren)· · · · · · · · · · · · ··139 ···· · · · ·- Redirect (Williams)· · · · · · · · · · ··403 ···· · · · ·- Recross (Lawton)· · · · · · · · · · · · ·143 24· · · · · · ·- Recross (Lawton)· · · · · · · · · · · · ·410 24· · · · · · ·- Recross (VanMiddlesworth)· · · · · · · ··144 ···· · · · ·- Recross (Lawler)· · · · · · · · · · · · ·414 25· · 25· ·

KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 11 (Pages 1538-1541) Page 1538 Page 1540 ·1·· · · · · · · · ·MR. VanMIDDLESWORTH:··Yes. ·1·· ·generation.··So that would be in addition to the ·2·· · · ·Q· ··(BY MR. VanMIDDLESWORTH)··Do you see the chart ·2·· ·twenty-nine eighty-nine and the thirty-three seventeen ·3·· ·at the bottom of Page 22? ·3·· ·megawatt numbers purchased. ·4·· · · ·A· ··Yes. ·4·· · · ·Q· ··Okay.··So do you know about what the overall ·5·· · · ·Q· ··Okay.··What does that tell you about the amount ·5·· ·growth in the overall generation is from year-to-year? ·6·· ·of capacity that Entergy is purchasing in what they call ·6·· · · ·A· ··So if we take the purchases plus the owned ·7·· ·the "rate year" versus the test year? ·7·· ·capacity and compare the two, the test year and the rate ·8·· · · ·A· ··That chart shows that as far as purchased ·8·· ·year, it's about a 7.8 percent change in overall ·9·· ·capacity is concerned that the Company anticipates that ·9·· ·capacity.

10·· ·it will need additional capacity or, roughly, if you 10·· · · ·Q· ··By the way, for the rate year, you mentioned 11·· ·take it on average, the test year number, 35,863, is 11·· ·something about the timing of the rate year.··What has 12·· ·about 2,989 megawatts per month, and the rate year would 12·· ·Entergy used for the rate year?

13·· ·go up to 39,807 which suggests an average amount of 13·· · · ·A· ··So the rate year that Entergy uses is the 14·· ·purchases of 3,317 megawatts per month. 14·· ·period -- I might get this wrong.··Let me look -- 15·· · · ·Q· ··Can you give me the -- so the numbers you have 15·· ·June 2012 through May 2013.

16·· ·here are megawatt month numbers and you just converted 16·· · · ·Q· ··And I guess that was what they used in their 17·· ·them to annual megawatt numbers? 17·· ·filing?

18·· · · ·A· ··Yes. 18·· · · ·A· ··That's correct.

19·· · · ·Q· ··Can you give me the test year and rate year 19·· · · ·Q· ··And since then, do you know if there's been any 20·· ·megawatts again, please? 20·· ·agreement about the implementation of rates in this 21·· · · ·A· ··2,989 test year; 3,317 rate year. 21·· ·case?

22·· · · ·Q· ··And is that just third-party purchases, or does 22·· · · ·A· ··My understanding is that rates would become 23·· ·that include the effect of all the purchases? 23·· ·effective on June 30th.··So that effectively moves the 24·· · · ·A· ··That's all the purchases.··So it's third-party, 24·· ·rate year up a month -- or back a month.

25·· ·affiliate and MSS-1. 25·· · · ·Q· ··All right.

Page 1539 Page 1541 ·1·· · · ·Q· ··And what are the MSS-1? ·1·· · · · · · · · ·Now, you mentioned the importance of unit ·2·· · · ·A· ··The MSS-1 is the reserve equalization payments. ·2·· ·costs.··The 300-plus megawatts of additional purchases, ·3·· ·So the Company takes service from the system.··So to the ·3·· ·what does that go to?··I'm talking about the 300-plus ·4·· ·extent that the Company's owned resources or purchased ·4·· ·megawatts of the difference between the test year and ·5·· ·power resources are less than its obligation, then it ·5·· ·rate year. ·6·· ·will purchase capacity from the other operating ·6·· · · ·A· ··The utility will purchase additional capacity ·7·· ·companies. ·7·· ·mainly because it anticipates serving additional load. ·8·· · · ·Q· ··Is that firm or interruptible capacity? ·8·· · · ·Q· ··It would make sense to purchase additional ·9·· · · ·A· ··It's firm -- the system provides service to the ·9·· ·capacity if you didn't and to have more capacity if you 10·· ·Company and those system resources are network 10·· ·weren't planning on serving more load?

11·· ·resources; therefore, the power is considered firm. 11·· · · ·A· ··No. 12·· · · ·Q· ··Is it -- but does each company operate 12·· · · ·Q· ··Do you know whether that load is wholesale load 13·· ·separately, or is the system generation operated as a 13·· ·or retail load?

14·· ·system? 14·· · · ·A· ··I do not.

15·· · · ·A· ··The system agreement is what basically ties all 15·· · · ·Q· ··Does that matter for purposes of the unit cost 16·· ·six operating companies together as a single unit for 16·· ·analysis?

17·· ·planning and operational purposes.··So for all things in 17·· · · ·A· ··No. 18·· ·effect, it's the system that's providing the service. 18·· · · ·Q· ··Why not?

19·· · · ·Q· ··So, if you show that there's, I think, a little 19·· · · ·A· ··Because initially we're determining the 20·· ·more than 300 megawatts difference in purchases -- 20·· ·Company's overall revenue requirement which includes 21·· · · ·A· ··Yes. 21·· ·retail and wholesale.··Ultimately, once you've 22·· · · ·Q· ··-- is there any difference in the -- I guess 22·· ·established what that number is, then you've got to 23·· ·purchases aren't all of their generation capacity.··They 23·· ·separate the retail and the wholesale to set rates in 24·· ·have -- what else do they have? 24·· ·this case.

25·· · · ·A· ··ETI has about 1200 megawatts of owned 25·· · · ·Q· ··So we've seen the number -- the proposed rate

KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 1 (Pages 1-4) Page i Page iii · · · · · · · ··SOAH DOCKET NO. XXX-XX-XXXX ·1· ·1· · · · · · · · ·TABLE OF CONTENTS (CONTINUED) ··· ·2· · · · · · · · · · · · · · · · · · · · · · · · · · · ·PAGE · · · · · · · · · ·PUC DOCKET NO. 39896 ·2· ··· ·3· ·PRESENTATION ON BEHALF OF · ·3· ··ENTERGY · TEXAS, INC. (CONTINUED) ··· ·APPLICATION OF ENTERGY· ··)· ·STATE OFFICE OF ·4· ·4· · ··TEXAS, · INC., FOR· · · · ··) ·AUTHORITY TO CHANGE RATES ) ·5· ···· ··CHRIS E. BARRILLEAUX ··AND · RECONCILE FUEL COSTS, ) ·5· · · · · · ·- Direct (Olson)· · · · · · · · · · · · · ·149 ·AND OBTAIN DEFERRED· · · ·) ·6· ··ACCOUNTING · TREATMENT· · ··) ADMINISTRATIVE HEARINGS ···· · · · ·- Cross (Lawton)· · · · · · · · · · · · · ·151 · ·7· ·6· · · · · · ·- Cross (Griffiths)· · · · · · · · · · · ··167 ··· · ·8· ···· · · · ·- Redirect (Olson)· · · · · · · · · · · · ·187 ··· ·7· · · · · · ·- Recross (Lawton)· · · · · · · · · · · · ·198 · ·9· ··· ·8· · · ··SAMUEL C. HADAWAY · 10· ···· · · · ·- Direct (Williams)· · · · · · · · · · · ··199 ··· · · · · · · · · · ·HEARING ON THE MERITS 11· ·9· · · · · · ·- Cross (Lawton)· · · · · · · · · · · · · ·201 ··· · · · · · · · · ··Thursday, May 3, 2012 12· ···· · · · ·- Cross (Griffiths)· · · · · · · · · · · ··212 ··· 10· · · · · · ·- Cross (Kelley)· · · · · · · · · · · · · ·230 · 13· ··· ···· · · · ·- Redirect (Williams)· · · · · · · · · · ··231 · 14· 11· · · · · · ·- Recross (Griffiths)· · · · · · · · · · ··239 ··· · · · · · · · · · ··TABLE OF CONTENTS 15· 12· ·PROCEEDINGS RECESSED· · · · · · · · · · · · · · · · ·246 ··· 13· · · · · · ·(Volumes 1 through 8, Pages i through l) 16· ··· 14· · · 17· 15· · ··· · 18· 16· · ··· · 19· 17· · ··· 18· · · 20· ··· 19· · · 21· 20· · ··· · 22· 21· · ··· 22· · · 23· ··· 23· · · 24· 24· · ··· · 25· 25· · Page ii Page iv ·1· · · · · · · · · · · ·TABLE OF CONTENTS ·1· · · · · · · · · ··TABLE OF CONTENTS ·2· · · · · · · · · · · · · · · · · · · · · · · · · · · ·PAGE ·2· · · · · · · · · · · · · · · · · · · · · · · · · · · ·PAGE ·3· ·PROCEEDINGS, TUESDAY, APRIL 24, 2012 - VOL. 1· · · · ··5 ·3· ·PROCEEDINGS, WEDNESDAY, APRIL 25, 2012 - VOLUME 2· ··248 ·4· ·OPENING STATEMENT ON BEHALF OF ·4· ·PRESENTATION ON BEHALF OF ··ENTERGY · TEXAS, INC. (Neinast)· · · · · · · · · · · · ·16 ··ENTERGY · TEXAS, INC. (CONTINUED)· · · · · · · · · · ··250 ·5· · ·5· · ···· ··ROBERT D. SLOAN ··OPENING · STATEMENT ON BEHALF OF ·6· · · · · · ·- Direct (Cyr)· · · · · · · · · · · · · · ·250 ·6· ·ENTERGY TEXAS, INC. (Wren)· · · · · · · · · · · · · ··22 ···· · · · ·- Cross (Kelley)· · · · · · · · · · · · · ·253 ·7· ·OPENING STATEMENT ON BEHALF OF ·7· · · · · · ·- Cross (Ferris)· · · · · · · · · · · · · ·258 ··CITIES · (Lawton)· · · · · · · · · · · · · · · · · · · ·37 ···· · · · ·- Redirect (Cyr)· · · · · · · · · · · · · ·285 ·8· · ·8· · · · · · ·- Recross (Ferris)· · · · · · · · · · · · ·295 ··OPENING · STATEMENT ON BEHALF OF ·9· · · ··H. VERNON PIERCE, JR. ·9· ·TEXAS INDUSTRIAL ENERGY CONSUMERS (VanMiddlesworth)· ·41 ···· · · · ·- Direct (Cyr)· · · · · · · · · · · · · · ·303 10· ·OPENING STATEMENT ON BEHALF OF 10· · · · · · ·- Cross (Mack)· · · · · · · · · · · · · · ·305 ··OFFICE · OF PUBLIC UTILITY COUNSEL (Ferris)· · · · · · ·49 ···· · · · ·- Cross (Younger)· · · · · · · · · · · · ··315 11· · 11· · ···· ··MICHAEL P. CONSIDINE ··OPENING · STATEMENT ON BEHALF OF 12· · · · · · ·- Direct (Neinast)· · · · · · · · · · · · ·317 12· ·STAFF (Smyth)· · · · · · · · · · · · · · · · · · · · ·52 ···· · · · ·- Cross (Lawton)· · · · · · · · · · · · · ·318 13· ·OPENING STATEMENT ON BEHALF OF 13· · · · · · ·- Cross (Griffiths)· · · · · · · · · · · ··352 ··THE · UNITED STATES DEPARTMENT OF ENERGY (Porter)· · · ·54 ···· · · · ·- Cross (Kelley)· · · · · · · · · · · · · ·355 14· · 14· · · · · · ·- Redirect (Neinast)· · · · · · · · · · · ·358 15· ·PRESENTATION ON BEHALF OF ···· · · · ·- Recross (Lawton)· · · · · · · · · · · · ·362 ··ENTERGY · TEXAS, INC.· · · · · · · · · · · · · · · · · ·60 15· · 16· · ··AFTERNOON · SESSION· · · · · · · · · · · · · · · · · ··365 ···· ··JOSEPH DOMINO 16· · ··PRESENTATION · ON BEHALF OF 17· · · · · · ·- Direct (Wren)· · · · · · · · · · · · · · ·60 17· ·ENTERGY TEXAS, INC. (CONTINUED)· · · · · · · · · · ··366 ···· · · · ·- Cross (Lawton)· · · · · · · · · · · · · ··62 18· · · ··WALTER C. FERGUSON 18· · ···· · · · ·- Direct (McNally)· · · · · · · · · · · · ·366 ··AFTERNOON · SESSION· · · · · · · · · · · · · · · · · ··103 19· · · · · · ·- Cross (Ferris)· · · · · · · · · · · · · ·367 19· · ···· · · · ·- Redirect (McNally)· · · · · · · · · · · ·369 ··PRESENTATION · ON BEHALF OF 20· · · · · · ·- Recross (Ferris)· · · · · · · · · · · · ·372 20· ·ENTERGY TEXAS, INC. (CONTINUED) ···· · · · ·- Further Redirect (McNally)· · · · · · · ·374 21· · · ··JOSEPH DOMINO 21· · ···· · · · ·- Cross (Lawton - Continued)· · · · · · · ·103 ···· ··DANE A. WATSON 22· · · · · · ·- Direct (Williams)· · · · · · · · · · · ··376 22· · · · · · ·- Cross (VanMiddlesworth)· · · · · · · · ··115 ···· · · · ·- Cross (Lawton)· · · · · · · · · · · · · ·380 ···· · · · ·- Cross (Kelley)· · · · · · · · · · · · · ·131 23· · · · · · ·- Cross (Lawler)· · · · · · · · · · · · · ·397 23· · · · · · ·- Redirect (Wren)· · · · · · · · · · · · ··139 ···· · · · ·- Redirect (Williams)· · · · · · · · · · ··403 ···· · · · ·- Recross (Lawton)· · · · · · · · · · · · ·143 24· · · · · · ·- Recross (Lawton)· · · · · · · · · · · · ·410 24· · · · · · ·- Recross (VanMiddlesworth)· · · · · · · ··144 ···· · · · ·- Recross (Lawler)· · · · · · · · · · · · ·414 25· · 25· ·

KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 43 (Pages 1938-1941) Page 1938 Page 1940 ·1·· ·Frontier is a contract that is already in place.··It was ·1·· · · · · · · · ·And for those reasons, this company could ·2·· ·in place during the test year.··All that remains to be ·2·· ·not procure in a manner that was consistent with our ·3·· ·done is to ensure that the costs, because those costs ·3·· ·general planning principles, as described by Mr. Cooper. ·4·· ·stepped up during the test year as well as the capacity ·4·· ·And so for those reasons, we're now put in the position ·5·· ·stepped up during the test year, that those costs are ·5·· ·of having to sort of make up.··It would be almost like ·6·· ·adequately adjusted for in the adjusted test year. ·6·· ·if you missed a few mortgage payments, you still have to ·7·· · · · · · · · ·Another example is the Calpine contract. ·7·· ·make those mortgage payments up.··And that's kind of ·8·· ·The Calpine contract does not increase the capacity of ·8·· ·where -- the position we are in today, trying to ·9·· ·the Entergy system.··That is a contract that is already ·9·· ·rebalance the company's portfolio in a way that's 10·· ·in place.··What will happen at the end of this month, 10·· ·consistent with those planning principles.

11·· ·that contract will be allocated differently to reflect 11·· · · ·Q· ··And can you explain -- do you have an idea of 12·· ·the fact that overhang of retail competition has been 12·· ·when the company on its current track would catch up and 13·· ·removed and now we are allocating modern and highly 13·· ·no longer become a short company?

14·· ·efficient, flexible generation to Entergy Texas; and 14·· · · ·A· ··No.··That -- that's a question -- 15·· ·that allocation is consistent with those criteria that 15·· · · ·Q· ··But we're not there now?

16·· ·Mr. Cooper talked about in his testimony. 16·· · · ·A· ··No, we certainly are not.

17·· · · · · · · · ·And so for those reasons, no, I don't 17·· · · ·Q· ··You had mentioned that the Calpine contract was 18·· ·believe that that example is consistent. 18·· ·not brought for serving new load.··Does it nonetheless 19·· · · ·Q· ··And you mentioned in your answer -- and this 19·· ·provide benefits to customers?

20·· ·also came up, I think, from Mr. Lawton -- that ETI is 20·· · · ·A· ··Yes, sir, it does.··The Calpine contract -- and 21·· ·short.··Can you explain -- 21·· ·that's the contract, as I mentioned, is already 22·· · · · · · · · ·MS. FERRIS:··Your Honor, I object.··This 22·· ·providing service to the system.··It's currently not 23·· ·is beyond the scope of my cross-examination. 23·· ·allocated to ETI.··However, I believe it's -- at the end 24·· · · · · · · · ·JUDGE WALSTON:··Well, but there was also 24·· ·of this month, it will begin providing service to 25·· ·other cross before the lunch break. 25·· ·Entergy Texas customers, a very attractive contract.··It Page 1939 Page 1941 ·1·· · · · · · · · ·MS. FERRIS:··Okay.··You're -- I'm sorry. ·1·· ·has an attractive heat rate, a 7500 heat rate; and the ·2·· · · · · · · · ·JUDGE WALSTON:··Right.··Yeah. ·2·· ·cost of that contract, given, for instance, the fact ·3·· · · · · · · · ·MR. NEINAST:··I agree. ·3·· ·that it also displaces MSS-1 capacity, gas prices would ·4·· · · · · · · · ·JUDGE WALSTON:··No problem. ·4·· ·probably have to drop below a dollar per MMBtu for that ·5·· · · · · · · · ·MR. NEINAST:··It is beyond hers. ·5·· ·contract not to be economic.··In other words, at gas ·6·· · · · · · · · ·MS. FERRIS:··Sorry about that. ·6·· ·prices today, the fuel savings alone from that contract ·7·· · · ·Q· ··(BY MR. NEINAST)··Mr. Lawton had asked you, I ·7·· ·pay for that contract over multiple times. ·8·· ·believe -- I believe it was Mr. Lawton -- about the ·8·· · · ·Q· ··And that benefits ETI's customers? ·9·· ·company being short, and you had started to talk about ·9·· · · ·A· ··Yes, sir, it does.

10·· ·why the company is short and it's been there -- can you 10·· · · ·Q· ··You might -- let me ask the question again; and 11·· ·go into more detail?··Why is the company short?··What is 11·· ·if you've already answered this question, then, please, 12·· ·it doing about it? 12·· ·you don't need to go any further into it.

13·· · · ·A· ··Yeah, and, you know, primarily, what -- what 13·· · · · · · · · ·But what I had written down, based on the 14·· ·happened is, we were required to go to retail 14·· ·cross-examination, was some discussion you had with 15·· ·competition; and that requirement began in 1999 with 15·· ·Mr. VanMiddlesworth, and, I think, Mr. Lawton, asking 16·· ·the -- with the -- if I recall correctly, the objective 16·· ·you about whether the post-test year PPA costs can be 17·· ·to go to retail competition in 2002.··However, for a 17·· ·known and measurable?

18·· ·number of reasons, we were not able to do that, and so 18·· · · ·A· ··Yes, sir.

19·· ·we had this sort of constant overhang that we're going 19·· · · ·Q· ··Can you explain why the costs for those 20·· ·to go to retail competition by such-and-such date. 20·· ·contracts can be known and measurable?

21·· ·Constantly a moving target.··You really can't go out and 21·· · · ·A· ··I'll try.

22·· ·procure long-term cash capacity.··You really can't go 22·· · · · · · · · ·The costs in question here -- and I sort 23·· ·out and build a new highly efficient, modern generating 23·· ·of ticked off a number of these.··One of them is the 24·· ·plant in a world where your customers could be severed 24·· ·Frontier contract.··That Frontier contract has probably 25·· ·by someone else in the very near future. 25·· ·been in place -- I don't -- close to a decade, perhaps.

KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 44 (Pages 1942-1945) Page 1942 Page 1944 ·1·· ·Not long after the plant was completed, we began ·1·· ·is, one of the routine sort of adjustments that are made ·2·· ·contracting for it. ·2·· ·are, for instance, merit increases for employees.··And ·3·· · · · · · · · ·What we're talking about here is that ·3·· ·so that's measured -- a known and measurable change. ·4·· ·contract stepping up from -- I believe it's ·4·· ·The fact of the matter is, the day after that ·5·· ·150 megawatts up to 300 megawatts.··And so all that ·5·· ·implementation of that merit increase or the acceptance ·6·· ·needs to be done is to recognize those additional costs ·6·· ·of that as a known and measurable change, an employee ·7·· ·because that step-up occurs in the -- in the midst of ·7·· ·could resign from the company; and, therefore, the costs ·8·· ·the test year.··It doesn't occur through the entire test ·8·· ·would deviate.··But, in general, those cost changes are ·9·· ·year, so it doesn't fully recognize the cost of that ·9·· ·known, they are measurable, and those little deviations 10·· ·contract.··That contract is needed to serve load today, 10·· ·are just not that much a significant part of the 11·· ·and because we have quite a bit of experiences, we have 11·· ·outcome.

12·· ·a good understanding of what the costs are today and 12·· · · ·Q· ··And, finally, on this purchased power topic, 13·· ·what the costs will be in the future. 13·· ·you'd discussed the Frontier contract, the Calpine 14·· · · · · · · · ·Similarly, Calpine, we have -- that is a 14·· ·contract.··I think there's another, the SRMPA?

15·· ·contract that we have some experience with as well.··The 15·· · · ·A· ··Yes, sir.

16·· ·capacity costs are well known.··It's based upon our 16·· · · ·Q· ··Was there anything about that contract that -- 17·· ·experience and based upon a negotiated contract.··I 17·· · · ·A· ··With the SR -- 18·· ·understand that there could be instances, as indicated 18·· · · ·Q· ··-- makes it not known and measurable?

19·· ·by Mr. VanMiddlesworth, that there could be some 19·· · · ·A· ··Well, the SRMPA has a very straightforward $3 20·· ·deviations from the actual payments made.··But, you 20·· ·per kW a month stated rate.··So it's very easy to 21·· ·know, the history there is those are very, very small 21·· ·calculate what those known and measurable costs are.

22·· ·deviations from the actual contracted costs. 22·· · · ·Q· ··My next topic -- almost done -- is MSS-1.··You 23·· · · · · · · · ·When we negotiate those contracts, our 23·· ·were asked some questions by -- I think it was 24·· ·intent is to get the full benefit of that capacity. 24·· ·Mr. VanMiddlesworth.··Generally, I mean, to cut to the 25·· ·Those provisions are generally intended to enforce and 25·· ·chase, there was discussion of maintaining test year Page 1943 Page 1945 ·1·· ·make sure that we get the full benefits of that ·1·· ·loads by taking into account rate year costs.··In the ·2·· ·capacity.··The counterparties intend to get the full ·2·· ·course of that discuss -- and Mr. VanMiddlesworth was ·3·· ·benefit of those capacity costs.··They want to make sure ·3·· ·asking you for some analyses in doing different things ·4·· ·that in the event they do have an outage or need to take ·4·· ·with Entergy Arkansas.··I remember that. ·5·· ·the unit off-line, that it's done in a way that's ·5·· · · ·A· ··Yes, sir. ·6·· ·consistent so they can continue to get paid their full ·6·· · · ·Q· ··But in the course of that discussion, you said ·7·· ·capacity. ·7·· ·something about an analysis by Mr. Cooper that involved ·8·· · · · · · · · ·So, for those reasons, we have a need -- ·8·· ·4.5 million.··What was that -- what was that? ·9·· ·we know what those costs are.··They are measurable, and ·9·· · · ·A· ··Yes, sir.··That is extremely relevant.

10·· ·I think that is consistent with the known and measurable 10·· · · · · · · · ·The situation that was being described by 11·· ·standard. 11·· ·Mr. VanMiddlesworth is what if EAI had higher load, 12·· · · ·Q· ··Well, and also you mentioned inconsistencies 12·· ·would that result -- in the test -- in the rate year, 13·· ·among contracts.··If a contract -- go back to some -- 13·· ·what if they had higher load?··What if ETI had higher 14·· ·not the contract we're talking about here, but some 14·· ·load?··What if they had lower load?

15·· ·contract that's already in base rates. 15·· · · · · · · · ·Mr. Cooper examined that very situation.

16·· · · · · · · · ·Once it's in base rates, does that mean 16·· ·What he did is he locked in the responsibility ratios, 17·· ·there are no inconsistencies in the costs going forward, 17·· ·and what I mean by that is the actual load that was in 18·· ·or those fluctuate so it's not absolutely without doubt 18·· ·the test year was locked in via those responsibility 19·· ·known that it is fixed and never going to change during 19·· ·ratios.··And then he measured for that rate year, what 20·· ·its life? 20·· ·would have been the difference in cost for MSS-1 if 21·· · · ·A· ··Well, while those fluctuations are rather 21·· ·nothing changed with regard to those -- that load 22·· ·small, the fact is, even those contracts in base rates 22·· ·growth.··No operating company deviated whatsoever.··They 23·· ·can fluctuate.··It's just that there's not any real 23·· ·actually used the test year load.··The result of that 24·· ·significant deviation from that. 24·· ·was approximately $4.5 million reduction in our MSS-1 25·· · · · · · · · ·And another example of this, in my mind 25·· ·cost as a result of locking in those loads.

KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 45 (Pages 1946-1949) Page 1946 Page 1948 ·1·· · · · · · · · ·MR. NEINAST:··No further questions. ·1·· · · · · · · · · · ·RECROSS-EXAMINATION ·2·· · · · · · · · · ··CLARIFYING EXAMINATION ·2·· ·BY MR. LAWTON: ·3·· ·BY JUDGE WALSTON: ·3·· · · ·Q· ··Mr. May, you would agree that the company has ·4·· · · ·Q· ··Okay.··I want to ask a couple of clarifying ·4·· ·had load growth over the past number of years? ·5·· ·questions, if I can, and I may just show my lack of ·5·· · · ·A· ··Yes, sometimes -- ·6·· ·understanding. ·6·· · · ·Q· ··Some years -- ·7·· · · · · · · · ·But if I understood your testimony, the ·7·· · · ·A· ··-- load growth, sometimes no. ·8·· ·new purchased power contracts are being -- or have been ·8·· · · ·Q· ··Okay.··And you would agree that the -- between ·9·· ·entered into to account for the shortage of capacity. ·9·· ·the test year and the rate year, the company is 10·· ·Correct? 10·· ·projecting load to grow?

11·· · · ·A· ··Yes, sir. 11·· · · ·A· ··Yes, sir.

12·· · · ·Q· ··Okay.··And not for load growth.··Correct? 12·· · · ·Q· ··Okay.··And if load growth occurs and the 13·· · · ·A· ··Yes.··In this case, the needs that are driven 13·· ·company does not buy any additional capability, what 14·· ·by the allocation -- for instance, Calpine.··That is a 14·· ·happens?··Does it become more short?

15·· ·contract that already exists on the system.··What is 15·· · · ·A· ··That would depend upon what happens with the 16·· ·happening right now, none of that comes to ETI.··But 16·· ·other operating companies.

17·· ·what will happen is, 50 percent of that will be 17·· · · ·Q· ··Fair enough.··All else equal, to use one of 18·· ·allocated to ETI.··The other 50 percent will be to 18·· ·Mr. VanMiddlesworth's phrases.

19·· ·Entergy Gulf States Louisiana.··That is essentially 19·· · · ·A· ··To the extent that load grows and we do not add 20·· ·recognizing the fact that this company now has some 20·· ·capacity, it is an accurate statement that the company 21·· ·resolution less uncertainty about what its future is, 21·· ·will become more short.

22·· ·and so it's allocating long-term contracts to meet its 22·· · · ·Q· ··Okay.··So we know that load grows from year to 23·· ·needs. 23·· ·year, or it's projected.··Correct?

24·· · · ·Q· ··But what I was leading up to is that capacity 24·· · · ·A· ··Certainly a possibility.

25·· ·is added, then the MSS-1 costs would go down? 25·· · · ·Q· ··All right.··And is some of the purchased power Page 1947 Page 1949 ·1·· · · ·A· ··Yes, sir. ·1·· ·here in this case being purchased to replace contracts ·2·· · · ·Q· ··Okay. ·2·· ·that are dropping off in the test year, or do you know? ·3·· · · ·A· ··It is a very straightforward calculation. ·3·· · · ·A· ··That direct relationship, I can't speak to. ·4·· · · ·Q· ··Okay.··And actually, that's all I want to know. ·4·· · · ·Q· ··That's something I'd ask Mr. Cooper? ·5·· · · · · · · · ·But just can you tell me, just in ballpark ·5·· · · ·A· ··You certainly can.··But certainly, it's a fact ·6·· ·amounts, is the increase and the decrease, is that a ·6·· ·that there are changes in the overall makeup. ·7·· ·wash or is one more or less? ·7·· · · ·Q· ··Fair enough. ·8·· · · ·A· ··It depends on the contract, sir.··For instance, ·8·· · · · · · · · ·MR. LAWTON:··Your Honor, I pass the ·9·· ·the Calpine contract is priced higher than MSS-1.··Now, ·9·· ·witness.··Thank you.

10·· ·when you look at our rate year MSS-1 calculation, it 10·· · · · · · · · ·Thank you, Mr. May.

11·· ·includes all that that you just identified there.··All 11·· · · · · · · · ·JUDGE WALSTON:··TIEC?

12·· ·of that capacity results, and that's what's reflected in 12·· · · · · · · · ·MR. VanMIDDLESWORTH:··Yes.

13·· ·our rate year, lower MSS-1 cost. 13·· · · · · · · · · · ··RECROSS-EXAMINATION 14·· · · · · · · · ·And in the case of Calpine, it has higher 14·· ·BY MR. VanMIDDLESWORTH: 15·· ·cost per kW than MSS-1 costs would be.··So the net cost 15·· · · ·Q· ··Following up on Judge Walston's questions, ETI 16·· ·of that contract -- net after the fact that MSS-1 goes 16·· ·in this filing shows that it's projecting to purchase 17·· ·down -- is still a positive value.··That's reflected in 17·· ·about 600 megawatts more capacity in the rate year, 18·· ·our rate year clause. 18·· ·third-party purchases, than in the test year.··Is that 19·· · · · · · · · ·In the case of SRMPA, this is a contract. 19·· ·right?

20·· · · ·Q· ··You've gone beyond my -- I got the answer that 20·· · · ·A· ··Let me think about that for a moment.··How much 21·· ·I wanted. 21·· ·is the number again?

22·· · · ·A· ··Thank you. 22·· · · ·Q· ··About 600 megawatts.

23·· · · ·Q· ··But I appreciate it. 23·· · · ·A· ··It's probably approaching 600.

24·· · · · · · · · ·JUDGE WALSTON:··Okay.··Further cross? 24·· · · ·Q· ··Okay.··And ETI is also projecting to purchase 25·· · · · · · · · ·MR. LAWTON:··I do.··Thank you, Your Honor. 25·· ·about 300 megawatts less of MSS-1 capacity in the rate

KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 46 (Pages 1950-1953) Page 1950 Page 1952 ·1·· ·year than in the test year.··Correct? ·1·· ·including MSS-1, ETI is proposing to add about ·2·· · · ·A· ··I can't tell you the specific amount, sir. ·2·· ·300 megawatts more in the rate year than in the test ·3·· · · ·Q· ··You don't know? ·3·· ·year.··Right? ·4·· · · ·A· ··I don't have that document in front of me. ·4·· · · ·A· ··If you put that in an exhibit, I can confirm ·5·· · · ·Q· ··Okay.··You know it's a lot less than the amount ·5·· ·that.··I don't know the number precisely. ·6·· ·of purchased capacity? ·6·· · · ·Q· ··Okay.··We can -- that's a -- we could get that ·7·· · · ·A· ··Absolutely, for the very reasons we discussed. ·7·· ·from, I think, H-12 in the rate filing, couldn't we? ·8·· · · ·Q· ··Oh, and those -- ·8·· · · ·A· ··I'm sorry. ·9·· · · ·A· ··Those reasons being that as you add capacity, ·9·· · · ·Q· ··We could do that calculation from H-12?··I'm 10·· ·that the MSS-1 amounts would be reduced. 10·· ·not going to make you do the calculation.··I think it's 11·· · · ·Q· ··Right.··But why wouldn't they be reduced by the 11·· ·in the record.

12·· ·same amount of the capacity you're adding? 12·· · · ·A· ··Okay.

13·· · · ·A· ··There would be a number of reasons why that 13·· · · ·Q· ··You don't have any reason to disagree?

14·· ·would be.··One of the primary reasons would be the fact 14·· · · ·A· ··No.··I believe that's right.··The company will 15·· ·that the system has other changes.··There are capacity 15·· ·be adding capacity.··Correct.

16·· ·being acquired on the other operating companies as well. 16·· · · ·Q· ··All right.··And when you add -- when a company 17·· ·We will be acquiring capacity at Arkansas and 17·· ·adds capacity, they need -- if a company is planning on 18·· ·Mississippi, I believe.··Those will likely occur this 18·· ·experiencing load growth, it needs to add a little more 19·· ·year. 19·· ·in capacity than the estimated load growth.··Right?

20·· · · ·Q· ··And you're saying the capacity acquired by 20·· ·Talking about reserve margins.

21·· ·Arkansas and Mississippi means that the MSS-1 won't 21·· · · ·A· ··If the -- okay.··I'm sorry.

22·· ·decrease as much as the purchased capacity for ETI? 22·· · · · · · · · ·To the extent that you have a hundred 23·· · · ·A· ··All things being relative. 23·· ·megawatts of load growth, planning principles would 24·· · · ·Q· ··All right.··And so you -- do you dispute that 24·· ·suggest, if the company was perfectly balanced in the 25·· ·ETI projects, when you add all the purchased capacity, 25·· ·first place, that they should add, for instance, 115.

Page 1951 Page 1953 ·1·· ·purchased -- all the purchased capacity, third party, ·1·· · · ·Q· ··Right.··And the 115 is the reserve -- ·2·· ·and we sometimes -- by the way, when we talk -- when you ·2·· · · ·A· ··Reserve margin. ·3·· ·use the term "short," you're not talking about all ·3·· · · ·Q· ··And that's built into your rates.··I mean, ·4·· ·purchased capacity as we use the term for the purchased ·4·· ·everybody that buys a megawatt from you is buying -- is ·5·· ·power rider.··Right?··You're talking about a subset of ·5·· ·paying for the reserve margin as a part of the rate? ·6·· ·that. ·6·· · · ·A· ··Theoretically. ·7·· · · ·A· ··I'm not sure I understand the question.··I'm ·7·· · · ·Q· ··All right. ·8·· ·sorry. ·8·· · · ·A· ··It should include that. ·9·· · · ·Q· ··When you say they're short, when ETI is short, ·9·· · · ·Q· ··All right.··So 300 megawatts of additional 10·· ·don't you mean that if you look at just the purchased 10·· ·purchased capacity would serve a little less than 11·· ·power and the legacy contracts and the other affiliate 11·· ·that -- I'm not going to -- can't do the math right 12·· ·contracts, that that -- and you don't look at MSS-1, you 12·· ·here -- of actual load growth?

13·· ·just look at the stuff either owned or purchased 13·· · · ·A· ··You know, I'm not sure I can agree with that 14·· ·directly by ETI, that that's not sufficient to meet 14·· ·without seeing the facts.

15·· ·their load? 15·· · · ·Q· ··Okay.··Well, you may be able to do that.··If 16·· · · ·A· ··That's correct. 16·· ·somebody said, "Phillip May, I need -- we're going to 17·· · · ·Q· ··And then you have to add -- and then the way 17·· ·have a hundred megawatts of load growth next year, and 18·· ·that ETI becomes not short anymore is it purchases 18·· ·we need the capacities -- you need to get capacity to 19·· ·MSS-1. 19·· ·meet that," how many megawatts capacity would you need, 20·· · · ·A· ··Yes, I think that's a reasonably accurate 20·· ·more or less, to do that?

21·· ·statement. 21·· · · ·A· ··Depends on a number of factors.··But if this 22·· · · ·Q· ··Okay.··I think sometimes the record -- it's 22·· ·were a standalone company, it would probably add 23·· ·probably partially my fault.··Sometimes the record has 23·· ·20 percent more than that hundred.

24·· ·gotten a little fuzzy about what that means. 24·· · · ·Q· ··Okay.··A little -- and that's the reserve 25·· · · · · · · · ·Now, but all in, all purchased capacity, 25·· ·margin?

KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 47 (Pages 1954-1957) Page 1954 Page 1956 ·1·· · · ·A· ··Yes. ·1·· ·attractive. ·2·· · · ·Q· ··Okay.··Now, you've previously taken the ·2·· · · ·Q· ··But the fallback proposal did not deal with ·3·· ·position that it was appropriate in looking at the rate ·3·· ·load growth or load shrinkage or whatever happened.··It ·4·· ·year purchased power to take load growth into account to ·4·· ·just stuck with the test year sales? ·5·· ·make sure that ETI doesn't over-recover, haven't you? ·5·· · · ·A· ··Yes, sir, the fallback proposal is consistent ·6·· · · ·A· ··Are you referring to the incremental capacity ·6·· ·with the current ratemaking in the PUCT. ·7·· ·rider testimony? ·7·· · · ·Q· ··Well, I was just -- ·8·· · · ·Q· ··No.··I'm referring to actually the position you ·8·· · · · · · · · ·MR. VanMIDDLESWORTH:··I'm going to take ·9·· ·originally filed in this case. ·9·· ·issue with that and move to strike the volunteering that 10·· · · ·A· ··Which was with regard to a capacity rider. 10·· ·its current -- consistent with current practice at the 11·· ·Correct? 11·· ·PUC.

12·· · · ·Q· ··I'm just -- and in that -- in your initial 12·· · · · · · · · ·MR. NEINAST:··I object.··He opened up the 13·· ·proposal, it was your position that the -- you should 13·· ·question by going back to the exhibit.

14·· ·take load growth into account, revenue growth into 14·· · · · · · · · ·MR. VanMIDDLESWORTH:··My question was 15·· ·account, in addition to costs. 15·· ·simply, is this what you proposed?··His answer was -- 16·· · · ·A· ··Yes.··In my original testimony, I indicated 16·· ·I'm not sure if he said yes, but then he said, "And 17·· ·that we would true that capacity up.··The only way to do 17·· ·that's consistent with PUCT practice."

18·· ·that is to consider load growth. 18·· · · · · · · · ·MR. NEINAST:··But it -- 19·· · · ·Q· ··And you indicated that if revenues collected 19·· · · · · · · · ·JUDGE WALSTON:··I think his answer -- you 20·· ·from the rider, which is how you proposed it, were 20·· ·asked another question about, well, what you're doing 21·· ·increased due to sales, then that would automatically be 21·· ·now in base rates, and he was responding to the base 22·· ·reflected in updates to the rider via over or under 22·· ·rate question.

23·· ·recovery? 23·· · · · · · · · ·MR. VanMIDDLESWORTH:··Oh, okay.

24·· · · ·A· ··Yes, sir, that would be part of the 24·· · · · · · · · ·JUDGE WALSTON:··Yeah.

25·· ·reconciliation process. 25·· · · · · · · · ·MR. VanMIDDLESWORTH:··Let me withdraw my Page 1955 Page 1957 ·1·· · · ·Q· ··So this problem we've talked about here under ·1·· ·motion to strike. ·2·· ·the purchased power rider, as you proposed it, if this ·2·· · · ·Q· ··(BY MR. VanMIDDLESWORTH)··Are you aware of any ·3·· ·hypothetical utility was adding -- ·3·· ·prior PUC decision where the PUC has said, "We're going ·4·· · · ·A· ··Yes, sir. ·4·· ·to look out two years past the test year and estimate ·5·· · · ·Q· ··-- a hundred dollars to meet an expected ·5·· ·purchased power costs and then apply those to test year ·6·· ·10 percent load -- ·6·· ·billing determinants"?··Any other PUC case ever in ·7·· · · ·A· ··Yes, sir. ·7·· ·Texas? ·8·· · · ·Q· ··-- increase on TIEC Exhibit 23 and that's what ·8·· · · ·A· ··Well, I think a number of these cases have been ·9·· ·they had -- ·9·· ·settled, so that would be hard to say.

10·· · · ·A· ··Yes, sir. 10·· · · ·Q· ··Are you aware of any PUC decision?

11·· · · ·Q· ··-- then there would be no over or under 11·· · · ·A· ··I -- I can't recall any specific PUCT finding 12·· ·recovery because it would be trued up? 12·· ·on that.

13·· · · ·A· ··That's right. 13·· · · ·Q· ··I mean, this -- we're treading new ground.

14·· · · ·Q· ··But when the Commission rejected your purchased 14·· ·This -- what you proposed here has never been done by 15·· ·capacity rider in this case, your position after that 15·· ·this commission, has it?

16·· ·was, "Well, just take the purchased capacity costs and 16·· · · ·A· ··I don't agree.

17·· ·apply it to test year sales"? 17·· · · ·Q· ··Okay.··Then tell me when this commission has 18·· · · ·A· ··Well, I think our position was kind of an 18·· ·ordered the use of test year -- or of rate year 19·· ·either/or.··We represented that had we not had a 19·· ·purchased capacity and test year sales numbers.

20·· ·capacity -- if we did not get a capacity rider, then you 20·· · · ·A· ··In my mind, this is really not different than a 21·· ·would use these for base rates. 21·· ·merit increase adjustment.··It's known; it's measurable.

22·· · · ·Q· ··Right.··Right.··And I'm showing that the 22·· ·Sure, it extends beyond the test year, but in this case, 23·· ·initial proposal dealt with this, and you thought that 23·· ·the capacity that this company must add is not being 24·· ·was a reasonable thing to do. 24·· ·added because we have some great load growth 25·· · · ·A· ··I think the initial proposal is still very 25·· ·expectation.

KENNEDY REPORTING SERVICE, INC. 512.474.2233 Page 48 (Pages 1958-1961) Page 1958 Page 1960 ·1·· · · ·Q· ··I'm just asking -- ·1·· ·contract was in place, that there were never ever two ·2·· · · ·A· ··And I'm answering the question, sir. ·2·· ·months that had the same capacity payment from ETI to ·3·· · · · · · · · ·JUDGE WALSTON:··I think you went beyond ·3·· ·Frontier? ·4·· ·his question. ·4·· · · ·A· ··I don't have that data in front of me, but I ·5·· · · ·Q· ··(BY MR. VanMIDDLESWORTH)··Yeah.··My question, ·5·· ·don't believe that there are huge variations in the ·6·· ·sir, is, tell me the case where there's a PUC decision ·6·· ·capacity cost.··Now, it is a shaped product -- ·7·· ·that says, "We will look two years out for purchased ·7·· · · ·Q· ··My question -- ·8·· ·capacity and come up with a projection of that and apply ·8·· · · · · · · · ·JUDGE WALSTON:··Okay. ·9·· ·it to test year sales."··Tell me the case. ·9·· · · ·Q· ··(BY MR. VanMIDDLESWORTH)··Can you answer my 10·· · · ·A· ··Sir, I can't point to specific language in a 10·· ·question?

11·· ·PUCT finding. 11·· · · · · · · · ·JUDGE WALSTON:··Try and just answer his 12·· · · ·Q· ··Can you point to any language about purchased 12·· ·question as concisely as you can.

13·· ·power capacity that does that? 13·· · · · · · · · ·WITNESS MAY:··I'm sorry.

14·· · · ·A· ··No. 14·· · · ·Q· ··(BY MR. VanMIDDLESWORTH)··We won't badger each 15·· · · · · · · · ·MR. NEINAST:··Objection, badgering the 15·· ·other.

16·· ·witness. 16·· · · · · · · · ·Do you -- isn't it a fact that for the 17·· · · · · · · · ·JUDGE WALSTON:··I don't know that he's 17·· ·entire ten months that contract was in place, there were 18·· ·badgering, but I think he's already told you before he 18·· ·no two months that had the same capacity payment from 19·· ·doesn't know -- 19·· ·ETI, if you know?

20·· · · · · · · · ·MR. VanMIDDLESWORTH:··Okay. 20·· · · ·A· ··I don't have the contract in front of me, 21·· · · · · · · · ·JUDGE WALSTON:··-- a finding or a case. 21·· ·but -- 22·· ·So it's repetitive, if nothing else. 22·· · · ·Q· ··I'm just asking you -- 23·· · · · · · · · ·MR. VanMIDDLESWORTH:··I haven't had an 23·· · · ·A· ··-- on a dollar basis, I would suspect that 24·· ·objection levied against me in years, Your Honor.··I 24·· ·that's correct.

25·· ·thought the witness was badgering me. 25·· · · ·Q· ··All right.··And, in fact, weren't there Page 1959 Page 1961 ·1·· · · · · · · · ·(Laughter) ·1·· ·adjustments made for availability during the test year ·2·· · · · · · · · ·MR. NEINAST:··But you asked the question. ·2·· ·for -- ·3·· · · ·Q· ··(BY MR. VanMIDDLESWORTH)··Let me go to another ·3·· · · ·A· ··I suspect -- ·4·· ·subject. ·4·· · · ·Q· ··-- the Frontier contract? ·5·· · · · · · · · ·You mentioned a Frontier contract, and it ·5·· · · ·A· ··Yes, sir.··I suspect there could have been. ·6·· ·was actually in place during the test year? ·6·· · · ·Q· ··And, in fact, weren't there months where the ·7·· · · ·A· ··Yes. ·7·· ·payments under the Frontier contract were about half of ·8·· · · ·Q· ··And that it was at a lower megawatt level. ·8·· ·the full contract amount? ·9·· ·Right? ·9·· · · ·A· ··I'm not familiar with that, but it is a shaped 10·· · · ·A· ··Yes.··It straddled the test year, so there was 10·· ·product.

11·· ·an increase in the capacity and the cost that was in the 11·· · · ·Q· ··Yes.

12·· ·midst of the test year. 12·· · · ·A· ··And that may be driving that.

13·· · · ·Q· ··Okay.··And I'm going to try to avoid asking you 13·· · · ·Q· ··Yes.··So in some months, all other things being 14·· ·anything that's highly sensitive.··We know there's a 14·· ·equal, even if they performed completely -- 15·· ·Frontier contract. 15·· · · ·A· ··Yes, sir.

16·· · · ·A· ··Yes, sir. 16·· · · ·Q· ··-- there would be higher capacity costs than 17·· · · ·Q· ··I think we may know the megawatts, but I'm not 17·· ·others?

18·· ·sure.··So I'm going to try to avoid that. 18·· · · ·A· ··Yes, sir.

19·· · · · · · · · ·But for the first ten months of the test 19·· · · ·Q· ··But, in fact, for the Frontier contract, in the 20·· ·year, the Frontier contract was in one level, and then 20·· ·test year, there were months when -- I mean, if that 21·· ·it went to another level. 21·· ·were the case, there were a number of months that had 22·· · · ·A· ··Yes, sir. 22·· ·the same percentage applicable.··Right?··June, July, 23·· · · ·Q· ··Now, you talked about the stability of that 23·· ·August, September all have the same?

24·· ·contract, but isn't it the fact -- a fact that for the 24·· · · ·A· ··Yes, sir.

25·· ·first ten months of the test year, when that Frontier 25·· · · ·Q· ··And so everybody knows what we're talking about

KENNEDY REPORTING SERVICE, INC. 512.474.2233 II II SOAH DOCKET NO. XXX-XX-XXXX PUC DOCKET NO. 39896

APPLICATION OF ENTERGY TEXAS, § INC. FOR AUTHORITY TO CHANGE § BEFORE THE STATE OFFICE RA TES, RECONCILE FUEL COSTS, § OF AND OBTAIN DEFERRED § ADMINISTRATIVE HEARINGS ACCOUNTING TRFATMENT §

DIRECT TESTIMONY AND EXHIBITS OF MARK E. GARRETT

ON BEHALF OF CITIES SERVED BY ENTERGY TEXAS, INC.

MARCH 27, 2012

Mark Garrett Garrett Group, LLC Oklahoma City, Oklahoma Blank Page TABLE OF CONTENTS

Section I. Witness Identification ........................................................................................... 3 Section II. Purpose of Testimony ............................................................................................ 4 Section III. Rate Base Adjustments A. FIN 48 Tax Adjustment .................................................................................. 5 B. Prepaid Pension Costs in Rate Base ............................................................... 7 C. Rita Regulatory Asset .................................................................................... 11 Section IV. Payroll and Benefits Expense Adjustments A. ET! Payroll Adjustment ............................................................................... 12 B. ESI Payroll Adjustment ................................................................................ 19 C. Lewis Creek and Sabine Payroll Adjustments ........................................... 23 D. Above-Market Payroll Cost Adjustments ................................................... 25 E. Incentive Compensation Adjustment ........................................................... 27 F. Supplemental Executive Retirement Compensation .................................. 54 G. Above-Market Benefit Costs Adjustment .................................................. 58 H. Ad Valorem Tax Expense Adjustment ....................................................... 60 Section V. MISO Transition Expense Adjustment ............................................................ 61 Section VI. River Bend Decommissioning Expense Adjustment ....................................... 64 Exhibit MG-1 Qualifications of Mark E. Garrett ......................................................... Attached Exhibit MG-2 Garrett Adjustment Workpapers .......................................................... Attached

Direct Testimony of Mark E. Garrett Page 2 of 58 Docket No. 39896 Blank Page SECTION I. WITNESS IDENTIFICATION Q: PLEASE STATE YOUR NAME AND OCCUPATION.

5 Q: HAVE YOUR QUALIFICATIONS BEEN ACCEPTED IN PROCEEDINGS 6 DEALING WITH COST-OF-SERVICE AND OTHER RATEMAKING ISSUES?

10 Q: ON WHOSE BEHALF ARE YOU APPEARING IN THESE PROCEEDINGS?

SECTION II. PURPOSE OF TESTIMONY Q: WHAT IS THE PURPOSE OF YOUR TESTIMONY IN THIS PROCEEDING?

Cities of Anahuac, Beaumont, Bridge City, Cleveland, Conroe, Dayton, Groves, Houston, Huntsville, Montgomery, Navasota, Nederland, Oak Ridge North, Orange, Pine Forest, Pinehurst, Port Arthur, Port Neches, Rose City, Shenandoah, Silsbee, Sour Lake, Splendora, Vidor, and West Orange.

Direct Testimony of Mark E. Garrett Page 4 of 65 Docket No. 39896 l Retirement Expense, Ad Valorem Tax Expense, MISO Transition Costs and River Bend 2 Decommissioning Costs. In total, my recommended adjustments reduce the Company's 3 requested revenue requirement increase by approximately $34.835 million.

SECTION III. A. FIN 48 TAX ADJUSTMENT Q: HAVE YOU REVIEWED ETI'S PROPOSED FIN 48 ADJUSTMENT TO 5 ACCUMULATED DEFERRED FEDERAL INCOME TAX ("AD FIT")?

Order on Rehearing, Docket 35717, page 18 at 60.

Direct Testimony of Mark E. Garrett Page 5 of65 Docket No. 39896 1 meantime, the utility does have the use of the cost free capital from the deferred taxes 2 associated with these deductions at its disposal.

6 A: No. The Company's FIN 48 adjustments remove $5,916,461 from ADFIT balance that 7 should be included for ratemaking purposes. 3 In response to Cities RFI 19-6, the 8 Company states: 9 "Because the Company removed all ADIT related to FIN48 uncertain tax 10 positions from test year end ADIT balances, there would be no change to 11 rate base. Please see the Company's response to Cities 4-21 (d) for the 12 amounts removed from test year end ADIT."

13 Q: SHOULD THE COMMISSION'S RULING IN DOCKET NO. 35717 APPLY IN 14 THIS CASE?

See AJ 10 for accounts 282901 and 282903 and the Highly Sensitive response to Cities 4-21.

Direct Testimony of Mark E. Garrett Page 6 of65 Docket No. 39896 Q: WHAT IS YOUR RECOMMENDATION WITH RESPECT TO THE 2 COMP ANY'S FIN 48 ADJUSTMENT?

SECTION III. B. PREPAID PENSION ASSET IN RATE BASE Q: PLEASE DESCRIBE THE COMPANY'S UNFUNDED PENSION BALANCE.

7 A: The Company included in pro forma rate base an item entitled Unfunded Pension 8 Balance. The amount requested in this account is supposed to represent the accumulated 9 difference between the Statement of Financial Accounting Standards ("SF AS") No. 87 10 calculated pension costs each year and the actual contributions made by the Company to 11 the pension fund. 5 The balance requested in rates is $55.9 million. 6

13 Q: WHAT IS THE ISSUE WITH RESPECT TO A PENSION ASSET IN RATE 14 BASE?

15 A: In general terms, a portion of the balance in Account 253.012, Unfunded Pension Plans 16 actually represents the accumulated difference between the SF AS 87 calculated pension 17 costs each year and actual contributions made by the Company to the pension fund.

This amount could be reduced by attributable IRS cash deposits identified by the Company in rebuttal testimony.

The Company incorrectly referred to this item as a PURA Section 36.065(b) reserve account. PURA Section 36.065(b) allows a utility to record the difference between the SF AS No. 87 pension cost established in a rate case and the actual SFAS No. 87 cost experienced during the rate-effective period. The balance here is the difference in SF AS 87 costs and contributions.

See ETl response to Cities' 13-21.

Direct Testimony of Mark E. Garrett Page 7 of 65 Docket No. 39896 1 When there is a debit balance in the account, as is the case here, the Company has been 2 contributing more to the fund than its SF AS 87 calculated cost levels. 7

4 Q: ARE THESE CONTRIBUTIONS MANDATORY?

5 A: No. Schedule G-2.1 shows the payments to the fund have significantly exceeded the 6 required minimum contributions levels.

8 Q: HAS THIS COMMISSION ADDRESSED THIS ISSUE IN A PREVIOUS CASE?

15 Q: DOES THE BENEFIT RECEIVED BY RATE PAYERS EQUAL THE INCREASE 16 IN RATES FROM INCLUDING EXCESS PENSION FUNDING IN RATE BASE?

See ETI response to Cities' 13-16.

Direct Testimony of Mark E. Garrett Page 8 of65 Docket No. 39896 1 occurred, is only 1.37%. 8 Thus, if this asset were included in rate base, ratepayers would 2 pay a substantial premium for the slight pension cost savings ETI' s excess contributions 3 may have achieved. From a ratemaking perspective, it would be inappropriate for the 4 Company to receive a greater benefit, through earning a full rate base return on the 5 excess contributions, than the benefit ratepayers receive through lower pension costs that 6 result from the pension fund returns. 9 In short, it would be inappropriate for the 7 Company to earn an 11.5% return on contributions that have only produced a 1.37% 8 benefit to ratepayers.

10 Q: HOW ARE PREPAID PENSION ASSETS TREATED IN OTHER STATES?

11 A: At least one state, Virginia, has included a prepaid pension balance in rate base and 12 Texas has included a portion of a prepaid balance in rate base (which was the prepaid 13 pension balance less CWIP in the AEP TCC case). West Virginia, on the other hand, in 14 a recent decision, entirely excluded a requested prepaid pension balance. 10 In Oklahoma, 15 the commission addressed this issue in four separate decisions, and in each decision 16 excluded the prepaid pension balance from rate base and provided a cost of debt carrying 17 charge on the balance. 11 In effect, the Oklahoma commission provided a return on the 18 balance because ratepayers had received a benefit from the excess contributions in the

The annual returns for 2007 through 2011 are the actual returns divided by the average of the beginning and ending balance. The average of these amounts is 1.37%. See Exhibit MG2.2.

For example, in Oklahoma, the commission allows a cost-of-money return (rather than a full rate base return) on excess pension contributions ifthe utility can show that ratepayers benefited from the excess contributions. In those cases, the utility's long term debt rate was representative of, though lower than, the actual returns received in the pension fund.

See Commission Order on March 30, 2011 in Case No. 10-0699-E-42T.

Direct Testimony of Mark E. Garrett Page 9 of65 Docket No. 39896 1 form of lower annual pension costs. In those cases, the actual pension fund returns were 2 much more similar to a long-term debt return than to a full rate base return.

4 Q: WHAT ADJUSTMENT ARE YOU PROPOSING?

5 A: I propose to remove the entire prepaid pension asset from rate base, because the 6 Company has not justified its inclusion in any way. This adjustment reduces pro forma 7 rate base by $36,382,803, which is the net amount of the prepaid balance less 8 accumulated deferred income tax (55,973,543 - 19,590,740 = 36,382,803)_12 I also 9 recommend that the Commission increase operating expense by $498,284, to provide a 10 1.3 7% return on the net balance. The adjustment calculations are set forth at Exhibit 11 MG-2.2.

12 In the alternative, if the Commission decides to follow its prior ruling in the AEP 13 TCC case, Docket No. 33309, the necessary reduction to pro forrna rate base would be 14 $25,311,236, which is the portion of the prepaid pension balance associated with 15 CWIP. 13

ONG rate case Cause No. PUD 91-1190; OG&E rate case Cause No. PUD 05-151; AEP PSO rate case Cause No. PUD 06-285; AEP PSO Cause No. PUD 08-144.

See ETI RFI response to Cities' 13-21.

The Company's expense ratio for pensions is 55.78% and the capitalization ratio is 44.22%. See ETI W/P AJ20.

Direct Testimony of Mark E. Garrett Page 10 of65 Docket No. 39896 SECTION III. C. RITA REGULATORY ASSET Q: WHAT IS THE ISSUE WITH RESPECT TO THE RITA REGULATORY 2 ASSET?

3 A: In this application the Company seeks to include a Rita Regulatory Asset in the amount 4 of $26,229,627. 14 This balance represents the unrecovered insurance proceeds from the 5 Rita storm loss. The Company seeks rate base treatment of the regulatory asset balance 6 along with a 5-year amortization of the balance in rates. The problem with the 7 Company's recommended treatment in this case is that the Rita balance was presented in 8 the Company's last rate case, Docket No. 37744, as a regulatory asset with a 5-year 9 amortization of the balance and no party in that case opposed the recovery of those costs 10 through rates. This means that, even though the last rate case settled, since no party 11 opposed the Company's inclusion in rates of the Rita regulatory costs, the Company 12 should have been amortizing the Rita regulatory balance since the last case, which would 13 mean that 22.5 months of the 60 month amortization would be complete by the time new 14 rates go into effect from this case. 15 From a ratemaking perspective, the appropriate 15 balance for rate treatment at this point would be $10,714,557, 16 which is the original 16 balance of $26,229,627, less $9,836,110, 22.5 months of the 5-year amortization, less 17 $5,678,960, which is the difference between insurance proceeds estimated in Docket No. 18 37744 and actual receipts. These calculations are set forth at MG-2.3 See Sch. P, P. 19, L. 23.

New rates from Docket No. 37744 went into effect on August 15, 2010 and new rates from this case will go into effect on June 30, 2012.

This is the balance that Mr. Pous will include in the storm reserve.

Direct Testimony of Mark E. Garrett Page 11 of65 Docket No. 39896 Q: WHAT DOES CITIES RECOMMEND WITH RESPECT TO THE RITA 2 REGULATORY ASSET?

3 A: The recommended rate treatment of the Rita regulatory asset going forward is being 4 addressed in the testimony of Cities' witness, Mr. Jacob Pous, who recommends that the 5 Rita regulatory asset balance be added to and amortized in the storm reserve. In light of 6 this alternate recovery methodology for the Rita regulatory asset balance I am 7 recommending that the entire balance be removed from pro forma rate base and the 8 amortization expense be removed from pro forma cost of service. This results in a 9 reduction to the requested rate base of $26,229,627 and a reduction to the requested cost 10 of service of$5,245,925. These adjustments are set forth at Exhibit MG 2.3.

SECTION IV. A. ETI PAYROLL ADJUSTMENT Q: PLEASE DESCRIBE ETI'S PROPOSED PAYROLL ADJUSTMENT.

12 A: ETI's payroll adjustment contains three components: (1) a decrease of $648,362 for a 13 reduction in the number of ETI employees during the test year, estimated by multiplying 14 the effective number of employees who left the Company by an average annual salary 15 amount; (2) an increase of $350,047 to recognize test year pay raises for both bargaining 16 and non-bargaining employees; 17 and (3) an increase of $628,947 for post-test year pay 17 raises for both bargaining and non-bargaining employees, calculated by multiplying total 18 payroll expense by the nominal rate of the pay raise. The post-test year raises for 19 bargaining employees occurred in early August 2011, just over one month after test year

Direct Testimony of Mark E. Garrett Page 12 of65 Docket No. 39896 1 end. The post-test year raises for non-bargaining employees are scheduled to occur in 2 April 2012, nine months after test year end. The combination of these three adjustments 3 results in a net requested increase to ETI payroll expense of $330,632. 18

5 Q: DO YOU AGREE WITH THE COMP ANY'S PROPOSED ADJUSTMENT TO 6 ETI PAYROLL EXPENSE?

7 A: I agree with the first two components of the Company's proposed adjustment, where the 8 Company attempts to reflect workforce reductions and pay raises that occur during the 9 test year. And, in the third component, I agree with the post-test year raises for 10 bargaining employees that occurred shortly after test year end. However, I do not agree 11 with the Company's adjustment which attempts to reflect the effects of pay raises that 12 are expected to occur up to nine months after test year end. From a ratemaking 13 perspective, there are several problems with the Company's proposed recognition of 14 these post-test year raises.

16 Q: WHAT ARE THE PROBLEMS YOU SEE WITH THE COMP ANY'S 17 PROPOSED APPROACH?

The Company awarded bargaining employees an effective 0.72% pay raise on 3/20/11 and non-bargaining employees an effective 1.50% pay raise on 4/1/11.

See Workpaper AJ22.12.

Direct Testimony of Mark E. Garrett Page 13 of65 Docket No. 39896 however, fails to consider other events occurring during the same period that could 2 decrease payroll levels by the same, or even greater, amounts. For example, workforce 3 reductions could have a greater impact on payroll expense than pay raises. In addition, 4 other more subtle changes may also decrease payroll levels. Even with a stable overall 5 workforce level, employees are being added to and removed from the payroll registers 6 on a fairly regular basis. Since retiring employees are generally paid higher salaries than 7 new employees, payroll expense levels can decrease significantly if higher paid 8 employees leave the company and are replaced with employees paid at lower 9 compensation levels. These potential reductions in payroll expense can more than offset 10 the anticipated increase from an annual raise. As a consequence, even if the 11 Commission were inclined to accept an adjustment for pay raises that occur up to nine 12 months outside the test year, the Company's proposed adjustment is inappropriate 13 because it fails to show that net payroll expense levels actually increased by the amount 14 of the pay raises.

16 Q: IF THE COMMISSION WERE INCLINED TO ACCEPT AN INCREASE FOR 17 PAY RAISES THAT OCCUR UP TO NINE MONTHS OUTSIDE THE TEST 18 YEAR, HOW WOULD THE IMP ACT OF THESE RAISES BE PROPERLY 19 MEASURED FOR RATEMAKING PURPOSES?

9 Q: EVEN IF THE AD.JUSTMENT WAS APPROPRJATEL Y BASED ON A PROPER 10 ANNUALIZATION OF PAYROLL LEVELS AT APRIL 2012, WOULD THE 11 RECOGNITION OF THESE POST TEST YEAR RAISES BE APPROPRIATE 12 FROM A RATEMAKING PERSPECTIVE?

13 A: No. From a ratemaking perspective, it is generally considered inappropriate to go 14 beyond the test year to recognize an isolated increase in one expense item, such as 15 payroll, without also recognizing other potential offsetting decreases, such as higher 16 revenue levels from load growth. The Company's proposed isolated recognition of pay 17 raises that occur nine months after test year end, without offsetting adjustments, amounts 18 to a piecemeal ratemaking approach for payroll costs and, in my opinion, should be 19 rejected by this Commission. The Company makes no attempt to update its Revenue, or 20 Accumulated Depreciation, or Accumulated Deferred Income Tax balances to a nine- 21 month post-test year level, each of which would more than offset the proposed increase 22 from the April 2012 raises. In my opinion, it is inappropriate to recognize an increase in Direct Testimony of Mark E. Garrett Page 15 of65 Docket No. 39896 1 one item nme months after test year end, while ignoring other obvious decreases.

2 Jurisdictions with which I am familiar typically require that if one item is updated to a 3 point in time substantially after test year end, then all items must be updated to that later 4 date as well. An isolated increase in one expense item is not allowed.

6 Q: ARE THERE OTHER REASONS WHY THE COMMISSION SHOULD NOT 7 INCLUDE THE APRIL 2012 PAY RAISES IN RATES?

8 A: Yes. According to Mr. Gardner's testimony, the Company's total payroll costs for 2011, 9 including both base pay and incentives, was I 0% above market. 19 Most of these above- 10 market payroll costs relate to the Company's incentives. The Company's incentive 11 levels are 63% above-market and the Company's base pay levels are 2% above market, 12 resulting in total above-market level of 10% for base pay and incentives. 20 The above- 13 market incentive pay is addressed in detail later in this testimony. However, the 14 Company's above-market base pay is relevant to mention here as well. Because the 15 Company's 2011 base pay is already 2% above market, an additional 2% pay raise 16 increase in April 2012 will only further exacerbate the problem.

See Table 5 at page 26 of Mr. Gardner's Direct Testimony.

See ETI response to Cities' RFI 18-S(b ).

Direct Testimony of Mark E. Garrett Page 16 of65 Docket No. 39896 l Q: IF THE COMMISSION FINDS IT APPROPRIATE TO RECOGNIZE THE 2 COMP ANY'S POST TEST YEAR PAY RAISES IN APRIL 2012, WHAT OTHER 3 ADJUSTMENTS SHOULD THE COMMISSION ALSO RECOGNIZE?

4 A: If the Commission decides to recognize the April 2012 post-test year pay raises, I believe 5 the Commission should, at a minimum, consider offsetting the post-test year pay raise 6 increases with the overall productivity improvements that should occur over the same 7 period of time. These productivity improvements must be considered in forward-looking 8 adjustments to payroll costs, such as the Company's proposed pay raise increases. It 9 would be inappropriate for the Company to recognize the incremental increases to 10 payroll associated with post-test year pay raises payroll and not consider the mitigating 11 effects of increased productivity.

13 Q: WHAT IS PRODUCTIVITY GROWTH AND WHY IS IT IMPORTANT IN THIS 14 CASE?

15 A: In economic terms, increased productivity is the ability to produce more with less input.

16 Productivity is measured by comparing the amount of goods and service produced with 17 the inputs used in the production of a product. Specifically, labor productivity is the 18 ratio of the output of goods and service to the labor hours devoted to the production of 19 the output. The Bureau of Labor Statistics ("BLS") reports significant growth in labor 20 productivity over the past few years.

Direct Testimony of Mark E. Garrett Page 17 of 65 Docket No. 39896 Q: WHY IS IT IMPORTANT TO RECOGNIZE PRODUCTIVITY GROWTH IN 2 THIS SITUATION?

3 A: Labor productivity is important here because of the forward-looking impacts of the post- 4 test year pay raises. An accurate projection of post-test year labor costs must give some 5 recognition to the expectation of increased productivity.

7 Q: WHAT AMOUNT OF PRODUCTIVITY GROWTH COULD BE EXPECTED 8 FOR THE COMPANY?

9 A: Based on projected productivity growth statistics, a reasonable productivity adjustment 10 would reduce labor cost by about 2.1 %. The BLS reported "business sector" 11 productivity growth of .4% for 2011, 4% for 2010, and 2.3% for 2009. This results in a 12 3-year average productivity growth of about 2.2%. The past 2-year average is 2.1 %. A 13 productivity offset of 2.1 % would recognize the fact that the Company should be 14 expected to achieve the same type of productivity gains that the business sector achieves 15 on average.

17 Q: HOW WOULD A PRODUCTIVITY ADJUSTMENT IMP ACT THE 18 COMP ANY'S PROPOSED INCREASE FOR APRIL 2012 P AYRAISES?

Direct Testimony of Mark E. Garrett Page 18 of65 Docket No. 39896 Q: WHAT IS YOUR RECOMMENDATION WITH RESPECT TO THE 2 COMPANY'S PAYROLL EXPENSE?

3 A: I recommend the Commission: (1) accept the Company's adjustment to decrease payroll 4 expense for workforce reductions in the test year; (2) accept the Company's adjustment 5 to increase payroll expense for pay raises awarded in March and April 2011 for 6 bargaining and non-bargaining employees respectively; (3) accept the Company's 7 adjustment to increase payroll for pay raises awarded in August 2011 for bargaining 8 employees; and (4) reject the Company's adjustment to increase payroll expense for pay 9 raises awarded in April 2012 for non-bargaining employees.

11 Q: PLEASE DESCRIBE YOUR PROPOSED ADJUSTMENT TO PAYROLL 12 EXPENSE.

13 A: My recommended adjustment reverses the Company's proposed increase for April 2012 14 pay raises in the amount of $316,989 and associated payroll-related expense of $41,081, 15 for a total adjustment of $358,071. The calculations supporting Cities' recommended 16 ETI payroll adjustment is set forth at Exhibit MG-2.4.

SECTION IV. B. ESI PAYROLL ADJUSTMENT Q: HAVE YOU REVIEWED THE COMP ANY'S PROPOSED ADJUSTMENT FOR 18 ESI PAYROLL EXPENSE?

19 A: Yes. Like the ETI payroll adjustment, the ESI payroll adjustment contains three 20 components: (1) a decrease of $243 ,416 for a reduction in the number of ESI employees Direct Testimony of Mark E. Garrett Page 19 of65 Docket No. 39896 1 during the test year, estimated by multiplying the effective number of employees who 2 left the Company by an average annual salary amount; (2) an increase of $466,666 to 3 recognize test year pay raises for non-bargaining employees; 21 and (3) an increase of 4 $622,221 for post-test year pay raises for non-bargaining employees, calculated by 5 multiplying total payroll expense by the nominal rate of the pay raise. The post-test year 6 pay raises for ESI employees are scheduled to occur in April, nine months after test year 7 end. The combination of all three of these adjustments results in a net requested increase 8 in ESI payroll expense allocated to ETI of $845,471.

10 Q: DO YOU AGREE WITH THE ESI PAYROLL ADJUSTMENT?

11 A: Not entirely. I agree with the first two components of the adjustment that occur during 12 the test year-the test year workforce reductions and the test year pay raises-but I do 13 not agree with the third component of the adjustment that inappropriately increases 14 payroll expense for pay raises expected to occur nine months after test year end. Not 15 only does this proposed adjustment fall far outside the test year, it also improperly 16 calculates the impact of these raises by merely multiplying labor costs times the nominal 17 percentage of the raise.

The Company awarded bargaining employees an effective .72% pay raise on 3/20/11 and non-bargaining employees an effective 1.50% pay raise on 4/1/11.

See Workpaper AJ22.23.

Direct Testimony of Mark E. Garrett Page 20 of65 Docket No. 39896 Q: EVEN IF THE ADJUSTMENT WAS APPROPRIATELY BASED ON A PROPER 2 ANNUALIZATION OF PAYROLL LEVELS AT APRIL 2012, WOULD THE 3 RECOGNITION OF THESE POST TEST YEAR RAISES BE APPROPRIATE 4 FROM A RA TEMAKING PERSPECTIVE?

5 A: No. From a ratemaking perspective, it is inappropriate to go beyond the test year to 6 recognize an isolated increase in one expense item, such as payroll, without also 7 recognizing other potential offsetting decreases, such as higher revenue levels from load 8 growth. As I testified with respect to the Company's proposed ETI Payroll adjustment, 9 the proposed adjustments to ESI payroll expense also recognize pay raises that occur 10 nine months after test year end without offsetting adjustments. This amounts to 11 piecemeal ratemaking for payroll costs and should be rejected by this Commission.

12 Because the Company makes no attempt to update Revenue, or Accumulated 13 Depreciation or Accumulated Deferred Income Tax balances to the nine-month post-test 14 year level, it is inappropriate to recognize an increase in a single isolated item.

16 Q: ARE THERE OTHER REASONS WHY THE COMMISSION SHOULD NOT 17 INCLUDE THE APRIL 2012 PAY RAISES IN RATES?

18 A: Yes. As discussed in the previous section of this testimony, Mr. Gardner's testimony 19 and responses to Cities' RFis indicate that the Company's 2011 base pay levels are 2% 20 above market. 23 With the Company's 2011 base pay levels already 2% above-market, an

See ETI response to Cities' RFI l 8-8(b ).

Direct Testimony of Mark E. Garrett Page 21 of65 Docket No. 39896 1 additional 2% increase for pay raises in April 2012 would only further exacerbate the 2 problem.

4 Q: IF THE COMMISSION FINDS IT APPROPRIATE TO RECOGNIZE THE 5 COMPANY'S POST TEST YEAR PAY RAISES, IN APRIL 2012, WHAT 6 OTHER ADJUSTMENTS SHOULD THE COMMISSION ALSO RECOGNIZE?

7 A: If the Commission should decide to recognize the April 2012 post-test year pay raises, I 8 believe the Commission should offset the 2% pay raises with a 2.1 % productivity 9 adjustment, which, according to the BLS, is the two-year average productivity factor for 10 the business sector.

12 Q: WHAT IS YOUR RECOMMENDATION WITH RESPECT TO THE 13 COMPANY'S PAYROLL EXPENSE?

14 A: I recommend the Commission: (1) accept the Company's adjustment to decrease payroll 15 expense for workforce reductions in the test year; (2) accept the Company's adjustment 16 to increase payroll expense for pay raises awarded in April 2011 (during the test year); 17 and (3) reject the Company's adjustment to increase payroll expense for post-test year 18 pay raises awarded in April 2012.

20 Q: PLEASE DESCRIBE YOUR PROPOSED ADJUSTMENT TO PAYROLL 21 EXPENSE.

SECTION IV. C. SABINE AND LEWIS CREEK PAYROLL ADJUSTMENT Q: HAVE YOU REVIEWED THE COMP ANY'S PROPOSED ADJUSTMENTS FOR 5 SABINE AND LEWIS CREEK PAYROLL EXPENSE?

6 A: Yes. Like the ETI and ESI payroll adjustment, the Sabine and Lewis Creek payroll 7 adjustment contains three components: (1) an increase for employees added during the 8 test year; (2) an increase to recognize test year pay raises for both bargaining and non- 9 bargaining employees; and (3) an increase for post-test year pay raises for both 10 bargaining and non-bargaining employees, calculated by multiplying total payroll 11 expense by the nominal rate of the pay raise. The post-test year raises for bargaining 12 employees occurred in early August 2011, just over one month after test year end. The 13 post-test year raises for non-bargaining employees are scheduled to occur in April 2012, 14 nine months after test year end.

16 Q: DO YOU AGREE WITH THE COMP ANY'S PROPOSED SABINE AND LEWIS 17 CREEK PAYROLL ADJUSTMENTS?

18 A: No. As with the ETI and ESI adjustments, I agree with the first two components of the 19 Company's proposed adjustment, where the Company attempts to reflect workforce

See Workpapers AJ22.15 and AJ22.18.

Direct Testimony of Mark E. Garrett Page 23 of65 Docket No. 39896 1 additions and pay raises that occur during the test year. And, I also agree with the post- 2 test year raises for bargaining employees that occurred shortly after test year end.

3 However, I do not agree with the component of the Company's adjustment that attempts 4 to reflect the effects of pay raises that are expected to occur up to nine months after test 5 year end. From a ratemaking perspective it is inappropriate to go that far beyond the test 6 year to recognize an isolated increase in one expense item without also recognizing 7 offsetting decreases in other items, such as revenue, accumulated depreciation and 8 accumulated deferred income taxes. Also, pay raises projected that far beyond the test 9 year should be offset with an appropriate corresponding productivity adjustment.

11 Q: WHAT IS YOUR RECOMMENDATION WITH RESPECT TO THE 12 COMPANY'S PAYROLL EXPENSE?

13 A: I recommend the Commission: (1) accept the Company's adjustment to increase payroll 14 expense for workforce additions in the test year; (2) accept the Company's adjustment to 15 increase payroll expense for pay raises awarded in April 2011 (during the test year) and 16 in August 2011 shortly after test year end; and (3) reject the Company's adjustment to 17 increase payroll expense for post-test year pay raises awarded in April 2012, nine 18 months after test year end.

20 Q: PLEASE DESCRIBE YOUR PROPOSED ADJUSTMENT TO PAYROLL 21 EXPENSE.

22 A: For Sabine, my recommended adjustment reverses the Company's proposed increase for Direct Testimony of Mark E. Garrett Page 24 of65 Docket No. 39896 l April 2012 pay raises in the amount of $81,894 and associated payroll-related expense in 2 the amount of $10,613, for a total adjustment of $92,507. For Lewis Creek, my 3 recommended adjustment reverses the Company's proposed increase for April 2012 pay 4 raises in the amount of $28,659 and associated payroll-related expense in the amount of 5 $3,713, for a total adjustment of $32,372. The calculations supporting Cities' 6 recommended Sabine and Lewis Creek payroll adjustments are set forth at Exhibit MG- 7 2.5 and MG 2.6.

SECTION IV. D. ABOVE-MARKET BASE PAY COMPENSATION Q: WHAT IS THE ISSUE REGARDING THE COMPANY'S ABOVE-MARKET 9 BASE PAY LEVELS?

See Table 5 at page 26 of Mr. Gardner's Direct Testimony.

Direct Testimony of Mark E. Garrett Page 25 of65 Docket No. 39896 Q: ARE YOU PROPOSING AN ADJUSTMENT TO THE BASE PAY LEVEL 2 REQUESTED IN RATES? ,, .) A: Yes. From a ratemaking perspective, ratepayers are only required to pay the necessary 4 costs of providing utility service. Although the Company is certainly free to pay its 5 employees at above-market wage levels if it so chooses, ratepayers should only be asked 6 to pay market-based costs for utility services the Company provides. Based upon the 7 Company's own calculation, its base pay wage levels are above market. This is 8 particularly inappropriate when ratepayers are experiencing, arguably, the worst 9 economy in the past 30 to 35 years and quite possibly the worst economy since the 10 great depression. In light of this economic downturn, it would be particularly unfair to 11 ask captive ratepayers to pay above-market wages for utility services. As a result, I am 12 recommending a 2% adjustment to the payroll expense included in pro forma rates, to 13 bring the Company's base pay down to a market-based level.

15 Q: IF THE COMMISSION ADOPTS YOUR ADJUSTMENT, WILL IT RESULT IN 16 A 2% PAYROLL REDUCTION?

17 A: No, certainly not. The Company alone decides how much it pays its employees; the 18 Commission, on the other hand, decides how much of that cost should be collected from 19 ratepayers. The Company will continue to pay its employees whatever it believes is 20 appropriate. Ratepayers, however, should bear only the necessary market-based price 21 for employee pay.

See ETI response to Cities' RFI l 8-8(b ).

Direct Testimony of Mark E. Garrett Page 26 of65 Docket No. 39896 Q: HOW IS YOUR PROPOSED ADJUSTMENT CALCULATED?

2 A: The adjustment is calculated by multiplying base pay wages in operating expense by 3 2%. 27 This results in an adjustment of $989,370, 28 which can be seen at Exhibit MG2.8.

SECTION IV. E. ETI INCENTIVE COMPENSATION Q: HAVE YOU REVIEWED THE LEVEL OF INCENTIVE COMPENSATION 5 EXPENSE INCLUDED IN THE COMPANY'S COST OF SERVICE?

6 A: Yes. The Company seeks to include $14, 187, 744 in cost of service for incentive 7 compensation expense. This includes 100% of ETI and ESI annual incentive plan 8 compensation, 100% of ETI and ESI long-term incentive compensation, and 100% of 9 ETI and ESI equity ownership incentive compensation. The Company makes no 10 adjustment to remove any of its test year incentive expense from cost of service, even 11 though it admits that at least 35% of the annual incentive plans and 100% of the long- 12 term plans are tied to the type of financial performance measures that the Commission 13 has routinely excluded in the past. 29 The Company's proposed inclusion of financial- 14 based incentive compensation is supported in the testimony of Jay C. Hartzell, who 15 asserts that incentive programs tied to cost controls, profitability and stock price help 16 companies attract, motivate and retain talented employees. The Company asserts that 17 without financial-based incentives, employees would not be motivated to look after the The actual percentage is 1.8%. See, ETI response to Cities' RFI l 8-8(b ).

Base pay payroll expense for ETI and ESI = $54.965 million times 1.8%. = $989,370. (See, TIEC 9-1 and Cities' l 8-8(b)).

Please see Testimony of Jay C. Hartzell, PhD at page 9 for the admission, and Gardner Exhibit KGG-4 for the percentage.

Direct Testimony of Mark E. Garrett Page 27 of65 Docket No. 39896 1 financial health of the company. 30 The inclusion of financial-based incentives is also 2 supported in the testimony of Kevin G. Gardner, who asserts that the incentives are part 3 of a total package of compensation and benefits that is reasonable when compared with 4 other companies. 31 ETI's test year incentive expense levels and the amounts included in 5 cost of service are set forth in the table below:

Table 1: Total Incentive Compensation Expense in Cost of Service Amount Included in Incentive Compensation Programs I Test Year Expense Cost of Service Management Incentive Plan $4,749,198 $4,749,198 Exempt Incentive Plan $1,858,337 $1,858,337 Team Share Incentive Plan $153,447 $153,447 Team Share for Bargaining Employees $384,877 $384,877 Executive Annual Incentive Plan $1,483,447 $1,483,447 ML6 Operational Plan 181,462 181,462 Long-Term Incentive Plans $815,608 $815,608 Equity Ownership Plans $4,561,367 $4,561,367 Total Incentive Compensation $14,187,744 $14,187,744

6 Q. WHAT IS YOUR RECOMMENDATION WITH RESPECT TO THE 7 COMPANY'S INCENTIVE COMPENSATION EXPENSE?

8 A. For incentive compensation expense, the general rule followed in most states is that 9 incentive payments related to the financial performance of the company are excluded for 10 ratemaking purposes. Under this rule, most short-term incentive expense and virtually

Direct Testimony of Jay C. Hartzell, PhD at page 7, lines 9-17.

Direct Testimony of Kevin G. Gardner at pages 5-30.

Direct Testimony of Mark E. Garrett Page 28 of65 Docket No. 39896 1 all long-term incentive expense for executives is excluded. In my opinion, this rule 2 should be applied to ETI's incentive plans.

4 Q: WHAT IS THE GENERAL RATIONALE FOR EXCLUDING INCENTIVE 5 COMPENSATION TIED TO FINANCIAL PERFORMANCE?

6 A: When incentive compensation costs associated with financial performance are excluded 7 from rates, the rationale is generally based on one or more of the following reasons: 8 (1) Payment is uncertain. Often, payment of incentive compensation is conditioned 9 upon meeting some predetermined financial goal such as achieving a certain 10 increase in earnings, reaching a targeted stock price or meeting budget objectives.

11 If the predetermined goals are not met, the incentive payment is not made, or 12 payment is made at some lesser amount. Therefore, there is no certainty from 13 year to year what the level of the payment may be or whether the payment will be 14 made at all. It is generally considered inappropriate to set rates to recover a 15 tentative level of expense 32 16 (2) Many of the factors that significantly impact earnings are outside the control 17 of most company employees and have limited value to customers. For 18 example, an unusually hot summer can easily trigger an incentive payment based 19 on company earnings for an electric utility. Obviously, weather conditions are 20 outside the control of utility employees and customers receive no benefit from 21 the higher utility bills that result from an unusually hot summer. Similarly, 22 company earnings may increase, thus triggering incentive payments, as a result of 23 customer growth, which commonly occurs without significant influence from 24 company personnel. In fairness, since shareholders enjoy the benefits of 25 customer growth between rate cases, shareholders should also bear the cost of 26 any incentive payments such growth may trigger. Finally, utility earnings may 27 increase substantially if the utility is able to successfully argue for a higher ROE 28 in a rate case proceeding. However, utility efforts to maximize ROE in a rate 29 proceeding have little to do with improving overall employee performance across 30 the company. If utility employee efforts are geared toward securing an This general rationale for excluding financial-based incentives is on point in this case. At page 28, lines 8-14, of his Direct Testimony, Mr. Gardner admits that actual payments for financial incentives may be considerably less than the targeted level. For example, the actual payouts under the Performance Unit Programs were only 57% of the targeted level in 2010 and a mere 10% of the target level in 2011.

Direct Testimony of Mark E. Garrett Page 29 of65 Docket No. 39896 1 unreasonably high ROE in a rate proceeding, the incentive mechanism actually 2 would work to the detriment of the utility customers.

3 (3) Earnings-based incentive plans can discourage conservation. When incentive 4 payments are based on earnings, employees may not be as supportive of 5 conservation programs designed to reduce usage if they perceive these programs 6 could adversely impact incentive payment levels. To the extent earnings-based 7 incentive plans discourage conservation and demand-side management programs, 8 these plans would not be in the public interest. This point is especially important 9 in light of the growing focus on energy efficiency at both the national and state 10 level. 33 11 (4) The utility and its stockholders assume none of the financial risks associated 12 with incentive payments. Ratepayers assume the risk that the amounts collected 13 through rates for incentive payments will instead be retained by the utility 14 whenever targeted increases are not reached. Employees assume the risk that the 15 incentive payments will not be made in a given year. However, the utility and its 16 stockholders assume no risk associated with these payments. Instead, the 17 company's only responsibility is to decide who gets the money, the stockholders 18 or the employees.

19 (5) Incentive payments based on financial performance measures should be 20 made out of increased earnings. Whatever the targets or goals may be that 21 trigger an incentive payment, when the plan is based in whole or in part on 22 financial performance measures there is always a financial benefit to the 23 company that comes from achieving these objectives. This financial benefit 24 should provide ample funds from which to make the payment. If not, the 25 incentive plan was poorly conceived in the first place. As such, employees 26 should be compensated out of the increased earnings, and not through rates.

Direct Testimony of Mark E. Garrett Page 30 of65 Docket No. 39896 1 for incentive payments acts as a financial hedge to shelter the poor financial 2 performance of the company.

3 Even though regulators often exclude incentive compensation payments based on one or 4 more of the reasons outlined above, this does not mean that regulated companies should 5 not offer incentive compensation packages. To the contrary, incentive plans that 6 motivate employees to achieve increased efficiencies (i.e., cost control) should be 7 encouraged. However, since the utility retains the savings generated from these 8 increased efficiencies between rate cases, payment to the employees for these plans 9 should be made from a portion of the savings these plans help achieve. Thus, incentive 10 compensation plans designed to enhance financial performance need not be subsidized 11 by ratepayers.

13 Q. HOW IS INCENTIVE COMPENSATION TREATED FOR RATEMAKING 14 PURPOSES IN TEXAS?

15 A. My understanding is that the Commission generally excludes the portion of incentive 16 payments designed to increase the financial position of the utility. For example, in PUC 17 Docket No. 28840, 34 the Commission disallowed sixty-six percent (66%) of AEP-Texas 18 Central's test year incentive payments in the amount of $4.2 million -- the portion of the 19 utility's incentive payments that was based on financial performance measures. 35

Application ofAEP Texas Central Company for Authority to Change Rates, Docket No. 28840; SOAH Docket No. XXX-XX-XXXX, Final Order(August 15, 2005).

Direct Testimony of Mark E. Garrett Page 31of65 Docket No. 39896 Q: HOW IS INCENTIVE COMPENSATION TREATED IN OTHER STATES?

2 A: The results of an Incentive Survey of 24 Western States 36 taken by the Garrett Group in 3 2007, and updated in 2009 and again in 2011, show that most states follow guidelines 4 similar to those described above for Texas, where incentive pay associated with financial 5 performance is not allowed in rates. Some states disallow incentive pay using other 6 criteria. None of the jurisdictions surveyed allow full recovery of incentive 7 compensation through rates as a general rule. The results of the survey are set forth 8 below.

States that closely follow the Financial Performance rule 9 Arizona The commission deals with incentive compensation plans on a case by 10 case basis. It first compares overall compensation to the state norm, then 11 asks if the costs are prudent and reasonable. The commission leans 12 toward disallowing programs which benefit only the shareholder even if 13 total compensation is comparable to the state norm. Staffs position is that 14 unless a plan is tied to performance issues it is unnecessary for the 15 provision of service and that shareholders should pay for plans tied to 16 financial measures. In practice, the costs of annual incentive plans are 17 often shared 50/50 between ratepayers and shareholders. 37 18 Arkansas Excludes 100% of the long-term, equity-based plans. Short-term 19 incentive plans are evaluated to determine if they are based on financial 20 or operational measures. Operational-based plans are allowed. 50% of 21 plans containing financial measures are disallowed. Any plans based 22 solely on the discretion of the company are seen as having no direct 23 benefit to ratepayers and are disallowed 100%. Settlements in recent 24 cases have upheld this treatment. 38

See ALJ's Proposal for Decision at page 113 in PUC Docket No. 28840, SOAH Docket No. XXX-XX-XXXX, issued July I, 2004. The PFD with respect to the treatment of incentive compensation was adopted by the Commission in its Final Order.

The survey does not cover Nebraska because the state does not regulate investor-owned electric utilities.

See e.g., APS 2008 rate case, Decision 70360, Southwest Gas 2008 rate case, Decision 70665 and UNS Gas 2008 rate case, Decision 70011.

Entergy Arkansas, 06-101-U, Order No. 10.

Direct Testimony of Mark E. Garrett Page 32 of65 Docket No. 39896 1 California Incentive funding is an issue that is typically litigated. In CPUC Decision 2 00-02-046, the commission established that utilities could recover 50% of 3 the regular employee's incentive compensation costs in rates. In 4 California's latest litigated rate case, the commission decided that 5 Edison's non-executive plans and 50% of the short-term executive plans 6 would be funded in rates and that 100% of the executive long-term stock 7 plans would be disallowed. 39 8 Colorado Regular employee programs are judged based on ratepayer verses 9 stockholder benefit ratio. Plans with metrics for goals benefiting 10 ratepayers but dependent on an earnings-per-share trigger are considered 11 to benefit shareholders and opposed by staff. Staff's approach is set forth 12 most recently, in 1OAL-963G by staff witness Kahl. The settlement in 13 that case removed the dollar amount opposed by Kahl. All executive 14 incentives are excluded from rates and typically no longer sought in 15 company filings.

16 Hawaii Hawaii does not allow incentive compensation to be included in rates. In 17 Docket No. 6531 the commission agreed that bonus awards tied to 18 company income and earnings benefit stockholders, not ratepayers. The 19 commission further states, "... we believe that a utility employee, 20 especially at the executive level, should perform at an optimum level 21 without additional compensation. Ratepayers should not be burdened 22 with additional costs for expected levels of service. " 23 Idaho The commission's policy for evaluating incentive compensation plans 24 involves determining who benefits, the customer or the company. This 25 treatment has been refined in the recent Idaho Power rate case for plans 26 which benefit the customer but require a financial trigger to be paid. For 27 these plans the commission reduced the percentage allowed in rates. The 28 commission also now does not include any executive compensation in 29 rates.

Hawaii's policy is set forth in Docket No. 6531 in the October 17, 1991 Order No. 11317. Prior Dockets in which the commission disallowed incentive compensation include No. 3216, No. 4215, No. 4588 and No. 5114.

The Commission's focus on customer benefit is reflected in the direct testimony of Staff witness Leckie, and in the final order for the recent IPC General Rate Case IPC-E-08-10. For earlier examples of the basic policy, see Idaho Power Company Rate Case IPC-E-05-28, Corrected Motion for Approval of Stipulation 3/1/06, 6e, p. 4; Idaho Power Company IPC-05-28, Order No. 30035, p. 4/10.

Direct Testimony of Mark E. Garrett Page 33 of 65 Docket No. 39896 1 executive annual incentive programs that have no focus on profitability or . 42 2 earmng 3 Louisiana Traditionally incentive compensation for upper level management and 4 officers is excluded, while costs for lower level managers and employees 5 are allowed. The criteria used to evaluate plan design consider whether 6 the goals of each plan directly benefit ratepayers or shareholders. Stock 7 based compensation plans at ail levels are excluded.

8 Minnesota Minnesota distinguishes between incentive plans tied to financial triggers 9 (such as a threshold ROE), and plans tied to criteria benefitting the 10 ratepayer. Plans based on goals which benefit ratepayers are allowed in 11 rates, but their costs are capped at 25% of base salaries. 43 The portions of 12 these plans that are allowed into rates are tracked and must be returned to 13 ratepayers if they are not paid to employees. Executive plans are largely 14 not allowed.

15 Missouri Missouri's treatment disallows incentives tied to goals benefitting 16 primarily the stockholders (e.g. tied to earnings per share) while allowing 17 plans with customer-specific goals (e.g. safety). Plans must also be 18 reasonable. The Commission also allows only the amounts actually paid, 19 not those accrued. The same criteria are used for executive pians and few 20 are allowed. 45 21 Nevada The commission excludes 100% of the long-term plans and all short-term 22 plans directly related to financial performance. 46

In the litigated 2010 KCP&L rate case (10-KCPE-415-RTS) the Commission also stated that relying on peer group statistics "can result in a continuing upward spiral [instead] the Commission must examine the elements of incentive packages, and the behavior they in cent." The Commission held that a focus on profitability or earning might incent employee behavior "detrimental to customers."

This general policy is demonstrated in recent orders in the Minnesota Power and Ottertail rate cases: E002/GR- 09-l l 51 and E002/GR-10-239 respectively.

Minnesota's general policy is demonstrated in recent orders in the Minnesota Power and Ottertail rate cases: E002/GR-09-l 15 l and E002/GR- l 0-239 respectively. See also Minnesota Power General Rate Case E002/GR/05/l 428.

See, e.g., in the latest Missouri American rate case (WR-2010-0131), not only were plans based on financial goals disallowed, but incentive payments based on customer satisfaction were disallowed due to the unreasonably small sample size used to establish a positive rating (a phone survey of927 of roughly 450,000 customers). The commission also removed incentive payments tied to lobbying and charitable activity. In the most recent case processed, the Ameren UE rate case, the company did not seek even short-term incentive compensation tied to earnings, providing further indication that staff's practice of disallowing financial performance based incentives is accepted by the companies. All incentive compensation adjustments were made not only to expense charges, but to construction charges as well. See also recent Kansas City Power and Light and Empire Electric District orders on the commission's website.

See, for example, the PUCN's final order in Docket 11-06006.

Direct Testimony of Mark E. Garrett Page 34 of65 Docket No. 39896 1 New Mexico The commission does not favor incentive compensation plans that are tied 2 to financial goals and tends to allow in rates those based on operational 3 goals. This standard is applied to all levels of utility employees and tends 4 to eliminate the greater portion of executive plans. 47 5 Oklahoma The commission excludes incentive payments tied to financial 6 performance. From a practical perspective this means that all executive 7 stock plans are excluded and some portion of the annual cash plan for all 8 employees. Since the commission has not been able to determine in 9 recent cases the precise portion of the annual plans tied to financial 10 measures, the commission has excluded 50% of the annual plans. 100% 11 of the executive stock plans are excluded. 48 12 Oregon The commission's general policy is to evaluate plans based on whether 13 they benefit the customers or the company. Customer-based plans 14 involving reliability, response speed, etc. are called "merit" (operational) 15 plans. Company-based plans which track increases to the bottom line, 16 ROE, etc. are called "performance" (financial) plans. 50% of the cost of 17 merit plans is disallowed and 75% of the performance plans is disallowed.

18 100% of officer bonuses are disallowed. 49 19 S. Dakota The commission's general policy is to disallow the portion of incentive 20 plans that are based on the company's financial performance. 5 Current ° 21 treatment also includes disallowing both executive and non-executive 22 management incentive compensation. There are no incentive 23 compensation plans for union employees. Several utilities have whole 24 incentive programs that hinge on whether or not the company earns a 25 certain return. These financial prerequisites cause the whole plans to be 26 excluded from rates.

27 Texas The general rule is that incentive payments designed to improve the 28 financial performance of the utility are excluded. For example, in PUC 29 Docket No. 28840, 51 the commission disallowed sixty-six percent (66%) See Docket 07-00077-UT.

See e.g., AEP-PSO Cause No. PUD 06-285; OG&E Cause No. PUD 05-151; and ONG Cause No. PUD 04-610.

A recent order reflecting this policy can be found in Docket UE 197, Order No. 09-020.

In Docket No. EL 08-030 the settlement excluded bonuses related to "stockholder-benefitting financial goals."

The settlement in Xcel rate case Docket No. EL09-009 removed payments based on financial performance indicators. In the settlement agreement signed July 7, 2010 in the Black Hills Power rate case Docket No. EL09- the Staff Memorandum states, "The settlement removes financial based incentive payments that were included in the capitalized labor costs for plant. Shareholders are the overwhelming beneficiaries of incentive plans that promote the financial performance of the Company and therefore should be responsible for the cost of such compensation."

Application ofAEP Texas Central Company for Authority to Change Rates, Docket No. 28840; SOAH Docket No. XXX-XX-XXXX, Final Order (August 15, 2005).

Direct Testimony of Mark E. Garrett Page 35 of65 Docket No. 39896 1 of AEP-Texas Central's test year incentive payments in the amount of 2 $4.2 million. This was the portion of the utility's incentive payments that 3 were based on financial performance measures. 52 4 Utah The commission's general policy is to allow in rates the parts of a plan 5 that are tied to ratepayer benefit and disallow the parts tied to financial 6 goals. Equity-based incentive compensation is excluded from rates. 53 7 Washington Incentive plans are evaluated on a case by case basis. Incentives tied to 8 operational efficiency or other measures which benefit ratepayers are 9 allowed in rates and incentives based on return on earnings or other 10 measures that benefit the shareholders are disallowed. 54 11 Wyoming Employee incentive compensation plans are evaluated on a case by case 12 basis, distinguishing between employee programs that benefit the 13 ratepayer or the stockholders and requiring the benefitting party to pay.

14 Executive incentive compensation plans are all excluded from rates.

States that use another approach 15 Alaska Incentive compensation is not an issue in rate cases in Alaska. There is 16 no relevant regulation or policy.

17 Iowa Incentive compensation is not typically an issue because few rate cases 18 are litigated in this jurisdiction. Mid-America has an incentive 19 compensation plan but hasn't filed a rate case in many years. For the 20 state's other utilities, it has been a long time since they have filed a rate 21 case or had a rate increase. The standing treatment is to consider 22 incentive compensation plans on a case by case basis and to evaluate 23 whether they are reasonably and prudently incurred. Both of the investor 24 owned utilities in Iowa are under rate freezes until 2013 and 2014.

The recent final order in Docket 09-035-23 follows this general policy as does the order in Docket 07-35-93. See also Missouri Corp. Rate Case Docket 97-035-01, pp. 10-12; US West Communications Rate Case Docket 95-049- 05.

See the Order in Pacific Power and Light Docket 061546.

Direct Testimony of Mark E. Garrett Page 36 of65 Docket No. 39896 1 compensation out of rates, but reserved the right to propose that it be 2 included in a later filing.

4 N. Dakota Historically, North Dakota has followed the general policy that the 5 portion of incentive compensation that relates to shareholder earnings is 6 disallowed and the rest is included. Recently the commission chose to 7 consider overall compensation and determine whether it was reasonable 8 as compared to the market. 55 Executive incentive compensation is not 9 allowed in rates, and is typically not sought by the company.

10 Q: HOW IS INCENTIVE COMPENSATION TREATED IN THE OTHER STATES 11 WHERE YOU HA VE PERSONAL EXPERIENCE?

12 A: The states in which I routinely practice all follow the majority rule that incentive 13 expense associated with financial performance is excluded from rates. As a practical 14 matter, this means that some portion of all incentive plans are excluded in these 15 jurisdictions, as set forth in the summary below: 16 In Arizona, the commission follows the same rule - that costs associated with 17 financial performance are excluded. In practice, this means that the costs of long-term 18 plans are excluded altogether and the costs of the short term annual cash plans are shared 19 50/50 between shareholders and ratepayers. As examples, see APS 2008 rate case, 20 Decision 70360, Southwest Gas 2008 rate case, Decision 70665 and UNS Gas 2008 rate 21 case, Decision 70011.

22 In Arkansas, incentive payments tied to financial performance measures that 23 benefit only the company such as stock-based plans and EPS measures are assigned

Other than Xcel, the utilities in North Dakota (Otter Tail and MDU) are highly diversified now (with mostly unregulated operations, e.g. MDU 90%). This allows utility executives to draw on the unregulated components for their compensation.

Direct Testimony of Mark E. Garrett Page 37 of65 Docket No. 39896 1 l 00% to the shareholders while measures that benefit both the company and its 2 customers are shared 50/50.

3 In Nevada, in the 2008 Nevada Power rate case, the commission excluded 100% 4 of the long-term plan for executives and key employees of the company, based on the 5 fact that these costs mainly benefit shareholders. 56 In Nevada Power's recent 2011 rate 6 case, Docket No. 11-06006, the Company voluntarily excluded the costs of its long-term 7 plan. With respect to short-term incentives, the commission excludes all plans directly 8 related to financial performance.

9 In Oklahoma, the commission also excludes incentive payments tied to financial 10 performance. From a practical perspective this means that all executive stock plans are 11 excluded and some portion of the annual cash plan for all employees. Since the 12 commission has not determined in recent years the precise portion of the annual plans 13 tied to financial measures, the commission has excluded 50% of the expense. All of the 14 long-term plan costs are routinely excluded. 57 15 In Utah, costs associated with financial performance are excluded. The rule is 16 followed so closely that the utility typically no longer submits the cost of its long term 17 incentive plan for rate case recovery.

See Draft Order issued June 17, 2009 in Docket No. 08-12002, at page 138.

See, e.g., AEP-PSO Cause No. PUD 06-285; OG&E Cause No. PUD 05-151; and ONG Cause No. PUD 04-610.

Direct Testimony of Mark E. Garrett Page 38 of65 Docket No. 39896 Q: WHY IS THE DISTINCTION BETWEEN FINANCIAL PERFORMANCE 2 MEASURES AND OPERATIONAL MEASURES IMPORTANT FOR 3 INCENTIVE COMPENSATION ANALYSIS?

4 A: When incentive compensation payments are based on financial performance measures, 5 the compensation agreement between shareholders and employees could be loosely 6 stated in this manner: "if you will help increase shareholder earnings, we will pay you a 7 bonus." The intended beneficiaries to this agreement are the shareholders and the 8 employees. Ratepayers have no stake in this agreement; therefore, they should bear none 9 of the costs that result from such an agreement. If, instead, the agreement were stated in 10 this manner: "if you will help increase reliability and quality of service to the customers, 11 we will pay you a bonus," then, ratepayers would have a stake in the agreement, and 12 could share in a portion of the costs. However, so long as some portion of the incentive 13 plan is designed to increase earnings, that portion of the plan should be funded out of the 14 increased earnings the plan helps produce.

16 Q: HOW MUCH OF THE COMPANY'S INCENTIVE COMPENSATION IS TIED 17 TO FINANCIAL PERFORMANCE?

18 A: The Company estimates that 35% of the annual incentive plan payments are related to 19 financial performance measures. This percentage is a weighted average percentage that 20 includes: (1) all payments tied to Financial and Cost Control measures; and (2) one- third 21 of the payments tied to a combination of Cost Control, Safety and Operational

Direct Testimony of Mark E. Garrett Page 39 of65 Docket No. 39896 l measures. The Company also indicates that 100% of the equity-based long-term 2 incentive plans and 100% of the stock option plans are related to financial 3 performance. 59

5 Q: WHAT TYPES OF INCENTIVES ARE PROVIDED TO COMPANY 6 EXECUTIVES?

7 A: Under the Company's plan, executives are provided three types of incentive 8 compensation: (1) the Executive Annual Incentive Plan; (2) the Long-Term Cash 9 Incentive plan; and (3) the Equity Ownership Plan, which provides stock options and 10 other stock-based awards to executives and other employees of the Company.

12 Q: DO YOU RECOMMEND THE INCLUSION OF THE EXECUTIVE INCENTIVE 13 EXPENSE IN RATES?

14 A: Generally, incentive compensation payments to officers, executives and key employees 15 of a utility company are excluded for ratemaking purposes, and I agree with this 16 treatment. Executive stock-based compensation in particular is excluded in most 17 jurisdictions because stock-based compensation is, on its face, tied to financial 18 performance. Since officers of any corporation have a duty of loyalty to the corporation 19 itself and not to the customers of the company, these individuals typically put the 20 interests of the company first. Undoubtedly, the interests of the company and the

This percentage is derived from Exhibit KGG-4 and is the weighted average of payments tied to financial and cost control measures. However, because Exhibit KGG-4 has been identified by the Company as a highly sensitive exhibit the exact derivation of this percentage is not provided in this "public" testimony, but is available for review.

Direct Testimony of Mark E. Garrett Page 40 of65 Docket No. 39896 1 interests of the customer are not always the same, and at times, can be quite divergent.

2 This natural divergence of interests creates a situation where not every cost associated 3 with executive compensation is presumed to be a necessary cost of providing utility 4 service.

5 It has been my experience that some utilities no longer seek recovery of 6 executive long-term incentive compensation, since long-term executive incentive plans, 7 such as stock option plans, are specifically designed to tie executive compensation to the 8 financial performance of the company to further align the interests of the executives with 9 those of the shareholders. Since the compensation of the employee is tied over a long 10 period of time to the company's stock price, it creates an incentive for the employee to 11 make business decisions from the perspective of long-term shareholders. This 12 intentional alignment of employee and shareholder interests means the costs of these 13 plans should be borne solely by the shareholders. It would be inappropriate to require 14 ratepayers to bear the costs of incentive plans designed to encourage utility executives to 15 put the interest of the shareholders first, especially when the interest of the shareholder is 16 directly bolstered by increases in utility rates.

17 While many regulators are inclined to exclude all executive bonuses, incentive 18 compensation and supplemental benefits from utility rates, my recommendation in this 19 testimony merely follows the Texas rule which excludes incentives tied to financial 20 performance measures - effectively eliminating most of the executive incentives.

See ETI responses to Cities' RFI 10-9(k) and Cities' RFI 10-lO(k).

Direct Testimony of Mark E. Garrett Page 41 of65 Docket No. 39896 Q: IS YOUR RECOMMENDATION TO EXCLUDE ALL EQUITY INCENTIVE 2 COMPENSATION CONSISTENT WITH THE TREATMENT OF INCENTIVES 3 IN THE OTHER STATES WHERE YOU REGULARLY PRACTICE?

4 A: Yes. Oklahoma, Nevada and Utah all follow the same general rule that excludes 5 incentive compensation tied to financial performance measures. This means that long- 6 term equity incentive plans are all excluded. For example, in Oklahoma, in each of the 7 most recently litigated rate cases for the three major utilities in that state, the commission 8 has excluded 100% of the utilities' long-term incentive compensation plans. Likewise, 9 in Nevada, the commission excluded 100% of the long-term incentive compensation 10 plan costs in Nevada Power's 2008 rate case. In the Company's 2011 rate case, the 11 utility voluntarily excluded the long-term incentive costs. In Utah, PacifiCorp also 12 voluntarily removes all costs associated with its long-term incentive compensation 13 plans. 60 The table below sets forth the most recent treatment of long-term incentive 14 compensation for the major utilities in these jurisdictions.

In PacifiCorp's last two general rate case, Docket No. 07-035-93 and Docket No. 08-035-38, the Company did not seek recovery of its long-term executive compensation plans.

Direct Testimony of Mark E. Garrett Page 42 of65 Docket No. 39896 TABLE: 2 LONG-TERM INCENTIVE TREATMENT IN OKLAHOMA, NEV ADA AND UTAH

Utility Company Amount Excluded Docket Number AEP/PSO 100% Excluded Cause Nos. PUD 06-285;08-144 Oklahoma Gas & Electric 100% Excluded Cause No. PUD 05-151 Oklahoma Natural Gas 100% Excluded Cause No. PUD 04-610 Nevada Power l 00% Excluded Docket No. 08-12002; 11-06006 PacifiCorp I 00% Excluded Docket No. 08-035-38

1 Q: HOW IS EQUITY INCENTIVE COMPENSATION TREATED IN OTHER 2 STATES?

3 A: As shown in the Garrett Group's Incentive Survey, most states follow guidelines similar 4 to those described above for Texas, Oklahoma, Nevada and Utah, that disallow incentive 5 pay associated with financial performance. As a result, equity-based incentives typically 6 are not allowed in most states. A synopsis of the survey results from each state was 7 included earlier in this section of testimony, with the treatment of executive incentives in 8 each state underlined. According to the survey, the following western states exclude all 9 or virtually all executive incentive pay: Oregon, California, Nevada, Idaho, Utah, South 10 Dakota, Oklahoma, Wyoming, North Dakota, Missouri, Arkansas, Louisiana and 11 Minnesota. Other states, like Washington, Missouri and Texas, apply the financial 12 performance rule, which has the effect of excluding executive incentives, especially 13 stock-based awards.

Direct Testimony of Mark E. Garrett Page 43 of65 Docket No. 39896 Q: WHEN UTILITIES DO SEEK TO INCLUDE EXECUTIVE STOCK 2 COMPENSATION IN RATES, WHAT RATIONALE IS GENERALLY 3 PROVIDED?

4 A: Generally, utilities argue that executive incentives are part of an overall compensation 5 package that is designed to attract and retain qualified personnel. Generally, the 6 rationale is that some other utilities may offer incentive plans to their executives, thus a 7 company runs the risk of not being able to compete for key personnel if it does not offer 8 a comparable plan. 61

10 Q: IS THIS ARGUMENT PLAUSIBLE?

11 A: No. The common problem with the Company's "total compensation package" argument 12 is that when an incentive payment is based on achieving financial performance goals 13 there should be a financial benefit to the company that comes from achieving these 14 goals. This financial benefit should provide ample additional funds from which to make 15 the incentive payments. If not, the plan was poorly conceived. Thus, a utility is not 16 placed at a competitive disadvantage when incentive payments tied to financial 17 performance are not collected through rates, because the funding for these payments is 18 available from the additional earnings the incentive plans help achieve.

19 Further, when utilities, such as ETI, compete with other utilities for qualified 20 executives, and the executive incentive compensation plans of the other utilities are not 21 being recovered through rates, ETI is not at a disadvantage when its equity incentive See, for example, the Direct Testimony of Jay C. Hartzell at page 7, lines 10-13.

Direct Testimony of Mark E. Garrett Page 44 of65 Docket No. 39896 1 compensation is excluded as well. Since most states exclude equity incentive pay as a 2 matter of course, and many others exclude equity incentives as a practical matter, ETI 3 would actually be given an unfair advantage if its equity plans were included in rates.

4 The fact that other utilities may offer equity incentive plans is not relevant; what is 5 relevant is the fact that other utilities typically are not recovering the costs of these plans 6 in rates. The Nevada Commission articulated this important ratemaking concept in its 7 order disallowing Nevada Power's long-term incentive plan in the Company's 2008 8 general rate case.

9 Therefore the Commission accepts BCP's and SNHG's recommendations 10 to disallow recovery of expenses associated with LTIP. Both parties 11 provide a valid argument that this type of incentive plan is mainly for the 12 benefit of shareholders. Further, both BCP and SNHG provide examples 13 of numerous other jurisdictions that do not allow the recovery of these 14 costs and, therefore, disallowance in this instance wouid not place NPC in 15 a competitive disadvantage. 62 (Emphasis added).

16 Q: IS THERE OTHER EVIDENCE THAT THE COMPANY WILL NOT BE 17 DISADVANTAGED BY A DISALLOWANCE OF INCENTIVE EXPENSE?

18 A: Yes. According to Mr. Gardner, the Company's total payroll costs for 2011, including 19 both base pay and incentives, was 10% above market. 63 Most of these above-market 20 payroll costs relate to the Company's incentives. The Company's incentive levels are 21 63% above-market and the Company's base pay levels are 2% above market, resulting in 22 a total above-market level of 10% for both base pay and incentives. 64 The above-market

See Final Order in Docket 08-12002 at paragraph 549. NPC did not seek recovery of its LTIP in the 2011 rate case, Docket No. 11-06006.

See Table 5 at page 26 of Mr. Gardner's Direct Testimony.

See ETI response to Cities' RFI l 8-8(b ).

Direct Testimony of Mark E. Garrett Page 45 of65 Docket No. 39896 1 base pay is addressed earlier in this testimony. The Company's 63% above-market 2 incentive pay, however, is relevant in this section of testimony. Cities' adjustment, 3 proposed below, to reduce incentive compensation levels associated with financial based 4 incentives (3 5% of the short term cash incentives and 100% for long term equity-based 5 incentives), only reduces the Company's overall incentive compensation by 59%, which 6 is less than the 63% that the incentives are above-market.

8 Q: WHAT ADJUSTMENT DO YOU PROPOSE WITH RESPECT TO THE 9 COMPANY'S INCENTIVE COMPENSATION COSTS?

10 A: My proposed adjustment removes 35% of the annual incentive plan costs. This is the 11 weighted-average portion of the Company's plan that is tied to financial performance, 12 according to the Company. My adjustment also removes 100% of (1) the Long-Term 13 Incentive plan and (2) the Stock Option awards. These plans are clearly based entirely 14 upon the financial performance of the Company. Stock options are financial-based on 15 their face, and the Company admits that the Long-Term awards are based on financial 16 performance. 65

See ETI responses to Cities' RFI I0-9(k) and Cities' RFI 10-lO(k).

Direct Testimony of Mark E. Garrett Page 46 of65 Docket No. 39896 Q: DOES THE AMOUNT YOU IDENTIFIED IN THE ANNUAL PLANS AS 2 ASSOCIATED WITH FINANCIAL PERFORMANCE DIFFER FROM THE 3 AMOUNT IDENTIFIED BY THE COMP ANY?

4 A: Yes. The Company identified 14.1 % costs in the annual incentive plans as associated 5 with financial performance. 66 The Company divided the plans into four categories: (1) 6 financial performance goals; (2) cost control goals; (3) operational goals; and (4) safety 7 goals. 67 The Company included only category (1 ), financial performance goals, in the 8 14.1 % tied to financial performance. 68 This category includes goals tied solely to 9 increasing shareholder wealth such as earnings per share, shareholder returns, and stock 10 price. 69 The Company did not include category (2), cost control goals, as goals tied to 11 financial performance, but does acknowledge that this category should be included based 12 on prior Commission orders. 70

14 Q: WHAT DID YOU DO TO ARRIVE AT YOUR CALCULATED 35% FOR 15 FINANCIAL PERFORMANCE COMPONENT OF THE ANNUAL INCENTIVE 16 PLANS?

17 A: To arrive at 35%, I included costs in category (2), cost control goals, as related to 18 financial performance. I also included one-third of the costs in category (5), which 19 included a combination of cost control, safety and operational goals. When categories 20 (1) and (2) and one-third (1/3) of category (5) are combined, the amount related to

Direct Testimony of Kevin G. Gardner at page 30, line 7.

Highly Confidential Exhibit KGG-4, page I of 1.

Calculated from the information on Highly Confidential Exhibit KGG-4.

Direct Testimony of Mark E. Garrett Page 47 of 65 Docket No. 39896 1 financial performance is 35%. I included the category (2), cost control goals, as related 2 to financial performance because, in my experience, this is the typical treatment for cost 3 control measures. Since the Company retains all of the savings generated from cost 4 cutting measures between rate cases, it should pay the related incentives out of the 5 savings these cost cutting measures generate. Moreover, this treatment is consistent with 6 the regulatory treatment used by this Commission in the past on this issue. 71

8 Q: HOW WAS YOUR ADJUSTMENT DEVELOPED?

9 A: The following table shows the amount of Cities' proposed adjustment for incentives:

From the Description of Goals box at the bottom of page l of Highly Confidential Exhibit KGG-4.

See Direct Testimony of Jay C. Hartzell, PhD, at page 9, lines 9-13.

See Id. at page 8, lines 9-13 and footnote 1.

Direct Testimony of Mark E. Garrett Page 48 of65 Docket No. 39896 Table 3: Cities' Incentive Compensation Adjustment Amount % Tied to CITIES' Incentive Compensation Plans Included in Financial Adjustment Cost of Service Performance Management Incentive Plan $4,749,198 35% $1,862,219 Exempt Incentive Plan $1,858,337 35% $650,418 Team Share Incentive Plan $153,447 35% $53,706 Team Share - Bargaining Employees $384,877 35% $134,707 Executive Annual Incentive Plan $1,483,447 35% $519,206 Long-Term Incentive Plans $815,608 100% $815,608 I Equity Ownership Plans $4,561,367 100% $4,561,367 CITIES' Adjustment $14,187,774 $8,397,2321 I I Q: ARE THERE OTHER REASONS THE COMMISSION COULD CONSIDER A 2 LARGER ADJUSTMENT TO INCENTIVE PAY?

3 A: Yes. The Company's "allowable" incentive payments, m effect, those not tied to 4 financial goals, are tied primarily to operational goals, made up of "reliability, customer 5 service, capacity factor and community relations." In the test year, the Company made 6 substantial incentive payments based on employees achieving some perceived acceptable 7 level with respect to these goals. However, these payments seem inconsistent with 8 Entergy's ratings in the annual J.D. Power's Report on Customer Satisfaction for 9 Residential customers. 71 The J.D. Power and Associates Reports are widely recognized 10 and unbiased. The J.D. Power's report ranks utilities based on customer satisfaction. The 11 Entergy companies did not fare well, with Entergy Arkansas and Entergy Louisiana 12 ranking below average and Entergy New Orleans ranking 124th out of the 125 utilities

Direct Testimony of Mark E. Garrett Page 49 of65 Docket No. 39896 1 ranked in the 2011 report. Entergy Texas ranked only slightly above average. The poor 2 showing of the Entergy companies in general in an independent, objective customer 3 satisfaction evaluation report brings into question whether ratepayers should be required 4 to pay any of the "allowable" ETI incentives that are based on customer service and 5 community relations.

7 Q: IS THERE EVIDENCE THAT THE ANNUAL INCENTIVE PLANS ACTUALLY 8 MAY BE TIED TO FINANCIAL PERFORMANCE AT LEVELS HIGHER THAN 9 THE 35% DIRECTLY RELATED TO STOCK PRICE GOALS AND COST 10 CONTROL GOALS?

11 A: Yes. Each Entergy business unit designs its incentive targets based on goals that include 12 both financial-performance and operational goals such as spending level goals, cost 13 constraint goals, reliability goals, safety goals and customer service goals. However, the 14 Company still uses the EAM (Entergy Achievement Multiplier) to arrive at the amount 15 to be funded each year. In the past, the EAM was a composite of the Company's 16 earnings per share increase and operating cash flows, and was used as a performance 17 target. Now, the EAM operates as a funding mechanism for all plans to ensure that 18 adequate additional funds exist to pay the incentives, and as a performance target for 19 certain executives. 73 This indicates that all incentive payments are directly dependent on 20 the financial success of the Company each year. For ratemaking purposes, this means 21 that the entire amount of incentive payments could be viewed as tied to financial

J.D. Power and Associates 2011 Electric Utility Residential Customer Satisfaction Study.

Direct Testimony of Mark E. Garrett Page 50 of65 Docket No. 39896 I performance and disallowed on this basis. 74 If that were the case, the adjustment 2 necessary to remove the entire amount of incentive payments from the cost of service 3 would be $14,187,744.

5 Q: HOW SHOULD THE COMMISSION TREAT INCENTIVE COMPENSATION 6 IN THIS CASE?

7 A: At a minimum, the Commission should continue to follow the rule observed in Texas 8 and in most other jurisdictions, by disallowing for ratemaking purposes all incentive 9 payments associated with financial performance goals. This approach would exclude 10 the portion of annual incentive costs associated with stock price and cost control goals - 11 as well as the costs of the long-term incentive plan and the stock option plans. In light of 12 the overwhelming trend against including financial-based incentives in rates, and 13 considering the current national economic downturn and the economic shortfalls being 14 experienced in Texas in particular, I believe the Commission should continue to follow 15 the approach to incentive compensation that protects ratepayers against even the 16 appearance of being forced to pay costs designed to increase shareholder wealth. A 17 policy that includes incentive payments based on financial performance in rates, as 18 proposed by the Company, has the effect of forcing ratepayers to become captive 19 contributors to the financial prosperity of one company. Cities' proposed adjustment

See Direct Testimony of Kevin G. Gardner at page 17-18.

In Oklahoma, the Commission disallowed l 00% of the ONEOK, Inc. incentives for regular employees, because, although many of the goals were purportedly customer-related goals, actual funding of the incentive payments depended on the financial success of the company each year. See Cause Nos. PUD 91-1190 and PUD 2004-610.

Direct Testimony of Mark E. Garrett Page 51 of65 Docket No. 39896 decreases pro forma operating expense by $8,397,232, and is set forth at Exhibit MG- 2 2.10.

3 In the alternative, the Commission could consider a larger adjustment based on 4 the fact the Company's performance with respect to operational goals, such as customer 5 service and customer satisfaction, should not be included in rates if the Company's 6 performance in these areas is clearly below average. Based on the assessment of an 7 independent third party in the J.D. Power report, the Company's performance in 8 customer satisfaction is below average and, thus, the Commission may determine that a 9 larger disallowance of incentive compensation is appropriate.

11 Q: ARE YOU PROPOSING ANY OTHER ADJUSTMENTS FOR INCENTIVE 12 COSTS?

13 A: Yes. Disallowed incentive costs should not just be removed from operating expense but 14 should also be removed from rate base as well. When a cost is disallowed for 15 ratemaking purposes it must be removed from both operating expense and rate base.

16 Since a significant portion of the Company's incentive payments are capitalized each 17 year into the plant accounts, these amounts are included in pro forma rate base where 18 they will earn a return and be recovered through depreciation rates if not adjusted in this 19 case. Thus, it is necessary to reduce the amount of incentives capitalized in rate base by 20 the same percentage disallowed in operating expense. In effect, capitalized annual 21 incentives should be reduced by 35% and capitalized stock-based incentives should be 22 reduced by 100%.

Direct Testimony of Mark E. Garrett Page 52 of65 Docket No. 39896 Q: HAVE YOU BEEN ABLE TO QUANTIFY THIS ADJUSTMENT?

2 A: Yes. In response to Cities' 10th Set of RFis, the Company provided the amounts 3 capitalized for each incentive plan from 2008 through the end of the test year. For my 4 proposed adjustment, I included capitalized incentives from 2008 through the beginning 5 of the test year but did not include incentive capitalized during the test year, as test year 6 incentives may still be recorded in the CWIP accounts and not included in pro forma rate 7 base in this case.

8 Cities' proposed adjustment decreases proforma rate base by $9,835,111 and is 9 set forth at Exhibit MG-2.10. This adjustment removes 35% of the annual incentives in 10 rate base and 100% of the equity-based incentives, from the 2007 inception of ETI 11 forward excluding the test year.

13 Q: ARE YOU PROPOSING ANY OTHER ADJUSTMENTS FOR INCENTIVE 14 COSTS?

15 A: Yes. Accumulated deferred federal income tax (ADFIT) associated with disallowed 16 long-term incentive plans should be removed from rate base. This means that rate base 17 should be reduced by a net $694,730 debit balance in ADFIT accounts associated with 18 the Company's long-term incentive and stock option plans. The calculations for this 19 adjustment are set forth at Exhibit MG2. l 0.

Direct Testimony of Mark E. Garrett Page 53 of65 Docket No. 39896 SECTION IV. F. SUPPLEMENTAL EXECUTIVE RETIREMENT PLANS Q: PLEASE DESCRIBE THE COMPANY'S SUPPLEMENTAL EXECUTIVE 2 RETIREMENT PLANS.

3 A: The Company provides supplemental retirement benefits to highly compensated employees 4 of the Company. These supplemental retirement plans for highly compensated individuals 5 are provided because benefits under the general retirement plans are subject to certain 6 limitations under the Internal Revenue Code (the "Code"). As such, these types of plans are 7 often referred to as non-qualified plans. Benefits payable under these non-qualified plans 8 are typically equivalent to the amounts that would have been paid but for the limitations 9 imposed by the Code. In general, the limitations imposed by the Code allow for the 10 computation of benefits on annual compensation levels of up to $245,000 for the year.

11 Retirement benefits on compensation levels in excess of the $245,000 limitation are paid 12 through supplemental plans. Supplemental retirement plans for highly compensated 13 employees are designed to provide benefits in addition to the benefits provided under the 14 general pension plans of the company.

15 The Company has three non-qualified retirement plans for highly compensated 16 employees: 17 1) Pension Equalization Plan; 18 2) System Executive Retirement Plan; and 19 3) Supplemental Retirement Plan.

The limits are $225,000 for 2007, $230,000 for 2008 and $245,000 for 2009.

Direct Testimony of Mark E. Garrett Page 54 of65 Docket No. 39896 1 The first plan covers all employees with compensation levels above the $245,000 limitation 2 under the internal revenue code. The other two plans are supplemental plans for executives 3 only. Benefits are paid out of the general funds of the Company.

5 Q: WHAT AMOUNTS WERE INCLUDED IN PROFORMA OPERATING EXPENSE 6 FOR THE EXECUTIVE PENSION PLAN?

7 A: The amount of non-qualified supplemental retirement plan costs included in the filed cost- 8 of-service was $2, 114,931. Of this amount, direct ETI costs were $721,643 and the amount 9 allocated from ESI was $1,393,288. 76

11 Q: WHAT DO YOU RECOMMEND FOR THE SUPPLEMENTAL EXECUTIVE 12 RETIREMENT PLAN COSTS?

13 A: I recommend that shareholders pay for the costs of the supplemental executive 14 retirement plans. This means that ratepayers will pay for all of the executive benefits 15 included in the Company's regular pension plans, and that shareholders pay for the 16 additional executive benefits included in the supplemental plan. For ratemaking 17 purposes, shareholders should bear the additional costs associated with supplemental 18 benefits to highly compensated executives, since these costs are not necessary for the 19 provision of utility service, but are instead discretionary costs of the shareholders 20 designed to attract, retain and reward highly compensated employees. However, because 21 officers of any corporation have a duty of loyalty to the corporation, these individuals

See ETI responses to Cities' RFI 12-47.

Direct Testimony of Mark E. Garrett Page 55 of 65 Docket No. 39896 1 will put the interests of the company first. This creates a situation where not every cost 2 associated with executive compensation is presumed to be a cost appropriately passed on 3 to ratepayers. Many regulators are inclined to exclude executive bonuses, incentive 4 compensation and supplemental benefits from utility rates, understanding that these costs 5 would be better borne by the utility shareholders. 77

7 Q: HOW IS SERP TREATED IN OTHER STATES?

8 A: Although I have not conducted a comprehensive study of SERP treatment in other states, 9 I know that SERP is disallowed in the states of Oregon, 78 Idaho 79 and Arizona. 80 10 Moreover, in Nevada, the commission disallowed all SERP expense in Docket Nos. 01- 11 10001 and 03-10001, and in Docket Nos. 06-l 1022and 08-12002, the Nevada 12 Commission disallowed a portion of SERP costs.

For example, this Commission excluded SERP costs in PSO's last rate case, PUD 200600285.

See Oregon Public Utilities Commission, Order No. 01-787, September 7, 2001, page 44.

The Commission has not allowed recovery of SERP expenses in other utility rate cases.

PacifiCorp has not persuaded us that it is necessary to pay SERP to hire and retain executive officers. The SERP costs are not allowed."

See Idaho Public Utilities Commission Order No. 32196 issued February 28, 2011 in Rocky Mountain Power's rate case, Case No. Pac-E-10-07: The Commission finds Staffs argument persuasive and finds it reasonable to disallow Company recovery of SERP costs of $2.6 million (total Company) in this case. The Company has not demonstrated that the costs are related to providing services to southeast Idaho. The responsibility for generous severance benefits for executives, we find, is the responsibility of the Company and its shareholders, not Idaho customers.

The Arizona Corporation Commission has issued several decisions in which it denied rate recovery for SERP expenses. See 258 PUR 4th 353 (2007) Re Arizona Public Service Company, 247 PUR 4th 243 (2006), In Re Southwest Gas Corp., 2008 WL 2332953 (Arizona Corp Commission Decision 70360, May 27, 2008), In the Matter of the Application of UNS Electric, and 2007 WL 4731250 (Arizona Corp Commission Decision 70011, November 27, 2007) Re UNS Gas, Inc.

Direct Testimony of Mark E. Garrett Page 56 of65 Docket No. 39896 1 In Oklahoma, the Commission disallowed 100% of AEP/PSO's SERP expense in 2 PSO's 2006 rate case, Cause No. PUD 200600285: 3 q. Employee Benefits-Supplemental Executive Retirement Plan 4 ("SERP").

6 PSO included $596,081 as Supplemental Executive Retirement Plan 7 ("SERP") in its cost-of-service. The Commission adopts OIEC's 8 proposal to remove the SERP Expense from the revenue requirement in 9 this proceeding. The Commission adopts OIEC's recommendation that I0 ratepayers pay for all of the executive benefits included in PSO's regular 11 pension plans and that shareholders pay for the additional executive 12 benefits included in the supplemental plan.

13 Again, in PSO's 2008 rate case, Cause No. PUD 200800144, the Oklahoma commission 14 disallowed 100% of the Company's SERP expense.

15 11. Supplemental Executive Retirement Plan ("SERP") 16 The AG and OIEC recommend reductions to reflect the elimination of 17 SERP expense from PSO' s cost of service. Staff proposed no adjustment 18 to PSO's recommendation. SERP is AEP's non-qualified defined benefit 19 retirement plan that allows PSO argued allows AEP the flexibility to 20 attract and retain key employees and provides benefits that cannot be 21 provided under AEP's qualified defined benefit plans. PSO stated that 22 the combined plans, of which SERP is a part, allow employees to 23 accumulate an appropriate level of replacement income upon retirement.

Direct Testimony of Mark E. Garrett Page 57 of65 Docket No. 39896 I Q: WHAT IS THE AMOUNT OF YOUR ADJUSTMENT?

2 A: Cities' proposed adjustment, in the amount of $2,114,931, removes the costs of the non- 3 qualified retirement plans from cost of service. The adjustment is set forth at Exhibit 4 MG-2.11.

SECTION IV. G. ABOVE-MARKET EMPLOYEE BENEFITS Q: WHAT IS THE ISSUE WITH RESPECT TO ABOVE-MARKET EMPLOYEE 6 BENEFITS?

7 A: This section of my testimony addresses the above-market value of the Company's 8 employee benefit plans. At page 41 of his direct testimony, Mr. Gardner admits that the 9 value of the Company's employee benefit plans is 14% above market when compared to 10 a peer group of Fortune 500 companies.

12 Q: HA VE YOU PROPOSED AN ADJUSTMENT TO THE BASE PAY LEVEL 13 REQUESTED IN RATES?

14 A: Yes. From a ratemaking perspective, ratepayers are only required to pay the necessary 15 costs of providing utility service. Although the Company is free to pay its employees 16 above-market wages and above-market benefits, ratepayers should only be asked to pay 17 market-based prices for employee costs. For purposes of this adjustment, the calculation 18 of market-based wages is based the Company's own calculation. Because ratepayers 19 are experiencing the effects of perhaps the most severe financial downturn in the past 30 20 to 35 years, it would be particularly unfair at this time to ask captive ratepayers to pay Direct Testimony of Mark E. Garrett Page 58 of65 Docket No. 39896 1 above-market wages for utility services. As a result, I am recommending a 14% 2 adjustment to the employee benefits expense included in proforma rates.

4 Q: HOW IS YOUR ADJUSTMENT CALCULATED?

5 A: The adjustment, calculated in the table below, removes 14% of the Company's identified 6 employee benefits expense. The adjustment can be seen at Exhibit MG 2.9.

Table 4: Cities' Employee Benefits Adjustment81 Total Amount in Employee Benefit Plans ETI ESI Cost of Service Medical I Dental 4,476,874 2,504,140 5,981,014 LTD 131,273 58,058 189,331 Life 142,636 79,328 221,964 Retirement Plans 7,324,753 5,711,755 13,036,508 Executive F'"etirement Plans 721,643 1,393,288 0 Totals 12,797,179 9,746,569 20,426,817 Above Market Percentage 14% CITIES' Adjustment $2,860,034

The information in this table is from ETI's response to Cities' RFI 18-l(d)(vii).

Direct Testimony of Mark E. Garrett Page 59 of65 Docket No. 39896 SECTION IV. H. ADV ALOREM TAX EXPENSE Q: WHAT IS THE COMPANY PROPOSING AS AN AD VALOREM TAX 2 EXPENSE ADJUSTMENT?

3 A: The Company is proposing a 10. 81 % increase in property tax expense based on a 4 weighted average projected increase in net plant and net operating income for 2011. 82 5 The Company asserts that both net plant and net income are drivers in determining a 6 company's calculation for property tax assessment purposes. 83 The Company gives its 7 projected net plant increase a 20% weighting and its projected net income increase an 8 80% weighting and then adds an additional 1% for "Annual Tax Rate Creep." 84 The 9 Company's 10.81 % projected increase in property tax valuation results in an adjustment 10 of $2,592,417 to test year property tax expense.

12 Q: DO YOU AGREEE WITH THE COMP ANY'S PROPOSED ADJUSTMENT?

13 A: No. The Company's proposed adjustment is based on estimates and seems unreasonably 14 high when compared to actual valuation increase over the last couple of years. The 15 Company provided actual valuation increases for 2010 and 2011 in Chart 1 at page 8 of 16 Patricia Galbraith's direct testimony. These actual valuation increases were 7.0% in 17 2010 and 4.2% in 2011, much less than the Company's predicted 10.81% increase for 18 2012.

See AJ25, Adjustment to Property Tax Expense.

See Direct Testimony of P. Galbraith at page 7, line 16.

See AJ25, Adjustment to Property Tax Expense.

Direct Testimony of Mark E. Garrett Page 60 of65 Docket No. 39896 Q: WHAT ADJUSTMENT WOULD YOU RECOMMEND FOR PROPERTY TAX 2 EXPENSE?

3 A: I would recommend a more conservative approach when estimating tax increases. Since 4 actual valuation increases have averaged about 5.6% over the last two year period, I 5 would recommend an increase in that range for ratemaking purposes. Since property tax 6 is typically assessed on the appraised value of property located within the jurisdiction of 7 the taxing authority, 85 I recommend an adjustment based upon the Company's estimated 8 percentage increase in net plant for 2011, which is 3.73%. 86 With a 1% "Tax Rate 9 Creep" added, this results in a 4.73% increase, which is much closer to the Company's 10 actual average valuation increase of 5.6%. A 4.73% increase in property tax expense 11 results in an increase to test year property tax expense of $1.1 million. Using a 4.73% 12 increase instead of the Company's recommended 10.81 % increase results in an 13 adjustment to pro forma cost of service of $1,457,975. This adjustment can be seen at 14 Exhibit MG2.13.

SECTIONV. MISO TRANSITION EXPENSE ADJUSTMENT Q: WHAT IS THE ISSUE REGARDING MISO TRANSITION EXPENSE?

16 A: In this case, the Company is requesting deferred accounting treatment for its MISO 17 transition costs. 87 The Company is also proposing a pro forma adjustment to include its 18 estimated MISO transition costs in rates in the event its requested deferred accounting See P. Galbraith Direct Testimony at page 6, line 16.

See AJ25.

See the Direct Testimony and the Supplemental Testimony of Mr. Jay A. Lewis.

Direct Testimony of Mark E. Garrett Page 61 of 65 Docket No. 39896 1 treatment is not approved. Cities oppose the Company's requested deferred accounting 2 for the MISO transitions costs in the testimony of Mr. James Brazell. In my testimony, I 3 address the Company's pro forma adjustment to recover MISO transition costs in the 4 event the deferred treatment is not approved.

6 Q: WHAT IS THE COMPANY PROPOSING FOR A PROFORMA ADJUSTMENT 7 TO RECOVER ESTIMATED MISO TRANSITION COSTS?

8 A: The Company's adjustment increases cost of service by $4 million annually to recover a 9 3-year amortization of estimated MISO transition costs of $12 million. 88

11 Q: DO YOU AGREE WITH THE COMP ANY'S PROPOSED ADJUSTMENT IN 12 THE EVENT DEFERRED ACCOUNTING IS NOT APPROVED FOR MISO 13 TRANSITION COSTS?

14 A: No. The Company's requested $4 million annual expense level is inconsistent with the 15 Company's own projections of anticipated cost levels provided in response to Cities' 6- 16 3. The test year level for these expenses was $916,535. 89 The actual expenses incurred 17 m 2011, January through November, were only $2.513 million. 90 Annualized, this 18 would be $2.742 million. For 2013, the Company is expecting to incur an expense level

See adjustment AJl 6.23L. The Company also removes test year expense of $9 l 6K so that the amount included in pro forma expense is $4 million.

See AJl 6L is ETI Workpapers.

This amount appears in ETI's response to Cities' 6-3(b), Confidential Attachment 2. Attachment 2 is not being provided as an exhibit to this testimony because of its confidential designation. Cities, however, is using the $2,513 ,932 total from Attachment 2 with permission of the Company.

Direct Testimony of Mark E. Garrett Page 62 of65 Docket No. 39896 1 of $2.587 million, 91 which is considerably less than the pro forma level of $4 million.

2 The projected 2012 level of $8.9 million is higher than $4 million, but the 2012 is an 3 estimated level and is not consistent with actual 2011 results, and, 2012 will be half-over 4 by the time new rates go into effect. In my opinion, the actual 2011 level of about $2. 7 5 million or the expected 2013 level of about $2.6 million would be the outside range of 6 what the Commission would use for setting prospective rates. However, these levels, on 7 a going forward basis, are not sufficiently known and measurable to include for 8 ratemaking purposes. It is unknown at this point whether the move to MISO will even 9 be approved by this or other commissions and whether the Company will continue to 10 incur costs toward a MISO transition. Consequently, we are left with only the test year 11 level as the level to include in rates.

13 Q: HOW IS YOUR ADJUSTMENT CALCULATED?

14 A: My recommendation to reduce the Company's requested level of $4 million to the actual 15 test year level of $916,535 results in an adjustment of $3,083,462. This adjustment can 16 be seen at Exhibit MG2.14.

This amount appears in ETI's responses to Cities' 6-3(a)and (c), Confidential Attachment 1. Attachment l is not being provided as an exhibit to this testimony because of its confidential designation. Cities, however, is using the $2,587,943 total from Attachment 1 with permission of the Company.

Direct Testimony of Mark E. Garrett Page 63 of65 Docket No. 39896 SECTION VI. RIVER BEND DECOMMISSIONING EXPENSE Q: WHAT IS THE ISSUE REGARDING THE RIVER BEND DECOMMISSIONING 2 EXPENSE?

3 A: In its application, the Company has included River Bend decommissioning costs in the 4 amount of $2,019,000. This level is based on an agreement of the parties in the 5 Company's 2009 rate case, Docket No. 37744. 92 In this case, the Company was 6 requested to provide the annual decommissioning expense responsibility for Texas retail 7 customers required for River Bend 70% calculated using the most current Texas 8 Jurisdictional decommissioning fund balance and assuming the escalation rates agreed to 9 in the settlement of Docket No. 37744. The Company was also asked to provide the 10 most current fund balance sheet for the total fund balance, the calculation of the annual 11 decommissioning expense, the proposed funding term, and any other assumptions 12 supporting ETis calculation. In response, the Company provided the annual 13 decommissioning revenue requirement based on the Texas retail trust fund liquidation 14 values as of December 31, 2011, the assumed nuclear cost escalation rate of 3.625% 15 agreed to in the settlement of Docket No. 37744, and the projected trust fund earnings 16 rates and the NRC minimum cost estimate utilized in the decommissioning revenue 17 requirement approved in Docket No. 37744. This annual revenue requirement is 18 $1,126,000.

See Order signed 12/13/10 in Docket No. 37744 at paragraph 32, and ETI responses to Cities' 10-20 and 10-22.

Direct Testimony of Mark E. Garrett Page 64 of65 Docket No. 39896 Q: WHAT IS YOUR RECOMMENDATION WITH RESPECT TO THIS ISSUE?

2 A: Chapter 25 of the Substantive Rules Applicable to Electric Providers at §25 .231 (b)(F)(i) 3 provides that the annual cost of decommissioning for ratemaking purposes must be 4 determined in each rate case and expressly included in the cost of service established by 5 the commission's order. The amount expressly established in this case should be the 6 Company's calculated annual decommissioning revenue requirement of $1,126,000.

7 Also, an adjustment of $893,000 to the pro forma cost of service is needed to reflect the 8 difference between the requested level for decommissioning costs of $2,019,000 and 9 recommended level of $1, 126,000. This adjustment is included at Exhibit MG 2.12.

11 Q: DOES THIS CONCLUDE YOUR TESTIMONY?

12 A: Yes. It does.

Direct Testimony of Mark E. Garrett Page 65 of65 Docket No. 39896 Blank Page II II SOAH DOCKET NO. XXX-XX-XXXX PUC DOCKET NO. 39896

APPLICATION OF ENTERGY TEXAS, § INC. FOR AUTHORITY TO CHANGE § BEFORE THE STATE OFFICE RATES, RECONCILE FUEL COSTS, § OF AND OBTAIN DEFERRED § ADMINISTRATIVE HEARINGS ACCOUNTING TREATMENT §

DIRECT TESTIMONY AND EXHIBITS OF DR. DENNIS W. GOINS

ON BEHALF OF CITIES SERVED BY ENTERGY TEXAS, INC.

MARCH 27, 2012

REDACTED PUBLIC VERSION Blank Page TABLE OF CONTENTS

Page INTRODUCTION AND QUALIFICATIONS .................................................................. 1 CONCLUSIONS •••••••••••••••••••••••••••••••••••.••••••••••••••••..••..•••••.•••••••••••••••••••••...•••••••••••..•••• 4 RECOMMENDATIONS ••••••••••••••••••••••••••••••••••••.••••.•.•.••••••••••••••••••••••••......••••••••...••••••• 8 WHOLESALE JURISDICTION ALLOCATION .••••••••••••••••••••••••••••••••••••••••••••••••••••••••• 10 PURCHASED POWER CAPA CITY COSTS ••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••••• 13 MSS-2 COSTS ••••••••••••••••••••••••••••••••••••••.•...••••••••••••••••••..••..•...••.•••••••••••••••••••••••••..... 19 STREET LIGHTING AND TRAFFIC SIGNAL RATES •••••••••••••.•••••••••••......•.•••••••••••••• 21 EXHIBITS APPENDIX: QUALIFICATIONS

Docket No. 39896 Dennis W. Goins - Direct Page i Blank Page SOAH DOCKET NO. XXX-XX-XXXX PUC DOCKET NO. 39896

APPLICATION OF ENTERGY TEXAS, INC. § BEFORE THE FOR AUTHORITY TO CHANGE RATES, § STATE OFFICE OF RECONCILE FUEL COSTS, AND OBTAIN § ADlVUNISTRATJVE HEARINGS DEFERRED ACCOUNTING §

DIRECT TESTIMONY OF DENNIS W. GOINS ON BEHALF OF CITIES

INTRODUCTION AND QUALIFICATIONS Q. PLEASE STATE YOUR NAME, OCCUPATION, AND BUSINESS 3 ADDRESS.

4 A. My name is Dennis W. Goins. I operate Potomac Management Group, an 5 economics and management consulting firm. My business address is 5801 6 Westchester Street, Alexandria, Virginia 22310.

7 Q. PLEASE DESCRIBE YOUR EDUCATIONAL AND 8 PROFESSIONAL BACKGROUND.

9 A. I received a Ph.D. degree in economics and a Master of Economics degree 10 from North Carolina State University. I also earned a B.A. degree with 11 honors in economics from Wake Forest University. Following graduate 12 school I worked as a staff economist at the North Carolina Utilities 13 Commission (NCUC). During my tenure at the NCUC, I testified in 14 numerous cases involving electric, gas, and telephone utilities on such 15 issues as cost of service, rate design, intercorporate transactions, and load 16 forecasting. While at the NCUC I also served as a member of the 17 Ratcmaking Task Force in the national Electric Utility Rate Design Study Docket No. 39896 Dennis W. Goins - Direct Page 1 sponsored by the Electric Power Research Institute (EPRI) and the National Association of Regulatory Utility Commissioners (NARUC).

3 Since leaving the NCUC, I have worked as an economic and management consultant to firms and organizations in the private and public sectors. My assignments focus primarily on market structure, policy, planning, and pricing issues involving firms that operate in energy markets. For example, I have conducted detailed analyses of product pricing, cost of service, rate design, and interutility planning, operations, and pricing issues; prepared analyses related to utility mergers, transmission access and pricing, and the emergence of competitive markets; evaluated and developed regulatory incentive mechanisms applicable to utility operations; and assisted clients in analyzing and negotiating interchange agreements and power and fuel supply contracts. I have also assisted clients on electric power market restructuring issues in Arkansas, New Jersey, New York, South Carolina, Texas, and Virginia.

16 I have submitted testimony and affidavits and provided technical assistance in nearly 200 proceedings before state and federal agencies as an expert in competitive market issues, regulatory policy, utility planning and operating practices, cost of service, and rate design. These agencies include the Federal Energy Regulatory Commission (FERC), the Government Accountability Office, state courts in Iowa, Montana, and West Virginia, and regulatory agencies in Alabama, Arizona, Arkansas, Colorado, Florida, Georgia, Hawaii, Idaho, Illinois, Indiana, Kansas, Kentucky, Louisiana, Maine, Maryland, Massachusetts, Minnesota, Mississippi, Missouri, New Jersey, New York, North Carolina, Ohio, Oklahoma, South Carolina, Texas, Utah, Vermont, Virginia, West Virginia, Wyoming, and the District of Columbia. Additional details of my educational and professional background are presented in the Appendix.

Docket No. 39896 Dennis W. Goins - Direct Page 2 Q. ON WHOSE BEHALF ARE YOU APPEARING IN THIS 2 PROCEEDING?

3 A. I am appearing on behalf of the Cities of Anahuac, Beaumont, Bridge City, 4 Cleveland, Conroe, Dayton, Groves, Houston, Huntsville, Montgomery, 5 Navasota, Nederland, Oak Ridge North, Orange, Pinc Forest, Pinehurst, 6 Port Arthur, Port Neches, Rose City, Shenandoah, Silsbee, Sour Lake, 7 Splendora, Vidor, and West Orange (collectively, the Cities).

8 Q. WHAT ASSIGNMENT WERE YOU GIVEN WHEN YOU WERE 9 RETAINED?

10 A. I was asked to undertake two primary tasks: 11 1. Review the application, testimony, and exhibits filed by Entergy 12 Texas, Inc. (ETI) to adjust its base rates, reconcile fuel costs, and 13 obtain deferred accounting. In particular, I was asked to focus on 14 issues related to ETI's proposed treatment of demand-related 15 production costs associated with serving wholesale customers, 16 recovery of purchased power and transmission capacity costs, and 17 the design of street lighting and traffic signal rates.

18 2. Evaluate the reasonableness of ETI's proposals, and recommend 19 necessary changes.

20 Q. WHAT INFORMATION DID YOU REVIEW IN CONDUCTING 21 YOUR EVALUATION?

22 A. I reviewed ETI' s filing, testimony, exhibits, and responses to requests for 23 information. I also reviewed selected testimony and Commission orders in 24 prior ETI rate cases related to issues that I address in my testimony. I also 25 reviewed street lighting and traffic signal rates offered by selected utilities 26 other than ETI. Finally, I reviewed information found on web sites 27 operated by ETI's parent company, Entergy, Inc., FERC, the Commission, 28 and other selected state regulatory commissions.

Docket No. 39896 Dennis W. Goins - Direct Page3 CONCLUSIONS Q. WHAT CONCLUSIONS HAVE YOU REACHED?

3 A. On the basis of my review and evaluation, I have concluded the following: 4 1. During the test year in this case (July 20 IO-June 2011 ), ETI 5 provided electric service to retail customers in Texas, as well as 6 three wholesale customers-including East Texas Electric 7 Cooperative (ETEC)-under service agreements and rates 8 approved by FERC. 1 ETEC-a partial requirements customer- 9 will be ETI's only wholesale customer during the forward-looking 10 rate year (June 2012-May 2013).

11 2. Because ETI does not own sufficient capacity to serve its Texas 12 retail and ETEC wholesale loads, it must rely on purchased 13 capacity. The principal sources of ETI's purchased capacity 14 resources are: 15 II System capacity purchases from EOCs with surplus capacity 16 that is billed under Service Schedule MSS- I of the Entergy 17 System Agreement (ESA). Because Schedule MSS-1 is 18 designed to share the cost of system reserve capacity among 19 the EOCs, MSS-1 transactions are referred to as Reserve 20 Equalization.

In addition to ETI, the other regulated Entergy Operating Companies (EOCs) are Entergy Gulf States Louisiana, LLC (EGSL), Entergy Arkansas, Inc. (EAI), Entergy Louisiana (ELL), Entergy Mississippi (EMI), and Entergy New Orleans, Inc. (ENOI). ETI's and EGSL's predecessor was Entergy Gulf States, Inc. (EGSI), which was split into two vertically integrated utilities-ETI and EGSL-~as a result of the Jurisdictional Separation Plan (JSP) that became effective December 31, 2007.

Under the JSP, all of EGSI's transmission and distribution assets and gas-fired generating plants were assigned to ETI and EGSL on a situs basis. ETI also got an undivided 42.5-percent share in EGSI's 70-percent ownership interest in Nelson 6 and a 42-percent ownership interest in Big

Docket No. 39896 Dennis W. Goins - Direct Page 4 example, as a result of the JSP, ETI has a life-of-unit 2 purchased power agreement for 42.5 percent of the 70 percent 3 of EGSL's River Bend nuclear station subject to retail 4 regulation. ETI refers to these purchases as Legacy Affiliate 5 Contracts. In addition, ETI makes unit power purchases from 6 EOCs that are unrelated to the JSP. ETI refers to these 7 affiliate purchases as Other Affiliate Contracts 3 8 II Third-party purchases from firms not affiliated with ETI or 9 other Entergy companies-for example, ETEC. Two of the 10 third-party contracts-the 10-year, 485-MW Carville contract 11 and the 25-year, 225-MW purchase power agreement with 12 Sam Rayburn Municipal Power Agency (SRMPA)-were not 13 in place during the test year, but will be in place during the 14 rate year. 4 15 3. ETI estimated its cost of servmg Wholesale customers m a 16 jurisdictional separation study that split ETI' s cost of service 17 between the Texas Retail and the Wholesale jurisdictions. In this 18 jurisdictional study, ETI assigned demand-related (fixed) 19 production costs to each jurisdiction using the average and excess, 20 4 coincident peak (AED4CP) allocation method-the same method 21 that ETI used in its class cost-of-service study to assign demand- 22 related production cost responsibility to each retail customer class.

Cajun 2, Unit 3---two coal units in Louisiana. EGSL became the owner of EGSI's remaining generating plants--including the River Bend nuclear plant.

See the direct testimony of ETI witness Robert R. Cooper (Cooper Direct) at 21: 1-8 and Exhibit RRC-1 (HS). (ETI updated and revised Exhibit RRC-1 (HS) on March 16, 2012.) Ibid. at 21 :10-22:14.

Docket No. 39896 Dennis W. Goins - Direct Page S MSS-4 capacity payments-through a new purchased power 2 recovery rider instead of base rates. 5 As a result of a Commission 3 ruling following ETI's filing, recovery of ETI's purchased power 4 capacity costs (PPCC) is restricted to base rates at present, and 5 ETI' s proposed purchased power recovery rider will not be 6 considered in this case.

7 5. In this case ETI proposed adjusting test-year PPCC to reflect 8 known and measurable changes (primarily the expiration of some 9 test-year contracts and the commencement of two new purchase 10 power agreements). To reflect these changes, ETI recommends 11 setting its adjusted test-year PPCC equal to its forecast rate year 12 PPCC ($276.2 million), which will be recovered in base rates.

13 Including rate-year PPCC in base rates set using historical adjusted 14 test-year billing determinants ensures overrecovery of ETI's PPCC 15 if its load grows relative to test-year levels-that is, if rate-year 16 billing determinants are expected to be greater than test-year billing 17 determinants. ETI made no adjustment to its rate-year PPCC to 18 prevent this likely overrecovery.

19 6. ETI has proposed a similar approach to recover transmission costs 20 associated with payments under Service Schedule MSS-2.

21 Specifically, ETI adjusted its test-year MSS-2 costs (approximately 22 $1.84 million) to reflect a nearly - increase in rate-year 23 MSS-2 costs (almost ETI's MSS-2 test-year 24 adjustment ignores Entergy' s announced divestiture/merger of its 25 transmission assets into ITC Holdings Corp. (ITC) in 2013. In On March 16, 2012, ETI updated and revised Exhibit RRC-1 (HS) to reflect the impacts ofrecent changes in the EAI WBL contract on ETI's rate-year costs for Other Affiliate Contracts and Reserve Equalization. The updated PPCC shown in Exhibit RRC-1 (HS-revised) is $275.8 million. Because ETI has not yet updated and revised witness Cooper's direct testimony, I use the $276.2 million shown in ETI's original filing and Exhibit RRC-1 when referring to ETI's rate-year PPCC in my testimony. However, Cities rec01mnended adjustments to ETI's rate-year PPCC that I present later include ETI's PPCC adjustments shown in Exhibit RRC-1 (HS-revised).

Docket No. 39896 Dennis W. Goins - Direct Page 6 effect, ETI's rate-year estimate assumes that the divestiture/merger 2 will have no effect on either the level of or method of recovering 3 (via Schedule MSS-2 of the ESA) such costs. In addition, ETI 4 again ignored the effects of load growth when it set rate-year MSS- 5 2 costs as adjusted test-year MSS-2 costs recovered in base rates.

6 That is, by ignoring load growth in setting both PPCC and MSS-2 7 costs that will be recovered in base rates, ETI almost certainly 8 ensured that it will overrecover both types of costs going forward.

9 7. ETI's principal rate schedules for street lighting and traffic signal 10 customers are Schedules SHL and TSS, respectively. Schedule 11 SHL applies to lighting for public streets, roads, and thoroughfares 12 in cities and in subdivisions with an incorporated homeowners 13 association. Schedule SHL sets fixed monthly charges for standard 14 and nonstandard fixture and lamps that ETI installs and maintains 15 (Rate Groups A and C). ETI also offers a fixed kWh rate for 16 lighting facilities that the customer owns and maintains (Rate 17 Groups D and E). Schedule TSS is a fixed kWh rate with a 18 monthly customer charge per delivery point applicable to 19 customer-owned and -maintained traffic signals. Both proposed 20 rates do not reflect the lower cost of operating and maintaining 21 lighting facilities using energy-efficient light-emitting diode (LED) 22 bulbs. Moreover, Schedule SHL includes a provision that 23 penalizes a customer that replaces a high-wattage bulb with a more 24 energy-efficient LED bulb.

Docket No. 39896 Dennis W. Goins - Direct Page 7 RECOMMENDATIONS Q. WHAT DO YOU RECOMMEND ON THE BASIS OF THESE 3 CONCLUSIONS?

4 A. I recommend that the Commission take the following actions regarding the 5 major issues discussed in my testimony: 6 1. Reject the AED4CP method used in ETI' s jurisdictional separation 7 study to assign demand-related production costs to its Texas retail 8 and wholesale jurisdictions. Instead, the Commission should 9 require ETI to assign these costs to the wholesale jurisdiction using 10 the 12 coincident peak (12CP) method to allocate demand-related 11 production costs. This approach is consistent not only with the 12 cost-of-service approach FERC typically uses to allocate demand- 13 related production costs reflected in wholesale rate schedules, but 14 also with the assignment of MSS-1 costs (as well as MSS-2 15 transmission costs) to ETI under the ESA. I have calculated test- 16 year 12CP allocation factors for the Texas Retail (94.6208 percent) 17 and Wholesale (5.3792 percent) jurisdictions, and provided them to 18 Cities witness Karl Nalepa for inclusion in his jurisdictional 19 separation study.

20 2. Reject ETI's adjusted test-year purchased power capacity costs 21 ($276.2 million). Instead, ETI should be allowed to recover no 22 more than approximately $241.3 million in PPCC. This 23 approximately $35 million reduction in ETI's proposed rate-year 24 PPCC estimate reflects the following three adjustments: 25 111 - reduction in costs for Legacy Affiliate Contracts 26 to reflect more current pricing data.

27 Ill reduction in costs for Other Affiliate Contracts 28 and Reserve Equalization to reflect more recent contract

Docket No. 39896 Dennis W. Goins - Direct Page 8 pncmg data and Cities recommended adjustment m costs 2 related to the EAI WBL contract. 6 3 111111 reduction to reflect the effects of load growth on 4 rate-year PPCC costs that ETI will recover going forward.

5 3. Reject ETI's adjusted test-year MSS-2 costs. ETI's unexplained 6 in MSS-2 costs relative to test-year 7 costs, plus complete uncertainty regarding the magnitude of ETI's 8 post-2012 MSS-2 costs under Entergy's proposed 9 divestiture/merger deal with ITC in 2013, make ETI's projected 10 rate-year MSS-2 costs speculative at best. I recommend setting 11 ETI's adjusted test-year MSS-2 costs no higher t h a n - - 12 or 13 value reflects ETI's actual 2011 MSS-2 costs plus a 14 to reflect the effects of load growth.

15 4. Require ETI to modify Schedules SHL (Rate Groups A and C) and 16 TSS to include a minimum 25 percent reduction in monthly fixed 17 charges applicable to street and traffic lighting fixtures that use 18 LED technology. Energy charges in Schedule SHL (Rate Groups 19 D and E) should also be reduced by 25 percent for LED customers.

20 This reduction should partially reflect the lower cost of operating 21 and maintaining energy-efficient LED fixtures. In addition, the 22 Commission should require ETI to eliminate the $50 fee applicable 23 to Rate Groups A and C under Schedule SHL when an existing 24 light is replaced with a more efficient light with lower wattage (for 25 example, an LED bulb). Eliminating this fee will remove a 26 disincentive for customers to adopt LED fixtures as conservation 27 measures.

EAI WBL denotes capacity entitlements in several of EAI's baseload generating units that EAI sells at wholesale. Justification for Cities recommended EAI WBL rate-year cost adjustment is provided in the direct testimony of Cities witness Karl Nalepa.

Docket No. 39896 Dennis W. Goins - Direct Page 9 WHOLESALE JURISDICTION ALLOCATION Q. DID ETI SERVE ANY WHOLESALE CUSTOMERS DURING THE 3 TEST YEAR?

4 A. Yes. ETI provided partial requirements service to 3 wholesale customers 5 during the test year. However, during the rate year, ETI projects that 6 ETEC will be its only partial requirements wholesale customer.

7 Q. DOES ETI OWN SUFFICIENT GENERATING CAPACITY TO 8 SERVE ITS RETAIL AND WHOLESALE CUSTOMERS?

9 A. No. ETI is a short EOC-that is, its owned capacity and firm purchases 10 are insufficient to meet its capability responsibility under the ESA. As a 11 result, ETI must rely on additional capacity purchases to meet this 12 shortfall.

13 Q. IN ITS FILING, DID ETI ESTIMATE ITS COST OF SERVING 14 WHOLESALE CUSTOMERS?

15 A. Yes. ETI conducted a jurisdictional separation study to determine its cost 16 of serving customers in its Texas Retail and Wholesale jurisdictions. As 17 part of this separation study, ETI used the AED4CP method to allocate 18 demand-related production costs. ETI also used the AED4CP method to 19 allocate demand-related production costs in its retail class cost-of-service 20 study.

21 Q. IS THE AED4CP THE MOST APPROPRIATE METHOD TO 22 ALLOCATE THESE COSTS BETWEEN JURISDICTIONS?

23 A. No. In my opinion, the 12CP allocation method would be preferable. The 24 12CP approach is consistent with the cost-of-service approach FERC 25 typically uses to allocate demand-related production costs reflected in 26 wholesale rate schedules. Moreover, the ESA uses a 12CP method to

Docket No. 39896 Dennis W. Goins - Direct Page 10 derive each EOC's load responsibility ratio, which is then used to derive 2 each EOC's share of monthly MSS-1 and MSS-2 charges. Finally, in 3 reviewing monthly data reflected in ETI's rate-year PPCC shown in 4 Exhibit RRC-1, I noticed that estimated PPCC by month are relatively 5 stable-that is, total projected PPCC do not vary significantly by month.

6 ETI's heavy reliance on capacity purchases to serve load (both retail and 7 wholesale), and the relative stability of projected monthly PPCC costs 8 imply that the 12CP method should properly split ETI's demand-related 9 production costs between the Texas Retail and Wholesale jurisdictions.

10 Q. IN DOCKET NO. 37744, DID YOU TESTIFY THAT THE AED4CP 11 METHOD WOULD BE REASONABLE TO USE IN ETl'S 12 JURISDICTIONAL SEPARATION STUDY?

13 A. Yes. Although I recommended the 12CP method, I noted that the 14 AED4CP method would also be reasonable to use in ETI's jurisdictional 15 separation study. However, in this case, ETI's reliance on capacity 16 purchases is even greater that it was during test- and rate-years that ETI 17 used in Docket No. 37744. Moreover, in my opinion, for the reasons I 18 cited earlier, the 12CP allocation method is preferable to the AED4CP 19 method proposed by ETI, and should be used to assign ETI' s demand- 20 related production costs to jurisdictions.

21 Q. DID YOU CALCULATE JURISDICTIONAL 12CP ALLOCATION 22 FACTORS IN THIS CASE?

23 A. Yes. I calculated test-year 12CP allocation factors for the Texas Retail 24 and Wholesale jurisdictions. I provided the 12CP factors to Cities witness 25 Karl Nalepa for inclusion in his jurisdictional separation study. As shown 26 in Exhibit DWG-1 and Table 1 below, the 12CP allocation factor for the 27 Wholesale jurisdiction is about 5.38 percent versus 4.62 percent under 28 ETI' s recommended AED4CP method.

Docket No. 39896 Dennis W. Goins - Direct Page 11 Table 1. Jurisdictional Separation Demand-Related Production Cost Allocation Factor Jurisdiction AED4CP 12CP TX Retail 95.3838% 94.6208% Wholesale 4.6162% 5.3792% Total 100.0000% 100.0000% Source: Schedule P-7.2 and Exhibit DWG-1.

2 Q. WHAT LOADS DID YOU USE IN CALCULATING THE 12CP 3 WHOLESALE ALLOCATION FACTOR THAT YOU PROVIDED 4 WITNESS NALEPA FOR USE IN HIS JURISDICTIONAL 5 SEPARATION ANALYSIS?

6 A. I used a loss-adjusted 150 MW (ETEC's monthly billing MW) as a proxy 7 for the 12 monthly CPs. The 150 MW is indicative of ETI's capacity 8 obligations to ETEC, and reflects known and measurable changes 9 compared to test-year wholesale CPs (which would include CPs for 10 wholesale customers that ETI no longer serves).

11 Q. SHOULD THE COMMISSION REQUIRE ETI TO USE THE 12CP 12 METHOD TO ASSIGN DEMAND-RELATED PRODUCTION 13 COSTS TO JURISDICTIONS?

14 A. Yes. The l 2CP method best reflects how ETI incurs demand-related 15 production costs to serve Texas Retail and Wholesale customers.

Docket No. 39896 Dennis W. Goins - Direct Page 12 PURCHASED POWER CAPACITY COSTS Q. DOES ETI CURRENTLY HAVE ENOUGH CAPACITY 3 RESOURCES TO SERVE ITS RETAIL AND WHOLESALE 4 CUSTOMERS?

5 A. No. Under Schedule MSS-1, an EOC with fewer capacity resources than 6 its capacity responsibility must buy capacity from other EOCs whose 7 capacity resources exceed their capacity obligations. This capacity deficit 8 situation is commonly referred to as a short position, in contrast to a long 9 position involving a capacity surplus. Even with major increases in 10 purchased capacity, ETI expects to be short more than - during the 11 rate year. 7 Q. WHAT TYPES OF PURCHASES DOES ETI PLAN TO USE TO 13 MEET THIS CAPACITY SHORTFALL?

14 A. ETI plans to use four principal categories of purchases: 15 1111 Schedule MSS-1 purchases (Reserve Equalization) from other 16 EOCs with surplus capacity.

17 1111 Schedule MSS-4 purchases related to purchased power 18 agreements arising from the JSP (Legacy Affiliate Contracts).

19 1111 Schedule MSS-4 unit power purchases unrelated to the JSP 20 (Other Affiliate Contracts).

21 1111 Third-party purchases from companies not affiliated with ETI 22 or other Entergy companies.

23 ETI witness Robert R. Cooper discusses these categories of purchases in 24 his direct testimony, and presents rate-year estimates of ETI' s purchases in 25 each category in Exhibit RRC-1 (Highly Sensitive).

See ETI's responses to Cities 2-1.d (RRC-1 Workpaper MSS-1 111215_HSPM) and TIEC 1- (HS).

Docket No. 39896 Dennis W. Goins - Direct Page 13 Q. ARE ETI'S RA TE-YEAR PPCC SIGNIFICANTLY HIGHER THAN 2 ITS TEST-YEAR PPCC?

3 A. Yes. ETI's projected rate-year PPCC ($276.2 million) exceed test-year 4 PPCC by a b o u t - . My review of these costs indicates that third- 5 party purchases are the principal driver of the increase-growing more 6 than - from to Q. HOW HAS ETI TRADITIONALLY RECOVERED PURCHASED 8 POWER CAPACITY COSTS?

9 A. ETI has traditionally recovered these costs in base rates smce the 10 Commission's current fuel rule excludes purchased power demand or 11 capacity costs from eligible and reconcilable fuel expenses absent a 12 finding of special circumstances. 9 Q. IN THIS CASE, DID ETI INITIALLY PROPOSE TO CONTINUE 14 RECOVERING PPCC IN BASE RATES?

15 A. No. ETI proposed recovering PPCC in a purchased power recovery rider.

16 However, the Commission issued a ruling indicating that ETI's proposed 17 rider would not be considered in this case because of the ongoing 18 rulemaking in Project No. 39246 to consider the issue of how PPCC 19 should be recovered. As a result, ETI will continue to recover PPCC 20 approved by the Commission in base rates.

21 Q. WHY IS IT IMPORTANT TO ENSURE THAT THE LEVEL OF 22 PPCC INCLUDED IN BASE RATES IS REASONABLE AND NOT 23 SIGNIFICANTLY OVERSTATED?

24 A. Purchased power capacity costs included in base rates are not subject to 25 true-up and reconciliation. If the level of PPCC included in base rates is See ETI's response to Cities 2-1.a.iii-iv (including Addendum 1).

PUC Subst. R. 25.236(a)(4).

Docket No. 39896 Dennis W. Goins - Direct Page 14 significantly overstated, ratepayers will simply pay for costs that ETI never 2 incurs. The level of PPCC included in base rates must strike a balance 3 between giving ETI a reasonable opportunity to recover prudent capacity 4 costs that it incurs going forward, and protecting ratepayers from giving a 5 windfall to ETI.

6 Q. DID ETI ADJUST ITS TEST-YEAR PPCC?

7 A. Yes. ETI recommends adjusting test-year PPCC for known and 8 measurable changes (including the expiration of some test-year contracts 9 and the start of two new post-test-year purchase power agreements). To 10 reflect these changes, ETI set adjusted test-year PPCC equal to rate-year 11 PPCC ($276.2 million).

12 Q. DOES ETl'S ADJUSTED TEST-YEAR PPCC RAISE ANY 13 CONCERNS?

14 A. Yes. ETI's estimate raises two major concerns: 15 1111 ETI did not modify the level of adjusted test-year PPCC it 16 proposes to include in base rates for the going-forward effects 17 of load growth on PPCC recovery. This oversight ensures that 18 ETI will overrecover its adjusted test-year PPCC if load 19 growth results in base rate billing determinants greater than 20 test-year billing determinants used to set base rates in this 21 case.

22 1111 ETI developed rate-year cost estimates for Legacy Affiliate 23 and Other Affiliate transactions using the September 2010- 24 August 2011 average cost per MW for each affiliate contract.

Docket No. 39896 Dennis W. Goins - Direct Page 15 Q. PLEASE EXPLAIN THE LOAD GROWTH ISSUE AND WHY IT 2 SHOULD BE REFLECTED IN THE LEVEL OF PPCC INCLUDED 3 IN BASE RATES IN THIS CASE.

4 A. A simple example illustrates the problem. Assume Utility X files a rate 5 case in which its test-year billing units and PPCC are 100 units and $500, 6 respectively (see Table 2 below). Also assume that Utility X's projected 7 rate-year PPCC is $1,000, which it asks the regulator to include in base 8 rates set in the current rate case instead of $500 in test-year PPCC that 9 Utility X actually incurred. Finally, assume the regulator allows Utility X 10 to include rate-year PPCC in base rates instead of test-year PPCC. As a 11 result, the level of PPCC included in base rates set in the current rate case 12 is $10 per billing unit (that is, $1,000 in rate-year PPCC, divided by 100 13 test-year billing units).

14 Now move forward to the rate year when rates set in the rate case are in 15 effect. Assume that Utility X was correct in the rate case-its rate-year 16 PPCC turns out to be $1,000 exactly as it had projected. However, Utility 17 X's rate-year billing units have grown to 200 units-not 100 units that it 18 sold in the test year. As a result of this load growth, Utility X will recover 19 $2,000 of PPCC during the rate year ($10 per billing unit in base rates, 20 times 200 rate-year billing units)-or twice the level of PPCC that it 21 actually incurs in the rate year, and twice the amount the regulator 22 assumed would occur when approving base rates in the rate case to recover 23 projected rate-year PPCC.

Docket No. 39896 Dennis W. Goins - Direct Page 16 Table 2. Effect of Load Growth on PPCC Recovery

Line Item Test Yr Rate Yr Comment 1 Billing Units 100 200 2 Actual PPCC $500 3 Projected PPCC $1,000 4 Base Rate PPCC $1,000 Rate-Yr PPCC included in Base Rates 5 PPCC/Billing Unit in Base Rates $10 Line 4 I 100 Test-Yr billing units 6 Actual PPCC Recovered $2,000 Line 5 * 200 Rate-Yr billing units

2 ETI's proposed adjusted test-year PPCC creates the same problem, 3 because ETI is implicitly asking the Commission to ignore load growth 4 and set base rates in this case using rate-year PPCC and test-year billing 5 units. Using test-year billing determinants to set rates to recover ETI's 6 rate-year PPCC guarantees that ETI will overrecover its estimated rate- 7 year PPCC if rate-year billing units exceed test-year billing units-that is, 8 if ETI' s load grows.

9 Q. DOES ETI EXPECT ITS LOAD TO GROW FROM THE TEST 10 YEAR THROUGH THE RATE YEAR?

11 A. Yes. ETI expects a steady growth in both energy sales and peak load in 12 the next few years. 10 Q. HA VE YOU MODIFIED ETI'S ESTIMATED RA TE-YEAR PPCC 14 TO REFLECT YOUR CONCERNS REGARDING THE LOAD 15 GROWTH AND AFFILIATE TRANSACTION PRICING ISSUES?

16 A. Yes. I first adjusted the average cost per MW (proxy price) used to 17 develop the rate-year cost of Legacy Affiliate and Other Affiliate 18 (excluding EAI WBL) transactions. Specifically, I used transaction cost 19 data from November 2010-0ctobcr 2011 (instead of September 2010- 20 August 2010 data that ETI used) to develop the transaction proxy prices See ETI's response to Cities 2-2 (HS).

Docket No. 39896 Dennis W. Goins - Direct Page 17 and rate-year costs. Next, I adjusted ETI's rate-year estimates of costs for 2 the EAI WBL contract and Reserve Equalization to reflect the adjustment 3 recommended by Cities witness Karl Nalepa. Finally, I adjusted the rate- 4 year total PPCC estimate to reflect the effects of load growth. The 5 resulting adjusted test-year PPCC by transaction category is shown in 6 Exhibit DWG-2. 11 As shown in this exhibit, ETI's adjusted test-year 7 PPCC should be set no higher than $241.3 million-or $35 million less 8 than ETI's original request. As I noted earlier, this $35 million reduction 9 in ETI's proposed rate-year PPCC estimate reflects the following three 10 adjustments: 11 II - reduction in costs for Legacy Affiliate Contracts 12 to reflect more current pricing data.

13 II reduction in costs for Other Affiliate Contracts 14 and Reserve Equalization to reflect more recent contract 15 pricing data and Cities recommended adjustment in costs 16 related to the Cities recommended SO-percent reduction m 17 adjusted test-year costs for the EAI WBL contract.

18 II reduction to reflect the effects of load growth.

19 Q. HOW DID YOU DEVELOP THE LOAD GROWTH ADJUSTMENT 20 YOU APPLIED TO YOUR PPCC ESTIMATE?

21 A. The development of my recommended load growth 22 adjustment is presented in Exhibit DWG-3. I first reviewed forecasts of 23 ETI's firm load (energy sales and peak demand) from 2011 through 2014.

24 I then calculated the growth in ETI' s energy sales and peak demands over 25 different intervals (Exhibit DWG-3, page 1). On the basis of this review, I 26 s e l e c t e d - as a reasonable estimate of the likely growth in ETI's 27 energy and demand billing determinants from the test year to the rate year.

Results shown in Exhibit DWG-2 are presented in a format similar to that used by ETI's witness Robert Cooper in Exhibit RRC-1 (HS-revised).

Docket No. 39896 Dennis W. Goins - Direct Page 18 I next estimated ETT's rate-year energy billing units, and derived an 2 average cost per billing unit (Exhibit DWG-3, page 2) for the estimated 3 rate-year PPCC shown in column (c) of Exhibit DWG-2. The product of 4 this average rate-year PPCC and ETI's test-year kWh billing units equals 5 the adjusted test-year PPCC that ETI should be allowed to include in base 6 rates.

7 Q. IS YOUR RECOMMENDED $241.3 MILLION IN ADJUSTED 8 TEST-YEAR PPCC A REASONABLE AND FAIR ESTIMATE OF 9 COSTS THAT ETI IS LIKELY TO INCUR IN THE RATE YEAR?

10 A. Yes. My estimate mitigates two problems that cause ETI to overstate its 11 rate-year PPCC-its failure to adjust rate-year projections to reflect load 12 growth, and the use of dated transaction price proxies. In addition, my 13 estimate reflects witness Nalepa's recommended cost adjustments related 14 to the EAI WBL contract.

15 MSS-2 COSTS Q. WHAT ARE MSS-2 COSTS?

17 A. Under the ESA's Service Schedule MSS-2, the EOCs share cost 18 responsibility for the Entergy transmission system much like they share 19 cost responsibility for generating resources under Service Schedule MSS- 20 1. Each month an EOC receives a payment or bill for System transmission 21 costs based on the EOC's level of transmission investment relative to total 22 System transmission investments, its load responsibility ratio, and the 23 average cost of total System investments.

Docket No. 39896 Dennis W. Goins - Direct Page 19 Q. WHAT LEVEL OF MSS-2 COSTS HAS ETI PROPOSED TO 2 INCLUDE IN BASE RATES IN THIS CASE?

3 A. ETI has proposed including almost of rate-year MSS-2 costs 4 in base rates.

5 Q. IS ETI'S PROPOSED LEVEL OF MSS-2 COSTS SIGNIFICANTLY 6 GREATER THAN ITS TEST-YEAR MSS-2 COSTS?

7 A. Yes. ETI' s projected rate-year MSS-2 costs are more than 8 actual test-year MSS-2 costs ($1.8 million).

9 Q. DID ETI PROVIDE DETAILS REGARDING WHY ITS RATE- 10 YEAR MSS-2 COSTS ARE EXPECTED TO GROW SO MUCH?

11 A. No. ETI provided workpapers supporting its rate-year MSS-2 cost 12 projection, 12 but did not provide details explaining the

14 Q. DID ETI ADJUST ITS PROJECTED RA TE-YEAR MSS-2 COSTS 15 TO REFLECT CHANGES IN BILLING AND TRANSMISSION 16 INVESTMENTS THAT MAY ARISE WHEN THE 17 DIVESTITURE/MERGER OF ENTERGY'S TRANSMISSION 18 ASSETS INTO ITC IS COMPLETED IN 2013?

19 A. No. ETI's MSS-2 cost projections assume business-as-usual even though 20 Entergy will no longer be sole owner of transmission assets used to deliver 21 power and energy to its EOCs following the proposed divestiture/merger.

22 This calls into question the future applicability of Service Schedule MSS-2 23 to the EOCs, and the reasonableness of ETI's MSS-2 rate-year 24 projection-a conclusion indirectly supported by ETI. For example, 25 during his deposition, ETI witness Phillip May acknowledged that if the 26 divestiture/merger takes place as planned, ETI's MSS-2 costs would be

Docket No. 39896 Dennis W. Goins - Direct Page 20 zero. 13 In general, the pending divestiture/merger makes ETI's MSS-2 cost 2 projections problematic.

3 Q. IS THERE AN ADDITIONAL PROBLEM WITH ETI'S ADJUSTED 4 TEST-YEAR MSS-2 COSTS?

5 A. Ycs. Including ETI's MSS-2 rate-year costs in base rates creates the same 6 problem that I discussed with respect to ETI's rate-year PPCC.

7 Specifically, using base rates that reflect test-year billing determinants to 8 recover projected rate-year MSS-2 costs guarantees ovcrrecovery if rate- 9 year billing units exceed test-year billing units-that is, if ETI's load 10 grows.

11 Q. HOW SHOULD ETl'S RATE-YEAR MSS-2 COSTS BE ADJUSTED 12 TO ADDRESS THESE ISSUES?

13 A. I recommend a 2-step approach: 14 II Because of the pending divestiture/merger of Entergy' s 15 transmission assets, limit MSS-2 costs included in base rates 16 to no more than actual MSS-2 costs incurred in the most 17 recent 12 months. This modification also addresses the 18 of ETI's MSS-2 costs.

19 II Adjust the modified post-test year MSS-2 cost estimate for 20 load growth in a manner similar to the approach I used in 21 adjusting rate-year purchased power capacity costs.

See ETI's response to Cities 5-3.a.

See the transcript of the March 6, 2012, deposition of ETI witness Phillip R. May at 43: 10.

Docket No. 39896 Dennis W. Goins - Direct Page 21 Q. HA VE YOU DEVELOPED AN ADJUSTED TEST-YEAR 2 ESTIMATE OF MSS-2 COSTS THAT SHOULD BE INCLUDED IN 3 BASE RATES?

4 A. Yes. As shown in Exhibit DWG-4, the level of adjusted test-year MSS-2 5 costs included in base rates should not exceed $4.1 million. This value 6 reflects ETI's actual annual MSS-2 costs through December 2011, and a 7 load growth adjustment.

8 STREET LIGHTING AND 9 TRAFFIC SIGNAL RATES Q. DID YOU REVIEW ETI'S STREET LIGHTING AND TRAFFIC 11 SIGNAL RATES?

12 A. Yes. ETI's principal rate schedule for street lighting customers is 13 Schedule SHL, while Schedule TSS is the principal rate schedule for ETI's 14 traffic lighting customers that own and maintain their lighting facilities.

15 Q. IS SERVICE UNDER SCHEDULE SHL UNIFORM FOR ALL 16 STREET LIGHTING CUSTOMERS?

17 A. No. The rate includes four categories of service (Rate Groups A, C, D, 18 and E). Rate Group A includes ETI's standard fixture and lamps mounted 19 on existing standard wood poles that ETI installs and maintains. If a 20 customer wants nonstandard lighting facilities (those not provided in Rate 21 Group A), the customer is assigned to Rate Group C and required to 22 prepay ETI for the incremental cost of the nonstandard facilities. Lighting 23 facilities that are customer-owned and customer-maintained are assigned 24 to Rate Group D, while incidental lighting services (for example, 25 underpass lighting) are assigned to Rate Group E.

Docket No. 39896 Dennis W. Goins - Direct Page 22 Q. DO CHARGES VARY BY CATEGORY OF SERVICE IN 2 SCHEDULE SHL?

3 A. Yes. Customers in Rate Groups A and C pay a fixed monthly charge per 4 lighting fixture, while customers in Rate Groups D and E pay a fixed (and 5 identical) energy charge per kWh. Each customer's monthly bill also 6 includes charges for ETI's fixed fuel factor (Schedule FF) and applicable 7 riders applied to monthly kWh per fixture.

8 Q. WHAT TYPES OF CHARGES ARE APPLICABLE UNDER 9 SCHEDULE TSS?

10 A. Traffic signal customers pay a fixed monthly charge ($3 .20 proposed) per 11 point of delivery, plus a fixed kWh rate and all applicable rider charges.

12 Q. DO ETI'S LIGHTING RATES INCORPORATE ANY SPECIAL 13 SERVICE OR PRICING PROVISIONS FOR NEW ENERGY- 14 EFFICIENT LIGHTING TECHNOLOGIES-FOR EXAMPLE, 15 LED FIXTURES?

16 A. No. The basic structure and pricing provisions of the SHL and TSS rates 17 have been in place for years. The rates were designed for lighting fixtures 18 that use older, less energy-efficient bulb technology.

19 Q. DID ETI CONDUCT A DETAILED COST ANALYSIS IN 20 DEVELOPING PROPOSED CHARGES FOR STREET LIGHTING 21 AND TRAFFIC SIGNAL CUSTOMERS?

22 A. I have seen no evidence that ETI conducted such an analysis. Moreover, 23 in this case, ETI did not conduct any analyses to estimate the cost 24 differential of serving street lighting and traffic signal customers that use 25 energy-efficient LED fixtures.

Docket No. 39896 Dennis W. Goins - Direct Page 23 Q. HOW DID ETI ADJUST PROPOSED PRICES IN ITS LIGHTING 2 RATES IN THIS CASE?

3 A. ETI applied a unifonn percentage increase to the kWh and fixed charges in 4 Schedule SHL. In Schedule TSS, ETI left the fixed monthly charge per 5 delivery point unchanged, but reduced the kWh charge to reflect its 6 proposal to recover PPCC through a rider. (This latter change will be 7 reversed to reflect the Commission's ruling in this case regarding recovery 8 of PPCC in base rates.)

9 Q. WHY ARE LED FIXTURES AN ATTRACTIVE LIGHTING 10 OPTION FOR MUNICIPALITIES?

11 A. The cost of street and traffic lighting services can be significant for many 12 cities and towns. As government agencies face increasing pressure to 13 control budgets, municipalities are increasingly looking at energy-efficient 14 lighting options such as LED fixtures to provide an ongoing, long-term 15 reduction in operating costs. LED fixtures use significantly less energy 16 than incandescent and most other lighting options, last longer, and may 17 require less maintenance (for example, fewer bulb replacements).

18 Q. HA VE ANY OF THE CITIES ADOPTED LED LIGHTING AS A 19 WAY TO REDUCE THEIR OPERATING COSTS?

20 A. Yes. Counsel has informed me that at least one of the Cities has an 21 ongoing program to replace incandescent fixtures with LED options, and 22 several others are actively considering moving to LED lighting.

23 Q. WOULD WIDESPREAD ADOPTION OF LED LIGHTING RATES 24 HELP REDUCE ENERGY CONSUMPTION IN TEXAS?

25 A. Yes. Such rates would encourage municipalities to adopt energy-efficient 26 LED options, and help offset the high front-end cost of LED lights.

Docket No. 39896 Dennis W. Goins - Direct Page 24 Q. HAVE MOST UTILITIES IMPLEMENTED LIGHTING RATES 2 THAT REFLECT THE LOWER COST OF OPERATING LED 3 FIXTURES?

4 A. No. I reviewed street lighting and traffic signal rates offered by a number 5 of utilities. Although some of them have implemented LED rates, most 6 utilities have not updated their rates to reflect the lower operating and 7 maintenance cost of serving energy-efficient LED fixtures.

8 Q. DOES ANY UTILITY IN TEXAS HAVE AN LED LIGHTING 9 OPTION?

10 A. Yes. In 2010 the Commission approved a street and traffic signal rate for 11 El Paso Electric (Docket No. 37690) that included separate charges for 12 LED traffic signals. (See Exhibit DWG-5.) The fixed monthly rate for 13 LED signals is generally less than one-third the comparable rate for 14 incandescent signals.

15 Q. SHOULD THE COMMISSION REQUIRE ETI TO INCLUDE AN 16 LED OPTION IN ITS SHL AND TSS RATES?

17 A. Yes. ETI should offer an LED option in these rates to encourage energy 18 efficiency investments and promote conservation. To facilitate these 19 goals, the Commission should require ETI to modify monthly fixed 20 charges in Schedule SHL (Rate Groups A and C) and TSS to reflect a 25- 21 percent discount for LED installations. The discounted Rate Group A 22 fixed charges (if applicable) in Schedule SHL should be applied according 23 to the estimated monthly kWh consumption of the installed LED fixture.

24 In addition, I recommended reducing by 25 percent the Schedule SHL 25 kWh charges applicable to LED customers assigned to Rate Groups D and 26 E to reflect the lower cost of operating and maintaining LED fixtures. In 27 the future, ETI should be required to provide detailed information

Docket No. 39896 Dennis W. Goins - Direct Page 25 regarding differences in the cost of serving LED and non-LED lighting 2 customers.

3 Q. HAVE YOU IDENTIFIED ANY OTHER CHANGES THAT 4 SHOULD BE MADE IN ETl'S PROPOSED LIGHTING RATES?

5 A. Yes. The Commission should require ETI to eliminate the service 6 condition applicable to Rate Groups A and C in Schedule SHL that 7 charges a $50 fee for any replacement of a functioning light with a lower- 8 wattage bulb. This fee actively discourages customers from adopting more 9 energy-efficient lighting technologies (for example, LED devices), and is 10 not supported in ETI' s filing. The Commission should get rid of this 11 barrier to conservation and efficiency improvements.

12 Q. DOES THIS COMPLETE YOUR DIRECT TESTIMONY?

13 A. Yes.

Docket No. 39896 Dennis W. Goins - Direct Page 26 Exhibit DWG-1 Page 1 of 1

Jurisdictional Separation: Demand-Related Production Costs - 12CP

12CP kW 12CP Class of Service at Plant Factor (a) (b) (c) Residential 1,240,632 43.4768% Small General Service 57,554 2.0169% General Service 531, 108 18.6122% Large General Service 212, 129 7.4339% Large Industrial Power Service 654,652 22.9417% Roadway Lighting 1,633 0.0572% Non-Roadway Lighting 2,345 0.0822% Total Texas Retail 2,700,053 94.6208% Wholesale For Resale 153,498 5.3792% Wheeling 0 0.0000% Total Texas Wholesale 153,498 5.3792% Total ETI 2,853,551 100.0000%

Source: Schedule P-7.2, pages 21-22, and ETl's response to TIEC 1-38 Highly Sensitive.

Blank Page Exhibit DWG-2 Redacted Highly Sensitive Blank Page Exhibit DWG-3 Redacted Highly Sensitive Blank Page Exhibit DWG-4 Redacted Highly Sensitive Blank Page EXHIBIT DWG-5

EL PASO ELECTRIC'S SCHEDULE NO. 08- GOVERNMENT STREET LIGHTING AND SIGNAL SERVICE RATE Blank Page EL PASO ELECTRIC COMPANY SCHEDULE NO. 08 GOVERNMENTAL STREET LIGHTING AND SIGNAL SERVICE RATE APPLICABILITY This rate is availabie to any village, town, city, county, state of Texas and Federal facilities for Mercury Vapor and High Pressure Sodium Vapor street light, freeway lighting and for traffic signal lights.

TERRITORY Texas Service Area MONTHLY RATE Street Lights MERCURY VAPOR-OVERHEAD SYSTEM-COMPANY OWNED FOOT MOUNTING HEIGHT - WOOD POLE ·k - Total Per Lamp Wattage Charge 175W - 7,000 Lumen Single ,__________~-· 195 $15.22 250W - 11,000 Lumen Single 275 $18.26 - 400W - 20,000 Lumen Single 460 $21.66 400W - 20,000 Lumen Double 920 $35.i9

HIGH PRESSURE SODIUM VAPOR - DOWNTOWN EL PASO AREA- COMPANY OWNED STEEL BASE STANDARD AND LUM1NA1RE Total Per Lamp Wattage Charge 1,000W -119,500 Lumen Overhead System 1,102 $54.81 1,000W - 119,500 Lumen Underground System 1,102 $89.45

H1GH PRESSURE SODIUM VAPOR- DOWNTOWN EL PASO AREA- COMPANY OWNED STEEL BASE STANDARD AND LUM!NAIRE Total Per Lamp Wattage Charge 450W - 50,000 Lumen Overhead System 485 $47.87 * Refer to Mercury Vapor Closed to New Installations and Conversiin/Replacement of Existing Installations section of the tariff. • UB!.IC UTILITY COMMISSION Of TEXAS . . ·· . ··· APPROVED JUL 3D'10 DOCKET CONTROL#.

Section Number_ _ __,_1_ _ _ __ Revision Number 20 ---- SheetNumber~~~--'-7-~~~­ Effective for consumQt!on on or Page~~~-~~-l~o_f~8~~~- after July 1, 2010 El PASO ELECTRIC COMPANY SCHEDULE NO. 08 GOVERNMENTAL STREET LIGHTING AND SIGNAL SERVICE RATE MERCURY VAPOR - OVERHEAD SYSTEM - COMPANY OWNED FOOT MOUNTING HEIGHT-STEEL POLE* Total Per Lamp ~· Wattage Charge 400W - 20,000 Lumen Single 460 $33.46 400W - 20,000 Lumen Double 920 $46.99

MERCURY VAPOR - NON-COMPANY OWNED SYSTEMS - INTERSTATE OR FREEWAY LIGHTING* Total Per Lamp Wattage Charge 250W - i 1,000 Lumen - Wall Mounted 292 $8.78 400W - 20,000 Lumen - 40 Foot Maximum Mounting Height 460 $12.08 1_,000W - 60,000 Lumen - 50 Foot Maximum Mounting Heigb_t__ 1, 102 $31.67

MERCURY VAPOR - NON-COMPANY OWNED - WOOD POLE UNDERGROUND OR OVERHEAD RESIDENTIAL SERViCE " -- Total Per Lamp Wattaoe Charqe 175W - 7,000 Lumen - 35 Foot Maximum Mounting Height 195 $6.68 * Refer to Mercury Vapor Closed to New Installations and Conversion/Replacement of Existing Installations section of the tariff.

HIGH PRESSURE SODIUM VAPOR - NON-COMPANY OWNED SYSTEMS INTERSTATE OR FREEWAY LIGHTING - Total Per Lamp Wattaqe Charqe 150W - 16,000 Lumen - Wall Mounted 193 $7.00 250W - 23,200 Lumen - Waif ~ounted 313 $9.42 250W • 23,200 Lumen - 40 Foot Maximum Mountinq Heiqht 313 $9.42 400'{1! - 50,000 Lumen - 50 Foot Maximum MountinQ Heiqht 485 $12.95 400W - 50,000 Lumen - Tower Structure 150 Foot-Climbing 485 $13.67 Maximum Mounting Height Luminaires per Tower PUB' !C UTiLJTY Cb;\:'.\ 1'.~S'.SlGN C , TEX.AS P~Ff ';1 Rate per fixture JUL 3 o~rn [)( f:'/'.7 ..._~n; .. l 'Z 7 ;.JI 690 CONTflOLil Section Number 1 ~~~---~~~~ Revision Number 20 ~~-------=--~~~~- Sheet Number 7~~~~~~~~~ Effective for consumption on or Page~~~~~~=2~o~f8,,,__~~~- after July 1, 201 O EL PASO ELECTRIC COMPANY SCHEDULE NO. 08 GOVERNMENTAL STREET LIGHTING AND SIGNAL SERVICE RATE 400W - 50,000 Lumen - Tower Structure 150 Foot-Lowering 485 $12.79 Maximum Mounting Height Luminaires per Tower Rate per fixture >---- - 116W - Obstruction Lights Incandescent 40 Foot Maximum 116 $4.47 Mounting Height 116W -150 Foot Tower ..116 $5.35

HIGH PRESSURE SODIUM VAPOR-NON-COMPANY OWNED SYSTEMS LARGE ARTERIAL LIGHTING Total Per Lamp Wattage Charg~ 150W-16,000 Lumen Wall Mounted 193 $7.11 250W - 23,?00 Lumen Wall Mounted 313 $10.24 250W -23,200 Lumen 40 FT Maximum Mounting Height 313 $10.24 ~OW - 50,000 Lumen 50 FT Maximum Mounting Height 485 $14.73

HIGH PRESSURE SODIUM VAPOR - NON-COMPANY OWNED WOOD/STEEL POLE UG OR OH STANDARD RESIDENTIAL SERVICE Total Per Lamp Wattage Charge OOW - 8,500 Lumen - 30 Foot Maximum Mounting Height 124 - $5.32 150W - 14,400 Lumen - 30 Foot Maximum Mounting Height 193 $6.21 250W - 23,200 Lumen - 30 Foot Maximum Mounting Height 313 $9.59

HIGH PRESSURE SODIUM VAPOR - OVERHEAD - NON-COMPANY OWNED FIXTURE- COMPANY OWNED EXISTING WOOD POLE (DISTRIBUTION OR STREET LIGHT CF or Dl Total Per Lamp WattaQe Charge OOW - 8,500 Lumen - 35 Foot Maximum Mounting Heii:iht 124 $7.43 · 150W - 14~190 Lumen - 35 Foot Maximum Mounting Height 193 $8.99 250W - 23,200 Lumen - 35 Foot Maximum Mounting Height 313 $11.41 250W - 23,200 Lumen - Double 35 Foot Maximum Mounting 626 $18.65 Heiqht 450W - 50,QOO Lumen - 50 Foot Maximum Mounting Height 485 $14.06

37690 Section Number 1 ~~~~~~~~- Revision Number OONJmt # Sheet Numb e r~~~--'-7~~~~~ Effective for consumption on or Page~~~~~~~3~o~f~8~~~~ after July 1, 2010 EL PASO ELECTRIC COMPANY SCHEDULE NO. 08 GOVERNMENTAL STREET LIGHTING AND SIGNAL SERVICE RATE

OVERHEAD SYSTEM - HIGH PRESSURE SODIUM VAPOR COMPANY OWNED - WOOD POLE - Total Perla~ ' Wattage Charg_E?

ORNAMENTAL HIGH PRESSURE SODIUM VAPOR - NON-COMPANY OWNED, OPERATED AND MAINTAINED -· Total Per Lamp Wattage Charge ?OW - 5,300 Lumen 82 $1.67 150W -1_4,400 Lumen 193 $3.04 175W- 14,400 Lumen 250W - 16,000 Lumen $6.65 $3.94 j HIGH PRESSURE SODIUM VAPOR- ROADWAY ILLUMINATION- NON COMPANY OWNED Total Per Lamp Watta_qe Cha roe 100W- HPS 124 $2.04 150W- HPS 193 $5.02 250W-HPS >----· 313 $5.08 400W- HPS 485 $13.48 l"iJ!:>UG UTiUTY COMMi0,~1;;' MONTHLY RA TE JUL 3 0 ' 1'0 DOCKET 3 769 Q Traffic Signal Lights .----~~-~~~,~~~· INCANDESCENT TRAFFIC SfGNALS Wattage of on y Type and Hours Incandescent Rate Of 0 eration Lam Per Unit Hours 61 $1.24 Hours 61 - - ' - - '$1.24 ----'

Section Number 1 ~--....._~~~~ Revision Number_ ____,,2=0_ _ _ __ Sheet Number 7 ~-~--'--~~~~ Effective for consumption on or Page~-~~-~~4~o~f8;..._~~~- after July 1. 2010 EL PASO ELECTRIC COMPANY SCHEDULE NO. 08 GOVERNMENTAL STREET LIGHTING ANO SIGNAL SERVICE RATE ~Lame Head 24 Hours 103 $2.09 Lamp Head 18 Hours Normal, 6 Hours Flashing 103 $2.09 Lamp Head 24 Hours 133 $2.72 Lamp Head 18 Hours Normal, 6 Hours Flashing 103 $2.09 Lamp Head 24 Hours 133 $2.72 Lame Head 18 Hours Normal, 6 Hours Flashinq 133 $2.72 Lamp Head 24 Hours 133 $2.72 ~J-ame Head 18 Hours Normal, 6 Hours Flashing 133 $2.72 Unit Walk Light 24 Hours 61 $1.24 Unit Walk Lh::iht 24 Hours 103 $2.09 Unit Walk Light 18 Hours Normal, 6 Hours Flashinq 103 $2.09 - ~

1 Unit Flashing 24 Hours 103 $2.09 ' Unit Flashing 24 Hours 133 $2.72 Unit Flashinq 24 Hours 103 $2.09 Unit School Flashers 351 Annual Burning Hours ·>-~ 103 - $2.09 Unit School Flashers 790 Annual Burninq Hours 133 $2.72 Watt Controller 24 Hours 30 $0.61 -- 100 Watt Controller 24 Hours ··-~..I ..

100 $2.60

LIGHT-EMITTING DIODE ("LED") TRAFFIC SIGNALS ~· - Wattage of High- Monthly Type and Hours Efficiency Rate Type of Unit Of Operation LED Lamp Per Unit Lamp Head 18 Hours Normal, 6 Hours Flashing 14 $0.34 Lamp Head 24 Hours 14 $0.6 Lamp Head 18 Hours Normal, 6 Hours Flashinq 14 $0.~ Lamp Head 24 Hours 14 $0.3 Lamp Head 18 Hours Normal, 6 Hours Flashing 14 $0.~ Lamp Head 24 Hours 14 $0.69;; --· Lamp Head 18 Hours Normal, 6 Hours Flashing 14 $0.6~) .~,· Unit Walk Liqht 24 Hours 9 $0.2$b Unit Walk Light 18 Hours Normal, 6 Hours Flashing 9 $0 23'.5 ~:: ......... 1••

i Unit Flashing 24 Hours 14 $0.18>,:: 1 ;, Unit Flashing 24 Hours 14 $0.352 Unit School Flashers 351 Annual Burning Hours 14 $0.28::.:1 Unit School Flashers 790 Annual Burning Hours 14 $0.28 :s Unit School Flashers 351 Annual Burning Hours -- 14 $0.69 ';:' Unit School Flashers 790 Annua! Burning Hours 14 $0.69 -

Section Number 1 Revision Number_ _~2_0_ _ _ _ __ ~~--~-~-- Sheet Number_ _ ___.;.?_ _ _ __ Effective for consumption on or Page~~---~~5~o~f~8----~~- after July 1, 2010 PU8UC UTlUT' Q;:: TEXfJ EL PASO ELECTRIC COMPANY SCHEDULE NO. 08 JUL 3 0 10 DOCl\\:T 3 7690 GOVERNMENTAL STREET LIGHTING AND SIGNAL SERVICE RATE MONTHLY RATE PER UNIT Street lights and traffic signal lights that do not operate under any of the preceding conditions will be billed under the rate with the closest operating conditions.

MERCURY VAPOR CLOSED TO NEW INSTALLATIONS AND CONVERSION/REPLACEMENT OF EXISTING INSTALLATIONS Mercury Vapor lamp categories are closed to new installations. The Company wit! continue to maintain existing Mercury Vapor installations and will, at the Company's option, install High Pressure Sodium Vapor ballasts in place of defective non-repairable Mercury Vapor ballasts. Customers with existing fixtures which are defective and must be replaced will have the option to convert its service to high pressure sodium vapor lamps or may cancel service at no cost.

Mercury Vapor Fixture Replacement Schedule For Company owned lights, when existing mercury vapor fixtures require replacement, the Company will make such replacements with comparable high pressure sodrum vapor lighi1ng at no cost, as specified below: Mercury Vapor - Overhead System - Company Owned, Foot Mounting Height - Wood Pol~----~----~ r Existing Mercury Vapor Lighting: High Pressure Sodium Vapor Replacement: Wattaqe Lu mens kWh Wattage Lu mens kWh 195 7,000 70 124 8,500 44 275 1 i ,000 98 193 14,400 69 460 20,000 164 313 23,200 112 920 20,0000 328 313* 23,200 112 Mercury Vapor - Overhead System - Company Owned, Existing Mercury Vapor Lighting: - . ht Stee I Poe F00t M oun fmg He1g I High Pressure Sodium Vapor Replacement: Wattage Lu mens kWh Wattage Lu mens kWh 460 20,000 164 313 23,200 112 920 20,0000 328 313* 23,200 112 ·-- *O=Double - Mercury Vapor with double lamps on a single pole will be converted to two separate poles with a Single High Pressure Sodium Vapor lamp each.

For Non-Company owned lights, upon the request of the Customer, the Company will convert or replace facilities with the high pressure sodium vapor lighting options listed below, at an amount equal to all applicable costs of such conversion or replacement.

Section Number 1 ~~~----~~~~~ Revision Number_ _~2~0_ _ _ _ __ SheetNumber~~~~~7~~~-~ Effective for consumption on or Page_~~~~~-6""--"o~f=8~--~ after July 1, 2010 EL PASO ELECTRIC COMPANY SCHEDULE NO. 08 GOVERNMENTAL STREET LIGHTING AND SIGNAL SERVICE RATE

Mercury vaeor - Non-Company 0 wned Systems -Interstate or Freewav L"lg ht mg I Existing M~ury Vaeor Lighting: High Pressure Sodium Vapor Replacement: Wattage Lu mens kWh Wattage Lu mens kWh 292 11,000 104 193 16,000 69 ~

460 20,000 164 313 23,200 112 1102 60,000 393 485 45,000 173

lacement: kWh At the time of the replacement, the Customer wlll be billed at the applicable rate charge and associated kWh usage for the high pressure sodium vapor replacement lighting.

Mercury Vapor Fixture Conversion Or Replacement Of Existing Facilities Upon the request of the Customer, the Company will convert or replace existing Company owned mercury vapor lighting to applicable Company offered street lighting options other than those indicated above.

Upon the request of and payment by the Customer, the Company will convert existing Company owned facilities (size or type of luminaire) to a different applicable Company offered size or type of luminaire at an amount equal to ail applicable costs less the salvage value of the existing facilities. (./') -5 0 GI !- 0' Upon the request of and payment by the Customer, the Company will replace existing ~!... ....0 c:i f'-..

Company owned lighting facilities at an amount equal to all applicable costs less the ;;;:;;;: !'t'\ C) salvage value of the existing facilities. Installation of new facilities requested by the ('/iD Customer will be performed pursuant to the applicable Schedule and lamp category f!'2 ~~ l-

,,~~~ u.1 described above. ~---"' ..... .,~ ~ 0__, CS~~ 11· Cl ~ FIXED FUEL FACTOR r::< :::i _! c:::> tiC The above rates are subject to the provisions of the Company's Tariff Schedule No. 98 § ;:--- I- entitled Fixed Fuel Factor. S.1! 0 z. s """' --' ENERGY EFFICIENCY COST RECOVERY FACTOR fr ::::=> ~

The above rates are subject to the provisions of the Company's Tariff Schedule No. 97, entitled Energy Efficiency Cost Recovery Factor.

Section Number____1-'------- Revision Number~-~~~--~~ 20 Sheet Number~---"'--~-~-- 7 Effective for consumption on or Pa ge_ _ _ _~--7~o_f_8_ _~~- after July 1, 2010 EL PASO ELECTRIC COMPANY SCHEDULE NO. 08 GOVERNMENTAL STREET LIGHTING AND SIGNAL SERVICE RATE MILITARY BASE DISCOUNT RECOVERY FACTOR The above rates are subject to the provisions of the Company's Tariff Schedule No. 96, entitled Military Base Discount Recovery Factor.

TERMS OF PAYMENT The due date of the bill for utility service shall not be less than sixteen (16) days after issuance. A bill becomes delinquent if not received at the Company by the due date.

TERMS AND CONDITIONS The Company's Rules and Regulations apply to service under this rate schedule.

Specific terms are as covered in various written agreements.

JUL 3 0 '10 DOC!<ET 7690 CONTFIOL# ----- Section Number____1.,___ _ _ __ Revision Number_ _---'2=0"------- SheetNurnber_ _ _ _7 ' - - - - - - - Effective for consumption on or Page~-------"-8~o~f~8---~ after July 1, 201 O APPENDIX

QUALIFICATIONS OF

DENNIS W. GOINS Blank Page DENNIS W. GOINS

PRESENT POSITION Economic Consultant, Potomac Management Group, Alexandria, VA PREVIOUS POSITIONS 11111 Vice President, Hagler, Bailly & Company, Washington, DC iii Principal, Resource Consulting Group, Inc., Cambridge, MA 111 Senior Associate, Resource Planning Associates, Inc., Cambridge, MA iii Economist, North Carolina Utilities Commission, Raleigh, NC EDUCATION College Major Degree Wake Forest University Economics BA North Carolina State University Economics ME North Carolina State University Economics PhD

RELEVANT EXPERIENCE Dr. Goins specializes in pricing, planning, and market structure issues affecting firms that buy and sell products in electricity and natural gas markets. He has extensive experience in evaluating competitive market conditions, analyzing power and fuel requirements, prices, market operations, and transactions, developing product pricing strategies, setting rates for energy-related products and services, and negotiating power supply and natural gas contracts for private and public entities. He has participated in more than 150 cases as an expert on competitive market issues, utility restructuring, power market planning and operations, utility mergers, rate design, cost of service, and management prudence before the Federal Energy Regulatory Commission, the General Accounting Office (now the Government Accountability Office), the First Judicial District Court of Montana, the Circuit Court of Kanawha County, West Virginia, the Linn County District Court of Iowa, and regulatory commissions in Alabama, Arizona, Arkansas, Colorado, Florida, Georgia, Hawaii, Idaho, Illinois, Indiana, Kansas, Kentucky, Louisiana, Maine, Maryland, Massachusetts, Minnesota, Mississippi, Missouri, New Jersey, New York, North Carolina, Ohio, Oklahoma, South Carolina, Texas, Utah, Vermont, Virginia, West Virginia, Wyoming, and the District of Columbia. He has also prepared an expert report on behalf of the Dennis W. Goins United States regarding pricing and contract issues in a case before the United States Court of Federal Claims.

PARTICIPATION IN REGULATORY, ADMINISTRATIVE, AND COURT PROCEEDINGS 1. Potomac Electric Power Company, before the Maryland Public Service Commission, Case No. 9286 (2012), on behalf of the General Services Administration, re retail cost recovery.

2. Indiana Michigan Power Company, before the Indiana Utility Regulatory Commission, Cause No. 44075 (2012), on behalf of Steel Dynamics, Inc., re retail cost-of-service and fuel and purchased power cost recovery.

3. Entergy Texas, Inc., before the Public Utilities Commission of Texas, PUC Docket No. 39896 (2012), on behalf of Texas Cities, re cost of service and retail rate design.

4. Potomac Electric Power Company, before the District of Columbia Public Service Commission, Formal Case No. 1087 (2012), on behalf of the General Services Administration, re retail cost recovery.

5. Dominion North Carolina Power, before the North Carolina Utilities Commission, Docket No. E-22, Sub 474 (2011), on behalf of Nucor Steel- Hertford, re fuel rate adjustments.

6. Mid-Kansas Electric Company, before the Kansas Corporation Commission, Docket No. 1 l-GIME-597-GIE (2011),on behalf of Kansas Electric Power Cooperative, Inc., re local delivery service and operating agreements.

7. Duke Energy Corporation et al., before the Federal Energy Regulatory Commission, Docket No. ECI 1-60-000 (2011), on behalf of the North Carolina Electric Membership Corporation, re merger-related market power issues.

8. Resale Power Group of Iowa et al., before the Linn County District Court of Iowa, Case No. LACV 054271 (2011), on behalf of Central Iowa Power Cooperative, re compensation for unauthorized transmission access.

9. Columbus Southern Power Company et al., before the Public Utilities Commission of Ohio, Case No. 11-346-EL-SSO et al., (2011), on behalf of the OMA Energy Group., re standard service offer electric security plan rate design issues.

Dennis W. Goins I 0. Appalachian Power Company and Wheeling Power Company, dba American Electric Power, before the Public Service Commission of West Virginia, Case No. 11-0274-E-GI (2011), on behalf of Steel of West Virginia, Inc., re expanded net energy cost rate issues.

11. Rocky Mountain Power Company, before the Wyoming Public Service Commission, Docket No. 20000-384-ER-10 (2011), on behalf of Cimarex Energy Company, QEP Field Services Company, and Kinder Morgan Interstate Gas Transmission, re utility rates, cost-of-service, and resource acquisition issues.

12. Duke Energy Indiana, Inc., before the Indiana Utility Regulatory Commission, Cause No. 43955 (2011 ), on behalf of Nucor Steel and Steel Dynamics, Inc., re utility-sponsored energy efficiency programs.

13. Kansas City Power & Light Company, before the Missouri Public Service Commission, Case No. ER-2010-0355 (2010), on behalf of the U.S. Department of Energy (Federal Executive Agencies), re cost-of-service and rate design issues.

14. Appalachian Power Company and Wheeling Power Company, dba American Electric Power, before the Public Service Commission of West Virginia, Case No. 10-0699-E-42T (2010), on behalf of Steel of West Virginia, Inc., re cost-of-service and rate design issues.

15. Entergy Arkansas, Inc., before the Arkansas Public Service Commission, Docket No. 10-010-U (2010), on behalf of Arkansas Electric Energy Consumers, Inc., re industrial opt out of utility-sponsored energy efficiency programs.

16. Indiana Michigan Power Company, before the Indiana Utility Regulatory Commission, Cause No. 38702 - FAC 62-Sl (2010), on behalf of Steel Dynamics, Inc., re fuel and purchased power cost recovery.

17. Dominion North Carolina Power, before the North Carolina Utilities Commission, Docket No. E-22, Sub 459 (2010), on behalf of Nucor Steel- Hertford, re cost of service and retail rate design.

18. Dominion North Carolina Power, before the North Carolina Utilities Commission, Docket No. E-22, Sub 461 (2010), on behalf of Nucor Stcel- Hertford, re fuel rate adjustments.

19. Entergy Texas, Inc., before the Public Utilities Commission of Texas, PUC Docket No. 37744 (2010), on behalf of Texas Cities, re cost of service and retail rate design.

20. Kentucky Utilities, Inc., before the Kentucky Public Service Commission, Case No. 2009-00548 (2010), on behalf of the Kentucky Industrial Utility Customers, re interruptible rates.

Dennis W. Goins 21. Louisville Gas and Electric Company, Inc., before the Kentucky Public Service Commission, Case No. 2009-00549 (2010), on behalf of the Kentucky Industrial Utility Customers, re interruptible rates.

22. Ohio Edison et al., before the Public Utilities Commission of Ohio, Case No. 09-1948-EL-POR et al., (2010), on behalf of Nucor Steel Marion, Inc., re energy efficiency and peak demand reduction portfolios.

23. Kauai Island Utility Cooperative, before the Hawaii Public Utilities Commission, Docket No. 2009-0050 (2010), on behalf of Kauai Marriott Resort & Beach Club, re retail cost allocation and rate design issues.

24. Entergy Arkansas, Inc., before the Arkansas Public Service Commission, Docket No. 09-024-U (2009), on behalf of Arkansas Electric Energy Consumers, Inc., re power plant environmental retrofit.

25. Appalachian Power Company, before the Virginia State Corporation Commission, Case No. PUE-2009-00030 (2009), on behalf of Steel Dynamics, Inc., re retail cost allocation and rate design issues.

26. Ohio Edison et al., before the Public Utilities Commission of Ohio, Case No. 09-906-EL-SSO (2009), on behalf of Nucor Steel Marion, Inc., re market rate offer.

27. Dominion North Carolina Power, before the North Carolina Utilities Commission, Docket No. E-22, Sub 456 (2009), on behalf of Nucor Steel- Hertford, re fuel cost adjustment.

28. Appalachian Power Company, before the Virginia State Corporation Commission, Case No. PUE-2009-00068 (2009), on behalf of Steel Dynamics, Inc., re demand response programs.

29. Indiana Michigan Power Company, before the Indiana Utility Regulatory Commission, Cause No. 43750 (2009), on behalf of Steel Dynamics, Inc., re wind power purchased power agreement.

30. Entergy Arkansas, Inc., before the Arkansas Public Service Commission, Docket No. 07-085-TF (2009), on behalf of Arkansas Electric Energy Consumers, Inc., re energy efficiency cost recovery.

31. CenterPoint Energy Arkansas Gas, before the Arkansas Public Service Commission, Docket No. 07-081-TF (2009), on behalf of Arkansas Gas Consumers, Inc., re energy efficiency cost recovery.

32. South Carolina Electric & Gas Company, before the South Carolina Public Service Commission, Docket No. 2009-261-E (2009), on behalf of CMC Steel-SC, re DSM cost recovery surcharge.

Dennis W. Goins 33. Duke Energy Indiana, Inc., before the Indiana Utility Regulatory Commission, Cause No. 38707 FAC81 (2009), on behalf of Steel Dynamics, Inc., re fuel and purchased power cost recovery.

34. Potomac Electric Power Company, before the District of Columbia Public Service Commission, Formal Case No. 1076 (2009), on behalf of the General Services Administration, re retail cost allocation and standby rate design issues for distributed generation resources.

35. Appalachian Power Company, before the Virginia State Corporation Commission, Case No. PUE-2009-00039 (2009), on behalf of Steel Dynamics, Inc., re environmental and reliability cost recovery.

36. Indiana Michigan Power Company, before the Indiana Utility Regulatory Commission, Cause No. 38702 - FAC 63 (2009), on behalf of Steel Dynamics, Inc., re fuel and purchased power cost recovery.

37. Appalachian Power Company, before the Virginia State Corporation Commission, Case No. PUE-2009-302-00038 (2009), on behalf of Steel Dynamics, Inc., re fuel and purchased power cost recovery.

38. South Carolina Electric & Gas Company, before the South Carolina Public Service Commission, Docket No. 2008-302-E (2008), on behalf of CMC Steel-SC, re fuel and purchased power cost recovery.

39. South Carolina Electric & Gas Company, before the South Carolina Public Service Commission, Docket No. 2008-196-E (2008), on behalf of CMC Steel-SC, re base load review order for a nuclear facility.

40. Ohio Edison et al., before the Public Utilities Commission of Ohio, Case No. 08-935-EL-SSO et al. (2008), on behalf of Nucor Steel Marion, Inc., re standard service offer via an electric security plan.

41. Ohio Edison et al., before the Public Utilities Commission of Ohio, Case No. 08-936-EL-SSO (2008), on behalf of Nucor Steel Marion, Inc., re market rate offer via a competitive bidding process.

42. Alabama Power Company, before the Alabama Public Service Commission, Docket No. 18148 (2008), on behalf of CMC Steel Alabama, Nucor Steel Birmingham, Inc., and Nucor Steel Tuscaloosa, Inc, re energy cost recovery.

43. Entergy Texas, Inc., before the Public Utilities Commission of Texas, PUC Docket No. 35269 (2008), on behalf of Texas Cities, re jurisdictional allocation of system agreement payments.

44. Duke Energy Indiana, Inc., before the Indiana Utility Regulatory Commission, Cause No. 43374 (2008), on behalf of Nucor Steel and Steel Dynamics, Inc., re alternative regulatory plan.

Dennis W. Goins 45. Entergy Gulf States Inc., before the Public Utilities Commission of Texas, PUC Docket No. 34800 (2008), on behalf of Texas Cities, re affiliate transactions.

46. Commonwealth Edison Company, before the Illinois Commerce Commission, Docket No. 07-0566 (2008), on behalf of Nucor Steel Kankakee, Inc., re cost-of-service and rate design issues.

47. Ohio Edison et al., before the Public Utilities Commission of Ohio, Case No. 07-0551-EL-AIR et al. (2008), on behalf of Nucor Steel Marion, Inc., re cost-of-service and rate design issues.

48. Appalachian Power Company dba American Electric Power, before the Public Service Commission of West Virginia, Case No. 06-0033-E-CN (2007), on behalf of Steel of West Virginia, Inc., re power plant cost recovery mechanism.

49. Oncor Electric Delivery Company and Texas Energy Future Holdings Limited Partnership, before the Public Utilities Commission of Texas, PUC Docket No. 34077 (2007), on behalf of Nucor Steel - Texas, re acquisition of TXU Corp. by Texas Energy Future Holdings Limited Partnership.

50. Arkansas Oklahoma Gas Company, before the Arkansas Public Service Commission, Docket No. 07-026-U (2007), on behalf of West Central Arkansas Gas Consumers, re gas cost-of-service and rate design issues.

51. Idaho Power Company, before the Idaho Public Utilities Commission, Case No. IPC-E-07-08 (2007), on behalf of the U.S. Department of Energy (Federal Executive Agencies), re cost-of-service and rate design issues.

52. Potomac Electric Power Company, before the District of Columbia Public Service Commission, Formal Case No. 1056 (2007), on behalf of the General Services Administration, re demand-side management and advanced metering programs.

53. South Carolina Electric & Gas Company, before the South Carolina Public Service Commission, Docket No. 2007-229-E (2007), on behalf of CMC Steel-SC, re cost-of-service and rate design issues.

54. Potomac Electric Power Company, before the Maryland Public Service Commission, Case No. 9092 (2007), on behalf of the General Services Administration, re retail cost allocation and standby rate design issues for distributed generation resources.

55. Potomac Electric Power Company, before the District of Columbia Public Service Commission, Formal Case No. 1053 (2007), on behalf of the General Services Administration, re retail cost allocation and standby rate design issues for distributed generation resources.

Dennis W. Goins 56. Entergy Gulf States Inc., before the Public Utilities Commission of Texas, PUC Docket No. 32907 (2006), on behalf of Texas Cities, re hurricane cost recovery.

57. Entergy Gulf States Inc., before the Public Utilities Commission of Texas, PUC Docket No. 32710/ SOAR Docket No. XXX-XX-XXXX (2006), on behalf of Texas Cities, re reconciliation of fuel and purchased power costs.

58. Florida Power & Light Company, before the Florida Public Service Commission, Docket No. 060001-EI (2006), on behalf of the U.S. Air Force (Federal Executive Agencies), re fuel and purchased power cost recovery.

59. Arizona Public Service Company, before the Arizona Corporation Commission, Docket No. E-01345A-05-0816 (2006), on behalf of the U.S. Air Force (Federal Executive Agencies), re retail cost allocation and rate design issues.

60. PacifiCorp (dba Rocky Mountain Power), before the Utah Public Service Commission, Docket No. 06-035-21 (2006), on behalf of the U.S. Air Force (Federal Executive Agencies), re rate design issues.

61. South Carolina Electric & Gas Company, before the South Carolina Public Service Commission, Docket No. 2006-2-E (2006), on behalf of CMC Steel-SC, re fuel and purchased power cost recovery.

62. Entergy Gulf States Inc., before the Public Utilities Commission of Texas, PUC Docket No. 31544/ SOAR Docket No. XXX-XX-XXXX (2006), on behalf of Texas Cities, re transition to competition rider.

63. Idaho Power Company, before the Idaho Public Utilities Commission, Case No. IPC-E-05-28 (2006), on behalf of the U.S. Department of Energy (Federal Executive Agencies), re cost-of-service and rate design issues.

64. Alabama Power Company, before the Alabama Public Service Commission, Docket No. 18148 (2005), on behalf of SMI Steel-Alabama, re energy cost recovery.

65. Florida Power & Light Company, before the Florida Public Service Commission, Docket No. 050001-EI (2005), on behalf of the U.S. Air Force (Federal Executive Agencies), re fuel and capacity cost recovery.

66. Entergy Gulf States Inc., before the Public Utilities Commission of Texas, PUC Docket No. 31315/ SOAR Docket No. XXX-XX-XXXX (2005), on behalf of Texas Cities, re incremental purchased capacity cost rider.

67. Florida Power & Light Company, before the Florida Public Service Commission, Docket No. 050045-EI (2005), on behalf of the U.S. Air Force (Federal Executive Agencies), re cost-of-service and interruptible rate issues.

Dennis W. Goins 68. Arkansas Electric Cooperative Corporation, before the Arkansas Public Service Commission, Docket No. 05-042-U (2005), on behalf of Nucor Steel and Nucor-Yamato Steel, re power plant purchase.

69. Arkansas Electric Cooperative Corporation, before the "Arkansas Public Service Commission, Docket No. 04-141-U (2005), on behalf of Nucor Steel and Nucor-Yamato Steel, re cost-of-service and rate design issues.

70. Dominion North Carolina Power, before the North Carolina Utilities Commission, Docket No. E-22, Sub 412 (2005), on behalf of Nucor Steel- Hertford, re cost-of-service and interruptible rate issues.

71. Public Service Company of Colorado, before the Colorado Public Utilities Commission, Docket No. 04S-164E (2004), on behalf of the U.S. Air Force (Federal Executive Agencies), re cost-of-service and interruptible rate issues.

72. CenterPoint Energy Houston Electric, LLC, et al., before the Public Utility Commission of Texas, PUC Docket No. 29526 (2004), on behalf of the Coalition of Commercial Ratepayers, re stranded cost true-up balances.

73. PacifiCorp, before the Utah Public Service Commission, Docket No. 04- 035-11 (2004), on behalf of the U.S. Air Force (United States Executive Agencies), re time-of-day rate design issues.

74. Arizona Public Service Company, before the Arizona Corporation Commission, Docket No. E-01345A-03-0347 (2004), on behalf of the U.S. Air Force (Federal Executive Agencies), re retail cost allocation and rate design issues.

75. Idaho Power Company, before the Idaho Public Utilities Commission, Case No. IPC-E-03-13 (2004), on behalf of the U.S. Department of Energy (Federal Executive Agencies), re retail cost allocation and rate design issues.

76. PacifiCorp, before the Utah Public Service Commission, Docket No. 03- 2035-02 (2004), on behalf of the U.S. Air Force (United States Executive Agencies), re retail cost allocation and rate design issues.

77. Dominion Virginia Power, before the Virginia State Corporation Commission, Case No. PUE-2000-00285 (2003), on behalf of Chaparral (Virginia) Inc., re recovery of fuel costs.

78. Jersey Central Power & Light Company, before the New Jersey Board of Public Utilities, BPU Docket No. ER02080506, OAL Docket No. PUC- 7894-02 (2002-2003), on behalf of New Jersey Commercial Users, re retail cost allocation and rate design issues.

Dennis W. Goins 79. Public Service Electric and Gas Company, before the New Jersey Board of Public Utilities, BPU Docket No. ER02050303, OAL Docket No. PUC- 5744-02 (2002-2003), on behalf of New Jersey Commercial Users, re retail cost allocation and rate design issues.

80. South Carolina Electric & Gas Company, before the South Carolina Public Service Commission, Docket No. 2002-223-E (2002), on behalf of SMI Steel-SC, re retail cost allocation and rate design issues.

81. Montana Power Company, before the First Judicial District Court of Montana, Great Falls Tribune et al. v. the Montana Public Service Commission, Cause No. CDV2001-208 (2002), on behalf of a media consortium (Great Falls Tribune, Billings Gazette, Montana Standard, Helena Independent Record, Missoulian, Big Sky Publishing, Inc. dba Bozeman Daily Chronicle, the Montana Newspaper Association, Miles City Star, Livingston Enterprise, Yellowstone Public Radio, the Associated Press, Inc., and the Montana Broadcasters Association), re public disclosure of allegedly proprietary contract information.

82. Louisville Gas & Electric et al., before the Kentucky Public Service Commission, Administrative Case No. 387 (2001), on behalf of Gallatin Steel Company, re adequacy of generation and transmission capacity in Kentucky.

83. PacifiCorp, before the Utah Public Service Commission, Docket No. 01- 035-01 (2001), on behalf of Nucor Steel, re retail cost allocation and rate design issues.

84. TXU Electric Company, before the Public Utilities Commission of Texas, PUC Docket No. 23640/ SOAH Docket No. XXX-XX-XXXX (2001), on behalf of Nucor Steel, re fuel eost recovery.

85. FPL Group et al., before the Federal Energy Regulatory Commission, Docket No. ECOl-33-000 (2001), on behalf of Arkansas Electric Cooperative Corporation, Inc., re merger-related market power issues.

86. Entergy Mississippi, Inc., et al., before the Mississippi Public Service Commission, Docket No. 2000-UA-925 (2001), on behalf of Birmingham Steel-Mississippi, re appropriate regulatory conditions for merger approval.

87. TXU Electric Company, before the Public Utilities Commission of Texas, PUC Docket No. 22350/ SOAH Docket No. XXX-XX-XXXX (2000), on behalf of Nucor Steel, re unbundled cost of service and rates.

88. PacifiCorp, before the Utah Public Service Commission, Docket No. 99- 035-10 (2000), on behalf of Nucor Steel, re using system benefit charges to fund demand-side resource investments.

Dennis W. Goins 89. Entergy Arkansas, Inc. et al., before the Arkansas Public Service Commission, Docket No. 00-190-U (2000), on behalf of Nucor-Yamato Steel and Nucor Steel-Arkansas, re the development of competitive electric power markets in Arkansas.

90. Entergy Arkansas, Inc. et al., before the Arkansas Public Service Commission, Docket No. 00-048-R (2000), on behalf of Nucor-Yamato Steel and Nucor Steel-Arkansas, re generic filing requirements and guidelines for market power analyses.

91. ScottishPower and PacifiCorp, before the Utah Public Service Commission, Docket No. 98-2035-04 (1999), on behalf of Nucor Steel, re merger conditions to protect the public interest.

92. Dominion Resources, Inc. and Consolidated Natural Gas Company, before the Virginia State Corporation Commission, Case No. PUA990020 (1999), on behalf of the City of Richmond, re market power and merger conditions to protect the public interest.

93. Houston Lighting & Power Company, before the Public Utility Commission of Texas, Docket No. 18465 (1998) on behalf of the Texas Commercial Customers, re excess earnings and stranded-cost recovery and mitigation.

94. PIM Interconnection, LLC, before the Federal Energy Regulatory Commission, Docket No. ER98-1384 (1998) on behalf of Wellsboro Electric Company, re pricing low-voltage distribution services.

95. DQE, Inc. and Allegheny Power System, Inc., before the Federal Energy Regulatory Commission, Docket Nos. ER97-4050-000, ER97-4051-000, and EC97-46-000 (1997) on behalf of the Borough of Chambersburg, re market power in relevant markets.

96. GPU Energy, before the New Jersey Board of Public Utilities, Docket No. E097070458 (1997) on behalf of the New Jersey Commercial Users Group, re unbundled retail rates.

97. GPU Energy, before the New Jersey Board of Public Utilities, Docket No. E097070459 (1997) on behalf of the New Jersey Commercial Users Group, re stranded costs.

98. Public Service Electric and Gas Company, before the New Jersey Board of Public Utilities, Docket No. E097070461 (1997) on behalf of the New Jersey Commercial Users Group, re unbundled retail rates.

99. Public Service Electric and Gas Company, before the New Jersey Board of Public Utilities, Docket No. E097070462 (1997) on behalf of the New Jersey Commercial Users Group, re stranded costs.

Dennis W. Goins 100. DQE, Inc. and Allegheny Power System, Inc., before the Federal Energy Regulatory Commission, Docket Nos. ER97-4050-000, ER97-4051-000, and EC97-46-000 (1997) on behalf of the Borough of Chambersburg, Allegheny Electric Cooperative, Inc., and Selected Municipalities, re market power in relevant markets.

101. CSW Power Marketing, Inc., before the Federal Energy Regulatory Commission, Docket No.ER97-1238-000 (1997) on behalf of the Transmission Dependent Utility Systems, re market power in relevant markets.

102. Central Hudson Gas & Electric Corporation et al., before the New York Public Service Commission, Case Nos. 96-E-0891, 96-E-0897, 96-E-0898, 96-E-0900, 96-E-0909 (1997), on behalf of the Retail Council of New York, re st~anded-cost recovery.

103. Central Hudson Gas & Electric Corporation, supplemental testimony, before the New York Public Service Commission, Case No. 96-E-0909 (1997) on behalf of the Retail Council of New York, re stranded-cost recovery.

104. Consolidated Edison Company of New York, Inc., supplemental testimony, before the New York Public Service Commission, Case No. 96-E-0897 (1997) on behalf of the Retail Council of New York, re stranded-cost recovery.

105. New York State Electric & Gas Corporation, supplemental testimony, before the New York Public Service Commission, Case No. 96-E-0891 (1997) on behalf of the Retail Council of New York, re stranded-cost recovery.

106. Rochester Gas and Electric Corporation, supplemental testimony, before the New York Public Service Commission, Case No. 96-E-0898 (1997) on behalf of the Retail Council of New York, re stranded-cost recovery.

107. Texas Utilities Electric Company, before the Public Utility Commission of Texas, Docket No. 15015 (1996), on behalf of Nucor Steel-Texas, re real- time electricity pricing.

108. Central Power and Light Company, before the Public Utility Commission of Texas, Docket No. 14965 (1996), on behalf of the Texas Retailers Association, re cost of service and rate design.

109. Carolina Power & Light Company, before the South Carolina Public Service Commission, Docket No. 95-1076-E (1996), on behalf of Nucor Steel- Darlington, re integrated resource planning.

110. Texas Utilities Electric Company, before the Public Utility Commission of Texas, Docket No. 13575 (1995), on behalf of Nucor Steel-Texas, re integrated resource planning, DSM options, and real-time pricing.

Dennis W. Goins 111. Arkansas Power & Light Company, et al., Notice of Inquiry to Consider Section 111 of the Energy Policy Act of 1992, before the Arkansas Public Service Commission, Docket No. 94-342-U (1995), Initial Comments on behalf of Nucor-Yamato Steel Company, re integrated resource planning standards.

112. Arkansas Power & Light Company, et al., Notice of Inquiry to Consider Section 111 of the Energy Policy Act of 1992, before the Arkansas Public Service Commission, Docket No. 94-342-U (1995), Reply Comments on behalf of Nucor-Yamato Steel Company, re integrated resource planning standards.

113. Arkansas Power & Light Company, et al., Notice of Inquiry to Consider Section 111 of the Energy Policy Act of 1992, before the Arkansas Public Service Commission, Docket No. 94-342-U (1995), Final Comments on behalf of Nucor-Yamato Steel Company, re integrated resource planning standards.

114. South Carolina Pipeline Corporation, before the South Carolina Public Service Commission, Docket No. 94-202-G (1995), on behalf of Nucor Steel, re integrated resource planning and rate caps.

115. Gulf States Utilities Company, before the United States Court of Federal Claims, Gulf States Utilities Company v. the United States, Docket No. 91- l 118C (1994, 1995), on behalf of the United States, re electricity rate and contract dispute litigation.

116. American Electric Power Corporation, before the Federal Energy Regulatory Commission, Docket No. ER93-540-000 (1994), on behalf of DC Tie, Inc., re costing and pricing electricity transmission services.

117. Texas Utilities Electric Company, before the Public Utility Commission of Texas, Docket No. 13100 (1994), on behalf of Nucor Steel-Texas, re real- time electricity pricing.

118. Carolina Power & Light Company, et al., Proposed Regulation Governing the Recovery of Fuel Costs by Electric Utilities, before the South Carolina Public Service Commission, Docket No. 93-238-E (1994), on behalf of Nucor Steel-Darlington, re fuel-cost recovery.

119. Southern Natural Gas Company, before the Federal Energy Regulatory Commission, Docket No. RP93- l 5-000 (1993-1995), on behalf of Nucor Steel-Darlington, re costing and pricing natural gas transportation services.

120. West Penn Power Company, et al., v. State Tax Department of West Virginia, et al., Civil Action No. 89-C-3056 (1993), before the Circuit Court of Kanawha County, West Virginia, on behalf of the West Virginia Department of Tax and Revenue, re electricity generation tax.

Dennis W. Goins 121. Carolina Power & Light Company, et al., Proceeding Regarding Consideration of Certain Standards Pertaining to Wholesale Power Purchases Pursuant to Section 712 of the 1992 Energy Policy Act, before the South Carolina Public Service Commission, Docket No. 92-231-E (1993), on behalf of Nucor Steel-Darlington, re Section 712 regulations.

122. Mountain Fuel Supply Company, before the Public Service Commission of Utah, Docket No. 93-057-01 (1993), on behalf of Nucor Steel-Utah, re costing and pricing retail natural gas firm, interruptible, and transportation services.

123. Texas Utilities Electric Company, before the Public Utility Commission of Texas, Docket No. 11735 (1993), on behalf of the Texas Retailers Association, re retail cost-of-service and rate design.

124. Virginia Electric and Power Company, before the Virginia State Corporation Commission, Case No. PUE92004 l (1993), on behalf of Philip Morris USA, re cost of service and retail rate design.

125. Carolina Power & Light Company, before the South Carolina Public Service Commission, Docket No. 92-209-E (1992), on behalf of Nucor Steel- Dariington.

126. Gulf States Utilities Company, before the Louisiana Public Service Commission, Docket No. U-17282, Rate Design (1992), on behalf of the Department of Energy, Strategic Petroleum Reserve.

127. Georgia Power Company, before the Georgia Public Service Commission, Docket Nos. 4091-U and 4146-U (1992), on behalf of Amicalola Electric Membership Corporation.

128. PacifiCorp, Inc., before the Federal Energy Regulatory Commission, Docket No. EC88-2-007 (1992), on behalf of Nucor Steel-Utah. 129. South Carolina Pipeline Corporation, before the South Carolina Public Service Commission, Docket No. 90-452-G (1991), on behalf of Nucor Steel-Darlington.

130. Carolina Power & Light Company, before the South Carolina Public Service Commission, Docket No. 91-4-E, 1991 Fall Hearing, on behalf of Nucor Steel-Darlington.

131. Sonat, Inc., and North Carolina Natural Gas Corporation, before the North Carolina Utilities Commission, Docket No. G-21, Sub 291 (1991), on behalf of Nucor Corporation, Inc. 132. Northern States Power Company, before the Minnesota Public Utilities Commission, Docket No. E002/GR-91-001 (1991), on behalf of North Star Steel-Minnesota.

Dennis W. Goins 133. Gulf States Utilities Company, before the Louisiana Public Service Commission, Docket No. U-17282, Phase IV-Rate Design (1991), on behalf of the Department of Energy, Strategic Petroleum Reserve.

134. Houston Lighting & Power Company, before the Public Utility Commission of Texas, Docket No. 9850 (1990), on behalf of the Department of Energy, Strategic Petroleum Reserve.

135. General Services Administration, before the United States General Accounting Office, Contract Award Protest (1990), Solicitation No. GS- OOP-AC87-91, Contract No. GS-OOD-89-B5D-0032, on behalf of Satilla Rural Electric Membership Corporation, re cost of service and rate design.

136. Carolina Power & Light Company, before the South Carolina Public Service Commission, Docket No. 90-4-E (1990 Fall Hearing), on behalf of Nucor Steel-Darlington, re fuel-cost recovery.

137. Gulf States Utilities Company, before the Louisiana Public Service Commission, Docket No. U-17282, Phase III-Rate Design (1990), on behalf of the Department of Energy, Strategic Petroleum Reserve, re cost of service and rate design.

138. Atlanta Gas Light Company, before the Georgia Public Service Commission, Docket No. 3923-U (1990), on behalf of Herbert G. Burris and Oglethorpe Power Corporation, re anticompetitive pricing schemes.

139. Ohio Edison Company, before the Ohio Public Utilities Commission, Case No. 89-1001-EL-AIR (1990), on behalf of North Star Steel-Ohio, re cost of service and rate design.

140. Gulf States Utilities Company, before the Louisiana Public Service Commission, Docket No. U-17282, Phase III-Cost of Service/Revenue Spread (1989), on behalf of the Department of Energy, Strategic Petroleum Reserve.

141. Northern States Power Company, before the Minnesota Public Utilities Commission, Docket No. E002/GR-89-865 (1989), on behalf of North Star Steel-Minnesota.

142. Gulf States Utilities Company, before the Louisiana Public Service Commission, Docket No. U-17282, Phase III-Rate Design (1989), on behalf of the Department of Energy, Strategic Petroleum Reserve.

143. Utah Power & Light Company, before the Utah Public Service Commission, Case No. 89-039-10 (1989), on behalf of Nucor Steel-Utah and Vulcraft, a division of Nucor Steel.

Dennis W. Goins 144. Soyland Power Cooperative, Inc. v. Central Illinois Public Service Company, Docket No. EL89-30-000 (1989), before the Federal Energy Regulatory Commission, on behalf of Soyland Power Cooperative, Inc., re wholesale contract pricing provisions 145. Gulf States Utilities Company, before the Public Utility Commission of Texas, Docket No. 8702 (1989), on behalf of the Department of Energy, Strategic Petroleum Reserve.

146. Houston Lighting and Power Company, before the Public Utility Commission of Texas, Docket No. 8425 (1989), on behalf of the Department of Energy, Strategic Petroleum Reserve.

147. Northern Illinois Gas Company, before the Illinois Commerce Commission, Docket No. 88-0277 (1989), on behalf of the Coalition for Fair and Equitable Transportation, re retail gas transportation rates.

148. Carolina Power & Light Company, before the South Carolina Public Service Commission, Docket No. 79-7-E, 1988 Fall Hearing, on behalf of Nucor Steel-Darlington, re fuel-cost recovery.

149. Potomac Electric Power Company, before the District of Columbia Public Service Commission, Formal Case No. 869 (1988), on behalf of Peoples Drug Stores, Inc., re cost of service and rate design.

150. Carolina Power & Light Company, before the South Carolina Public Service Commission, Docket No. 88-11-E (1988), on behalf of Nucor Steel- Darlington.

151. Northern States Power Company, before the Minnesota Public Utilities Commission, Docket No. E-002/GR-87-670 (1988), on behalf of the Metalcasters of Minnesota.

152. Ohio Edison Company, before the Ohio Public Utilities Commission, Case No. 87-689-EL-AIR (1987), on behalf of North Star Steel-Ohio. 153. Carolina Power & Light Company, before the South Carolina Public Service Commission, Docket No. 87-7-E (1987), on behalf of Nucor Steel- Darlington.

154. Gulf States Utilities Company, before the Louisiana Public Service Commission, Docket No. U-17282, Phase I (1987), on behalf of the Strategic Petroleum Reserve.

155. Gulf States Utilities Company, before the Public Utility Commission of Texas, Docket No. 7195 (1987), on behalf of the Strategic Petroleum Reserve.

Dennis W. Goins 156. Gulf States Utilities Company, before the Federal Energy Regulatory Commission, Docket No. ER86-558-006 (1987), on behalf of Sam Rayburn G&T Cooperative.

11 -t::.'7 JI. Utah Power & Light Company, before the Utah Public Service Commission, Case No. 85-035-06 (1986), on behalf of the U.S. Air Force.

158. Houston Lighting & Power Company, before the Public Utility Commission of Texas, Docket No. 6765 (1986), on behalf of the Strategic Petroleum Reserve.

159. Central Maine Power Company, before the Maine Public Utilities Commission, Docket No. 85-212 (1986), on behalf of the U.S. Air Force.

160. Gulf States Utilities Company, before the Public Utility Commission of Texas, Docket Nos. 6477 and 6525 (1985), on behalf of North Star Steel- Tcxas.

161. Ohio Edison Company, before the Ohio Public Utilities Commission, Docket No. 84-1359-EL-AIR (1985), on behalf of North Star Steel-Ohio. 162. Utah Power & Light Company, before the Utah Public Service Commission, Case No. 84-035-01 (1985), on behalf of the U.S. Air Force.

163. Central Vermont Public Service Corporation, before the Vermont Public Service Board, Docket No. 4782 (1984), on behalf of Central Vermont Public Service Corporation.

164. Gulf States Utilities Company, before the Louisiana Public Service Commission, Docket No. U-15641 (1983), on behalf of the Strategic Petroleum Reserve.

165. Southwestern Power Administration, before the Federal Energy Regulatory Commission, Rate Order SWPA-9 (1982), on behalf of the Department of Defense.

166. Public Service Company of Oklahoma, before the Federal Energy Regulatory Commission, Docket Nos. ER82-80-000 and ER82-389-000 (1982), on behalf of the Department of Defense.

167. Central Maine Power Company, before the Maine Public Utilities Commission, Docket No. 80-66 (1981), on behalf of the Commission Staff.

168. Bangor Hydro-Electric Company, before the Maine Public Utilities Commission, Docket No. 80-108 (1981), on behalf of the Commission Staff.

169. Oklahoma Gas & Electric, before the Oklahoma Corporation Commission, Docket No. 27275 (1981), on behalf of the Commission Staff.

Dennis W. Goins 170. Green Mountain Power, before the Vermont Public Service Board, Docket No. 4418 (1980), on behalf of the PSB Staff.

171. Williams Pipe Line, before the Federal Energy Regulatory Commission, Docket No. OR79-1 (1979), on behalf of Mapco, fac.

172. Boston Edison Company, before the Massachusetts Department of Public Utilities, Docket No. 19494 (1978), on behalf of Boston Edison Company.

173. Duke Power Company, before the North Carolina Utilities Commission, Docket No. E-7, Sub 173, on behalf of the Commission Staff.

174. Duke Power Company, before the North Carolina Utilities Commission, Docket No. E-100, Sub 32, on behalf of the Commission Staff.

175. Virginia Electric & Power Company, before the North Carolina Utilities Commission, Docket No. E-22, Sub 203, on behalf of the Commission Staff.

176. Virginia Electric & Power Company, before the North Carolina Utilities Commission, Docket No. E-22, Sub 170, on behalf of the Commission Staff.

177. Southern Bell Telephone Company, before the North Carolina Utilities Commission, Docket No. P-5, Sub 48, on behalf of the Commission Staff.

178. Western Carolina Telephone Company, before the North Carolina Utilities Commission, Docket No. P-58, Sub 93, on behalf of the Commission Staff.

179. Natural Gas Ratemaking, before the North Carolina Utilities Commission, Docket No. G-100, Sub 29, on behalf of the Commission Staff.

180. General Telephone Company of the Southeast, before the North Carolina Utilities Commission, Docket No. P-19, Sub 163, on behalf of the Commission Staff.

181. Carolina Power and Light Company, before the North Carolina Utilities Commission, Docket No. E-2, Sub 264, on behalf of the Commission Staff.

182. Carolina Power and Light Company, before the North Carolina Utilities Commission, Docket No. E-2, Sub 297, on behalf of the Commission Staff.

183. Duke Power Company, et al., Investigation of Peak-Load Pricing, before the North Carolina Utilities Commission, Docket No. E-100, Sub 21, on behalf of the Commission Staff.

184. Investigation of Intrastate Long Distance Rates, before the North Carolina Utilities Commission, Docket No. P-100, Sub 45, on behalf of the Commission Staff.

Revised- Cities' Errata No. 3

effect, ETI' s rate-year estimate assumes that the divestiture/merger 2 will have no effect on either the level of or method of recovering 3 (via Schedule MSS-2 of the ESA) such costs. In addition, ETI 4 again ignored the effects of load growth when it set rate-year MSS- 5 2 costs as adjusted test-year MSS-2 costs recovered in base rates.

6 That is, by ignoring load growth in setting both PPCC and MSS-2 7 costs that will be recovered in base rates, ETI almost certainly 8 ensured that it will overrecover both types of costs going forward.

9 7. ETI' s principal rate schedules for street lighting and traffic signal 10 customers are Schedules SHL and TSS, respectively. Schedule 11 SHL applies to lighting for public streets, roads, and thoroughfares 12 in cities and in subdivisions with an incorporated homeowners 13 association. Schedule SHL sets fixed monthly charges for standard 14 and nonstandard fixture and lamps that ETI installs and maintains 15 (Rate Groups A and C). ETI also offers a fixed kWh rate for 16 lighting facilities that the customer owns and maintains (Rate 17 Groups D and E). Schedule TSS is a fixed kWh rate with a 18 monthly @ttst@m@r tiMfffium charge per delivery point applicable to 19 customer-owned and -maintained traffic signals. Both proposed 20 rates do not reflect the lower cost of operating and maintaining 21 lighting facilities using energy-efficient light-emitting diode (LED) 22 bulbs. Moreover, Schedule SHL includes a provision that 23 penalizes a customer that replaces a high-wattage bulb with a more 24 energy-efficient LED bulb.

Docket No. 39896 Dennis W. Goins - Direct Page7 Revised- Cities' Errata No. 3

effect, ETI' s rate-year estimate assumes that the divestiture/merger 2 will have no effect on either the level of or method of recovering 3 (via Schedule MSS-2 of the ESA) such costs. In addition, ETI 4 again ignored the effects of load growth when it set rate-year MSS- 5 2 costs as adjusted test-year MSS-2 costs recovered in base rates.

6 That is, by ignoring load growth in setting both PPCC and MSS-2 7 costs that will be recovered in base rates, ETI almost certainly 8 ensured that it will overrecover both types of costs going forward.

9 7. ETI's principal rate schedules f'or street lighting and traffic signal 10 customers are Schedules SHL and TSS, respectively. Schedule 11 SHL applies to lighting for public streets, roads, and thoroughfares 12 in cities and in subdivisions with an incorporated homeowners 13 association. Schedule SHL sets fixed monthly charges for standard 14 and nonstandard fixture and lamps that ETI installs and maintains 15 (Rate Groups A and C). ETI also offers a fixed kWh rate for 16 lighting facilities that the customer owns and maintains (Rate 17 Groups D and E). Schedule TSS is a fixed kWh rate with a 18 monthly minimum charge per delivery point applicable to 19 customer-owned and -maintained traffic signals. Both proposed 20 rates do not reflect the lower cost of operating and maintaining 21 lighting facilities using energy-efficient light-emitting diode (LED) 22 bulbs. Moreover, Schedule SHL includes a provision that 23 penalizes a customer that replaces a high-wattage bulb with a more 24 energy-efficient LED bulb.

Docket No. 39896 Dennis W. Goins - Direct Page7

{ '] Revised - Cities' Errata No. 3

1 RECOMMENDATIONS Q. WHAT DO YOU RECOMMEND ON THE BASIS OF THESE 3 CONCLUSIONS?

4 A. I recommend that the Commission take the following actions regarding the 5 major issues discussed in my testimony: 6 1. Reject the AED4CP method used in ETI's jurisdictional separation 7 study to assign demand-related production costs to its Texas retail 8 and wholesale jurisdictions. Instead, the Commission should 9 require ETI to assign these costs to the wholesale jurisdiction using 10 the 12 coincident peak (12CP) method to allocate demand-related 11 production costs. This approach is consistent not only with the 12 cost-of-service approach FERC typically uses to allocate demand- 13 related production costs reflected in wholesale rate schedules, but 14 also with the assignment of MSS-1 costs (as well as MSS-2 15 transmission costs) to ETI under the ESA. I have calculated test- 16 year 12CP allocation factors for the Texas Retail (94.6208 percent) 17 and Wholesale (5.3792 percent) jurisdictions, and provided them to 18 Cities witness Karl Nalepa for inclusion in his jurisdictional 19 separation study.

20 2. Reject ETI's adjusted test-year purchased power capacity costs 21 ($276.2 million). Instead, ETI should be allowed to recover no 22 more than approximately ~ ~ million in PPCC. This 23 approximately~ (II million reduction in ETI's proposed rate- 24 year PPCC estimate reflects the following three adjustments: 25 • - reduction in costs for Legacy Affiliate Contracts 26 to reflect more current pricing data.

27 • reduction in costs for Other Affiliate Contracts 28 and Reserve Equalization to reflect more recent contract

Docket No. 39896 Dennis W. Goins - Direct Page8

\6 Revised- Cities' Errata No. 3 1 RECOMMENDATIONS Q. WHAT DO YOU RECOMMEND ON THE BASIS OF THESE 3 CONCLUSIONS?

4 A. I recommend that the Commission take the following actions regarding the 5 major issues discussed in my testimony: 6 1. Reject the AED4CP method used in ETI's jurisdictional separation 7 study to assign demand-related production costs to its Texas retail 8 and wholesale jurisdictions. Instead, the Commission should 9 require ETI to assign these costs to the wholesale jurisdiction using 10 the 12 coincident peak (12CP) method to allocate demand-related 11 production costs. This approach is consistent not only with the 12 cost-of-service approach FERC typically uses to allocate demand- 13 related production costs reflected in wholesale rate schedules, but 14 also with the assignment of MSS-1 costs (as well as MSS-2 15 transmission costs) to ETI under the BSA. I have calculated test- 16 year 12CP allocation factors for the Texas Retail (94.6208 percent) 17 and Wholesale (5.3792 percent) jurisdictions, and provided them to 18 Cities witness Karl Nalepa for inclusion in his jurisdictional 19 separation study.

20 2. Reject ETI's adjusted test-year purchased power capacity costs 21 ($276.2 million). Instead, ETI should be allowed to recover no 22 more than approximately $242.9 million in PPCC. This 23 approximately $33.3 million reduction in ETI's proposed rate-year 24 PPCC estimate reflects the following three adjustments: 25 • - reduction in costs for Legacy Affiliate Contracts 26 to reflect more current pricing data.

27 • reduction in costs for Other Affiliate Contracts 28 and Reserve Equalization to reflect more recent contract

Docket No. 39896 Dennis W. Goins - Direct Page8

\1 Revised - Cities' Errata No. 3 pricing data and Cities recommended adjustment in costs 2 related to the EAI WBL contract.6 3 • - reduction to reflect the effects of load growth on 4 rate-year PPCC costs that ETI will recover going forward.

5 3. Reject ETI's adjusted test-year MSS-2 costs. ETI's unexplained 6 in MSS-2 costs relative to test-year 7 costs, plus complete uncertainty regarding the magnitude of ETI' s 8 post-2012 MSS-2 costs under Entergy's proposed 9 divestiture/merger deal with ITC in 2013, make ETI's projected 10 rate-year MSS-2 costs speculative at best. I recommend setting 11 ETI's adjusted test-year MSS-2 costs no higher than - - 12 or This lower 13 value reflects ETI's actual 2011 MSS-2 costs , plus a 14 to reflect the effects of load growth.

15 4. Require ETI to modify Schedules SHL (Rate Groups A and C) and 16 TSS to include a minimum 25 percent reduction in monthly fixed 17 charges applicable to street and traffic 18 lighting fixtures that use LED technology. Energy charges in 19 Schedule SHL (Rate Groups D and E) should also be reduced by 20 25 percent for LED customers. This reduction should partially 21 reflect the lower cost of operating and maintaining energy-efficient 22 LED fixtures. In addition, the Commission should require ETI to 23 eliminate the $50 fee applicable to Rate Groups A and C under 24 Schedule SHL when an existing light is replaced with a more 25 efficient light with lower wattage (for example, an LED bulb).

26 Eliminating this fee will remove a disincentive for customers to 27 adopt LED fixtures as conservation measures.

EAi WBL denotes capacity entitlements in several of EAi' s baseload generating units that EAi sells at wholesale. Justification for Cities recommended EAi WBL rate-year cost adjustment is provided in the direct testimony of Cities witness Karl Nalepa.

Docket No. 39896 Dennis W. Goins - Direct Page9

\B Revised- Cities' Errata No. 3

pricing data and Cities recommended adjustment in costs 2 related to the EAI WBL contract.6 • reduction to reflect the effects of load growth on 4 rate-year PPCC costs that ETI will recover going forward.

5 3. Reject ETI's adjusted test-year MSS-2 costs. ETI's unexplained 6 in MSS-2 costs relative to test-year 7 costs, plus complete uncertainty regarding the magnitude of ETI's 8 post-2012 MSS-2 costs under Entergy's proposed 9 divestiture/merger deal with ITC in 2013, make ETI's projected 10 rate-year MSS-2 costs speculative at best. I recommend setting 11 ETI's adjusted test-year MSS-2 costs no higher than - - - 12 or This lower 13 value reflects ETI's actual 2011 MSS-2 costs , plus a 14 to reflect the effects of load growth.

15 4. Require ETI to modify Schedules SHL (Rate Groups A and C) and 16 TSS to include a minimum 25 percent reduction in monthly fixed 17 (SHL) and minimum (TSS) charges applicable to street and traffic 18 lighting fixtures that use LED technology. Energy charges in 19 Schedule SHL (Rate Groups D and E) should also be reduced by 20 25 percent for LED customers. This reduction should partially 21 reflect the lower cost of operating and maintaining energy-efficient 22 LED fixtures. In addition, the Commission should require ETI to 23 eliminate the $50 fee appliqable to Rate Groups A and C under 24 Schedule SHL when an existing light is replaced with a more 25 efficient light with lower wattage (for example, an LED bulb).

26 Eliminating this fee will remove a disincentive for customers to 27 adopt LED fixtures as conservation measures.

EAi WBL denotes capacity entitlements in several of EAi' s baseload generating units that EAi sells at wholesale. Justification for Cities recommended EAi WBL rate-year cost adjustment is provided in the direct testimony of Cities witness Karl Nalepa.

Docket No. 39896 Dennis W. Goins - Direct Page9

l~ Revised- Cities' Errata No. 3

and rate-year costs. Next, I adjusted ETI's rate-year estimates of costs for 2 the EAI WBL contract and Reserve Equalization to reflect the adjustment 3 recommended by Cities witness Karl Nalepa. Finally, I adjusted the rate- 4 year total PPCC estimate to reflect the effects of load growth. The 5 resulting adjusted test-year PPCC by transaction category is shown in 6 Exhibit DWG-2. 11 As shown in this exhibit, ETI's adjusted test-year 7 PPCC should be set no higher than $241.a W million-or~ Im 8 million less than ETI's original request. As I noted earlier, this~ Ila 9 million reduction in ETI's proposed rate-year PPCC estimate reflects the 10 following three adjustments: 11 • - reduction in costs for Legacy Affiliate Contracts 12 to reflect more current pricing data.

13 • reduction in costs for Other Affiliate Contracts 14 and Reserve Equalization to reflect more recent contract 15 pricing data and Cities recommended adjustment in costs 16 related to the Cities recommended 50-percent reduction in 17 adjusted test-year costs for the EAI WBL contract.

18 • - reduction to reflect the effects of load growth.

19 Q. HOW DID YOU DEVELOP THE LOAD GROWTH ADJUSTMENT 20 YOU APPLIED TO YOUR PPCC ESTIMATE?

21 A. The development of my recommended load growth 22 adjustment is presented in Exhibit DWG-3. I first reviewed forecasts of 23 ETI's firm load (energy sales and peak demand) from 2011 through 2014.

24 I then calculated the growth in ETI's energy sales and peak demands over 25 different intervals (Exhibit DWG-3, page 1). On the basis of this review, I 26 selected - as a reasonable estimate of the likely growth in ETI's 27 energy and demand billing determinants from the test year to the rate year.

Results shown in Exhibit DWG-2 are presented in a format similar to that used by ETI' s witness Robert Cooper in Exhibit RRC-1 {HS-revised).

Docket No. 39896 Dennis W. Goins - Direct Page 18 Revised - Cities' Errata No. 3 1 and rate-year costs. Next, I adjusted ETI's rate-year estimates of costs for 2 the EAI WBL contract and Reserve Equalization to reflect the adjustment 3 recommended by Cities witness Karl Nalepa. Finally, I adjusted the rate- 4 year total PPCC estimate to reflect the effects of load growth. The 5 resulting adjusted test-year PPCC by transaction category is shown in 6 Exhibit DWG-2. 11 As shown in this exhibit, ETI's adjusted test-year 7 PPCC should be set no higher than $242.9 million-or $33.3 million less 8 than ETI' s original request. As I noted earlier, this $33 .3 million reduction 9 in ETI' s proposed rate-year PPCC estimate reflects the following three 10 adjustments: 11 • - reduction in costs for Legacy Affiliate Contracts 12 to reflect more current pricing data. • reduction in costs for Other Affiliate Contracts 14 and Reserve Equalization to reflect more recent contract 15 pricing data and Cities recommended adjustment in costs 16 related to the Cities recommended 50-percent reduction in 17 adjusted test-year costs for the EAI WBL contract.

18 • reduction to reflect the effects of load growth.

19 Q. HOW DID YOU DEVELOP THE LOAD GROWTH ADJUSTMENT 20 YOU APPLIED TO YOUR PPCC ESTIMATE?

21 A. The development of my recommended load growth 22 adjustment is presented in Exhibit DWG-3. I first reviewed forecasts of 23 ETI's firm load (energy sales and peak demand) from 2011 through 2014.

24 I then calculated the growth in ETI's energy sales and peak demands over 25 different intervals (Exhibit DWG-3, page 1). On the basis of this review, I 26 s e l e c t e d - as a reasonable estimate of the likely growth in ETI's 27 energy and demand billing determinants from the test year to the rate year.

Results shown in Exhibit DWG-2.are presented in a fonnat similar to that used by ETI's witness Robert Cooper in Exhibit RRC-1 (HS-revised).

Docket No. 39896 Dennis W. Goins - Direct Page 18 Revised- Cities' Errata No. 3

I next estimated ETI's rate-year energy billing units, and derived an 2 average cost per billing unit (Exhibit DWG-3, page 2) for the estimated 3 rate-year PPCC shown in column (c) of Exhibit DWG-2. The product of 4 this average rate-year PPCC and ETI's test-year kWh billing units equals 5 the adjusted test-year PPCC that ETI should be allowed to include in base 6 rates.

7 Q. IS YOUR RECOMMENDED $241.J em MILLION IN 8 ADJUSTED TEST-YEAR PPCC A REASONABLE AND FAIR 9 ESTIMATE OF COSTS THAT ETI IS LIKELY TO INCUR IN THE 10 RATE YEAR?

11 A. Yes. My estimate mitigates two problems that cause ETI to overstate its 12 rate-year PPCC-its failure to adjust rate-year projections to reflect load 13 growth, and the use of dated transaction price proxies. In addition, my 14 estimate reflects witness Nalepa's recommended cost adjustments related 15 to the EAI WBL contract.

16 MSS-2 COSTS Q. WHAT ARE MSS-2 COSTS?

18 A. Under the ESA's Service Schedule MSS-2, the EOCs share cost 19 responsibility for the Entergy transmission system much like they share 20 cost responsibility for generating resources under Service Schedule MSS- 21 1. Each month an EOC receives -'O!Il!t«m 23 EOC's level of transmission investment relative to 24 total System transmission investments, its hHtfi re~011sibili-ty ratie, and the 25 tifJD average cost=of total System 26 investments.

Docket No. 39896 Dennis W. Goins - Direct Page 19 Revised - Cities' Errata No. 3

I next estimated ETI's rate-year energy billing units, and derived an 2 average cost per billing unit (Exhibit DWG-3, page 2) for the estimated 3 rate-year PPCC shown in column (c) of Exhibit DWG-2. The product of 4 this average rate-year PPCC and ETI's test-year kWh billing units equals 5 the adjusted test-year PPCC that ETI should be allowed to include in base 6 rates.

7 Q. IS YOUR RECOMMENDED $242.9 MILLION IN ADJUSTED 8 TEST-YEAR PPCC A REASONABLE AND FAIR ESTIMATE OF 9 COSTS THAT ETI IS LIKELY TO INCUR IN THE RATE YEAR?

10 A. Yes. My estimate mitigates two problems that cause ETI to overstate its 11 rate-year PPCC-its failure to adjust rate-year projections to reflect load 12 growth, and the use of dated transaction price proxies. In addition, my 13 estimate reflects witness Nalepa's recommended cost adjustments related 14 to the EAI WBL contract.

15 MSS-2 COSTS Q. WHAT ARE MSS-2 COSTS?

17 A. Under the ESA's Service Schedule MSS-2, the EOCs share cost 18 responsibility for the Entergy transmission system much like they share 19 cost responsibility for generating resources under Service Schedule MSS- 20 1. Each month an EOC receives an MSS-2 transmission equalization 21 payment or bill that reflects the EOC's level of transmission investment 22 relative to its responsibility for total System transmission investment, and 23 the System average annual transmission ownership.

Docket No. 39896 Dennis W. Goins - Direct Page 19 SOAH DOCKET NO. XXX-XX-XXXX PUC DOCKET NO. 39896

• APPLICATION OF ENTERGY TEXAS, § INC. FOR AUTHORITY TO CHANGE § BEFORE THE STATE OFFICE RATES, RECONCILE FUEL COSTS, § OF AND OBTAIN DEFERRED § ADMINISTRATIVE HEARINGS ACCOUNTING TREATMENT §

DIRECT TESTIMONY AND EXHIBITS OF KARL J. NALEPA

ON BEHALF OF CITIES SERVED BY ENTERGY TEXAS, INC.

MARCH 27, 2012

REDACTED PUBLIC VERSION

ReSolved Energy Consulting, LLC 11044 Research Blvd., Suite D-230 Austin, Texas 78759 Blank Page DIRECT TESTIMONY OF KARL J. NALEPA TABLE OF CONTENTS

I. INTRODUCTION AND QUALIFICATIONS .................................................................. 2 II. PURPOSE AND SCOPE .................................................................................................... 4 III. SUMMARY AND RECOMMENDATIONS ..................................................................... 4 IV. COST OF SERVICE ADJUSTMENTS ............................................................................. 7 A. PURCHASED CAP A CITY COSTS ...................................................................... 7 B. NATURAL GAS STORAGE ............................................................................... 18 C. COAL INVENTORIES ........................................................................................ 27 D. RENEW ABLE ENERGY CREDIT RIDER ........................................................ 30 E. COST OF SERVICE MODEL ............................................................................. 32 F. COST ALLOCATION .......................................................................................... 34 V. OVERVIEW OF ETI'S FUEL COSTS ............................................................................ 37 VI. FUEL COST ADJUSTMENTS ........................................................................................ 38 A. NATURAL GAS STORAGE COSTS .................................................................. 38 B. LOSS FACTORS .................................................................................................. 43

APPENDICES APPENDIX A - Statement of Qualifications APPENDIX B -Previously Filed Testimony

DIRECT TESTIMONY NALEPA Blank Page DIRECT TESTIMONY OF KARL J. NALEPA TABLE OF CONTENTS ATTACHMENTS KJN-1 Cities' Cost of Service Model KJN-2 Fuel Reconciliation Adjustments KJN-3 Test Year Capacity Costs KJN-4 Rate Year Capacity Costs

DIRECT TESTIMONY 2 NALEPA Blank Page SOAH Docket No. XXX-XX-XXXX PUC Docket No. 37744

APPLICATION OF ENTERGY § BEFORE THE TEXAS, INC. FOR AUTHORITY § STATE OFFICE OF TO CHANGE RATES AND TO § ADMINISTRATIVE HEARINGS RECONCILE FUEL COSTS § 3 DIRECT TESTIMONY OF 4 KARL J. NALEPA 5 I. INTRODUCTION AND QUALIFICATIONS

7 Q. PLEASE STATE YOUR NAME, OCCUPATION, AND BUSINESS ADDRESS.

8 A. My name is Karl J. Nalepa. I am the President of ReSolved Energy Consulting, LLC 9 ("REC"), formerly R.J. Covington Consulting, LLC. REC is an independent utility 10 consulting company. My business address is 11044 Research Blvd., Suite D-230, 11 Austin, Texas 78759.

13 Q. ON WHOSE BEHALF ARE YOU PRESENTING TESTIMONY IN THIS 14 PROCEEDING?

15 A. I am presenting testimony on behalf of Cities served by Entergy Texas, Inc. 16 ("Cities").

18 Q. PLEASE OUTLINE YOUR EDUCATIONAL AND PROFESSIONAL 19 BACKGROUND.

20 A. I hold a Bachelor of Science degree in Mineral Economics and a Master of Science 21 degree in Petroleum Engineering, and am a certified mediator. My professional

DIRECT TESTIMONY 2 NALEPA 1 II. PURPOSE AND SCOPE

3 Q. WHAT IS THE PURPOSE AND SCOPE OF YOUR TESTIMONY IN THIS 4 PROCEEDING?

5 A. The purpose and scope of my testimony is twofold: First, to review certain issues 6 ranging from purchase power to expense and rate base items and if necessary to 7 present certain recommendations regarding Entergy Texas, Inc.' s ("ETI") proposed 8 cost of service, based on a test year ending June 30, 2011. 1 Second, to review fuel 9 related issues and if necessary to present recommendations regarding ETI' s request to 10 reconcile its fuel costs incurred during the period July 1, 2009 through June 30, 2011 11 (the "Reconciliation Period").2 Third, I sponsor the cost of service for the Cities case 12 and propose an allocation of any increase in the event Cities recommendation to 13 maintain the existing rates is not approved. Within my testimony, references to "ETI" 14 or the "Company" may be used interchangeably.

16 III. SUMMARY AND RECOMMENDATIONS

18 Q. PLEASE SUMMARIZE YOUR RECOMMENDATIONS IN THIS 19 PROCEEDING?

20 A. I make the following recommendations regarding the Company's proposed 21 rate request:

Statement of Intent and Application for Authority to Change Rates and to Reconcile Fuel Costs, p. 4.

2Jd., p. I.

DIRECT TESTIMONY 4 NALEPA 1 1. ETI is requesting purchased power capacity expense of $275,809,485. I propose 2 several alternative adjustments to the MSS-4 and 3rd party purchase components 3 of ETis request for purchased power capacity expense to better reflect the known 4 and measurable nature of these costs as well as all attendant impacts. My 5 recommendation is that the Commission approves purchased power capacity 6 expense of $236,838,634, a reduction of $38,970,851 to the ETI requested 7 capacity cost amount. This adjustment is presented as an alternative to Dr. Goins 8 purchase power recomn1endation-should the ALJ s and the Commission adopt 9 my alternative for adjusting the Company's purchase power request.

11 2. The Company operates the Spindletop gas storage facility to provide gas supply 12 reliability and flexibility for ETI's Sabine and Lewis Creek power plants. The 13 Company has acknowledged there are less costly options to provide this same 14 supply reliability and flexibility in gas supply. Eliminating the Spindletop facility 15 and selecting the less costly and readily available alternative will save customers 16 $ 11.4 million per year without diminishing fuel supply flexibility or reliability. It 17 would be imprudent to continue with the Company's Spindletop alternative. As 18 such, I recommend that the facility be removed from rates and from regulated 19 service if necessary. Total base rate costs to be removed are $7,653,293. In 20 addition, the Commission should exclude as an eligible fuel expense the variable 21 non-gas operating costs of Spindletop, which during the test year were 22 $5,424,895. The variable non-gas operating costs of Spindletop for the 23 reconciliation period will be addressed in the fuel reconciliation portion of my 24 testimony.

26 3. ETI is requesting an average test year coal inventory value of $6,740,528 at 27 Nelson 6. This is equivalent to 66 days of inventory at full bum. However, the 28 Company has established that an average target inventory of 43 days at Nelson 6 29 is sufficient to meet its reliability requirements. I recommend that the 43 day coal 30 inventory level be included in rate base, resulting in a revised inventory level for 31 Nelson 6 of $4,381,988 and reducing the Company's requested inventory level by 32 $2,358,540.

DIRECT TESTIMONY 5 NALEPA 1 In addition, I make the following recommendations regarding the Company's 2 reconcilable costs: 3 6. During the reconciliation period, the Spindletop gas storage facility did not provide 4 any increased supply reliability or flexibility relative to other options available to 5 ETI at the Sabine and Lewis Creek Generating Stations. Compared to other /:;. v supply options available to the Company, the Spindletop facility cost customers 7 $11.4 million more per year for the same supply reliability and flexibility. It 8 would not be prudent to continue charging customers for this unreasonable level 9 of expense. I adjusted reconcilable storage costs to reflect the average cost of 10 transportation to Sabine plus call options on supply as a reasonable alternative to 11 storage. This reduces storage related reconcilable costs by $6,595,290.

13 7. ETI's proposed tariff Schedule FF Fixed Fuel Factor includes loss multipliers by 14 voltage level which were calculated in a study based on the 12 months ending 15 December 3 l, 1997. I adjust line loss factors to reflect current losses, reducing 16 fuel expenses properly allocable to Texas retail customers by $3,981,271.

18 Q. WHAT IS THE TOTAL DOLLAR AMOUNT OF YOUR 19 RECOMMENDATIONS?

20 A. My recommended adjustments to the Company's proposed base rate or non fuel cost 21 of service are summarized in Table 1. I recommend a total adjustment to reconcilable 22 fuel costs of $10,576,561 (consisting of $6,595,290 in storage costs and $3,981,271 in 23 line loss costs). This adjustment is summarized on a monthly basis in Attachment 24 KJN-2.

25 TABLE 1 Adjustment Rate Base Expense Nelson 6 Coal Inventory ($2,358,540) Spindletop Gas Storage ($48,301,624) ($2,090,116) Renewable Energy Credit Rider Deny Rider - include $633,985 in cost of service Purchased Power Capacity EAI WBL Total ($50,660, 164)

DIRECT TESTIMONY 6 NALEPA It should be noted that the load growth related third party Purchased Power Capacity adjustment included in the $38,970,851 recommendation above is presented as an alternative to Dr. Goins purchase power capacity recommendation and is not part of the total adjustment shown in Table 1. Another portion of my $38,970,851 purchase power adjustment related to the Entergy Arkansas Inc. or EAI WBL contract is proposed to be included in the cost of service and is part of Dr. Goins' analysis. The two components of the purchase power adjustment are discussed in detail below.

1 IV. COST OF SERVICE ADJUSTMENTS

3 Q. PLEASE DESCRIBE THE COST OF SERVICE ADJUSTMENTS YOU ARE 4 RECOMMENDING.

5 A. I am recommending the following cost of service adjustments: 6 1. Purchased Capacity Costs; 7 2. Natural Gas Storage; 8 3. Coal Inventories; 9 4. Renewable Energy Credit Rider; 10 5. Cost of Service Model quantification of adjustments 11 provided by other Cities witnesses; and 12 6. Customer Class Allocation 15 A. PURCHASED CAPA CITY COSTS Q. WHAT ISSUE ARE YOU ADDRESSING IN THIS SECTION OF YOUR 17 TESTIMONY?

18 A. In this section of my testimony I develop the MSS-4 and third party purchased power 19 capacity costs for inclusion in base rates.

DIRECT TESTIMONY 7 NALEPA Q. DID THE COMPANY ORIGINALLY REQUEST A RECONCILABLE 3 PURCHASED POWER RIDER?

4 A. Yes. Originally, ETI filed this case requesting a total purchase power amount 5 (including MSS-1, MSS-4, and third party capacity purchases) of $276,242,239 3 6 which would be part of a Purchased Power Rider ("PPR") and subject to periodic 7 reconciliation. 4 Thus, the fact that the Company's forecast and estimate of future 8 purchase power levels of $276,242,239 could be overstated was of little concern to 9 ETI because under the original proposal, such amounts would be subject to periodic 10 reconciliation and true-up to actual levels.

11 Now that the Commission has ruled that a PPR will not be authorized in this 12 proceeding, the Company has requested that the full estimated purchase power 13 amount of $276,242,239 be included in base rates. The problem with the Company's 14 proposal to include the entire $276,242,239 estimate in base rates is that there is no 15 future reconciliation for excess purchase power estimates. Furthermore, the 16 Company has mixed and matched apples and oranges by including a forecast of rate 17 year purchase power costs with test year end billing determinates. Under the 18 Company's approach of mixing estimated rate year costs with test year billing units, 19 there is a failure to recognize customer growth and increased sales revenue-thus 20 overstating the revenue requirement. And while it is true that a reconciliation 21 mechanism, such as proposed by ETI, may alleviate any excess earnings caused by an 22 overestimate of capacity costs or a mismatch of test year costs to rate year billing ETI Schedule Q-8.8, ETI Proposed Tariffs at page 44.5.

Direct Testimony of Phillip May, p. 5-6.

DIRECT TESTIMONY 8 NALEPA 1 determinates, ETI should not be permitted to overestimate capacity costs to 2 artificially create its own need for a reconcilable PPR.

4 Q. PLEASE PROVIDE AN EXAMPLE DEMONSTRATING THE BIAS IN ETI'S 5 APPROACH AND THE PROPER METHOD OF ADJUSTING RA TE YEAR 6 PURCHASED POWER COSTS FOR TEST YEAR CAPACITY LEVELS?

7 A. Assume that a utility has one cost-purchase power capacity-and a test year 8 purchase power cost of $100.00 for 100 kW of capacity to serve test year load of 100 9 kW (including reserves). The test year rate would be $1.00 /kW shown in Table 2: 10 TABLE2 Test Year Total Capacity Costs $100.00 Capacity to Serve Load lOOkW Capacity Cost Embedded in Rates $1.00 /kW

12 Now, if during some future period this utility needs 50 more kW for an increase in 13 load and it can acquire the 50 kW of capacity for $50, then the cost of capacity 14 embedded in rates--$1 /kW of supply-would be sufficient to recover the additional 15 costs. This is demonstrated in Table 3 below: 16 TABLE 3 Test Year Future Year Total Capacity Costs $100.00 $150.00 Capacity to Serve Load 100 kW 150 kW Cost of Capacity $1.00 /kW $1.00 /kW Capacity Cost Embedded in Rates $1.00 /kW $1.00 /kW

DIRECT TESTIMONY 9 NALEPA Under the above scenario, no change in the rate would be necessary to recover the 2 additional costs of acquiring the additional kW of capacity. But, if the added 50 kW 3 cost $1.50 /kW, or $75.00, the utility would need an increase in rates of $0.1667 to 4 recover the incremental costs, as shown in Table 4: 5 TABLE4 Test Year Future Year Total Capacity Costs $100.00 $175.00 Capacity to Serve Load 100 kW 150kW Cost of Capacity $1.00 /kW $1.1667 /kW I

I Capacity Cost Embedded in Rates $1.00 /kW $1.00 /kW Difference $0.1667 /kW

7 Under the Company's approach in this case, ETI would ignore the fact that it already 8 collects $1.00 of revenues under the existing rate and requests the full $1.50 9 incremental increase for the added 50 kW. This would lead to an over-collection of 10 revenues by the Company and would result in excess profits for shareholders.

12 Q. DO YOU AGREE WITH THE COMPANY'S REQUESTED AMOUNT?

13 A. No, the $276,242,239 purchased power capacity amount is not reasonable and is 14 excessive.

16 Q. WHY IS THE REQUESTED AMOUNT NOT REASONABLE?

17 A. I compared the requested purchased power capacity expenses to the test year amount 18 in this proceeding. Table 5 summarizes these values:

DIRECT TESTIMONY 10 NALEPA TABLE 5 Source Test Year Rate Year MSS-1 $25,461,352 MSS-4 $189,032,441 Third Party $30,818,009 Total $245,311,802 $276,242,239 2 ETI' s request is almost $31 million higher than its test year capacity costs.

4 Q. WHAT HAS CAUSED THIS DRAMATIC INCREASE IN COSTS?

5 A. While the MSS-1 and MSS-4 rate year requests are actually less than the test year 6 amount, the rate year third party purchases are more than • million higher than the 7 test year. This increase is mostly attributable to three new purchased power 8 agreements. These are with Exelon-Frontier, which added 150 MW to its existing 150 9 MW contract beginning May 2011, Calpine-Carville, which will add 243 MW (50% 10 of 485 MW) for a ten year term beginning June 2012, and 225 MW with Sam 11 Rayburn Municipal Power Agency ("SRMP A") for a 25 year term beginning 12 December 2011. 5

14 Q. HOW DOES THE COMP ANY'S PROPOSAL ADVERSELY AFFECT 15 CUSTOMERS?

16 A. The Company is contracting for capacity resources to meet future demand, but is 17 intending to recover these costs from current customers. As discussed earlier, 18 dividing projected rate year costs by test year adjusted billing determinants results in

Direct Testimony of Robert Cooper, p. 16-17.

DlRECT TESTIMONY 11 NALEPA 1 a violation of the matching principal of ratemaking. Commission Rules require that 2 only the electric utility's historical test year expenses as adjusted for known and 3 measurable changes will be considered in allowable expenses. Post test year 4 adjustments for known and measurable rate base additions to historical test year data 5 will be considered in part only where the attendant impacts on all aspects of a utility's 6 operations (including but not limited to, revenue, expenses and invested capital) can 7 with reasonable certainty be identified, quantified and matched. And while this 8 section of the Rule refers to rate base additions, the concept of matching a post test 9 year adjustment with its attendant impacts applies to post test year expense 10 adjustments as well. In fact, prior versions of the Substantive Rules did require this: 11 to 12 revenue, 17 The development of the proposed purchased capacity costs should correspond with 18 the billing determinants used to calculate the rates.

20 Q. WHAT AMOUNT OF CAPACITY COSTS DO YOU PROPOSE BE 21 INCLUDED IN RATES?

22 A. I propose that third party capacity costs be calculated using the average cost of the 23 Company's third party rate year capacity applied to the test year end capacity. In this 24 way, the increased cost of the new resources is recognized, but current demand is Rule §25.231 (b ).

Rule §25.23 l(c)(2)(F).

Docket No. 1175, Texas Urilities Electric For General Counsel Into The Texas Utilities

DIRECT TESTIMONY 12 NALEPA l better matched to current resources. My Attachments KJN-3 and KJN-4 detail the test 2 year and rate year capacity and capacity costs. The Company's proposed rate year 3 capacity cost o f - divided by the total capacity of 12,834 annual MW (or 4 an average 1,070 kW/mo) yields an average rate of . This compares to 5 the test year cost of $5.08 /kW/mo. Multiplying the test year end third party capacity 6 of 671 MW (or 8,052 annual MW) by the average rate year cost yields third party 7 , which is an increase o f - over the test year 8 but a reduction of I 111 to the Company's proposed third party capacity costs.

9 These calculations are summarized in Table 6.

10 TABLE 6 Third Party Capacity Cost Calculation Rate Year Proposed Annual Average Average Test Year Annual Capacity Monthly Monthly End Capacity Cost Capacity Rate Capacity Cost 1,070 MW 671 MW Q. DO YOU MAKE ANY ADJUSTMENTS TO ETI'S PROPOSED MSS-4 13 CAPACITY COSTS?

14 A. Yes. I recommend an adjustment to the EAI WBL contract expense, included in its 15 MSS-4 tariff.

17 Q. PLEASE DESCRIBE THE EAi WBL CONTRACT.

18 A. The contract is with affiliate Entergy Arkansas, Inc. for wholesale baseload resources 19 ("EAi WBL"), selected as a result of Entergy's July 2009 Baseload RFP. ETI was 20 allocated 31. 7% of the 336 MW capacity associated with the units that make-up this

DIRECT TESTIMONY 13 NALEPA 1 WBL resource. 9 It consists of a portion of EAI's nuclear and coal generating capacity 2 as summarized in Table 7: 10 3 TABLE 7 Resource Total ~+--~ Capacity.-"---1~---'

Total 3,455 336 Q. WHAT IS YOUR ADJUSTMENT?

6 A. The original term of the EAI WBL contract was for three years ending December 31, 7 2012.

8 My adjustment recognizes that the contract will expire only 18 months after the rates 9 are expected go into effect in this proceeding. Assuming that ETI' s rates will be in 10 effect for three years, I recommend that the EAI WBL contract be "normalized" over ]1 the three year period.

Docket No. 37744, Direct Testimony of Robert Cooper, p. 27.

Jd., WP/RRC Testimony 2 (Highly Sensitive) ETI Response to TIEC 5-1 (Highly Sensitive).

DIRECT TESTIMONY 14 NALEPA Q. WHAT IS YOUR BASIS FOR ASSUMING THAT ETI'S RATES WILL BE IN 2 EFFECT FOR THREE YEARS?

3 A. Three years is a common assumption for the time period between rate changes. For 4 example, in this proceeding, ETI proposes to amortize over three years its expected 5 MISO transition costs. 12

7 Q. PLEASE EXPLAIN THE COMPANY'S AMORTIZATION OF MISO 8 TRANSITION COSTS.

9 A. ETI is proposing two adjustments to rates in this proceeding regarding its MISO 10 transition costs. First, it seeks to defer expenses incurred after January 1, 2012 related 11 to its proposed transition to membership in the MISO regional transmission 12 organization. Its request for deferral was filed in Docket No. 39741, but was 13 subsequently consolidated with this proceeding. 13 Second, if the Company is not 14 granted deferred accounting, then it proposes to amortize its projected MISO 15 transition expenses of $12 million over 3 years and recover the amount of $4 million 16 annually in account 575100. 14

18 Q. HOW DO YOU NORMALIZE THE EAi WBL CONTRACT?

19 A. The rates in this proceeding are expected to be effective July 2012, based on the 20 agreed procedural schedule. ETI has projected rate year EAI WBL contract expense

Direct Testimony of Michael Considine, p. 21-22.

Docket No. 39741, SOAH Order No. 2.

WP P AJ16.20-16.23L.

DIRECT TESTIMONY 15 NALEPA 15 16 1 of-, but has subsequently revised this amount to Since 2 the contract will expire half way through the expected period that the rates will be 3 effect, I recommend that only half the contract expense be included in rates. This 4 ensures that the Company collects in rates only the capacity expenses that it actually 5 incurs. Therefore, I recommend the amount of capacity expense for the EAI WBL 6 I , a reduction of - from the 7 Company's requested amount. I have provided this adjustment to Dr. Goins for 8 inclusion in his overall purchase power capacity adjustment.

10 Q. WHAT ARE MSS-1 PAYMENTS?

11 A. Service Schedule MSS-1 (called "Reserve Equalization" in the Entergy System 12 Agreement) prescribes a method for sharing some of the fixed costs of generating 13 capability among Entergy Operating Companies. Some Operating Companies own 14 more than their share of the System's total capability relative to their load, and thus 15 are "long" or own more than their share of System reserves. Other Companies own 16 less than their share, or are "short." A short company makes a payment for the MW 17 by which it is short. The payments are computed monthly by multiplying the 18 company's MW shortfall times a $/MW rate for the cost of owmng reserve 19 ·1· 17 capab11ty.

Direct Testimony of Robert Cooper, Exhibit RRC-1 (Highly Sensitive).

Jd., Revised Exhibit RRC-1 (Highly Sensitive).

Direct Testimony of Patrick Cicio, p. 11-15.

DIRECT TESTIMONY 16 NALEPA Q. DO YOU MAKE ANY ADJUSTMENTS TO ETI'S PROPOSED MSS-1 2 CAPACITY COSTS? ,.., .) A. No, I recommend the Company's updated level of MSS-1 capacity costs of 4 - , which was revised from the Company's original request of 5 l . 19 I provided this updated MSS-1 value to Dr. Goins for use in his 6 purchase power analysis in this case.

8 Q. WHAT IS YOUR TOTAL PURCHASED CAPACITY RECOMMENDATION?

9 A. I recommend total purchased capacity expense of $236,838,634, which is a reduction 10 of $38,970,851 from the Company's request, as summarized in Table 8.

TABLE 8 Source City MSS-1 MSS-4 Total $275,809,485 $236,838,634

11 Q. DO YOU HAVE ANY OTHER COMMENTS RELATED TO ETl'S 12 PURCHASED CAPACITY REQUEST?

13 A. Yes. While Cities' are opposed to a purchase power rider as proposed by ETI, to the 14 extent that this proceeding is used to establish a baseline for purchased capacity costs, 15 any baseline should reflect the unit cost of capacity, i.e., $/kW, rather than simply 16 total dollars. As I discussed earlier in my testimony, the unit cost provides a more 17 accurate measure of the level of capacity costs required by the utility. In my Direct Testimony of Robert Cooper, Revised Exhibit RRC-1 (Highly Sensitive).

Id., Exhibit RRC-1 (Highly Sensitive).

DIRECT TESTIMONY 17 NALEPA 1 Attachments KJN-3 and KJN-4, the total dollars as well as the total kW purchased 2 power capacity supply and owned generation is provided.

3 B. NATURAL GAS STORAGE Q. WHY ARE YOU ADDRESSING NATURAL GAS STORAGE COSTS?

5 A. As I discuss in the following section of my testimony, based on the Company's filed 6 or claimed costs the SpindletopGas Storage Facility ("Spindletop") costs $13,078, 188 7 per year to operate. ETI can achieve the same supply reliability and flexibility 8 benefits derived from Spindletop through other alternative gas supply options at an 9 alternative cost of $ 1, 724,659 per year. Thus, eliminating Spindletop saves 10 customers $11,353,529 per year. It would be imprudent to continue including 11 Spindletop in rates.

13 Q. WHAT IS THE ISSUE WITH THE COMPANY'S NATURAL GAS STORAGE 14 FACILITY?

15 A. The Spindletop facility costs customers approximately $13,078, 188 annually. The 16 costs are detailed in Table 9:

DIRECT TESTIMONY 18 NALEPA l TABLE 9 SPINDLETOP GAS STORAGE FACILITY TOT AL COST IMP ACT Component Amount Source Return Component Net Plant $5,974,070 Cities 7-73 Gas lnventorJI $42,327,554 Schedule E-2.3 Rate Base $48,301,624 Rate of Return Long Tenn Debt 0.03376777 Schedule K-1 Common Equity 0.05291520 Schedule K-1 Tax Adjustment 1.53846154 Adjusted Common Equity 0.08140800 Adjusted Rate of Return 0.11517577 Return $5,563, 177 Depreciation Expense $309,751 Cities 7-74 Other Taxes Ad Valorem Taxes $1,780,365 Cities 7-72 Total Base Rate Costs $7,653,293

Spindletop Storage Total Eligible Fuel Costs $5,424,895 Exhibit KDM-13 Total Annual Cost $13,078, 188

2 Q. ARE THESE CHARGES TO CUSTOMERS REASONABLE OR JUSTIFIED?

3 A. No. Spindletop costs customers about $13 million during the test year. However, the 4 facility is not used to provide any necessary services that are not provided by other 5 gas transportation contracts or balancing agreements of ETI. Table 10 provides a cost 6 benefit analysis comparing the costs ETI would incur to acquire the same services 7 that were provided by the Spindletop facility.

DIRECT TESTIMONY 19 NALEPA TABLElO Storage Base Rate Variable Total Alternative Total Withdrawals/ Storage Storage Storage Transport Call Alternative Net Cost Month Adjustments Costs Costs Costs Costs Options Costs (e h) a b e d e f g h I 7/10 1,248,176 $637,774 $ 769,753 $1,407,527 $ 224,672 $ 26,250 $ 250,922 $1,156,605 8/10 1,000,525 $637,774 $ 112,203 $ 749,977 $ 180,095 $ 26,250 $ 206,345 $543,632 9/10 715,348 $637,774 $ 419,413 $ 1,057,187 $ 128,763 $ 26,250 $ 155,013 $902,174 10/10 831,584 I $637,774 I $ 449,539 $ 1,087,313 $ 149,685 $0 $ 149,685 $937,628 ·- 11/10 413,276 $637,774 $ 433,368 $ 1,071,142 $ 74,390 $0 $ 74,390 $996,752 12/10 288,652 $637,774 $ 130,669 $ 768,443 $51,957 $0 $ 51,957 $716,486 1/11 411,742 $637,774 $ 338,323 $ 976,097 $74,114 $ 26,250 $ 100,364 $875,733 2/11 601,934 $637,774 $ 612,537 $ 1,250,311 $ 108,348 $ 26,250 $ 134,598 $1,115,713 3/11 580,673 $637,774 $ 667,727 $ 1,305,501 $ 104,521 $ 26,250 $ 130,771 $1,174,730 4/11 766,831 $637,774 $ 606,674 $ 1,244,448 $ 138,030 $0 $ 138,030 $1,106,418 5/11 827,689 $637,774 $ 574,684 $ 1,212,458 $ 148,984 $0 $ 148,984 $1,063,474 6/11 874.174 $637,774 $310,005 $ 947,779 $ 157,351 $ 26.250 $ 183,601 $764,178 Total 8,560,604 $ 7,653,293 $ 5,424,895 $ 13,078,188 $ 1,540,909 $ 183,750 $ 1,724,659 $11,353,529 3 As shown above, ETI' s charges to customers associated with the Spindletop gas 4 storage facility are about $ 11.4 million more, annually, than the cost of providing 5 comparable services. Even so, I recommend that the full amount of costs associated 6 with the Spindletop facility be removed from cost of service because ETI does not use 7 or need the Spindletop facility, as more fully detailed below. No other Entergy 8 Operating Company owns or leases its own gas storage facility 20 and the supply 9 reliability and swing flexibility provided by Spindletop is obtained under other 10 existing gas supply and transportation contracts at a much lower cost. Moreover, 11 other Entergy Operating Companies do not even contract for the transportation and 12 balancing agreements ETI acquires for its Texas gas generating facilities.

Response to Cities 18-15.

DIRECT TESTIMONY 20 NALEPA Q. WHAT WAS THE STATED PURPOSE OF THE SPINDLETOP GAS 2 STORAGE FACILITY WHEN IT WAS ORIGINALLY PLACED IN 3 SERVICE?

4 A. Gulf States Utilities ("GSU"), the predecessor to ETI, first raised the issue of the 5 benefits of the gas storage facility in Docket No. 10894. In that proceeding, GSU 6 alleged that the purpose of using the Spindletop Facility was to provide the 7 maximum/minimum swing requirements presently supplied by GSU's existing 8 suppliers. GSU further stated that the gas storage facility provided the same benefits 9 to customers, but at a much lower cost: 10 There is only one basic difference between the SGT agreement and 11 other transportation agreements-the SGT agreement is a far better 12 deal for ratepayers. . . . . As a result of the SGT arrangement, 13 ratepayers will receive transportation and swing services at a very 14 reasonable price in the near term and at an extremely low price 15 following payoff of the facility costs. These benefits are reflected in 16 the Company's cost benefit analysis, which shows net savings ranging 17 from $10 to $15 million per year through year eight and then 18 increasing to approximately $25 million per year thereafter, following 19 payoff of the facility. 21 21 The Company's cost benefit analysis relies on costly firm transportation backed up by 22 third party storage to provide equivalent reliability and flexibility. While this might 23 have been necessary in 1992 when the study was prepared, the Company now admits 24 that it can obtain sufficient reliability and flexibility without these more expensive 25 options. I discuss this in more detail later in my testimony.

Docket No. 10894, Reply Briefof GSU at 102-103.

DIRECT TESTIMONY 21 NALEPA Q. WHAT IS THE STATED PURPOSE OF THE SPINDLETOP GAS 2 STORAGE FACILITY TODAY?

3 A. Ms. Mcllvoy explains that the primary benefits derived from the storage facility are 4 increased supply reliability and swing flexibility. In the event of a total curtailment of 5 supply, Spindletop is capable of providing 100 percent of the fuel requirements for all 6 five units at Sabine Station and either one of the Lewis Creek units for a period of up 7 to four days, at a 70 percent capacity factor. The storage facility also provides 8 flexibility of gas supply to Sabine Station and Lewis Creek, both on a daily and 9 . mstantaneous bas1s. . 22

11 Q. HOW DO OTHER ENTERGY OPERATING COMPANIES OBTAIN SUPPLY 12 RELIABILITY AND SWING FLEXIBILITY?

13 A. According to Ms. Mcllvoy, other operating companies obtain supply reliability and 14 swing flexibility simply through the companies' monthly, daily, and intra-day natural 15 gas supply contracts. 23 Entergy Gulf States Louisiana ("EGSL") for example has no 16 firm transportation contracts, no firm supply contracts, and no fuel oil back-up at its 17 generating plants in Louisiana. The only cost incurred by EGSL for reliability and 18 flexibility is the commodity cost of the gas purchased at its generating plants. 25

Direct Testimony of Karen Mcllvoy, p. 32-33.

Deposition of Karen Mcllvoy, p. 32.

Id., p. 26-29.

Id., p. 33.

DIRECT TESTIMONY 22 NALEPA Q. DO THE OTHER OPERATING COMPANIES EXPERIENCE THE SAME 2 LEVEL OF SERVICE AS ETI?

3 A. Ms. Mcllvoy claims that ETI provides a much higher level of service than does 4 EGSL, reasoning that Spindletop would protect ETI's operations in the event of an 5 extreme gas curtailment such as a hurricane or freeze-off, because it would allow ETI 6 to operate for four days without the need to obtain gas from outside sources. 26 Even 7 Ms. Mcllvoy admits, however, that EGSL is subject to the same risks for hurricanes 8 and freeze-offs as is ETI, and that the Entergy System has nonetheless determined 9 that EGSL does not need firm transportation contracts, firm supply contracts, fuel oil 10 back-up, or gas supply backed up by gas storage at its generating plants. And while 11 EGSL is backed up by other generating units and purchased power in the event of the 12 loss of fuel supply, so is ETI. 27 In short, the options for reliability and flexibility at 13 EGSL also exist at ETI, without incurring the cost of the Spindletop facility for the 14 Louisiana generating plants.

16 Q. YOU MENTIONED THAT ONE REASON THAT ETI MAINTAINS 17 SPINDLETOP IS FOR PROTECTION AGAINST EXTREME EVENTS SUCH 18 AS HURRICANES. DO YOU HA VE ANY ADDITIONAL COMMENTS ON 19 THIS?

20 A. Yes. The Company testified that the Spindletop facility was out of service for nearly 21 2 weeks when Hurricane Rita made landfall in 2005. 28 While the facility was

26/d., p. 44. /d., p. 44-46.

Docket No. 32710, Rebuttal Testimony of KenroyHinkson, p. l 0.

DIRECT TESTIMONY 23 NALEPA 1 prudently evacuated for safety reasons, this event highlights the fact that the facility 2 was not available for the specific purpose the Company argues makes it valuable.

4 Q. PLEASE SUMMARIZE THE FINDINGS RELATED TO THE SPINDLETOP 5 NATURAL GAS STORAGE FACILITY THAT YOU DEVELOPED EARLIER 6 IN YOUR TESTIMONY.

7 A. The Company could, and has, entered into long term gas supply and transportation 8 agreements that provide the same reliability and flexibility as the Spindletop facility, 9 at a lower cost. Therefore, I adjusted storage costs incurred during the reconciliation 10 period to reflect the reasonable cost of providing these services to customers.

12 Q. WHAT WERE THE TEST YEAR COSTS ASSOCIATED WITH THE 13 FACILITY?

14 A. Table 9 summarizes the test year expenses associated with the Spindletop facility.

15 Total base rate costs are $7,653,293 and total variable non-gas operating costs 16 recovered in the fuel factor are $5,424,895.

18 Q. CAN YOU ESTIMATE THE TOTAL COST OF OPERATING THE 19 SPINDLETOP FACILITY?

20 A. Yes. The sum oftest year base rate and variable O&M costs is $13,078,188. These 21 costs divided by the sum of the test year withdrawals and adjustments of 8,560,604 22 MMBtu, results in an all-in per unit rate of $1.53 per MMBtu. 29

($7,653,293 $5,424,895) I (8, l 06,576 + 454,028) = $1.53 per MMBtu.

DIRECT TESTIMONY 24 NALEPA Q. PLEASE SUMMARIZE THE ALTERNATIVES TO STORAGE THAT 2 PROVIDE SUPPLY RELIABILITY AND SWING FLEXIBILITY TO THE 3 SABINE AND LEWIS CREEK STATIONS.

4 A. Effective December 2008, ETI entered into a long-term gas supply and transportation 5 agreement with Enbridge Pipeline L.P. The agreement will provide increased supply 6 reliability at Lewis Creek and Sabine because the supply associated with the Enbridge 7 agreement is from the Barnett Shale and East Texas production areas rather than the 8 prior south Texas and Louisiana Gulf Coast production areas, which are susceptible 9 to tropical weather related disruptions. The agreement adds diversity to ETI's supply 10 portfolio and therefore reduces the dependence on the other intrastate pipelines at 11 both plants. 30 12 In addition, spot gas to meet swing requirements can be delivered through 13 multiple pipeline connections at both plants, 31 and The Company can even take 14 advantage of imbalances under its operational balancing agreement with TETCO 15 pipeline for hourly swing flexibility, depending on operating conditions. 32 Other 16 pipelines provide swing service as well. For instance, Capano Pipeline serving the 17 Lewis Creek plant,

Docket No. 37744, Direct Testimony of Devon Jaycox, p. 15-17.

Schedule I-6.

Response to Cities RFI 18-14.

Schedule I-6, Intrastate Gas Transportation Agreement with Copano Pipeline (Highly Sensitive).

DIRECT TESTIMONY 25 NALEPA Q. CONSIDERING THESE OTHER OPTIONS, DID YOU DO A COST 2 BENEFIT STUDY OF THE SPINDLETOP FACILITY?

3 A. Yes, I did. The results are presented above in Table 10. Based on the operating plans 4 for EGSL's generating plants, sufficient reliability and swing flexibility can be 5 obtained through the existing natural gas supply and transportation contracts at 6 Sabine and Lewis Creek. Compared to the $1.53 per MMBtu cost of operating the 7 Spindletop facility, transportation on various pipelines connected to Sabine and Lewis 8 Creek ranged from 2.5¢ to 22¢ per MMBtu. I used as an average transportation rate 9 the margin between the average cost of gas delivered to the Sabine Station and the 10 Gas Daily Houston Ship Channel Index. This average margin is 18¢ per MMBtu and 11 is a reasonable rate because Spindletop primarily serves the Sabine Station and the 12 daily index best represents the supply flexibility described by Ms. Mcllvoy in her 13 deposition. I then added call options to provide the additional supply reliability that 14 ETI claims is provided by storage. I included call options on 35,000 MMBtu/d for 5 15 days at a cost of $0.15 per option, and purchased options for June through September 16 and January through March. These assumptions are consistent with the Company's 17 experience during the last rate case. 34 18 Using 18¢ per MMBtu as the replacement cost of providing flexibility and the 19 call options to provide reliability, the cost of the test year Spindletop withdrawals and 20 adjustments of 8,560,604 MMBtu would have been $1,724,659. On a total cost basis, 21 the Spindletop facility costs $13 .1 million per year to operate compared to $1. 7 22 million for the same amount of gas delivered by other existing contracts. ETI could

Docket No. 37744, Direct Testimony of Devon Jaycox, Exhibit DSJ-2.

DIRECT TESTIMONY 26 NALEPA 1 save its customers $11.4 million per year by simply relying on its other supply 2 options and selling the facility or at least removing it from regulated service ,., .J

4 Q. WHAT IS YOUR RECOMMENDATION REGARDING THE COST TO 5 OPERATE AND MAINTAIN THE SPINDLETOP STORAGE FACILITY?

6 A. No other Entergy Operating Company owns its own gas storage facility 35 and the 7 supply reliability and swing flexibility provided by Spindletop can be obtained under 8 other existing gas supply and transportation contracts at a much lower cost.

9 Therefore, the costs outlined in Table 9 should be removed from the cost of service 10 and fuel factor. Total base rate costs to be removed are $7,653,293 and the 11 Commission should also exclude as an eligible fuel expense the variable non-gas 12 operating costs of the Spindletop facility. During the test year these costs were 13 $5,424,895. I will discuss the non-gas operating costs that should be excluded from 14 the reconciliation period in the fuel reconciliation portion of my testimony.

16 C. COAL INVENTORIES 17 Q. WHY DOES THE COMP ANY REQUIRE COAL INVENTORIES?

18 A. Coal is obtained from the Power River Basin ("PRB") in Wyoming and delivered by 19 rail, 36 so coal inventories are maintained at ETI's coal-fired power plants to help

Response to Cities 18-15.

Direct Testimony of Ryan Trushenski, p. 6-7.

DIRECT TESTIMONY 27 NALEPA 1 mitigate delivery uncertainties, physical measurement uncertainties, and plant 2 . equipment f:m·1 ures. ·37

4 Q. WHAT ARE THE COMPANY'S TARGET INVENTORY LEVELS?

5 A. For Nelson 6, the current inventory policy provides for (1) a base target of 290,000 6 tons (36 days) of inventory and (2) an average annual inventory target of 340,000 7 tons (43 days). 38

9 Q. WHAT LEVEL OF COAL INVENTORY IS THE COMPANY REQUESTING?

10 A. ETI is requesting an average test year inventory level of $6,740,528. 39 This reflects its 11 actual inventory level at test year end of approximately - tons and is equivalent 12 to approximately. days of inventory at full burn. 40

14 Q. DO YOU AGREE WITH THE COMPANY'S REQUESTED LEVEL OF 15 INVENTORY?

16 A. No. Figure 1 compares the actual and target inventory levels.

Schedule E-2.1.

Schedule E-2.3.

ETI Response to Cities 6-28 (Highly Sensitive).

DIRECT TESTIMONY 28 NALEPA FIGURE 1

HIGHLY SENSITIVE MATERIAL REDACTED

2 The Company's actual inventory levels far exceed its target inventory level. Since the 3 Company has established that its average target inventory of 43 days at Nelson 6 is 4 sufficient to meet its reliability requirements, there is no reason to require customers 5 to pay for more than this level of inventory. In other words, customers should not be 6 responsible for paying for inventory levels over and above the inventory levels the 7 Company determined to be reasonable and necessary. Therefore, I recommend that 8 the 43 day coal inventory level amount be included in rate base, resulting in a revised 9 inventory level for Nelson 6 of $4,381,988 and reducing the Company's requested 10 inventory level by $2,358,540.

DIRECT TESTIMONY 29 NALEPA D. RENEWABLE ENERGY CREDIT RIDER Q. PLEASE DESCRIBE RENEW ABLE ENERGY CREDITS.

3 A. To encourage the development of renewable energy technologies and to meet the 4 State's goals for renewable capacity, the Commission has adopted a set of rules 5 governing the issuance and trading of Renewable Energy Credits ("RECs"). 41 A 6 "retail entity" must hold RECs equal to its proportionate share of sales based on the 7 State's renewable energy goals on an annual basis, and a generator will earn RECs 8 when it generates energy from a renewable energy resource.

10 Q. HOW ARE REC COSTS CURRENTLY RECOVERED?

11 A. REC costs are currently recovered through base rates. 42

13 Q. HOW IS THE COMPANY PROPOSING TO TREAT ITS PURCHASE OF 14 RENEWABLE ENERGY CREDITS?

15 A. The Company is requesting approval of a Renewable Energy Credit Rider ("REC") in 16 this case. It proposes to shift recovery of its renewable energy credit costs from base 17 rates to the REC Rider. The initial amount to be included in the Rider is $633,985, 18 based on test year REC costs. 43 The grossed up amount will be divided by non- 19 transmission level KWh sales and applied to applicable retail rate schedules.

20 Customers taking transmission level service are eligible to opt out of the Rider. 44

16 TAC §25.173. Goa/for Renewable Energy.

Direct Testimony of Heather LeBlanc, p. 25.

ETI Schedule Q-1 (Rev.) /bid., p. 26.

DIRECT TESTIMONY 30 NALEPA Q. HOW WOULD THE REC RIDER BE ADJUSTED AS COSTS CHANGE 3 OVER TIME?

4 A. The Company proposes that the tariff be updated on an annual basis and on or before 5 May 1, beginning in 2013, a redetermination of purchased power rates would be 6 made. The revised rate will include: 45 7 • renewable energy credit costs that the Company expects to incur during 8 the twelve-month period beginning June l immediately following the 9 filing; 10 • a true-up adjustment for past over(under)-recovery of Rider REC revenue; 11 and 12 • any corresponding revenue-related expenses associated with the recovery 13 of the above costs Q. WHY IS THE COMPANY PROPOSING THE RIDER IN THIS CASE?

16 A. The Company argues that because RECs are mandated by law, the costs are variable, 17 and because certain customers can opt out of the Rider, the REC Rider is the most 18 efficient method to recover the costs. 46

20 Q. DO YOU AGREE WITH THE COMPANY'S PROPOSAL?

21 A. No. The Commission should not permit the Company to single out REC costs from 22 base rates. It has presented no evidence that suggests the costs should be treated 23 differently than they are now. RECs are not related to fuel so much as they are related 24 to retail sales and plant output. And RECs must be held to meet the renewal energy

DIRECT TESTIMONY 31 NALEPA 1 rules but the purchase and sale of the RECs are not related to fuel consumption at all.

2 For example, these transactions have occurred generally on an annual basis, as 3 summarized in Table 11 for the years since 2006. 47 TABLE 11 I Year Month Amount 2006 March $323,561 2007 March $390,864 2008 March $873,064 2009 January $367,500 February $185,000 March $138,616 2010 June $378,469 2011 Mar $584,000 I Apr $47,803

4 Q. WHAT AMOUNT OF REC EXPENSE DO YOU RECOMMEND BE 5 INCLUDED IN BASE RATES?

6 A. I recommend the adjusted test year amount of $633,985.

8 E. COST OF SERVICE MODEL Q. ARE THE CITIES PROPOSING AN OVERALL REVENUE REQUIREMENT 10 IN THIS PROCEEDING?

11 A. Yes. I am sponsoring a cost of service model based on the Company's model, and 12 have compiled the adjustments to the Company's proposed revenue requirement 13 recommended by each of the Cities' experts. The cost of service model is included as 14 Attachment KJN-1.

Response to Staff RFI 2-8 and State of Texas RF! 4-10.

DIRECT TESTIMONY 32 NALEPA Q. HOW WAS THE COST OF SERVICE MODEL DEVELOPED?

2 A. The cost of service model is a reproduction of the Company's model. It incorporates 3 all of the components of the Company's model, and generates the same results as the 4 Company's model prior to any adjustments by the City.

6 Q. ARE YOU SPONSORING THE CITIES' ADJUSTMENTS TO THE COST OF 7 SERVICE MODEL?

8 A. No. I have compiled the adjustments to the cost of service model, but I am only 9 sponsoring the model. The individual experts sponsor their own adjustments. A 10 summary of the adjustments proposed by Cities' experts is included in my 11 workpapers.

13 Q. WHAT IS THE CITIES' PROPOSED REVENUE REQUIREMENT?

14 A. The Company is proposing a total revenue requirement of $1 ,493.5 million, which is 15 an increase of $111. 8 million over current revenues. 48 The Cities' proposed revenue 16 requirement is $1,367.5 million, which is $126.0 million less than the Company's 17 proposed revenue requirement and approximately $14.2 million less than current 18 revenues. Although Cities adjustments would support a decrease in current rates, 19 Cities are recommending that the rates set by agreement and approved by the 20 Commission in Docket No. 37744 remain in effect.

Schedule Q-1.

DIRECT TESTIMONY 33 NALEPA 1 F. COST ALLOCATION

3 Q. WHAT ISSUE DO YOU ADDRESS IN THIS SECTION OF YOUR 4 TESTIMONY?

5 A. In this section of my testimony I address an alternative class cost allocation issues.

6 Specifically, I address the Company's proposed production and transmission related 7 class cost allocation employing the Average and Excess/4 Coincident Peak 8 ("A&E/4CP") allocation method. I also address the Company's complete failure to 9 recognize substantial cost changes and uncertainties occurring in the near future.

10 Q. WHAT IS THE IMPACT, BY CUSTOMER CLASS, OF THE PROPOSED 11 RATE INCREASE UNDER THE COMPANY'S COST ALLOCATION 12 METHOD?

13 A. The Company's proposed increase by customer class is set forth in Table 12:

14 TABLE12 Customer Class Increase Percent Residential $ 82,095,079 21.64% Small General $ 428,754 1.62% General $ 7,690,498 4.81% Large General $ 8,171,696 16.55% LIPS $ 11,233,897 10.77% Lighting $ 2,203,940 20.38% Total $ 111,823,864 15.32%

DIRECT TESTIMONY 34 NALEPA 1 As can be seen from the above table, the residential and lighting customer classes 2 receive the highest rate increases while the Small General Service, General Service, 3 and LIPS classes receive below system average rate increases of 1.62%, 4.81 %, and 4 10. 77%, respectively.

5 Q. HA VE THE RESIDENTIAL AND LIGHTING CUSTOMERS PLACED AN 6 INCREASED BURDEN ON THE SYSTEM DUE TO LOAD OR CUSTOMER 7 GROWTH?

8 A. No. I have examined test year customer quantities, energy and loads by customer 9 class for each of the last three cases. Residential and lighting customers are not 10 imposing an undue cost burden on the system. Instead, other classes are growing at a 11 faster rate causing system costs to increase.

12 Q. HOW DOES THE COMPANY PLAN FOR SYSTEM GROWTH TO MEET 13 PRODUCTION AND TRANSMISSION DEMANDS?

14 A. The system is planned pursuant to the requirements of the System Agreement. Under 15 the System Agreement production and transmission assets are added and costs are 16 incurred based on meeting the EOC's peak demands coincident with the System peak.

17 (See Section 2.16 of the System Agreement) Moreover, the System is planned and 18 costs are incurred to meet all twelve monthly System coincident peaks ("12 CP").

19 Cost responsibility under the System Agreement for production and transmission 20 costs (MSS-1 and MSS-2 tariffs) is assigned to each Entergy Operating Company 21 ("EOC") based on the 12 CP.

DIRECT TESTIMONY 35 NALEPA Q. ARE CHANGES OCCURRING ON THE SYSTEM THAT CAN AFFECT 2 SYSTEM AND SPECIFICALLY ETI'S COSTS?

3 A. Yes, a number of factors are occurring which will impact costs. First, the Entergy 4 Operating Company's ("EOC's") are seeking approval for a change in control and 5 joining the Midwest Independent System Operator ("MISO") as the Regional 6 Transmission Organization ("RTO"). A change to the current Independent 7 Coordinator of Transmission ("ICT") could have implications" ... for the quantity and 8 mix of resource requirements ... " 49 Thus, system production plans and costs may be 9 impacted and quite possibly substantially impacted by the MISO decision.

10 Another potential impact on System planning and costs is the fact that Entergy 11 Arkansas ("EAI") and Entergy Mississippi ("EMI") are leaving the joint system.

12 These EOC' s - EAI and EMI - have given their respective notice to exit the System 13 Agreement. The impact of EAI and EMI on the remaining four EOC Systems is not 14 known at this time, but production costs and planning will be impacted.

15 Q. ARE THERE OTHER CHANGES THAT MAY IMPACT SYSTEM COSTS?

16 A. Yes, recently Entergy Corp announced its plan to totally divest the EOC' s including 17 ETI of the transmission system. In other words, the EOC's and ETI would purchase 18 transmission service from a third party and there would be no transmission 19 investment to allocate or to plan in the future.

See 2009 Strategic Resource Plan Refresh at 5.

Idat4.

DIRECT TESTIMONY 36 NALEPA Q. GIVEN THE SUBSTANTIAL CHANGES EXPECTED TO IMPACT THE 2 SYSTEM, HOW SHOULD THE RATE CHANGES AND COST 3 RESPONSIBILITY BE ALLOCATED AMONG CUSTOMER CLASSES?

4 A. At this time, given the changes and uncertainties with MISO, the System Agreement 5 and the proposed divestiture of the entire transmission system, I propose that any 6 increase or decrease be spread proportionately across the system classes. Once 7 Entergy and ETI address the proposed system cost changes - a reasonable class cost 8 allocation study can be presented.

10 v. OVERVIEW OF ETl'S FUEL COSTS

12 Q. WHAT ARE THE COMPANY'S TOTAL FUEL AND PURCHASED POWER 13 EXPENSES DURING THE RECONCILIATION PERIOD?

14 A. For the period July 1, 2009 through June 30, 2011, ETI generated or purchased 15 44,145,144 MWh at a total cost of $1,697,471,673 or an average cost of $38.45 per 16 MWh. The Company had off-system sales of 7,778,021 MWh with total revenues of 17 $376,671,971 or average revenue of $48.43 per MWh. The net cost during the period 18 was $36.32 per MWh. 51

Direct Testimony of Gregory Zakrzewski, Exhibit GRZ-1.

DIRECT TESTIMONY 37 NALEPA Q. WHAT IS THE STANDARD BY WHICH ETI'S FUEL COSTS SHOULD BE 2 EVALUATED?

3 A. PUC Rule §25.236 (d) requires that in a proceeding to reconcile fuel factor revenues 4 and expenses, an electric utility has the burden of showing that: 5 (A) its eligible fuel expenses during the reconciliation period were reasonable 6 and necessary expenses incurred to provide reliable electric service to retail 7 customers; 8 (B) if its eligible fuel expenses for the reconciliation period included an item or 9 class of items supplied by an affiliate of the electric utility, the prices 10 charged by the supplying affiliate to the electric utility were reasonable and 11 necessary and no higher than the prices charged by the supplying affiliate 12 to its other affiliates or divisions or to unaffiliated persons or corporations 13 for the same item or class of items; and 14 (C) it has properly accounted for the amount of fuel-related revenues collected 15 pursuant to the fuel factor during the reconciliation period.

17 VI. FUEL COST ADJUSTMENTS

19 Q. PLEASE DESCRIBE THE FUEL COST ADJUSTMENTS YOU ARE 20 RECOMMENDING.

21 A. I am recommending several adjustments to fuel costs related to: 22 1. Natural Gas Storage Costs 23 2. Line Loss Factors 25 A. NATURAL GAS STORAGE COSTS Q. PLEASE DESCRIBE THE COMPANY'S NATURAL GAS STORAGE 27 FACILITY.

DIRECT TESTIMONY 38 NALEPA system that interconnects the storage caverns with Sabine Station. The Lewis Creek 2 station is served from Spindletop through interconnections with Kinder Morgan Tejas 3 Gas Pipeline, Kinder Morgan Texas Pipeline, and Copano Pipeline. In 2004, the 4 Company purchased the Spindletop gas storage facility from Spindletop Gas 5 Transmission Company. Beginning in January 2005, the Company contracted with 6 PB Energy Storage Services ("PB Energy") to operate the facilities. The payments 7 ETI makes to PB Energy are treated as fuel payments and are included in the fuel 8 reconciliation.

10 Q. WHAT IS THE PURPOSE OF THE SPINDLETOP GAS STORAGE 11 FACILITY?

12 A. As detailed earlier in my testimony, Ms. Mcllvoy explains that the primary benefits 13 derived from the storage facility are increased supply reliability and swing 14 fl ex1"b"l" 11ty. 53

16 Q. HOW HAS THE SPINDLETOP GAS STORAGE FACILITY BEEN USED?

17 A. Figure 1 shows by month the sum of daily injections and withdrawals during the 18 reconciliation period.

Direct Testimony of Karen Mcllvoy, p. 31. /d., p. 32-33. /d., Exhibit KDM-12.

DIRECT TESTIMONY 39 NALEPA 1 FIGURE 2 Spindletop Gas Inventory Activity 1,500,000 1,000,000 500,000

iii Injections D Withdrawals D Adjustments

4 Q. WHAT WERE THE ELIGIBLE FUEL COSTS ASSOCIATED WITH THE 5 FACILITY?

6 A. Table 13 summarizes the eligible fuel costs associated with the Spindletop facility.

TABLE 13 Payments to Costs Allocated to Costs Allocated to Eligible Fuel Storage Operator Injections Withdrawals Costs $10,002, 745 $(144,752) $403,670 $10,261,663

8 Q. ARE THE SPINDLETOP STORAGE COSTS REASONABLE?

9 A. No. As I discussed earlier in my testimony, the costs are not reasonable and the I0 facility should be removed from rates.

id., Exhibit KDM-13.

DrRECT TESTIMONY 40 NALEPA l Q. HA VE YOU MADE AN ADJUSTMENT TO STORAGE COSTS FOR THE 2 RECONCILIATION PERIOD?

3 A. Yes. The Company can and has entered into long term gas supply and transportation 4 agreements that provide the same reliability and flexibility as the Spindletop facility, 5 at a lower cost. I have adjusted the storage costs to reflect this alternative.

7 Q. PLEASE SUMMARIZE THE ALTERNATIVES TO STORAGE THAT 8 PROVIDE SUPPLY RELIABILITY AND SWING FLEXIBILITY TO THE 9 SABINE AND LEWIS CREEK STATIONS.

10 A. Effective December 2008, ETI entered into a long-term gas supply and transportation 11 agreement with Enbridge Pipeline L.P. The agreement will provide increased supply 12 reliability at Lewis Creek and Sabine because the supply associated with the Enbridge 13 agreement is from the Barnett Shale and East Texas production areas rather than the 14 prior south Texas and Louisiana Gulf Coast production areas, which are susceptible 15 to tropical weather related disruptions. The agreement adds diversity to ETI's supply 16 portfolio and therefore reduces the dependence on the other intrastate pipelines at 17 both plants. 56 18 In addition, spot gas to meet swing requirements can be delivered through 19 multiple pipeline connections at both plants, 57 and the Company can even take 20 advantage of imbalances under its operational balancing agreement with TETCO 21 pipeline for hourly swing flexibility, depending on operating conditions. 58 Other

Docket No. 37744, Direct Testimony of Devon Jaycox, p. 15-17.

Schedule I-6.

Response to Cities RFI 18-14.

DIRECT TESTIMONY 41 NALEPA 1 pipelines provide swing service as well. For instance, Copano Pipeline serving the 2 Lewis Creek plant,

4 Q. CONSIDERING THESE OTHER OPTIONS, DID YOU DO CALCULATE AN 5 ADJUSTMENT TO STORAGE COSTS?

6 A. Yes. Based on the operating plans for EGSL' s generating plants, sufficient reliability 7 and swing flexibility can be obtained through the existing natural gas supply and 8 transportation contracts at Sabine and Lewis Creek. Transportation rates on various 9 pipelines connected to Sabine and Lewis Creek ranged from 2.5¢ to 22¢ per MMBtu.

10 I used as an average transportation rate the margin between the average cost of gas 11 delivered to the Sabine Station and the Gas Daily Houston Ship Channel Index. This 12 average margin is 18¢ per MMBtu and is a reasonable rate because Spindletop 13 primarily serves the Sabine Station and the daily index best represents the supply 14 flexibility described by Ms. Mcilvoy in her deposition. I then added call options to 15 provide the additional supply reliability that ETI claims is provided by storage. I 16 included call options on 35,000 MMBtu/d for 5 days at a cost of $0.15 per option, and 17 purchased options for June through September and January through March. These 18 assumptions are consistent with the Company's experience during the last rate case. 60

Schedule I-6, Intrastate Gas Transportation Agreement with Copano Pipeline (Highly Sensitive).

Docket No. 37744, Direct Testimony of Devon Jaycox, Exhibit DSJ-2.

DIRECT TESTIMONY 42 NALEPA 1 Q. WHAT IS YOUR RECOMMENDATION REGARDING THE COST TO 2 OPERATE AND MAINTAIN THE SPINDLETOP STORAGE FACILITY? ,., .) A. The average operating cost of the Spindletop facility during the reconciliation period 4 was $0.56 per MMBtu. 61 I restated the average operating cost at the Spindletop 5 facility to $0.18 per MMBtu plus the call options to provide reliability for the period 6 and applied the resulting average $0.20 per MMBtu rate to the period withdrawals 7 and adjustments of 18,331,863 MMBtu. This reduces storage costs to $3,666,373, or 8 $6,595,290 less than the period amount. I addressed the base rate portion of 9 Spindletop-related costs earlier in my testimony.

11 B. LOSS FACTORS

13 Q. WHAT ISSUE DO YOU ADDRESS IN THIS SECTION OF YOUR 14 TESTIMONY?

15 A. In this section of my testimony, I recommend that the Commission approve ETI's 16 updated calculation of line loss factors and associated line loss multipliers. The line 17 loss study was performed by ETI for the annual period ending December 31, 2010, in 18 order to fairly allocate base rate demand and energy costs in this case to the wholesale 19 class and the respective retail customer classes based upon the delivery voltage level 20 of each customer. Loss factors are the actual average line losses experienced at each 21 voltage level of the ETI transmission and distribution system. Line loss multipliers 22 are the corresponding factors for each customer class, wholesale and retail, based

$10,261,663 (Exhibit KDM-13) I 18,331,863 (Exhibit KDM-12) = $0.56 per MMBtu.

DIRECT TESTIMONY 43 NALEPA upon the make-up of the various voltage level customers within that class. The 2 purpose of line loss factors and line loss multipliers is to ensure that customers, who 3 are billed for energy at the meter, are responsible for their fair share of costs incurred 4 at the plant.

6 Q. IS THERE A PROBLEM WITH CONTINUING TO USE THE LINE LOSS 7 FACTORS AND ASSOCIATED LINE LOSS MULTIPLIERS REFLECTED IN 8 ETI'S FUEL FACTOR?

9 A. Yes. ETI' s proposed tariff Schedule FF Fixed Fuel Factor62 includes loss multipliers 10 by voltage level which were calculated in a study based on the 12 months ending 11 December 31, 1997, and approved in Docket No. 19834. The loss factors by voltage 12 level used to calculate the fuel factor and any fuel factor over/(under) recovery, are 13 over 14 years old and do not represent the current cost of providing service to the 14 wholesale customers or to the various retail customer classes. ETI's own analysis 15 demonstrates that adjusting the allocation of fuel costs over the reconciliation period 16 to reflect the actual line losses for each voltage level for the reconciliation period 17 results in retail customers subsidizing wholesale customers by approximately $3.98 18 million.

Schedule Q-8.8, p. 26.1.

DIRECT TESTIMONY 44 NALEPA Q. ARE THERE MORE RECENT LOSS FACTORS AVAILABLE TO 2 CALCULATE THE FIXED FUEL FACTOR?

3 A. Yes there are. ETI performed a line loss study for the twelve months ending 4 December 31, 2010, which falls squarely within the current reconciliation period.

5 Schedule 0-6.3 of the Company's rate filing package provides the results of the line 6 loss study and ETI's amended response to Cities' RFI 6-1 provides the corresponding 7 line loss multipliers by customer class. ETI uses these loss factors to calculate the 8 demand and energy related allocation factors in its Schedule P-9 cost of service 9 analysis, but did not apply these current loss factors to its fuel factor reconciliation. In 10 ETI's response to Cities' RFI 16-9, ETI applies these line loss factors to the fuel costs 11 over the reconciliation period.

13 Q. HAVE YOU CALCULATED THE IMPACT ON THE RETAIL CUSTOMER 14 CLASS ALLOCATION OF FUEL COSTS USING THE CURRENT LOSS 15 FACTORS?

16 A. Yes I have. In response to a request for information, 63 the Company provided a 17 revised Schedule I-22A for the reconciliation period of July 2009 through June 2011 18 which was updated to reflect the actual loss factors calculated by the Company in 19 Docket No. 39896 for the annual period in the middle of the two-year reconciliation 20 period. In addition the Company provided kWh sales at the meter for each customer 21 class for the reconciliation period. Using the data provided in this RFI response, I

ET!' s Response to Cities RFI 16-9.

DIRECT TESTIMONY 45 NALEPA 1 have calculated the actual fuel costs incurred at the plant by wholesale customers and 2 retail customer classes by voltage level.

4 Q. PLEASE DESCRIBE YOUR ANALYSIS.

5 A. I first allocated the Company's proposed Fixed Fuel Factor allocable fuel cost 6 provided in the rate filing package Schedule I-22a using metered kWh adjusted for 7 losses using the 1997 loss factors. This allocation is provided on pages 2 through 6 of 8 23 in my Fuel Cost Recovery workpapers. I then allocated the fuel cost provided in 9 the updated Schedule I-22a included in the response to requests for information using 10 metered kWh adjusted for losses based on the Company's current actual loss factors.

11 This allocation is provided on pages 7 through 11 of 23 in my Fuel Cost Recovery 12 workpapers and reflects the actual fuel costs at plant incurred by wholesale and retail 13 customers at each voltage level. Pages 12 through 23 of these workpapers detail the 14 loss adjustment to metered kWh using the 1997 and current loss factors.

16 Q. PLEASE DESCRIBE THE RESULTS OF YOUR ANALYSIS.

17 A. Table 14 compares a fuel cost allocation using line losses calculated in 1997 with the 18 recommended fuel cost allocation using the Company's actual current loss factors 19 provided in Docket No. 39896.

DIRECT TESTIMONY 46 NALEPA

3 TABLE14 Cities Line Customer ETI Allocated Allocated No. Class Fuel Costs Fuei Costs Chan e (a) (b) (c) (d) RS Secondary 466, 940, 745 464,097,898 2 SGS - SA Secondary 9,079 8,858 3 SGS Secondary 25,354,289 25, 199,082 4 GS - SA Secondary 326,370 324,415 5 GS Secondary 243,253, 190 241,761,967 6 GS - SA Primary 312,020 310,920 7 GS Primary 10,904,338 10,867,331 8 GS 69/138 KV 5,087, 170 5, 104,073 9 GS 230 KV 413,814 415,688 10 LGS Secondary 76,900,410 76,427,635 11 LGS Primary 31,339,382 31,232,487 12 LGS 69/138 KV 4,095,205 4, 108,800 13 LIPS-CS Primary 8,771, 136 8,740,784 14 LPS 69/138 KV 0 0 0 15 LPS 230 KV 0 0 0 16 LIPS 69/138 KV 266,481,094 267,370,925 889,831 17 LIPS 230 KV 64,476, 161 64,748,818 272,656 18 HLFS 69/138 KV 0 0 0 19 S&OL Secondary 5,950,713 5,914, 165 20 Total Retail 1,210,615,116 1,206,633,845 Q. WHAT IS YOUR RECOMMENDATION REGARDING THE ALLOCATION 6 OF FUEL COSTS?

7 A. I recommend that the Commission approve the Company's line loss study and 8 associated line loss factors and multipliers for use in future allocations of fuel costs, 9 including the proposed future surcharge or refund for fuel factor over (under) 10 recovery. I also recommend that the Commission approve the line loss multipliers 11 calculated by ETI for use in future revisions of the fixed fuel factor tariff Schedule

DIRECT TESTIMONY 47 NALEPA 1 FF. A comparison of the current fuel factor loss multipliers and those based on the 2 current line loss study performed in Docket No. 39896 are provided in Table 15: 3 TABLEI5 Delivery Voltage 1997 Loss Multiplier 2011 Loss Multiplier Secondary 1.034603 1.021709 Primary 1.004911 0.995128 68kV/138kV 0.962921 0.960014 230kV 0.945741 0.943839 The updated 2011 Loss Multipliers were calculated by the Company and provided in the amended response to RFI Cities 6-1 Q. DOES THIS CONCLUDE YOUR TESTIMONY?

6 A. Yes, it does.

DIRECT TESTIMONY 48 NALEPA APPENDIX A STATEMENT OF QUALIFICATIONS Blank Page KARLJ. NALEPA Mr. Nalepa is an energy economist with more than 25 years of private and public sector experience in the electric and natural gas industries. He has extensive experience analyzing utility rate filings and resource plans with particular focus on fuel and power supply requirements, quality of fuel supply management, and reasonableness of energy costs. Mr. Nalepa developed peak demand and energy forecasts for municipal and electric cooperative utilities and has forecast the price of natural gas in ratemaking and resource plan evaluations. He led a management and performance review of the Texas Public Utility Commission, and has conducted performance reviews and valuation studies of a number of municipal utility systems. Mr. Nalepa previously directed the Railroad Commission of Texas' Regulatory Analysis & Policy Section, with responsibility for preparing timely natural gas industry analysis, managing ratemaking proceedings, mediating informal complaints, and overseeing consumer complaint resolution. He has prepared and defended expert testimony in both administrative and civil proceedings, and has served as a technical examiner in natural gas rate proceedings.

EDUCATION 1998 Certificate of Mediation Dispute Resolution Center, Austin 1989 NARUC Regulatory Studies Program Michigan State University 1988 M .S. - Petroleum Engineering University of Houston 1980 B.S. - Mineral Economics Pennsylvania State University PROFESSIONAL HISTORY 2003 - ReSolved Energy Consulting, LLC (Formerly R.J. Covington Consulting, LLC) President and Managing Director 1997 - 2003 Railroad Commission of Texas Asst. Director, Regulatory Analysis & Policy 1995 - 1997 Karl J. Nalepa Consulting Principal 1992 - 1995 Resource Management International, Inc. Supervising Consultant 1988 1992 Public Utility Commission of Texas Fuels Analyst 1980 - 1988 Transco Exploration Company Reservoir and Evaluation Engineer

AREAS OF EXPERTISE Regulatory Analysis Electric Power: Analyzed electric utility rate, certification, and resource forecast filings. Assessed the quality of fuel supply management, and reasonableness of costs recovered from ratepayers. Projected the cost of fuel and purchased power. Estimated the impact of environmental costs on utility resource selection.

Participated in regulatory rulemaking activities. Provided expert staff testimony in a number of proceedings before the Texas Public Utility Commission.

As consultant, represent interests of municipal clients intervening in large utility rate proceedings through analysis of filings and presentation of testimony before the Public Utility Commission. Also assist municipal utilities in preparing and defending requests to change rates and other regulatory matters before the Public Utility Commission.

Natural Gas: Directed the economic regulation of gas utilities in Texas for the Railroad Commission of Texas. Responsible for monitoring, analyzing and reporting on conditions and events in the natural gas industry. Managed Commission staff representing the public interest in contested rate proceedings before the Railroad Commission, and acted as technical examiner on behalf of the Commission. Mediated informal disputes between industry participants and directed handling of customer billing and service complaints.

Oversaw utility compliance filings and staff rulemaking initiatives. Served as a policy advisor to the Commissioners.

As consultant, represent interests of municipal clients intervening in large utility rate proceedings through analysis of filings and presentation of testimony before the cities and Railroad Commission. Also assist small utilities in preparing and defending requests to change rates and other regulatory matters before the Railroad Commission.

Litigation Support Retained to support litigation in natural gas contract disputes. Analyzed the results of contract negotiations and competitiveness of gas supply proposals considering gas market conditions contemporaneous with the period reviewed. Supported litigation related to alleged price discrimination related to natural gas sales for regulated customers. Provided analysis of regulatory and accounting issues related to ownership of certain natural gas distribution assets in support of litigation against a natural gas utility. Supported independent power supplier in binding arbitration regarding proper interpretation of a natural gas transportation contract. Provided expert witness testimony in administrative and civil court proceedings.

Utility System Assessment Led a management and performance review of the Public Utility Commission. Conducted performance reviews and valuation studies of municipal utility systems. Assessed ability to compete in the marketplace, and recommended specific actions to improve the competitive position of the utilities. Provided comprehensive support in the potential sale of a municipal gas system, including preparation of a valuation study and all activities leading to negotiation of contract for sale and franchise agreements.

Energy Supply Analysis Reviewed system requirements and prepared requests for proposals (RFPs) to obtain natural gas and power supplies for both utility and non-utility clients. Evaluated submittals under alternative demand and market conditions, and recommended cost-effective supply proposals. Assessed supply strategies to determine optimum mix of available resources.

Econometric Forecasting Prepared econometric forecasts of peak demand and energy for municipal and electric cooperative utilities in support of system planning activities. Developed forecasts at the rate class and substation levels. Projected price of natural gas by individual supplier for Texas electric and natural gas utilities to support review of utility resource plans.

Reservoir Engineering Managed certain reserves for a petroleum exploration and production company in Texas. Responsible for field surveillance of producing oil and natural gas properties, including reserve estimation, production forecasting, regulatory reporting, and performance optimization. Performed evaluations of oil and natural gas exploration prospects in Texas and Louisiana.

PROFESSIONAL MEMBERSHIPS Society of Petroleum Engineers International Association for Energy Economics

SELECT PUBLICATIONS, PRESENTATIONS, AND TESTIMONY "Natural Gas Regulatory Policy in Texas," Hungarian Oil and Gas Policy Business Colloquium, U.S. Trade and Development Agency, Houston, May 2003 "Railroad Commission Update," Texas Society of Certified Public Accountants, Austin, April 2003 "Gas Utility Update," Railroad Commission Regulatory Expo and Open House, October 2002 "Deregulation: A Work in Progress," Interview by Karen Stidger, Gas Utility Manager, October 2002 "Regulatory Overview: An Industry Perspective," Southern Gas Association's Ratemaking Process Seminar, Houston, February 2001 "Natural Gas Prices Could Get Squeezed," with Commissioner Charles R. Matthews, Natural Gas, December 2000 "Railroad Commission Update," Texas Society of Certified Public Accountants, Austin, April 2000 "A New Approach to Electronic Tariff Access," Association of Texas Intrastate Natural Gas Pipeline Annual Meeting, Houston, January 1999 "A Texas Natural Gas Model," United States Association for Energy Economics North American Conference, Albuquerque, 1998 "Texas Railroad Commission Aiding Gas Industry by Updated Systems, Regulations," Natural Gas, July 1998 "Current Trends in Texas Natural Gas Regulation," Natural Gas Producers Association, Midland, 1998 ·'An Overview of the American Petroleum Industry," Institute ofinternational Education Training Program, Austin, 1993 Direct testimony in PUC Docket No. 10400 summarized in Environmental Externality, Energy Research Group for the Edison Electric Institute, 1992 "God's Fuel - Natural Gas Exploration, Production, Transportation and Regulation," with Danny Bivens, Public Utility Commission of Texas Staff Seminar, 1992 "A Summary of Utilities' Positions Regarding the Clean Air Act Amendments of 1990," Industrial Energy Technology Conference, Houston, 1992 "The Clean Air Act Amendments of 1990," Public Utility Commission of Texas Staff Seminar, 1992 'The Industrial End-Use Model," Chapter Three, End Use Modeling Project: Interim Report, Public Utility Commission of Texas, 1989

APPENDIXB PREVIOUSLY FILED TESTIMONY

KARL J. NALEPA TESTIMONY FILED

DKTNO. DATE REPRESENTING UTILITY PHASE ISSUES Louisiana Public Service Commission U-31971 Novll PSC Staff Entergy Louisiana, LLC/ Resource Certification Prudence I Cost Recovery Entergy Gulf States Louisiana Public Utility Commission of Texas 39366 Jul 11 Cities Entergy Texas, Inc. Energy Efficiency Cost of Service/Rate Design Cost Recovery Factor 38480 Nov 10 Cities Texas-New Mexico Power Cost of Service Cost of Service/Rate Design 38815 Sep 10 Denton Municipal Electric Denton Municipal Electric Interim TCOS Wholesale Transmission Rate 37744 Jun 10 Cities Entergy Texas, Inc. Cost of Service/ Cost of Service/ Fuel Reconciliation Nat Gas/ Purch Power/ Gen 37580 Dec 09 Cities Entergy Texas, Inc. Fuel Refund Fuel Refund Methodology 36956 Jul 09 Cities Entergy Texas, Inc. EEC RF EECRF Methodology 36392 Nov08 TMPA TMPA Interim TCOS Wholesale Transmission Rate 35717 Nov08 Cities Steering Committee Oncor Cost of Service Cost of Service/Rate Design 34800 Apr 08 Cities Entergy Gulf States Fuel Reconciliation Natural Gas/Coal/Nuclear 16705 May97 North Star Steel Entergy Texas Fuel Reconciliation Natural Gas/Fuel Oil/

DKTNO. DATE REPRESENTING UTILITY PHASE ISSUES Public Utility Commission of Texas (continued} 10694 Jan 92 PUC Staff Midwest Electric Coop Revenue Requirements Depreciation/ Quality of Service 10473 Sep 91 PUC Staff HL&P Notice of Intent Environmental Costs 10400 Aug 91 PUC Staff TU Electric Notice oflntent Environmental Costs 10092 Mar91 PUC Staff HL&P Fuel Reconciliation Natural Gas/Fuel Oil 10035 Jun 91 PUC Staff West Texas Utilities Fuel Reconciliation Natural Gas Fuel Factor Natural Gas/Fuel Oil/Coal 9850 Feb 91 PUC Staff HL&P Revenue Req. Natural Gas/Fuel Oil/ETSI Fuel Factor Natural Gas/Coal/Lignite 9561 Aug90 PUC Staff Central Power & Light Fuel Reconciliation Natural Gas Revenue Requirements Natural Gas/Fuel Oil Fuel Factor Natural Gas 9427 Jul 90 PUC Staff LCRA Fuel Factor Natural Gas 9165 Feb 90 PUC Staff El Paso Electric Revenue Requirements Natural Gas/Fuel Oil Fuel Factor Natural Gas 8900 Jan 90 PUC Staff SWEPCO Fuel Reconciliation Natural Gas Fuel Factor Natural Gas 8702 ser 89 PUC Staff Gulf States Utilities Fuel Reconciliation Natural Gas/Fuel Oil Ju 89 Revenue Requirements Natural Gas/Fuel Oil Fuel Factor Natural Gas/Fuel Oil 8646 May89 PUC Staff Central Power & Light Fuel Reconciliation Natural Gas Jun 89 Revenue Requirements Natural Gas/Fuel Oil Fuel Factor Natural Gas 8588 Aug 89 PUC Staff El Paso Electric Fuel Reconciliation Natural Gas

DKTNO. DATE REPRESENTING UTILITY PHASE ISSUES Railroad Commission of Texas 10106 Oct 11 Gulf Coast Coalition CenterPoint Energy Entex Cost of Service Cost of Service/Rate Design 10083 Aug 11 City of Magnolia, Texas Hughes Natural Gas Cost of Service Cost of Service/Rate Design 10038 Feb 11 Cities Steering Committee CenterPoint Energy Entex Cost of Service Cost of Service/Rate Design 10021 Oct 10 AgriTex Gas, Inc. AgriTex Gas, Inc. Cost of Service Cost of Service/Rate Design 10000 Dec 10 Cities Steering Committee Atmos Pipeline Texas Cost of Service Cost of Service/Rate Design 9902 Oct 09 Gulf Coast Coalition CenterPoint Energy Entex Cost of Service Cost of Service/Rate Design/Riders 9810 Jul 08 Bluebonnet Natural Gas Bluebonnet Natural Gas Cost of Service Cost of Service/Rate Design 9797 Apr 08 Universal Natural Gas Universal Natural Gas Cost of Service Cost of Service/Rate Design 9732 Jul 08 Cities Steering Committee Atmos Energy Corp. Gas Cost Review Natural Gas Costs 9670 Oct 06 Cities Steering Committee Atmos Energy Corp. Cost of Service Affiliate Transactions/ O&M Expenses/GRIP 9667 Nov06 Oneok Westex Transmission Oneok Westex Transmission Abandonment Abandonment 9598 Sep 05 Cities Steering Committee Atmos Energy Corp. GRIP Appeal GRIP Calculation 9530 Apr 05 Cities Steering Committee Atmos Energy Corp. Gas Cost Review Natural Gas Costs 9400 Dec 03 Cities Steering Committee TXU Gas Company Cost of Service Affiliate Transactions/ O&M Expenses/Capital Costs

Attachment KJN 1 Page 1of3 Entergy Texas, Inc. Docket No. 39896 Cities Schedule P For the Test Year Ended June 30, 2011

ALLOCATION TOTAL COMPANY Ln No. DESCRIPTION TOTAL RETAIL WHOLESALE FACTOR ADJUSTED

SUMMARY OF RES UL TS

RATE BASE 1,558,489,613 1,538,729,862 19,759,751 REVENUES 2 RATE SCHEDULE REVENUE 648.019,550 634, 114,242 13,905,308 3 OTHER SALES FOR RESALE 58,675,159 55,518,905 3,156,254 4 TOTAL SALES REVENUES (L2 + L3) 706,694, 709 689,633, 147 17,061,562 5 OTHER OPERATING REVENUES 48, 171,991 47,772,887 399, 105 6 PROVISION FOR RATE REFUND 0 0 0 TOTAL REVENUES (L4 +LS+ L6) 754,866, 700 737,406,034 17,460,666 TOTAL OPERATING EXPENSES 460,474,258 449,744,074 10,730,184 TOTAL OPERATING INCOME (L7 - LS) 294,392,442 287,661,960 6,730,482 EARNED RATE OF RETURN ON RATE BASE (L9 I L 1) 18.89% 18.69% 34.06%

REVENUE REQUIREMENT DETERMINATION REQUIRED RATE OF RETURN 8.12% 8.12% 8.12% REQUIRED OPERATING INCOME (L 1*L11) 126,536,524 124,932, 195 1,604,329

REVENUE CONVERSION FACTORS 13 INCOME TAX REVENUE CONVERSION FACTOR 53.85% 53.85% 53.85% 14 REVENUE RELATED TAX REVENUE CONVERSION FACTOR 1.03% 1.03% 1.03% 15 BAD DEBT REVENUE CONVERSION FACTOR 0.27% 0.27% 0.00% REVENUE DEFICIENCY 16 OPERATING INCOME DEFICIENCY (L 12 - L9) (167,855,918) (162,729,765) (5,126,153) 17 INCREMENTAL INCOME TAX (L 16*L13) (90,383,956) (87,623,719) (2,760,236) 18 INCREMENTAL REVENUE RELATED TAX (L 16+L17+L19) * L 14 (2,662,910) (2,581,781) (81,129) 19 INCREMENTAL BAD DEBT EXPENSE (L 16+L17+L18) * L 15 (616,247) (616,247) 0 TOTAL REVENUE DEFICIENCYl(EXCESS) EXCL PUR. PWR. (SUM OF L 16 - L 19) (261,519,031) (253,551,512) (7,967,519) PLUS PPR RIDER (35,870,747) (33,941, 188) (1,929,559) PLUS IS RIDER 79 PLUS REC RIDER 79 PLUS MUNICIPAL FRANCHISE FEES TOTAL REVENUE DEFICIENCY/(EXCESS) (297,389,778) (287,492,700) (9,897.078) % INCREASEl(DECREASE) (L20 I L2) -45.89% -45.34% -71.17%

26 RATE SCHEDULE REVENUE REQUIREMENT (L2 + L20) 350,629,772 346,621,542 4,008,229

27 ETl'S REQUESTED REVENUE REQUIREMENT 479,928,299 472,621,802 7.306.497 ETl'S REQUESTED REVENUE DEFICIENCY INCL RIDERS (LINE 24) 118, 142,929 111,823,864 6.319,065 CITIES ADJUSTMENT (129,298,527) (126,000,260) (3,298,268) REVENUE DEFICIENCYl(EXCESS) (11,155,598) (14, 176,396) 3,020,797 CITIES ADJUSTMENT EXCLUDING PPR IS & REC RIDERS (93,427, 780) (92,059,072) (1,368.708) Attachment KJN 1 Page 2 of 3 Entergy Texas, Inc. Docket No. 39896 Cities Schedule P For the Test Year Ended June 30, 2011

I I Ln No DESCRIPTION ALLOCATION FACTOR TOTAL COMPANY ADJUSTED TOTAL RETAIL WHOLESALE

RATE BASE SUMMARY

1 PLANT IN SERVICE 3, 198,793,204 3, 139,991,077 58,802,127 2 ACCUMULATED DEPRECIATION I AMORTIZATION (1,212,712,279) (1, 178,895,472) (33,816,807) NET PLANT 1,986,080,925 1,961,095,605 24,985,320 WORKING CASH (21,237,882) (20,974,670) (263,212) FUEL INVENTORY 9,073.881 8,719,426 354,455 MATERIALS AND SUPPLIES EXCLUDING ALLOWANCES 29,252,574 28,711,438 541.136 PREPAYMENTS 7,218,037 7,186,858 31,179 PROPERTY INSURANCE RESERVE 34,051,597 34,051,597 0 INJURIES & DAMAGES RESERVES (5,569,243) (5,404, 120) (165,122) 10 COAL CAR MAINTENANCE RESERVE 1,400,350 1,345,648 54,702 11 UNFUNDED PENSION (9,835,109) (9,543,509) (291,601) 12 ALLOWANCES 68,914 67,647 1,267 13 COMMERCIAL LITIGATION 0 0 0 14 ENVIRONMENTAL RESERVES (1,062,190) (1,044,215) (17,974) 15 CUSTOMER DEPOSITS (35,872,476) (35,872,476) 0 16 ACCUMULATED DEFERRED INCOME TAXES (441,391,997) (435,921,599) (5,470,398) 17 ACCUMULATED DEFERRED ITC 0 0 0 18 RATE CASE EXPENSES 6,175,000 6,175,000 0 REGULATORY ASSETS AND LIABILITIES 137,232 137,232 0 RATE BASE 1,558,489,613 1,538,729,862 19,759.751 (182,606,822) Attachment KJN 1 Page 3 of 3 Entergy Texas, Inc. Docket No. 39896 Cities Schedule P For the Test Year Ended June 30, 2011

ALLOCATION TOTAL COMPANY Ln No. DESCRIPTION TOTAL RETAIL WHOLESALE FACTOR ADJUSTED

REVENUES SALES REVENUES 706,694,709 689,633, 147 17,061,562 OTHER OPERATING REVENUES 48,171,991 47,772,887 399.105 PROVISION FOR RATE REFUND 0 0 0 TOTAL REVENUES 754,866,700 737,406,034 17,460,666 OPERATING EXPENSES & M EXPENSE 5 PRODUCTION EXPENSES 47,575,533 45,344,134 2,231,399 6 TRANSMISSION EXPENSES 22,891,692 22,891,692 0 7 REGIONAL MARKET EXPENSES 1,009,426 1,008,442 984 8 DISTRIBUTION EXPENSES 30,680,337 30,398,544 281,793 9 CUSTOMER ACCOUNTING EXPENSES 17.839,743 17,088,390 751,353 10 CUSTOMER SERVICES EXPENSES 4,340,078 4,340,078 0 11 SALES EXPENSES 1,089,611 1,070,128 19,483 12 ADMINISTRATIVE & GENERAL EXPENSES 63,160,315 61,282,501 1,877,815 13 OPERATION & MAINTENANCE EXPENSE '188,586, 734 183,423,907 5,162,827 14 GAINS FROM DISP OF ALLOWANCES 0 0 0 15 REGULATORY DEBITS AND CREDITS 5,245,925 4,963,736 282, 189 16 INTEREST ON CUSTOMER DEPOSITS 68,985 68.130 855 17 DEPRECIATION AND AMORTIZATION EXPENSE 75,569,475 74,395,233 1,174,242 18 TAXES OTHER THAN INCOME 58,804,807 58.172,965 631,842 CURRENT INCOME TAXES 19 FEDERAL INCOME TAX 118,847,134 115,799,865 3,047,269 20 STATE INCOME TAX (37,732) (36,613) (1,119) 21 CURRENT INCOME TAXES '118.809,402 115,763,252 3,046,150 PROVISION FOR DEFERRED INCOME TAXES 22 PROVISION FOR DEFERRED INCOME TAXES - FEDERAL 14,962,189 14,502,193 459,995 23 PROVISION FOR DEFERRED INCOME TAXES - STATE 84.347 81,846 2,501 24 PROVISION FOR DEFERRED INCOME TAXES 15,046,536 14,584,039 462,496 25 INVESTMENT TAX CREDITS A/C 411 (1,657,606) (1,627,189) (30,417) 26 TOTAL OPERATING EXPENSES 460,474,258 449,744,074 10,730,184 Blank Page Attachment KJN--2

Fuel Reconciliation Cost Adjustment Summary Spindletop Storage Facility Operating Costs Line Loss Costs Storage Cities Payments to ETI Eligible Withdrawals Proposed Difference in Difference in Total Storage Cost Allocation to Inventory Storage and Storage Storage ETI Allocated Cities Allocated Line Loss Difference Operator Injections Withdrawals Fuel Cost Adjustments Fuel Cost Fuel Cost Fuel Cost Fuel Cost Fuel Cost - Jul-09 190,586 0 68,341 258,927 (967,954} 193,591 (65,336} 60,508,694 60,309,479 (199,215} (264,551} Aug-09 458,607 (7,636) 0 450,971 (910,787) 182,157 (268,814} 47,892,586 47,734,672 (157,913) (426,727) Sep-09 277,203 (637) 0 276,566 (809,549) 161,910 (114,656) 38,132,827 38,007,278 (125,549) (240,20:;) Oct-09 586,214 (17,862) 0 568,352 (675,482) 135,096 (433,256) 39,860,472 39,729,460 (131,012} (564,267) Nov-09 558,364 0 28,091 586,455 (328,023) 65,605 (520,850) 34,608,184 34,494,283 (113,901} (634,751} Dec-09 0 0 46,849 46,849 (642,533} 128,507 81,658 53,047,070 52,872,626 (174,444) (92,787) Jan-10 346,088 (34,181) 0 311,907 (402,070} 80,414 (231,493} 68,250,582 68,026,673 (223,909) (455,402} Feb-10 623,341 0 14,501 637,842 (340,204) 68,041 (569,801} 53,105,832 52,931,070 (174,762) (744,564) Mar-10 185,536 0 32,417 217,953 (352,558} 70,512 (147,441} 37,225,005 37,102,516 (122,489) (269,930) Apr-10 406,932 0 37,736 444,668 (650,919} 130,184 (314,484) 33,053,739 32,945,129 (108,610) (423,094) May-10 568,957 (9,251) 0 559,706 (761,151} 152,230 (407,476) 54,062,212 53,884,276 (177,936} (585,412} Jun-10 490,857 (14,285} 0 476,572 (828,524) 165,705 (310,867) 68,342,777 68,118,429 (224,348} (535,215} Jul-10 733,329 0 36,424 769,753 (1,248,176) 249,635 (520,118} 70,356,347 70,124,901 (231,446) (751,563} Aug-10 113,151 (948) 0 112,203 (1,000,525) 200,105 87,902 81,934,891 81,665,245 (269,646} (181,744) Sep-10 430,021 (10,608} 0 419,413 (715,348) 143,070 (276,343} 49,869,341 49,705,504 (163,837) (440,180) Oct-10 426,185 0 23,354 449,539 (831,584} 166,317 (283,222) 25,631,179 25,546,682 (84,497} (367,719} Nov-10 446,619 (13,251) 0 433,368 (413,276) 82,655 (350,713} 31,317,885 31,214,945 (102,940) (453,653) Dec-10 132,759 (2,090) 0 130,669 (288,652} 57,730 (72,939) 45,737,661 45,587,106 (150,555) (223,493} Jan-11 341,006 (2,683) 0 338,323 (411,742) 82,348 (255,975) 51,829,772 51,659,579 {170,193) (426,168) Feb-11 603,212 0 9,325 612,537 (601,934) 120,387 (492,150) 48,624,815 48,464,956 (159,859) (652,009) Mar-11 699,044 (31,317) 0 667,727 (580,673) 116,135 (551,592} 45,801,902 45,651,389 {150,512} (702,105} Apr-11 537,836 0 68,838 606,674 (766,831) 153,366 (453,308} 42,429,275 42,289,625 (139,650} (592,958} May-11 555,439 0 19,245 574,684 (827,689} 165,538 (409,146) 60,993,800 60,793,134 (200,666) (609,812} Jun-11 291,458 0 18,547 310,005 (874,174) 174,835 (135,170) 67,998,268 67,774,884 (223,384) (358,554) 10,002,744 (144,749) 403,668 10,261,663 (16,230,358) 3,246,072 (7,015,591) 1,210,615,116 1,206,633,845 (3,981,271) (10,996,863) Using Exhibit KDM 12 totals: {'.l,$1,1°Jl&!i>3} ' 3)666,313 / ,.J,<l::l\Jt; 0'~'~1')5i1();s:~ir.

Blank Page Attachment KJN-3

HIGHLY SENSITIVE: CONFIDENTIAL

TEST-YEAR CAPACITY COSTS Blank Page Attachment KJN-4

HIGHLY SENSITIVE: CONFIDENTIAL

RATE-YEAR CAPACITY COSTS ENTERGY TEXAS, INC. PUBLIC UTILITY COMMISSION OF TEXAS SOAH DOCKET NO. 4 73-12-2979 PUC DOCKET NO. 39896 - 2011 ETI Rate Case Response of: Entergy Texas, Inc. Prepared By: Subparts "a through "f' Counsel; Subparts "g" and "h" Kelly Louque to the Third Set of Data Requests Sponsoring Witness: Subparts "a through "f' NIA; Subparts "g" and "h" Patrick Cicio of Requesting Party: Cities Beginning Sequence No. Ending Sequence No. Question No.: Cities 3-3 Part No.: Addendum: Question: In reference to the proposed sale of the Entergy transmissions assets to ITC Holdings, please provide the following fonnation: a. A copy of the current agreement of sale; b. A copy of all due diligence analyses performed by or on behalf of Entergy evaluating the sale; c. The current expected or estimated date for completion of the proposed transaction; d. The total proceeds expected to be received by Entergy from the proposed transaction; e. The book value of transmission assets to be sold under the transaction; f. The book value of transmission assets located in Texas that are to be sold under the proposed transaction; g. The total MSS-2 charges to all Entergy operating companies for each of the past five years 2006-2010 and the test year in this case; h. The total MSS-2 charges to Entergy Texas for each of the past five years 2006-2010 and for the test year.

Response: ETI objects to this RFI because it seeks information or data that is not relevant to the Company's pending request for relief and is therefore outside the scope of this proceeding. Parties and the Commission will have a full opportunity to review issues

39896 CITIES' EXHIBIT 28 Cities 3-3 LR154 ' Question No.: Cities 3-3 relating to the Company's plan to transfer its electric transmission business to ITC Holdings Corp. in a future, separate proceeding requesting approval of that proposed transaction. ETI is not seeking any relief or approval associated with that proposed transaction in the instant proceeding. Notwithstanding this objection, and without waiving the same, ETI provides the following response:

(a) See the Company's response to State 1-6. (b) The Company has filed an objection to this request. (c) As disclosed in the December 5, 2011 press release, the transaction is expected to close by the end of 2013. (d) See the Company's response to TIEC 1-48. (e) See the Company's response to State 1-6. Refer to the Form 8-K filed December 6, 2011, Item 1.01. Entry into a Material Definitive Agreement, Separation Agreement. (f) See(e)above. (g) Please see the attached. (h) See (g) above.

39896 Cities 3-3 LR155 PUCT Docket 39896 Cities 3·3 (g) Entergy Operating Companies MSS-2 payments/{receipts) for the years 2006 • 2011 Credits reflect revenue (receipts); Debits reflect expense (payments) Year EAi EGSJ ELL EGSL EMI ENCi ETI 2006 $ 7,691,868 (2,649,584) (8,111,212) $ (1,971,870) $ 5,040,797 2007 2,204,469 5,882,997 {6,856,050) (5,962,975) 4,731,559 2008 {1,415,587) (7,837,669) 11,762,725 (5,653,578) 5,804,604 (2,660,494) 2009 (3,812,177) (7,896,585) 9,427,916 (3,532,269) 6,773,517 (960,402) 2010 {4,909,612) (7,424,245) 7,377,010 {3,835,941) 8,233,158 559,630 2011" (2,104,269) (1,691,230) 1,515,163 (3,400,589) 4,331,993 1,348,932 Grand Total $ {2,345,309) $ 3,233,413 $ (39,816,991) $ 30,082,815 $ (24,357,222) $ 34,915,628 (1,712,334) •2011 includes January -June 2011 Entergy Operating Companies MSS·2 payments/{ receipts) for the test year July 2010 ·June 2011 Credits reflect revenue (receipts); Debits reflect expense {payments) EAi ELL EGSL EMI ENO! ETI 7/2010. 6/2011 $ (4,169,001) $ (4,738,043) $ 3,955,371 $ {5,329,599) $ 8,527,476 $ 1,753,797

39896 Cities 3-3 LR156 CITIES' EXHIBIT 29

ENTERGY TEXAS, INC. PUBLIC UTILITY COMMISSION OF TEXAS SOAH DOCKET NO. XXX-XX-XXXX PUC DOCKET NO. 39896 - 2011 ETI Rate Case Response of: Entergy Texas, Inc. Prepared By: Frances Grant/Rachelle Hayes to the Fifth Set of Data Requests Sponsoring Witness: Robert R. Cooper/ Patrick Cicio of Requesting Party: Cities Beginning Sequence No. Ending Sequence No. Question No.: Cities 5-1 Part No.: Addendum: 2 Question: In reference to Mr. Cicio's direct testimony at page 8 of75, lines 19-23, through page 9, lines 1-11, please provide: a. A complete and detailed explanation outlining how the system does its joint planning of generation resources; b. List all the factors that go into the joint plan ofresources; c. Provide copies of the most recent three joint resource plans; d. Provide monthly peaks coincident with the System for each of the operating companies for the past five years 2006-2010 and all the months available in 2011 that are employed in the joint planning process; e. Provide a list of generating resources for each operating company showing Mw capability for each resource by month for calendar 2010 and test year and rate year; f. Provide a list of all firm purchase capability available to each operating company showing Mw capability for each resource purchase by month for calendar 2010, test year and rate year; g. Provide the current load forecast for each operating company; h. Provide the current system estimate long or short resources for each system operating company.

Response: In response to several data requests in this set, Entergy Texas is providing a copy of the Intra-System Bill (ISB) for January 2006 through November 2011. We will reference the responsive Attachment number for each subsequent inquiry. See the attached public CD.

39896 1 CITIES 5-1ADDENDUM2 KH1587 Question No.: Cities 5-1 Addendum 2

a. Please see the response to Cities 1-36.

b. Please see the response to Cities 1-36.

c. Please see the response to Cities 1-36.

d. See Attachment 4 of the ISBs for Monthly Coincident Peaks.

e. The Company objects to this request on grounds that the responsive materials are highly sensitive protected ("highly sensitive") materials.

Specifically, the responsive materials are protected pursuant to Texas Government Code Sections 552.101, 552.104 and/or 552.110. Highly sensitive materials will be provided pursuant to the terms of the Protective Order in this docket.

See attachment 5 section (A) of the ISBs for owned generating resources with MW. Please also see the attached Highly Sensitive CD for supporting workpapers.

f. The Company objects to this request on grounds that the responsive materials are highly sensitive protected ("highly sensitive") materials.

Specifically, the responsive materials are protected pursuant to Texas Government Code Sections 552.101, 552.104 and/or 552.110. Highly sensitive materials will be provided pursuant to the terms of the Protective Order in this docket.

See Attachment 5 sections (B) and (D) of the ISBs for purchased capability with MW. Please also see the attached Highly Sensitive CD for supporting workpapers.

g. The Company objects to this request on grounds that the responsive materials are highly sensitive protected ("highly sensitive") materials.

Specifically, the responsive materials are protected pursuant to Texas Government Code Sections 552.101, 552.104 and/or 552.110. Highly sensitive materials will be provided pursuant to the terms of the Protective Order in this docket.

See the attached Highly Sensitive CD.

"FEA12l_Firm_NonCoin_Pks_xBrazos_HSPI.xls" contains the current long-term forecast for each operating company's annual firm peak, non- coincident to the system. AECC load is not included.

h. Please see the response to Cities 1-36.

39896 2 CITIES 5-1 ADDENDUM 2 KHl 588 Question No.: Cities 5-1Addendum2

Addendum 1: Please see the attached public CD containing the December 2011 Intra-System Bill (!SB).

Addendum 2: See the attached ISBs for January and February 2012.

39896 3 CITIES 5-1ADDENDUM2 KH1589 Entergy Electric System Date range -20100101through20100131 Attachment 5 Intra-System Billing-201001RA Service Schedule MSS ~ 21 Transmission Equalization Page 46

AR LA MS NO EGSL ETI Total Investment 410,205,414.53 494,272,097.89 260,087,078.50 31, 189,868.31 320,330,456.87 214,793,237.35 Deferred Taxes 36,427.497.00 58,284,456.00 31,434,045.00 3,238,453,00 28,094,818.00 19,886,865.00 Depreciation Reserve 159,055,766.00 175,602,699.00 92,625,850.00 14,199,888.00 161,930,338,00 57,270,189.00 Net Transmission Investment 214,722,151.53260,384,942.89136,027,183.50 13,751,527.31 130,305,300,87 137,636,183.35 Cost of Capital Debt Ratio (DR) 0.477800 0.497100 0.484800 0.453100 0.478900 0.486400 Bond Cost (I) 0.061400 0.068000 0.061900 0.060800 0.058700 0.053500 Preferred Ratio {PR) 0.039500 0.022700 0.035800 0.047300 0.003600 Preferred Cost (p) 0.059900 0.075800 0.056900 0.048200 0.087100 Common Ratio (ER) 0.482700 0.480200 0.479400 0.499600 0.517500 0.513600 Common Cost (c) 0.110000 0.110000 0.110000 0.110000 0.110000 0.110000 Total Cost of Capital (CM) 0,084800 0.088346 0.084780 0.084784 0.085350 0.082518 Tax Rate (F) 0.035797 0.034112 0,033927 0,035796 0.035798 0.030421 Operating Expenses Depreciation Factor (D) 0.0148650 0.0280260 0.0225760 0.0282250 0.0198170 0.0200000 Insurance Expense (I) 0.0043880 0.0040920 0.0062920 0.0008440 Property Tax (PT) 0.0045360 0.0091200 0.0174110 0.0112200 0.0085080 0.0075140 Franchise Tax (FT) 0.0000490 0.0010150 0.0014940 (0.0000140) 0.0014770 Operations & Maintenance (OM) 0.0377920 0.0420730 0.0351650 0.0475470 0.0509460 0.0343280 Total Operating Expenses 0.0572420 0.0836070 0.0802590 0.0884860 0.0855490 0.0641630 Net Investment Ratio (K) 0.523450 0.526805 0.523006 0.440897 0.406784 0.640785 Annual Ownership Cost 0.229952 0.281163 0.272164 0.321275 0.331453 0.213070 Net Transmission Investment* AOC 49,375,788.00 73,210,612.00 37,021,702.00 4,418,022.00 43,190,083.00 29,326, 142.00 System Average Annual Ownership Cost 236,542,349.00 I 892,827,289.45 0.2649363 System Average Monthly Ownership Cost 0.2649363 I 12 0.0220780 Responslbillty Ratio 0.2100 0.2600 0.1389 0.0450 0.1920 0.1541 Transmission Responsibility 187,493,730.78 232,135,095.26 124,013,710.50 40, 177,228.03 171,422,839.57 137,584,685.30 Investment Difference 27,228,420.75 28,249,847.63 12,013,473.00 (26,425,700.72)(41, 117,538.70) 51,498.05 Payments 583,427.26 907,794,01 Receipts 601,149.73 623,700.82 265,233.75 1,136.98

Attachment Snapshct: 20101)223192132 Runro: 16123 Bllllng Snapshot: 20100223183926

Entergy Electric System Date range· 20100201 through 20100228 Attachment 5 Intra-System Bllling-201002RA Service Schedule MSS • 2 I Transmission Equalization Page 39

AR LA MS NO EGSL ETI Total Investment 410,284,549.48 494,946,439.93 260,055,826.87 31, 189,868.31 320,881,450.31 214,892,263.91 Deferred Taxes 36,427,497.00 58,284,456.00 31,434,045.00 3,238,453.00 28,094,818.00 19,888,865.00 Depreciation Reserve 159,055,766.00175,602,699.00 92,625,850.00 14,199,888.00 161,930,338.00 57,270,189.00 Net Transmission Investment 214,801,286.48 261,059,284.93 135,995,931.87 13,751,527.31 130,856,294.31 137,735,209.91 Cost of Cap!tal Debt Ratio {DR} 0.477800 0.497100 0.484800 0.453100 0.478900 0.486400 Bond Cost (i) 0.061400 0.068000 0.061900 0.060800 0.058700 0.053500 Preferred Ratio (PR) 0.039500 0.022700 0.035800 0.047300 0.003600 Preferred Cost (p) 0.059900 0.075800 0.056900 0.048200 0.087100 Common Ratio (ER) 0.482700 0.480200 0.479400 0.499600 0.517500 0.513800 Common Cost (c) 0.110000 0.110000 0.110000 0.110000 0.110000 0.110000 Total Cost of Capital (CM) 0.084800 0.088346 0.084780 0.084784 0,085350 0.082518 Tax Rate (F) 0.035797 0.034112 0.033927 0.035798 0.035798 0.030421 Operating Expenses Depreciation Factor (D) 0.0148650 0.0280260 0.0225760 0.0282250 0.0198170 0.0200000 Insurance Expense (I) 0.0043880 0.0040920 0.0062920 0.0008440 Property Tax (PT) 0.0045360 0.0091200 0.0174110 0.0112200 0.0085080 0.0075140 Franchise Tax (FT) 0.0000490 0.0010150 0.0014940 (0.0000140) 0.0014770 Operations & Maintenance (OM) 0.0377920 0.0420730 0.0351650 0.0475470 0.0509460 0.0343280 Total Operating Expenses 0.0572420 0.0836070 0.0802590 0.0884860 0.0855490 0.0641630 Net Investment Ratio (K) 0.523542 0.527450 0.522949 0.440897 0.407803 0.640950 Annual Ownership Cost 0.229933 0.280969 0.272180 0.321275 0.330928 0.213045 Net Transmission Investment *AOC 49,389,904.00 73,349,566.00 37,015,373.00 4,418,022.00 43,304,012.00 29,343,798.00 System Average Annual Ownership Cost 236,820,675.00 I 894, 199,534.81 0.2648410 System Average Monthly Ownership Cost 0.2648410 112 0.0220701 Responsibility Ratio 0.2100 0.2610 0.1384 0.0454 0.1894 0.1558 Transmission ResponslbJ!ity 187,781,902.31 233,386,078.59123,757,215.62 40,596,658.88 169,361,391.89 139,316,287.52 Investment Difference 27,019,384.17 27,673,206.34 12.238,716.25 (26,845,131.57) (38,505,097.58) (1,581 ,077.61) Payments 592,474.23 849,810.63 34,894.51 Receipts 596,320.00 610,749.91 270,109.46

Attachment Snapshlt: 20100327200632 RunlO: 16439 Biiiing Snapshot: 20100327200632

Entergy Electric System Date range. 20100301 through 20100331 Attachment 5 Intra-System Billing-201003RA Service Schedule MSS • 21 Transmission Equalization Page 44

AR LA MS NO EGSL ETI Total Investment 410,321,729.39 515,491,730.27 265,915,679.32 27,047,831.26 323,328,537,13 216,671,976.21 Deferred Taxes 36,427,497.00 58,284,456.00 31,434,045.00 3,238,453.00 28,094,818.00 19,886,865.00 Depreciation Reserve 159,055,766.00 175,602,699.00 92,625,850,00 14,199,888.00 161,930,338.00 57,270,189,00 Net Transmission Investment 214,838,466.39 281,604,575.27 141,855,784.32 9,609,490.26 133,303,381.13 139,514,922.21 Cost of Capita!

Debt Ratio (DR) 0.477800 0.497100 0.484800 0.453100 0.478900 0.486400 Bond Cost (I) 0.061400 0.068000 0.061900 0.060800 0.058700 0.053500 Preferred Ratio (PR) 0.039500 0.022700 0.035800 0.047300 0.003600 Preferred Cost (p) 0.059900 0.075800 0.056900 0.048200 0.087100 Common Ratio {ER) 0.482700 0.480200 0.479400 0.499600 0.517500 0.513600 Common Cost {c) 0.110000 '0.110000 0.110000 0, 110000 0.110000 0.110000 Total Cost of Capital (CM) 0.084800 0.088346 0.084780 0.084784 0.085350 0.082518 Tax Rate (F) 0.035797 0,034112 0.033927 0.035796 0.035798 0.030421 Operating Expenses Depreciation Factor {D) 0.0148650 0.0280260 0,0225760 0.0282250 0,0198170 0.0200000 Insurance Expense (I) 0.0043880 0.0040920 0.0062920 0.0008440 Property Tax (PT) 0.0045360 0.0091200 0.0174110 0.0112200 0.0085080 0.0075140 Franchise Tax (FT) 0.0000490 0.0010150 0.0014940 (0.0000140) 0.0014770 Operations & Maintenance {OM) 0.0377920 0.0420730 0.0351650 0,0475470 0.0509460 0.0343280 Total Operating Expenses 0.0572420 0.0836070 0.0802590 0,0884860 0.0855490 0.0641630 Net Investment Ratio (K) 0.523585 0.546283 0.533462 0.355278 0.412285 0.643899 Annual Ownership Cost 0.229924 0.275505 0.269156 0,369641 0.328647 0.212586 Net Transmission Investment* AOC 49,396,520.00 77,583,469,00 38,181 ,335.00 3,552,062.00 43,809,756.00 29,658,919.00 System Average Annual Ownership Cost 242,182,061.00 I 920,726,619.58 0.2630336 System Average Monthly Ownership Cost 0.2630336 112 0.0219195 Respcnslblllty Ratio 0.2099 0.2604 0.1376 0.0455 0, 1882 0. 1584 Transmission Responsibility 193,260,517.45 239,757,211.74 126,691,982.85 41,893,061, 19 173,280,749.80 145,843,096.54 Investment Difference 21,577,948.94 41,847,363.53 15, 163,801.47 (32,283,570.93) (39,977,368.67) (6,328, 174.33) Payments 707,638.73 876,282.69 138,710.22 Receipts 472,977.18 917,271.98 332,382.47

Attachment Snapshct: 20100427145'432 RunlD: 15724 Bll!lng Snapshot: 201004Zl145432

Entergy Electric System Date range - 20100401 through 20100430 Attachment 5 Intra-System 8illing-201004RA Service Schedule MSS • 2 /Transmission Equalization Page 4o

AR LA MS NO EGSL ETI Total Investment 410,959,209.58515,178,314.04 267,631,740,26 27,048,535.93 331,250,005.35 216,613,685,21 Deferred Taxes 36,427,497.00 58,284,456.00 31,434,045.00 3,238,453.00 28,094,818.00 19,886,865.00 Depreciation Reserve 159,055,766.00 175,602,699.00 92,625,850.00 14, 199,888.00 161,930,338.00 57,270, 189,00 Net Transmission Investment 215,475,946.58281,291,159.04 143,571,845.26 9,610, 194.93 141,224,849.35 139,456,631.21 Cost of Cap!tal Debt Ratio (DR) 0.477800 0.497100 0.484800 0.453100 0.478900 0.486400 Bond Cost (i) 0.061400 0.068000 0.061900 0.060800 0.058700 0.053500 Preferred Ratio (PR) 0.039500 0.022700 0.035800 0.047300 0.003600 Preferred Cost (p) 0.059900 0.075800 0.056900 0.048200 0.087100 Common Ratio (ER) 0.482700 0.480200 0.479400 0.499600 0.517500 0.513600 Common Cost (c) 0.110000 0.110000 0.110000 0.110000 0.110000 0.110000 Total Cost of Capllal (CM} 0.084800 0.088346 0.084780 0.084784 0.085350 0.082518 Tax Rate (F) 0.035797 0.034112 0.033927 0.035796 0.035798 0.030421 Operating Expenses Depreciation Factor (D) 0.0148650 0.0280260 0.0225760 0.0282250 0.0198170 0.0200000 Insurance Expense (J) 0.0043880 0.0040920 0,0062920 0.0008440 Property Tax (PT} 0.0045360 0.0091200 ·0.0174110 0.0112200 0.0085080 0.0075140 Franchise Tax (FT) 0.0000490 0.0010150 0.0014940 (0.0000140) 0.0014770 Operations & Maintenance {OM) 0.0377920 0.0420730 0.0351650 0.0475470 0.0509460 0.0343280 Total Operating Expenses 0.0572420 0.0836070 0.0802590 0.0884860 0.0855490 0.0641630 Net Investment Ratio (K) 0.524324 0.546007 0.536453 0.355294 0.426339 0.643803 Annual Ownership Cost 0.229769 0.275582 0.268317 0.369630 0.321807 0.212601 Net Transmission Investment'" AOC 49,509,693.00 77 ,518,780.00 38,522,767.00 3,552,216.00 45,447,145.00 29,648,619.00 System Average Annual Ownership Cost 244, 199,220.00 I 930,630,626.37 = 0.2624019 System Average Monthly Ownership Cost 0.2624019 / 12 0.0218668 Responsibility Ratio 0.2080 0.2609 0.1372 0.0457 0.1881 0.1601 Transmission Responslbl!ity 193,571,170.28 242,801,530,42 127,682,521.94 42,529,819.63 175,051,620.82 148,993,963.28 Investment Difference 21,904,776.30 38,489,628.62 15,889,323.32 (32,919,624.70) (33,826,771.47) (9,537,332.07) Payments 719,847.60 739,684.02 208,551.15 Receipts 478,987.86 841,645.89 347,449.02

AttachmentSnapshO:: 2D100526143752 RunlO: 16029 Bill!ng Snapshot: 20100526143752

Entergy Electric System Date range-20100501through20100531 Attachment 5 Intra-System Billing-201005RA Service Schedule MSS - 21 Transmission Equalization Page 42

AR LA MS NO EGSL ETI Total Investment 411,217,204.18 515,213, 187.86 270,079,411. 77 27 ,048, 703.26 331,270, 197 .89 222,210,473,94 Deferred Taxes 36,427,497.00 58,284,456.00 31,434,045.00 3,238,453.00 28,094,818.00 19,886,865.00 Depreciation Reserve 159,055,766.00 175,602,699.00 92,625,850,00 14, 199,888.00 161,930,338.00 57,270, 189,00 Net Transmission Investment 215,733,941.18 281,326,032.86 146,019,516.77 9,610,362.26 141,245,041.89 145,053,419.94 Cost of Capital Debt Ratio (DR) 0.477800 0.497100 0.484800 0.453100 0.478900 0.486400 Bond Cost (J) 0.061400 0.068000 0.061900 0.060800 0.058700 0.053500 Preferred Ratio (PR) 0.039500 0.022700 0.035800 0.047300 0.003600 Preferred Cost (p) 0.059900 0.075800 0.056900 0.048200 0.087100 Common Ratio (ER) 0.482700 0.480200 0.479400 0.499600 0.517500 0.513600 Common Cost (c) 0.110000 0.110000 0.110000 0.110000 0.110000 0.110000 Total Cost of Capita! (CM) 0.084800 0.088346 0.084780 0.084784 0.085350 0.082518 Tax Rate (F) 0.035797 0.034112 0.033927 0.035796 0.035798 0.030421 Operating Expenses Dapraclatlon Factor (D) 0.0148650 0.0280260 0.0225760 0.0282250 0.0198170 0.0200000 Insurance Expense (I) 0.0043880 0.0040920 0.0062920 0.0008440 Property Tax (PT) 0.0045360 0.0091200 0.0174110 0.0112200 0,0085080 0.0075140 Franchise Tax (FT) 0.0000490 0.0010150 0.0014940 (0.0000140) 0.0014770 OperaUons & Malntenance (OM) 0.0377920 0.0420730 0.0351650 0.0475470 0.0509460 0.0343280 Total Operating Expenses 0.0572420 0,0836070 0.0802590 0.0884860 0.0855490 0.0641630 Net Investment Ratio {K) 0.524623 0.546038 0.540654 0.355298 0.426374 0.652775 Annual Ownership Cost 0.229707 0.275573 0.267154 0,369627 0.321791 0.211231 Net Transmission Investment* AOC 49,555,596.00 77,525,859.00 39,009,698.00 3,552,249.00 45,451,383.00 30,639,779.00 System Average Annual Ownership Cost 245, 734,564.00 I 938,988,314.90 0.2617014 System Average Monthly Ownership Cost 0.2617014 / 12 0,0218084 Responslbf!ity Ratio 0.2088 0.2597 0.1363 0.0456 0.1887 0.1609 Transmission Respons!bllity 196,060,760.15 243,855,265.38 127,984,107.32 42,817,867.16 177,187,095.02 151,083,219.87 Investment Difference 19,673, 181.03 37,470,767.48 18,035,409.45 (33,207,504.90) (35,942,053.13) (6,029,799.93) Payments 724,204.23 783,840.49 131,500.59 Receipts 429,041.60 817,179.38 393,324.34

Attachment Snapshct: 201006261114103 . -Run!O: 16341 Biiiing Snapshot: 20100625173239

Entergy Electric System Date range - 20100601 through 20100630 Attachment 5 Intra-System Billing-201006RA Service Schedule MSS ~ 2 I Transmission Equalization Page 44

AR LA MS NO EGSL ETI Tota! Investment 411,270,947.16 516,493,136.74 270,353,906.99 27,048,703.25 331,881,485.90 242,644,575.63 Deferred Taxes 37,430,361.00 58,063,215.00 30,006,678.00 3,089,864,00 25,629,920.00 19, 783,447.00 Depreciation Reserve 162,587,708.00 186,714,652.00 98,019,787.00 14, 138,861.00 167 ,174,252.00 61,398,531.00 Net Transmission Investment 211,252,878.16 271,715,269.74 142,327,441.99 9,819,978.25 139,077,313.90 161,462,597.63 Cost of Cap!tal Debt Ratio {DR) 0.476500 0.502800 0.527000 0.455600 0.491300 0.483500 Bond Cost (i) 0.061600 0.067100 0.063400 0.060700 0.060900 0.075100 Preferred Ratio {PR) 0.039300 0.019900 0.031800 0,047700 0.003200 Preferred Cost (p) 0.059900 0.075500 0.056900 0,048200 0.087100 Common Ratio (ER) 0.484200 0.477400 0.441200 0.496700 0.505500 0.516500 Common Cost (c) 0.110000 0.110000 0.110000 0.110000 0.110000 0.110000 Total Cost of Capita! (CM) 0.084968 0.087754 0.083753 0.084591 0.085804 0.093126 Tax Rate (F) 0.035895 0.033783 0.031183 0.035609 0.034951 0.030593 Operat!ng Expenses Depreciation Factor (D} 0.0153010 0.0271140 0.0229240 0.0277360 0.0202970 0.0197710 Insurance Expense (I) 0.0038030 0.0011480 0.0038520 0,0021750 0.0018310 Property Tax (PT) 0.0043820 0.0082710 0.0166890 0.0121940 0.0067670 0.0074320 Franchise Tax (FT) 0.0001530 0.0010110 0.0020450 0.0008500 Operations & Maintenance (OM} 0.0351800 0.0374620 0.0356540 0.0424620 0.0448010 0.0263850 Total Operating Expenses 0.0588190 0.0739950 0.0801300 0.0844370 0.0740400 0.0562690 Net Investment Ratio (K) 0.513659 0.526077 0.526449 0.363048 0.419057 0.665428 Annual Ownership Cost 0.235372 0.262191 0.267144 0.352778 0.297437 0.208279 Net Transmission Investment* AOC 49,723,012.00 71,241,298.00 38,021,922.00 3,464,272.00 41,366, 739.00 33,629,268.00 System Average Annual Ownership Cost 237,446,511.00 I 935,655,479.67 0.2537756 System Average Monthly Ownership Cost 0.2537756 / 12 0.0211480 Respons!b!llty Ratio 0.2100 0.2594 0.1366 0.0455 0.1874 0.1611 Transmission Responsibility 196,487,650.73 242,709,031.43 127,810,538.52 42,572,324.32 175,341,836,89 150,734,097.77 Investment Difference Payments 14,765,227.43 29,006,238.31 14,516,903.47 (32,752,346.07) (36,264,522.99) 10,728,499,86 692,645.47 766,920.86 I Receipts 312,254.51 613,422.91 307,002.97 226,885.94

AttachmentSnapshd!: 20100728092959 RimlD: 16707 Bllllng Snapshot: 20100728092959

Entergy Electric System Date range· 20100701 through 20100731 Attachment 5 Intra-System Bllling-201007RA Service Schedule MSS • 21 Transmission Equalization Page 44

AR LA MS NO EGSL ETI Total Investment 414,292,644.47 516,998,737.69 270,282,974.70 26,290,825.51 332,286,730.47 246,384,445.14 Deferred Taxes 37,430,361.00 58,063,215.00 30,006,678.00 3,089,864.00 25,629,920.00 19,783,447,00 Depreciation Reserve 162,587,708.00 186,714,652.00 98,019,787.00 14, 138,861.00 167,174,252.00 61,398,531.00 Net Transmission Investment 214,274,575.47 272,220,870.69142,256,509.70 9,062, 100.51 139,482,558.47 165,202,467.14 Cost of Capital Debt Ratio (DR) 0.476500 0.502800 0.527000 0.455600 0.491300 0.483500 Bond Cost (I) 0.061600 0.067100 0.063400 0.060700 0.060900 0.075100 Preferred Ratio (PR) 0.039300 0.019900 0.031800 0.047700 0.003200 Preferred Cost {p} 0.059900 0.075500 0.056900 0.048200 0.087100 Common Ratio {ER) 0.484200 0.477400 0.441200 0.496700 0.505500 0.516500 Common Cost (c) 0.110000 0.110000 0. 110000 0.110000 0.110000 0.110000 Total Cost of Capltal (CM) 0.084968 0.087754 0.083753 0.084591 0.085804 0.093126 Tax Rate {F) 0.035895 0.033783 0.031183 0.035609 0.034951 0.030593 Operating Expenses Depreciation Factor (D} 0.0153010 0.0271140 0.0229240 0.0277360 0.0202970 0.0197710 Insurance Expense (l) 0.0038030 0.0011480 0.0038520 0.0021750 0.0018310 Property Tax (PD 0.0043820 0.0082710 0.0166890 0.0121940 0.0067670 0.0074320 Franchise Tax (FD 0.0001530 0.0010110 0.0020450 0.0008500 Operations & Maintenance (OM) 0.0351800 0.0374620 0.0356540 0.0424620 0.0448010 0.0263850 Total Operating Expenses 0.0588190 0.0739950 0.0801300 0.0844370 0.0740400 0.0562690 Net Investment Ratio (K) 0.517206 0.526541 0.526324 0.344687 0.419766 0.670507 Annual Ownership Cost 0.234587 0.262067 0.2671 BO 0.365167 0.297138 0.207639 Net Transmission Investment* AOC 50,266,030,00 71,340, 107.00 38,008,094.00 3,309,180.00 41,445,568.00 34,302,475.00 ' System Average Annual Ownership Cost 238,671,454.00 I 942,499,081.98 0.2532326 System Average Monthly Ownership Cost 0.2532326 / 12 0.0211027 Responslbll!ty Ratio 0.2108 0.2590 0.1370 0.0450 0.1853 0.1629 Transmission Responsibility 198,678,806.48 244,107,262.23 129, 122,374.23 42,412,458.69 174,645,079.89 153,533, 100.45 Investment Difference 15,595,768.99 28, 113,608.46 13,134, 135.47 (33,350,358.18) (35, 162,521.42) 11,669,366.69 Payments 703,783.04 742,024.61 Receipts 329,113.04 593,273.42 277,165.89 246,255.30

Attachment Snapshd: 20100826181933 Run10: 17029 BIH!ng Snapshot: 20100826175230

Entergy Electric System Date range -20100801through20100831 Attachment 5 Intra-System Billing-201008RA Service Schedule MSS • 2 /Transmission Equalization Page 48

AR LA MS NO EGSL ETI Total Investment 414,756,346.25 517,198.430.56 273,055,871.75 26,286,818.76 346,877,541.44 248,054,884.20 Deferred Taxes 37,430,361.00 56,063,215.00 30,006,676.00 3,089,864.00 25,629.920.00 19,783.447.00 Depreciation Reseive 162.587,708.00186,714,652.00 98,019,787.00 14,138,861.00 167,174,252.00 61,398,531.00 Net Transmission Investment 214,738,277.25 272.420,563.56 145;029.406.75 9,058,093.76 154,073,369.44166,872,906.20 Cost of Cap!tar Debt Ratio (DR) 0.476500 0.502800 0.527000 0.455600 0.491300 0.483500 Bond Cost (i) 0.061600 0.067100 0.063400 0.060700 0.060900 0.075100 Preferred Ratio (PR) 0.039300 0.019900 0.031800 0.047700 0.003200 Preferred Cost (p) 0.059900 0.075500 0.056900 0.048200 0.087100 Common Ratio {ER) 0.484200 0.477400 0.441200 0.496700 0.505500 0.516500 Common Cost (c) 0.110000 0.110000 0.110000 0.110000 0.110000 0.110000 Total Cost of Capital (CM) 0.084968 0.087754 0.083753 0.084591 0.085804 0.093126 Tax Rate (F) 0.035895 0.033783 0.031183 0.035609 0.034951 0.030593 Operating Expenses Depreciation Factor (D) 0.0153010 0.0271140 0.0229240 0.0277360 0.0202970 0.0197710 Insurance Expense (I) 0.0038030 0.0011480 0.0038520 0.0021750 0.0018310 Property Tax (PT) 0.0043820 0.0082710 0.0166890 0.0121940 0.0067670 0.0074320 Franchise Tax (FT) 0.0001530 0.0010110 0.0020450 0.0008500 Operations & Maintenance (OM) 0.0351800 0.0374620 0.0356540 0.0424620 0.0448010 0.0263850 Total Operating Expenses 0.0588190 0.0739950 0.0801300 0.0844370 0.0740400 0.0562690 Net Investment Ratio (K) 0.517746 0.526723 0.531135 0.344587 0.444172 0.672726 Annual Ownership Cost 0.234468 0.262018 0.265801 0.365238 0.287447 0.207362 Net Transmission Investment .. AOC 50,349,254.00 71,379,091.00 38,548,961.00 3,308,360.00 44,287,928.00 34,603, 100.00 System Average Annual Ownership Cost 242,476,694.00 I 962,192,616.96 0.2520043 System Average Monthly Ownership Cost 0.2520043 /12 0.0210004 Responsibility Raflo 0.2118 0.2586 0.1376 0.0449 0.1830 0.1641 Transmission Responsib!Hty 203,792,396.27 248,823,010.75 132,397,704.09 43,202,448.50 176,081.248.90157.895.808.44 Investment Difference 10,945,880.98 23.597.552.81 12,631.702.66 (34,144,354.74) (22,007,879.46) 8,977,097.76 Payments 717,043.74 462,173.39 Receipts 229,867.44 495,557.10 265,270.30 188,522.28

Attachment Snapshi:t: 2010092721202.1 RunlD: 17306 Biiiing Snapshot: 20100927145113

Entergy Electric System Date range - 20100901 through 20100930 Attachment 5 Intra-System Billing-201009RA Service Schedule MSS • 2 I Transmission Equalization Page 43

AR LA MS NO EGSL ETI Total Investment 414,738,135.57 517,477,482.94 273,038,040.36 26,298,420.03 346,868,159,71 223,998,394.51 Deferred Taxes 37,430,361.00 58,063,215.00 30,006,678.00 3,089,864.00 25,629,920.00 19,783,447,00 Depreciation Reserve 162,587,708.00 186,714,652.00 98,019,787.00 14, 138,861.00 167, 174,252.00 61,398,531,00 Net Transmission Investment 214,720,066.57 272,699,615.94145,011,575.36 9,069,695.03 154,063,987,71 142,816,416.51 Cost of Capital Debt Ratio {DR) 0.476500 0.502800 0.527000 0.455600 0.491300 0.483500 Bond Cost (i) 0.061600 0.067100 0.063400 0,060700 0.060900 0.075100 Preferred Ratio {PR) 0.039300 0.019900 0.031 BOO 0.047700 0.003200 Preferred Cost {p) 0,059900 0.075500 0.056900 0.048200 0.087100 Common Ratio (ER) 0.484200 0.477400 0.441200 0.496700 0.505500 0.516500 Common Cost (c) 0.110000 0.110000 0.110000 0.110000 0. 110000 0.110000 Total Cost of Capital (CM) 0.084968 0.087754 0.083753 0.084591 0.085804 0.093126 Tax Rate (F) 0.035895 0.033783 0.031183 0.035609 0.034951 0.030593 Operating Expenses Depi-eciation Factor (D) 0.0153010 0.0271140 0.0229240 0.0277360 0.0202970 0.0197710 Insurance Expense (J) 0.0038030 0.0011480 0.0038520 0.0021750 0.0018310 Property Tax (PT) 0.0043820 0.0082710 0.0166890 0.0121940 0.0067670 0.0074320 Franchise Tax (FT} 0.0001530 0.0010110 0.0020450 0.0008500 Operations & Maintenance (OM) 0.0351800 0.0374620 0,0356540 0,0424620 0.0448010 0.0263850 Total Operating Expenses 0.0588190 0.0739950 0.0801300 0.0844370 0.0740400 0.0562690 Net Investment Ratio (K) 0.517724 0.526979 0.531104 0.344876 0.444157 0.637578 Annual Ownership Cost 0.234473 0.261950 0.265810 0,365032 0.287452 0.211973 Net Transmission Investment"' AOC 50,346,058.00 71,433,664.00 38,545,527,00 3,310,729.00 44,286,001.00 30,273,224.00 System Average Annual Ownership Cost 238,195,203.00 I 938,381,357.12 0.2538362 System Average Monthly Ownership Cost 0.2538362 / 12 0.0211530 Responsfbilily Ratio 0.2120 0.2588 0.1387 0.0449 0. 1826 0.1630 Transmission Responsibility 198,936,847.71 242,853,095.22 130,153,494.23 42, 133,322.93 171,348,435.81 152,956, 161.21 Investment Difference 15, 783,218.86 29,846,520.72 14,858,081 .13 (33,063,627.90) (17,284,448.10) (10, 139,744.70) Payments 699,395.60 365,618.29 214,486.23 Receipts 333,862.75 6311344.07 314,293.30

Attachment Snapshot: 20101027081939 Run!D: 17618 BIUlng Snapshot: 20101026135839

Entergy Electric System Date range· 20101001through20101031 Attachment 5 Intra-System Bllling-201010RA Service Schedule MSS - 21 Transmission Equalization Page 42

AR LA MS NO EGSL ET!

Total Investment 414,791,036,09 505,655,952.56 273,529,330.19 26,299,394.26 347,196,039.47 223,962,656.04 Deferred Taxes 37,430,361.00 58,063,215.00 30,006,678.00 3,069,864.00 25,629,920.00 19,783,447.00 Depreciation Reserve 162,587,708.00 186,714,652.00 98,019,787.00 14, 138,861.00 167, 174,252.00 61,398,531.00 Net Transmission Investment 214,772,967.09 260,878,085,56145,502,865.19 9,070,669.26 154,391,867.47 142,780,678.04 Cost of Capltal Debt Ratio (DR) 0.476500 0.502800 0.527000 0.455600 0.491300 0.483500 Bond Cost (i) 0.061600 0.067100 0,063400 0.060700 0.060900 0.075100 Preferred Ratio (PR) 0.039300 0.019900 0.031800 0.047700 0.003200 Preferred Cost (p) 0.059900 0.075500 0.056900 0.048200 0.087100 Common Ratio (ER) 0.484200 0.477400 0.441200 0.496700 0.505500 0.516500 Common Cost (c) 0.110000 0.110000 0.110000 0.110000 0.110000 0.110000 To!al Cost of Capital (CM) 0.084968 0.087754 0.083753 0.084591 0.085804 0.093126 Tax Rate (F) 0.035895 0.033783 0,031183 0.035609 0.034951 0.030593 Operating Expenses Depreclallon Factor (D) 0.0153010 0.0271140 0.0229240 0.0277360 0.0202970 0.0197710 Insurance Expense (I) 0.0038030 0.0011480 0.0038520 0.0021750 0.0018310 Property Tax (PT) 0.0043820 0.0082710 0.0166890 0.0121940 0.0067670 0.0074320 Franchise Tax (FT) 0.0001530 0.0010110 0.0020450 0.0008500 Operations & Maintenance (OM) 0.0351800 0.0374620 0.0356540 0.0424620 0,0448010 0.0263850 Tota! Operating Expenses 0.0588190 0.0739950 0.0801300 0.0844370 0.0740400 0.0562690 Net Investment Ratio (K) 0.517786 0.515920 0.531946 0.344900 0.444682 0.637520 Annual Ownership Cost 0.234460 0.264960 0.265571 0.365015 0.287256 0.211981 Net Transmission Investment ~ AOC 50,355,670.00 69, 122,258.00 38,641,341.00 3,310,930.00 44,349,990.00 30,266, 791.00 System Average Annual Ownership Cost 236,046,980.00 I 927,397' 132.61 0.2545263 System Average Monthly Ownership Cost 0.2545263 /12 0.0212105 Responsiblllty Ratio 0.2115 0.2601 0.1386 0.0450 0.1810 0.1638 Transmission ResponsibUity 196, 144,493.55 241,215,994.19 128,537,242.58 41,732,870.97 167,858,881.00 151,907,650.32 Investment Difference 18,628,473.54 19,662,091.37 16,965,622.61 (32,662,201. 71) (13,467,013.53) (9,126,972.28) Payments 692,782.50 285,642.45 193,587.89 Receipts 395,119.74 417,043.31 359,849.79

Attachment Snapshot: 20101124124641 RunlO: 171161 Bl!llng Snapshot: 201011Z4DB4S11

Entergy Electric System Date range· 20101101through20101130 Attachment 5 Intra-System Billing-201011 RA Service Schedule MSS ~ 21 Transmission Equalization Page 40

AR LA MS NO EGSL ETI Total Investment 414,855,854.25 506,433,213.41 273,547,229.46 26,299,413.85 348,837,905.80 224,013,632.72 Deferred Taxes 37,430,361.00 58,063,215.00 30,006,678.00 3,089,864.00 25,629,920.00 19,783,447.00 Depreclatlon Reserve 162,587,708.00 186,714,652.00 98,019,787.00 14,138,861.00 167, 174,252.00 61,398,531.00 Net Transmission Investment 214,837,785.25 261,655,346.41145,520,764.46 9,070,688.85 156,033,733.80 142,831,654.72 Cost of Capital Debt Ratio (DR) 0.476500 0.502800 0.527000 0.455600 0.491300 0.483500 Bond Cost (I) 0.061600 0.067100 0.063400 0.060700 0.060900 0.075100 Preferred Ratio (PR) 0.039300 0.019900 0.031800 0.047700 0.0.03200 Preferred Cost (p) 0.059900 0.075500 0.056900 0.048200 0.087100 Common Ratio (ER) 0.484200 0.477400 0.441200 0.496700 0.505500 0.516500 Common Cost (c} 0.110000 0.110000 0.110000 0.110000 0.110000 0.110000 Total Cost of Capita! (CM} 0.084968 0.087754 0.083753 0.084591 0.085804 0.093126 Tax Rate (F} 0.035895 0.033783 0.031183 0.035609 0.034951 0.030593 Operating Expenses Depreciation Factor (D} 0.0153010 0.0271140 0.0229240 0.0277360 0.0202970 0.0197710 Insurance Expense (I) 0.0038030 0.0011480 0.0038520 0.0021750 0.0018310 Property Tax (PT) 0.0043820 0.0082710 0.0166890 0.0121940 0.0067670 0.0074320 Franchise Tax (FT) 0.0001530 0.0010110 0.0020450 0.0008500 Operations & Maintenance (OM) 0.0351800 0.0374620 0.0356540 0.0424620 0.0448010 0.0263850 Total Operating Expenses 0.0588190 0.0739950 0.0801300 0.0844370 0.0740400 0.0562690 Net Investment Ratio (K) 0.517861 0.516663 0.531977 0.344901 0.447296 0.637603 Annual Ownership Cost 0.234443 0.264754 0.265562 0.365015 0.286282 0.211969 Net Transmission Investment *AOC 50,367 ,215.00 69,274,300.00 38,644,785.00 3,310,937.00 44,669,649.00 30,275,883.00 System Average Annual Ownership Cost 236,542,769.00 I 929,949,973.49 0.2543608 System Average Monthly Ownership Cost 0.2543608 /12 0.0211967 Responslbllity Ratio 0.2104 0.2606 0.1377 O.o450 0.1808 0.1655 Transmission Responsibility 195,661,474.42 242,344,963.09 128,054,111.35 41,847,748.81 168,134,955.21 153,906,720.61 Investment Difference 19, 176,310.83 19,310,383.32 17,466,653.11 (32,777,059.96) (12,101,221.41) (11,075,065.89) Payments 694,766.45 256,506.31 234,755.17 Receipts 406,475.06 409,316.96 370,235.91

Attachment Snepshtt: :Z01012291)80014 Runic: 18142 Bllllng Snapshot: :Z0101:Z2B1705J9

Entergy Electric System Date range. 20101201 through 20101231 Attachment 5 Intra-System Billlng-201012RA Service Schedule MSS 21 Transmission Equalization w Page 42

AR LA MS NO EGSL ETI Total Investment 415,060,255.12 506,501,649.34 273,867,644.31 26,291,850.27 350,235,178.26 225,614,138.80 Deferred Taxes 37,430,361.00 58,063,215.00 30,006,678.00 3,089,864.00 25,629,920.00 19,783,447.00 Depreciation Reserve 162,587,708.00 186,714,652.00 98,019,787.00 14, 138,861.00 167, 174,252.00 61,398,531.00 Net Transmission Investment 215,042, 186.12 261, 723, 782.34 145,841, 179.31 9,063,125.27 157,431,006.26 144,432, 160.80 Cost of Capital Debt Ratio (DR) 0.476500 0.502800 0.527000 0.455600 0.491300 0.483500 Bond Cost (i) 0.061600 0.067100 0.063400 0.060700 0.060900 0.075100 Preferred Ratio (PR) 0'.039300 0.019900 0.031800 0,047700 0.003200 Preferred Cost (p) 0.059900 0.075500 0.056900 0.048200 0.087100 Common Ratio (ER) 0.484200 0.477400 0.441200 0.496700 0.505500 0.516500 Common Cost (c) 0.110000 0.110000 0.110000 0.110000 0.110000 0.110000 Total Cost of Capital (CM) 0.084968 0.087754 0.083753 0.084591 0.085804 0.093126 Tax Rate (F) 0.035895 0.033783 0.031183 0.035609 0.034951 0.030593 Operating Expenses Depreciation Factor (D) 0.0153010 0.0271140 0.0229240 0.0277360 0.0202970 0.0197710 Insurance Expense (I) 0.0038030 0.0011480 0.0038520 0.0021750 0.0018310 Property Tax (PT) 0.0043820 0.0082710 0,0166890 0.0121940 0.0067670 0.0074320 Franchise Tax (FT) 0.0001530 0.0010110 0.0020450 0.0008500 Operations & Maintenance (OM) 0.0351800 0.0374620 0.0356540 0.0424620 0.0448010 0.0263850 Total Operating Expenses 0.0588190 0.0739950 0.0801300 0.0844370 0.0740400 0.0562690 Net Investment Ratio (K) 0.518099 0.516728 0.532524 0.344712 0.449501 0.640173 Annual Ownership Cost 0.234391 0.264736 0.265408 0.365149 0.285470 0.211615 Net Transmission Investment"' AOC 50,403,953.00 69,287,707.00 38, 707,416.00 3,309,391.00 44,941,829.00 30,564,012.00 System Average Annual Ownership Cost 237,214,308.00 I 933,533,440.10 = 0.2541037 System Average Monthly Ownership Cost 0.2541037 /12 0.0211753 Responslblllty Ratio 0.2094 0.2598 0.1373 0.0450 0.1818 0.1667 Transmission Responsfbil!ty 195,481,902.36 242,531,987.74128,174,141.33 42,009,004.80 169,716,379.41 155,620,024.46 Investment Dlffererice 19,560,283.76 19, 191, 794.60 17,667,037.98 (32,945,879.53) (12,285,373.15) (11, 187,863.66) Payments 697,639.18 260,146.57 236,906.47 Receipts 414,195.05 406,392.18 374,104.99

AttachmentSnap1;hd;: 2.011D125173007 RunlD: 18459 B!Ulng Snapshot: 2()110125162604

Entergy Electric System Date range -20110101 through 20110131 Attachment 5 Intra-System Billing-201101RA Service Schedule MSS • 2 /Transmission Equalization Page 42

AR LA MS NO EGSL ET!

Total Investment 415,393,432.12 507 ,724,414.94 274,208,896.85 26,332, 130.65 351,726,496.11 226,605,916.47 Deferred Taxes 37,430,361.00 58,063,215.00 30,006,678.00 3,089,864.00 25,629,920.00 19,783,447.00 Depreciation Reserve 162,587,708.00 186,714,652.00 98,019,787.00 14, 138,861.00 167,174,252.00 61,398,531.00 Net Transmission Investment 215,375,363.12 262,946,547.94 146,182,431.85 9,103,405.65 158,922,324.11 145,423,938.47 Cost of Capital Debt Ratio (DR) 0.476500 0.502800 0.527000 0.455600 0.491300 0.483500 Bond Cost (i) 0.061600 0.067100 0.063400 0.060700 0.060900 0.075100 Preferred Ratio (PR) 0.039300 0.019900 0.031800 0.047700 0.003200 Preferred Cost (p) 0.059900 0.075500 0.056900 0,048200 0.067100 Common Ratio (ER) 0.464200 0.477400 0.441200 0.496700 0.505500 0.516500 Common Cost (c) 0.110000 0.110000 0.110000 0.110000 0.110000 0.110000 Total Cost of Capital (CM} 0.064966 0.087754 0.083753 0.084591 0.065804 0.093126 Tax Rate (F) 0,035695 0.033763 0.031163 0.035609 0.034951 0.030593 Operating Expenses Depreciation Factor (D) 0.0153010 0.0271140 0.0229240 0.0277360 0.0202970 0.0197710 Insurance Expense (I) 0.0038030 0.0011460 0.0036520 0.0021750 0.0016310 Property Tax (PD 0.0043620 0.0082710 0.0166890 0.0121940 0.0067670 0.0074320 Franchise Tax (FT) 0.0001530 0.0010110 0.0020450 0.0008500 Operations & Maintenance (OM) 0.0351800 0.0374620 0.0356540 0.0424620 0.0448010 0.0263650 Total Operating Expenses 0.0566190 0.0739950 0.0601300 0;0644370 0.0740400 0.0562690 Net Investment Ratio (K) 0.516465 0.517892 0.533106 0.345715 0.451635 0.641748 Annual Ownership Cost 0.234306 0.264414 0.265243 0.364436 0.284620 0.211399 Net Transmission Investment* AOC 50,463,740.00 69,526,749.00 36,773,667,00 3,317,627.00 45,232,472.00 30,742,475.00 System Average Annual Ownership Cost 236,056,930.00 I 937,954,011.14 = 0.2536045 System Average Monthly Ownership Cost 0.2536045 / 12 0.0211504 Responsib!lity Ratio 0.2101 0.2601 0.1374 O.D451 0.1604 0.1669 Transmission Responslbllity 197,064,137.74 243,961,836.30 126,674,681.13 42,301,725.90 169,206,903.61 156,544,524.46 Investment Difference 16,311,225.36 16,984, 709.64 17,307,550.72 (33,196,320.25) (10,264,579.50) (11, 120,565,99) Payments 702,156.87 217,522.70 235,204.55 Receipts 387,289.25 401,533.70 366,061.16

Attachment Snapshct: 2Cl11Cl223222207 RunlD: 18694 ermng Snapsht1t: 2011e12232222!l7

Entergy Electric System Date range -20110201 through 20110228 Attachment 5 Intra-System Billing-201102RA Service Schedule MSS 2 /Transmission Equalizatlon M Page42

AR LA MS NO EGSL ETI Total Investment 415,506,469.44 510,394,566.06 289,177,798.89 26,421,689.73 351,505,989.04 227,499,338.89 Deferred Taxes 37,430,361.00 58,063,215.00 30,006,678.00 3,089,864.00 25,629,920.00 19,783,447.00 Depreciation Reserve 162,587, 708.00 186, 714,652.00 98,019, 787.00 14, 138,861.00 167, 174,252.00 61,398,531.00 Net Transmission Investment 215,488,400.44 265,616,699.06 161,151,333.89 9, 192,964.73 158,701,817.04 146,317,360.89 Cost of Capital Debt Ratio (DR) 0.476500 0.502800 0.527000 0.455600 0.491300 0.483500 Bond Cost (I) 0.061600 0.067100 0.063400 0.060700 0.060900 0.075100 Preferred Ratio (PR) 0.039300 0.019900 0.031800 0.047700 0.003200 Preferred Cost (p) 0.059900 0.075500 0.056900 0.048200 0.087100 Common Ratio (ER) 0.484200 0.477400 0.441200 0.496700 0.505500 0.516500 Common Cost (c) 0.110000 0.110000 0.110000 0.110000 0.110000 0.110000 Total Cost of Capita! (CM) 0.084968 0.087754 0.083753 0.084591 0.085804 0.093126 Tax Rate (F) 0.035895 0.033783 0.031183 0.035609 0.034951 0.030593 Operating Expenses Depreciation Factor (D) 0.0153010 0.0271140 0.0229240 0.0277360 0.0202970 0.0197710 Insurance Expense (I) 0.0038030 0.0011480 0.0038520 0.0021750 0.0018310 Property Tax (PT) 0.0043820 0.0082710 0.0166890 0.0121940 0.0067670 0.0074320 Franchise Tax (FT) 0.0001530 0.0010110 0.0020450 0.0008500 Operations & Maintenance (OM) 0.0351800 0.0374620 0.0358540 0.0424620 0.0448010 0.0263850 Total Operating Expenses 0.0588190 0.0739950 0.0801300 0.0844370 0.0740400 0.0562690 Net Investment Ratio (K) 0.518616 0.520414 0.557274 0.347933 0.451491 0.643155 Annual Ownership Cost 0.234278 0.263721 0.258725 0.362881 0.284744 0.211208 Net Transmission Investment* AOC 50,484, 191.00 70,048,701.00 41,693,879.00 3,335,952.00 45, 189,390.00 30,903,397.00 System Average Annual Ownership Cost 241,655,51 o.oo I 956,468,576,05 0.2526539 System Average Monthly Ownership Cost 0.2526539 / 12 0.0210545 Responsibility Ratio 0.2100 0.2608 0.1376 0.0453 0.1815 0.1648 Transmission Responslbilily 200,858,400.97 249,447,004.63 131,610,076.06 43,328,026.50 173,599,046.55 157 ,626,021.33 Investment Difference 14,629,999.47 16,169,694.43 29,541,257.83 (34,135,061.77) (14,897,229.51) (11,308,660.44) Payments 718,696.36 313,653.59 238,098.09 Receipts 308,027.19 340,444.69 621,976.15

Attachment Snapshct: 20110328192727 RunTD: 19029 BllUng snapshot: 20110328162603

Entergy Electric System Date range -20110301through20110331 Attachment 5 Intra-System Billing-201103RA Service Schedule MSS ~ 21 Transmission Equalization Page 41

AR LA MS NO EGSL ET!

Total Investment 415,658,021.66 510.490,052.28 289,224,221.25 26,421,689.73 351,339,192.74 229,664,396,61 Deferred Taxes 37,430,361.00 58,063,215.00 30,006,678.00 3,089,864.00 25,629,920.00 19,783,447.00 Depreciation Reserve 162,587,708.00 186,714,652.00 98,019,787.00 14, 138,861.00 167,174,252.00 61,398,531.00 Net Transmission Investment 215,639,952.66 265, 712, 185.28 161,197 ,756.25 9, 192,964. 73 158,535,020. 74 148,482,418.61 Cost of Cap!tal Debi Ratio (DR) 0.476500 0.502800 0.527000 0.455600 0.491300 0.483500 Bond Cost (i) 0.061600 0.067100 0.063400 0.060700 0.060900 0.075100 Preferred Ratio (PR) 0.039300 0.019900 0.031800 0.047700 0.003200 Preferred Cost (p) 0.059900 0.075500 0.056900 0.048200 0.087100 Common Ratio (ER) 0.484200 0.477400 0.441200 0.496700 0.505500 0.516500 Common Cost (c) 0.110000 0.110000 0.110000 0.110000 0.110000 0.110000 Total Cost of Capital (CM) 0.084968 0.087754 0.083753 0.084591 0.085804 0.093126 Tax Rate (F) 0.035895 0.033783 0.031183 0.035609 0.034951 0.030593 Opera!Jng Expenses Depreciation Factor (D) 0.0153010 0.0271140 0.0229240 0.0277360 0.0202970 0.0197710 Insurance Expense (I) 0.0038030 0.0011480 0.0038520 0.0021750 0.0018310 Property Tax (PT) 0.0043820 0.0082710 0.0166890 0.0121940 0.0067670 0.0074320 Franchise Tax (FT) 0.0001530 0.0010110 0.0020450 0.0008500 Operations & Maintenance (OM) 0.0351800 0.0374620 0.0356540 0.0424620 0.0448010 0.0263850 Total Operating Expenses 0.0588190 0.0739950 0.0801300 0,0844370 0.0740400 0.0562690 Net Investment Ratio (K) 0.518792 0.520504 0.557345 0.347933 0.451231 0.646519 Annual Ownership Cost 0.234239 0.263697 0.258706 0.362881 0.284839 0.210752 Net Transmission Investment• AOC 50,511,287.00 70,067,506.00 41,702,827.00 3,335,952.00 45, 156,957.00 31,292,967.00 System Average Annual Ownership Cost 242,067,496.00 I 958,760,298,27 0.2524797 System Average Monthly Ownership Cost 0.2524797 / 12 0.0210400 Responslbf!lty Ratio 0.2088 0.2615 0.1377 0.0455 0.1809 0.1656 Transmission Responsibility 200, 189,150.28 250,715,818.00 132,021,293.07 43,623,593.57 173,439,737.96 158,770,705.39 Investment Difference Payments 15,450,802.38 14,996,367,28 29,176,463.18 (34,430,628.84) (14,904,717.22) (10,288,286.78) 724,419.52 313,594.86 216,465.28 l I

Receipts 325,084.47 315,523.17 613,872.01

Attachment Snapshct: 20110426164256 Run[D: 19349 BJIUng Snapshot: 20110426161055

Entergy Electric System Date range -20110401 through 20110430 Attachment 5 Intra-System Bllllng-201104RA Service Schedule MSS ~ 21 Transmission Equalization Page 45

AR LA MS NO EGSL ETI Tota! Investment 415,088,642,28 512,511,972.90 290,098,703.50 26,520,278.59 353,427,619.57 232,455,038.76 Deferred Taxes 37,430,361.00 58,063,215.00 30,006,678.00 3,089,864.00 25,629,920.00 19,783,447.00 Depreciation Reserve 162,587,706.00 186,714,652.00 98,019,787.00 14, 138,861.00 167,174,252.00 61,398,531.00 Net Transmission Investment 215,070,573.28 267,734, 105.90 162,072,238.50 9,291,553.59 160,623,447.57 151,273,060.76 Cost of Capital Debt Ratio (OR) 0.476500 0.502800 0.527000 0.455600 0.491300 0.483500 Bond Cost (I) 0.061600 0.067100 0,063400 0,060700 0,060900 0.075100 Preferred Ratio (PR) 0.039300 0.019900 0.031800 0.047700 0.003200 Preferred Cost (p) 0.059900 0.075500 0.056900 0.048200 0.087100 Common Ratio (ER) 0.484200 0.477400 0.441200 0.496700 0.505500 0.516500 Common Cost (c) 0.110000 0.110000 0.110000 0.110000 0.110000 0.110000 Total Cost of Capital (CM) 0.084968 0,087754 0.083753 0.084591 0.085804 0.093126 Tax Rate (F) 0.035895 0.033783 0.031183 0,035609 0.034951 0.030593 Operating Expenses Depreciation Factor (0) 0.0153010 0.0271140 0.0229240 0.0277360 0.0202970 0.0197710 Insurance Expense {I) 0.0036030 0.0011480 0.0038520 0.0021750 0.0018310 Property Tax (PT) 0.0043820 0.0082710 0.0166890 0.0121940 0.0067670 0.0074320 Franchise Tax (FT) 0.0001530 0.0010110 0.0020450 0.0006500 Operations & Maintenance (OM) 0.0351800 0.0374620 0.0356540 0.0424620 0.0448010 0.0263850 Total Operating Expenses 0.0588190 0,0739950 0.0801300 0.0844370 0.0740400 0.0562690 Net Investment Ratio (K) 0.518132 0.522396 0.558680 0.350357 0.454473 0.650763 Annual Ownership Cost 0.234384 0.263182 0.258363 0.361202 0.283668 0.210185 Net Transmission Investment* AOC 50,409,101.00 70,462,797.00 41,873,470.00 3,356, 128.00 45,563,732.00 31,795,326.00 System Average Annual Ownership Cost 243,460,556.00 I 966,064,979.60 0.2520126 System Average Monthly Ownership Cost 0.2520126 /12 0.0210010 ResponslbllJly Ratio 0.2071 0.2627 0.1380 0.0454 0.1811 0.1657 Transmission Responsibility 200,072,057.26 253,785,270.14 133,316,967.18 43,659,350.07 174,954,367.81 160,076,967.12 Investment Difference 14,998,516.00 13,946,635.76 26,755,271.32 (34,567,796.46) (14,330,920.24) (6,603,906.36) Payments 725,960.05 300,964.38 184,891.28 Receipts 314,984.60 292,940.21 603,890.91

Attai::hment Snapshct: 20110525170533 RunlD: 19693 Biiiing Snapshot: 20110625170533

I Entergy Electric System Date range - 20110501 through 20110531 Attachment 5 I Intra-System Billing-201105RA Service Schedule MSS - 21 Transmission Equalization Page 42

AR LA MS NO EGSL ETI Total Investment 418,905,714.73 516,003,522.22 290,104,664.22 27,616,205.12 353,181,118. 18 235,558,750.94 Deferred Taxes 37,430,361.00 58,063,215.00 30,006,678.00 3,089,864.00 25,629,920.00 19,783,447.00 Depreciation Rese!Ve 162,587,708.00 186,714,652.00 98,019,787.00 14,138,861.00 167, 174,252.00 61,398,531.00 Net Transmission Investment 218,887,645.73 271,225,655.22 162,078, 199.22 10,387,480.12 160,376,946.18 154,376,772.94 Cost of Capital Debt Ratio (DR) 0.476500 0.502800 0.527000 0.455600 0.491300 0.483500 Bond Cost (I) 0.061600 0.067100 0.063400 0.060700 0.060900 0.075100 Preferred Ratio (PR) 0.039300 0.019900 0.031800 0.047700 0.003200 Preferred Cost (p) 0.059900 0.075500 0.056900 0.048200 0.087100 Common Ratio (ER) 0.484200 0.477400 0.441200 0.496700 0.505500 0.516500 Common Cost (c) 0.110000 0.110000 0.110000 0.110000 0.110000 0.110000 Total Cost of Capita! (CM) 0.084968 0.087754 0.083753 0.084591 0.085804 0.093126 Tax Rate (F) 0.035895 0.033783 0.031183 0.035609 0.034951 0.030593 Operating Expenses Depreciation Factor (D) 0.0153010 0.0271140 0.0229240 ' 0.0277360 0.0202970 0.0197710 Insurance Expense (I} 0.0038030 0.0011480 0.0038520 0.0021750 0.0018310 Property Tax (PD 0.0043820 0.0082710 0.0166890 0.0121940 0.0067670 0.0074320 Franchise Tax (FT) 0.0001530 0.0010110 0.0020450 0.0008500 Operations & Maintenance {OM) 0.0351800 0.0374620 0.0356540 0,0424620 0.0448010 0.0263850 Total Operating Expenses 0.0588190 0.0739950 0.0801300 0.0844370 0.0740400 0.0562690 Net Investment Ratio (K) 0.522522 0.525628 0.558689 0.376137 0.454093 0.655364 Annual Ownership Cost 0.233430 0.262311 0.258361 0.344684 0.283805 0.209578 Net Transmission Investment* AOC 51,094,943.00 71, 145,473.00 41,874,686.00 3,580,398,00 45,515, 779.00 32,353,975.00 System Average Annual Ownership Cost 245,565,254,00 I 977,332,699.41 0.2512606 System Average Monthly Ownership Cost 0.2512606 / 12 0.0209384 Responslb!lfty Ratio 0.2058 0.2627 0.1385 0.0457 0.1804 0.1669 Transmission Responsiblllty 201,135,069.54 256,745,300.14135,360,578.87 44,664,104.36 176,310,818.97 163,116,827.53 Investment Difference 17,752,576.19 14,480,355.08 26,717,620.35 (34,276,624.24) (15,933,872.79) (8,740,054.59) Payments 717,697.25 333,629.61 183,002.65 Receipts 371,710.33 303, 195.29 559,423.90

At1achmcntSnapshd:: 20110627175012 RunlO: 20095 Bllllng Snapshot: 20110627175012

Entergy Electric System Date range -20110601 through 20110630 Attachment 5 Intra-System Billlng-201106RA Service Schedule MSS - 2 /Transmission Equalization Page 41

AR LA MS NO EGSL ET!

Total Investment 424,209,890.60 517,832,426.21 298,253,065.58 27,638,800.89 372,099,963.16 236,387,445.08 Deferred Taxes 40,474, 156.00 66,697,341.00 34,898,123.00 2,321, 112.00 28,441,593.00 23,459,553.00 Depreciation Reserve 168,087,392.00 206, 102,378.00 106, 141,224.00 11,539,821.00 173,877 ,578.00 68,979,950.00 Net Transmlss!on Investment 215,648,342.60 245,032,707.21157,213,718.58 13,777,867.89 169,780,792.16 143,947,942.08 Cost of Capltat Debt Ratio (DR) 0.474200 0.474400 0.508300 0.431500 0.474500 0.500000 Bond Cost (I) 0.056200 0.064700 0.062000 0.062200 0.058300 0.069800 Preferred Ratio (PR) 0.039700 0.019200 0.031500 0.053800 0.003200 Preferred Cost (p) 0.059900 0.075300 0.056900 0.048200 0.087100 Common Ratio (ER) 0.486200 0,506300 0.460200 0.514700 0.522300 0.500000 Common Cost (c) 0.110000 0.110000 0.110000 0.110000 0.110000 0.110000 Total Cost of Capita[ (CM) 0.082510 0.087833 0.083929 0.086049 0.085395 0.089900 Tax Rate (F) 0.036053 0.035736 0.032467 0.037031 0.036106 0.029615 Operating Expenses Depreciation Factor {D) 0.0152270 0.0283830 0.0229140 0.0292210 0.0201180 0.0205130 Insurance Expense {I) 0.0036370 0.0003100 0.0039710 0.0021970 0.0017570 Property Tax (PD 0.0043900 0.0098690 0.0168800 0.0138350 0.0072620 0.0077650 Franchise Tax (FT) 0.0001400 0.0010400 0.0018540 0.0001760 Operations & Maintenance (OM) 0.0372880 0.0438560 0.0365650 0.0588120 0.0435820 0.0288180 Total Operating Expenses 0.0606820 0.0824180 0.0813700 0.1037220 0.0731590 0.0590290 Net Investment Ratio (K) 0,508353 0.473189 0.527115 0.498497 0.456277 0.608949 Annual Ownership Cost 0.237932 0.297744 0.270764 0.331149 0.281840 0.216450 Net Transmission Investment* AOC 51,309,641.00 72,957,018.00 42,567 ,815.00 4,562,527 .00 47,851,018.00 31,157,532.00 System Average Annual Ownership Cost 250,405,551.00 I 945,401,370.52 0.2648669 System Average Monthly Ownership Cost 0.2648669 / 12 0.0220722 Responslbll!ty Ratio 0.2044 0.2626 0.1392 0.0457 0.1796 0.1685 Transmission Responslblllty 193,240,040.13 248,262,399.90 131,599,870.78 43,204,842.63 169,794,086.15"159,300, 130.93 Investment Difference 22,408,302.47 (3,229,692.69) 25,613,847.80 (29,426,974.74) (13,293.99) (15,352, 188.85) Payments 71,286.56 649,519.35 293.43 338,857.25 Receipts 494,601.51 565,355.09

Atta~hment Snapshtt:: 20110726141150 RunlO: 20433 Bltnng Snapshot: 20110725133622

Entergy Electric System Date range - 20110701 through 20110731 Attachment 6 Intra-System Billing-201107RA Service Schedule MSS - 21 Transmission Equalization Page 42

AR LA MS NO EGSL ETI Total Investment 424,795,416.73 518,659,046.34 313,547,024.61 27,618,517.54 374,379,933.08 236,535,467.35 Deferred Taxes 40,474, 156.00 66,697,341.00 34,896,123.00 2,321, 112.00 26,441,593.00 23,459,553.00 Depreciation Reserve 166,067,392.00 206,102,376.00106,141,224.00 11,539,821.00 173,877,578.00 68,979,950.00 Net Transmission Investment 216,233,868.73 245,859,327.34 172,507,677.61 13,757 ,584.54 172,060,762.08 144,095,964.35 Cost of Capital Debt Ratio (DR) 0.474200 0.474400 0.506300 0.431500 0.474500 0.500000 Bond Cost (I) 0.056200 0,064700 0.062000 0.062200 0.056300 0.069800 Preferred Ratio (PR) 0.039700 0.019200 0.031500 0.053800 0.003200 Preferred Cost (p) 0.059900 0.075300 0.056900 0.048200 0,087100 Common Ratio (ER) 0.466200 0.506300 0.460200 0.514700 0.522300 0.500000 Common Cost (c) 0.110000 0.110000 0.110000 0.110000 0.110000 0.110000 Total Cost of Capital (CM) 0.082510 0.087833 0.083929 0.086049 0.085395 0.089900 Tax Rate (F) 0.036053 0.035736 0.032467 0.037031 0.036106 0.029615 Operating Expenses Depredation Factor (D) 0.0152270 0.0263830 0.0229140 0.0292210 0.0201160 0.0205130 Insurance Expense (1) 0.0036370 0.0003100 0.0039710 0.0021970 0.00l7570 Property Tax (PT) 0.0043900 0.0098690 0.0166800 0.0136350 0.0072620 0.0077650 Franchise Tax (FT) 0.0001400 0.0010400 0,0018540 0.0001760 Operations & Maintenance (OM) 0.0372880 0,0438560 0.0365650 0.0588120 0.0435820 0.0288180 Total Operating Expenses 0.0606820 0.0824180 0.0613700 0.1037220 0.0731590 0.0590290 Net Investment Ratio (K) 0,509031 0.474029 0.550181 0.498129 0.459569 0.609194 Annual Ownership Cost 0.237773 0.297435 0.264292 0.331303 0.280664 0.216411 Net Transmission Investment* AOC 51,414,576.00 73,127,169.00 45,592,399.00 4,557,929.00 46,294,703.00 31, 163,952.00 System Average Annual Ownership Cost 254,170,728.00 I 964,515, 164.65 0.2635218 System Average tvlonthly Ownership Cost 0.2635218 /12 0.0219602 Responslb!llty Ratio 0.2031 0.2637 0.1389 0.0459 0.1795 0.1669 Transmission Responslblflty 195,893,034.00 254,342,654.19 133,971, 159.15 44,271,246.98 173,130,475.64 162,906,614.69 Investment Difference 20,340,834.73 (8,463,326.85) 36,536,518.46 (30,513,662.44) (1,069,713.56) (18,810,650.34) Payments 186,295.09 670,084.47 23,491.07 413,084,62 Receipts 446,687.69 846,267.56

Attachment Snapshct: 20110828185123 RunlD: 20828 Bllllng Snapshot: 20110826165123

Entergy Electric System Date range -20110801 through 20110831 Attachment 5 Intra-System Billing-20110BRA Service Schedule MSS 2 /Transmission Equalization R Page 41

AR LA MS NO EGSL ETI Total Investment 430,480,300.58 519,579,413.16 313,695,696.12 27,619, 102.03 375,686,576.07 236,733,346.30 Deferred Taxes 40,474, 156.00 66,697,341.00 34,696, 123.00 2,321, 112.00 26,441,593.00 23,459,553.00 Depreciation Reserve 166,087,392.00 206,102,376.00 106,141.224.00 11,539,621.00 173,677,576.00 66,979,950.00 Net Transmission Investment 221,916,752.56 246,779,694.16 172,656,549.12 13,756,169.03 173,567,405.07 144,293,645.30 Cost of Capital Debt Ratio (DR) 0.474200 0.474400 0.506300 0.431500 0.474500 0.500000 Bond Cost (i) 0.056200 0.064700 0.062000 0.062200 0.056300 0.069800 Preferred Ratio (PR) 0.039700 0.019200 0.031500 0.053600 0.003200 Preferred Cost (p} 0.059900 0.075300 0.056900 0.048200 0,067100 Common Ratio {ER) 0.466200 0.506300 0.460200 0,514700 0.522300 0.500000 Common Cost (c) 0.110000 0.110000 0.110000 0.110000 0.110000 0.110000 Total Cost of Capltal {CM) 0.062510 0.087833 0.063929 0.066049 0.065395 0.089900 Tax Rate (F) 0.036053 0.035736 0.032467 0.037031 0.036106 0.029615 Operating Expenses Depreciation Factor (D) 0.0152270 0.0263630 0.0229140 0.0292210 0.0201160 0.0205130 Insurance Expense (I) 0.0036370 0.0003100 0.0039710 0.0021970 0.0017570 Property Tax (PT) 0.0043900 0.0096690 0.0168800 0.0138350 0.0072620 0.0077650 Franchise Tax (FT) 0.0001400 0.0010400 0.0016540 0.0001760 Operations & Maintenance (OM) 0.0372660 0.0436560 0.0365650 0.0566120 0.0435820 0.0288180 Total Operating Expenses 0.0606620 0.0824160 0.0613700 0.1037220 0.0731590 0.0590290 Net Investment Ratio (K) 0.515514 0.474960 0.550661 0.496140 0.461755 0.609521 Annual Ownership Cost 0.236274 0.297095 0.264156 0.331296 0.279937 0.216359 Net Transmission Investment* AOC 52,433,631.00 73,317,013.00 45,661,440.00 4,558,054.00 46,567,939.00 31,219,272.00 System Average Annual Ownership Cost 255,777,349.00 I 973, 174,415.26 0.2626279 System Average Monthly Ownership Cost 0.2626279 /12 0.0219023 ResponslbJllly Ratio 0.2043 0.2630 0.1389 0.0456 0.1792 0.1690 Transmission Respons!bllity 196,619,533.04 255,944,671.21135,173,926.26 44,376,753.34 174,392,855.21164,466,476.16 Investment Difference 23,099.219.54 (9,165,177.05) 37,662,622.64 (30,616,564.31) (625,450.14) (20, 172,630.68) Payments 200,736.66 670,618.08 16,079.27 441,827.45 Receipts 505,926.54 825,336.93

Attachmen(Snapshct: 20110927172811 RunlD: 21193 Blll!ng Snapshot: 20110921164044

Entergy Electric System Date range -20110901through20110930 Attachment 5 Intra-System Bllling-201109RA Service Schedule MS~ - 21 Transmission Equalization Page 40

AR LA MS NO EGSL ETI Total Investment 434,281,095.23 519,752,682.65 314,109,029.61 27,619,102.03 377,406,576.04 236,757,056.43 Deferred Taxes 40,474, 156.00 66,697,341.00 34,898, 123.00 2,321,112.00 28,441,593,00 23,459,553.00 Depreciation Reserve 168,087,392.00 206,102,378.00 106,141,224.00 11,539,821.00 173,677,578.00 66,979,950.00 Net Transmission Investment 225,719,547.23 246,952,963.65173,069,662.61 13,758,169.03 175,087,405.04144,317,553.43 Cost of Capita!

Debt Ratio (DR) 0.474200 0.474400 0.508300 0.431500 0.474500 0.500000 Bond Cost (i) 0.056200 0.064700 0.062000 0.062200 0.058300 0.069800 Preferred Ratio (PR) 0.039700 0.019200 0.031500 0.053800 0.003200 Preferred Cost (p) 0.059900 0.075300 0,056900 0.048200 0.087100 Common Ratlo (ER) 0.486200 0.506300 0.460200 0.514700 0.522300 0.500000 Common Cost (c) 0.110000 0.110000 0.110000 0.110000 0.110000 0.110000 Total Cost of Capital (CM) 0.082510 0.087833 0.083929 0.086049 0.085395 0.089900 Tax Rate (F) 0.036053 0.035736 0.032467 0.037031 0.036106 0.029615 Operating Expenses Depreciation Factor (D) 0.0152270 0.0283830 0.0229140 0.0292210 0.0201180 0.0205130 Insurance Expense {J) 0.0036370 0.0003100 0.0039710 0.0021970 0.0017570 Property Tax (PT) 0.0043900 0.0098690 0.0168800 0.0138350 0.0072620 0.0077650 Franchise Tax (FT) 0.0001400 0.0010400 0.0018540 0.0001760 Operations & Maintenance (OM) 0.0372880 0.0438560 0.0365650 0.0588120 0.0435820 0.0288180 Total Operating Expenses 0.0606820 0.0824180 0.0813700 0.1037220 0.0731590 0.0590290 Net Investment Ratlo (K) 0.519754 0.475136 0.550986 0.498140 0.463923 0.609560 Annual Ownership Cost 0.235314 0.297030 0.264076 0.331298 0.279197 0.216353 Net Transmission Investment *AOC 53, 114,970.00 73,352,439.00 45,703,550,00 4,558,054.00 48,883,878.00 31,223,536.00 System Average Annual Ownership Cost 256,836,427.00 I 978,905,320.99 0.2623711 System Average Monthly Ownership Cost 0.2623711 / 12 0.0218643 Responsibility Ratio 0.2054 0.2636 0.1384 0.0454 0.1781 0.1691 Transmission Responsibil!ty 201,067, 152.93 258,039,442.61 135,480,496.43 44,442,301.57 174,343,037.67 165,532,889.78 Investment Difference 24,652,394.30 (11,086,478.96) 37,589,186.18 (30,684,132.54) 744,367.37 (21,215,336.35) Payments 242,397.60 670,885.70 463,857.52 Receipts 539,006.24 821,859.55 16,275.04

AttachmentSnapshot: 20111026161442 RunlD: 21466 Blll!ng Snapshot: 2111111126161442

Entergy Electric System Date range-20111001through20111031 Attachment 5 Intra-System Billing-20111 ORA Service Schedule MSS ~ 21 Transmission Equalization Page 37

AR LA MS NO EGSL ETI Total Investment 435,044,558.90 520,322,159.84315,132,168.58 27,616,290.90 381,121,510.02 236,812,347.39 Deferred Taxes 40,474,156.00 66,697,341.00 34,898,123.00 2,321,112.00 28,441,593.00 23,459,553.00 Depreciation Reserve 168,087,392.00 206,102,378.00 106, 141,224.00 11,539,821.00 173,877,578.00 68,979,950.00 Net Transmission Investment 226,483,010.90 247,522,440.84174,092,621.58 13,755,357.90 178,802,339.02 144,372,844.39 Cost of Capltal Debt Ratio (DR) 0.474200 0.474400 0.508300 0.431500 0.474500 0.500000 Bond Cost (J) 0.056200 0.064700 0.062000 0.062200 0.058300 0.069800 Preferred Ratio (PR) 0.039700 0.019200 0.031500 0.053800 0.003200 Preferred Cost {p) 0.059900 0.075300 0.056900 0.048200 0.087100 Common Ratio (ER) 0.486200 0.506300 0.460200 0.514700 0.522300 0.500000 Common Cost {c) 0.110000 0.110000 0.110000 0.110000 0.110000 0.110000 Total Cost of Capital (CM) 0.082510 0.087833 0.083929 0.086049 0.085395 0.089900 Tax Rate (F) 0.036053 0,035736 0.032467 0.037031 0.036106 0.029615 Operating Expenses Depreciation Factor (D) 0.0152270 0.0283830 0.0229140 0.0292210 0.0201180 0.0205130 Insurance Expense (I) 0.0036370 0.0003100 0,0039710 0.0021970 0.0017570 Property Tax (PT) 0.0043900 0.0098690 0.0168800 0.0138350 0.0072620 0.0077650 Franchise Tax {FT) 0.0001400 0.0010400 0.0018540 0.0001760 Operations & Maintenance (OM) 0.0372880 0.0438560 0.0365650 0.0588120 0.0435820 0.0288180 Total Operating Expenses 0.0606820 0.0824180 0.0813700 0,1037220 0.0731590 0.0590290 Net Investment Ratio (K) 0.520597 0.475710 0.552444 0.498089 0.469148 0.609651 Annual Ownership Cost 0.235125 0.296821 0.263686 0.331319 0.277441 0.216339 Net Transmission Investment "' AOC 53,251,818.00 73,469,858.00 45,905,840.00 4,557,411.00 49,607' 100.00 31,233,477.00 System Average Annual Ownership Cost 258,025,504,00 I 985,028,814.63 0.2619472 System Average Monthly Ownership Cost 0.2619472 / 12 0.0218289 Responsibility Ratio 0.2072 0.2618 0.1390 0.0448 0.1769 0.1703 Transmission Responsibility 204,097,970,39 257,880,543.67 136,919,005.23 44, 129,290.90 174,251,597.31 167,750,407.13 Investment Difference 22,385,040.51 (10,358,102.83) 37, 173,816.35 (30,373,933.00) 4,550,741.71 (23,377,562.74) Payments 226,106.30 663,030.47 610,307.19 Receipts 488,641.49 811,464.65 99,337.82

Attachment Snapshct: 20111122172545 RunlD: 21756 Biiiing Snapshot: 20111122170808

Entergy Electric System Date range -20111101through20111130 Attachment 5 Intra-System Bllllng-201111RA Service Schedule MSS ~ 2 /Transmission Equalization Page 37

AR LA MS NO EGSL ETI Total Investment 457,964,979.45 510,584,691.68 314,533,166.34 27,617, 140.62 381,298,924.42 236,909,330.02 Deferred Taxes 40,474,156.00 66,697,341.00 34,898, 123.00 2,321, 112.00 28,441,593.00 23,459,553.00 Depreciation Reserve 168,087,392.00206,102,378.00 106,141,224.00 11,539,821.00 173,877,578.00 68,979,950.00 Net Transmission Investment 249,403,431.45 237,784,972.68 173,493,819.34 13,756,207.62 178,979,753.42 144,469,827.02 Cost of Capital Debt Ratio (DR) 0.474200 0.474400 0.508300 0.431500 0.474500 0.500000 Bond Cost (I) 0.056200 0.064700 0.062000 0.062200 0,058300 0.069800 Preferred Ratio (PR) 0.039700 0.019200 0.031500 0.053800 0.003200 Preferred Cost (p) 0.059900 0.075300 0.056900 0.048200 0.087100 Common Ratio {ER) 0.486200 0.506300 0.460200 0.514700 0.522300 0.500000 Common Cost (c) 0.110000 0.110000 0.1.10000 0.110000 0.110000 0.110000 Total Cost of Capital (CM) 0.082510 0.087833 0.083929 0.086049 0.085395 0.089900 Tax Rate (F) 0.036053 0.035736 0.032467 0.037031 0.036106 0.029615 Operating Expenses Depreciation Factor (D) 0.0152270 0.0283830 0.0229140 0.0292210 0.0201180 0.0205130 Insurance Expense (I) 0.0036370 0.0003100 0.0039710 0.0021970 0.0017570 Property Tax (PT) 0.0043900 0.0098690 0.0168800 0.0138350 0.0072620 0.0077650 Franchise Tax (FT) 0.0001400 0.0010400 0.0018540 0.0001760 Operations & Maintenance (OM) 0.0372880 0.0438560 0.0365650 0.0588120 0.0435820 0.0288180 Total Operating Expenses 0.0606820 0.0824180 0.0813700 0.1037220 0.0731590 0.0590290 Net Investment Ratio (K) 0.544591 0.465711 0.551591 0.498104 0.469395 0.609811 Annual Ownership Cost 0.229989 0.300541 0.263914 0.331313 0.277359 0.216313 Net Transmission Investment • AOC 57,360,046.00 71,464, 133.00 45,787,448.00 4,557,610.00 49,641,645.00 31,250,702.00 System Average Annual Ownership Cost 260,061,584.00 I 997,888,011.53 0.2606120 System Average Monthly Ownership Cost 0.2606120 / 12 0.0217177 Responsibility Ratio 0.2100 0.2617 0.1394 0.0446 0.1755 0.1688 Transmission Responsibllity 209,556,482.42 261,147,292.62 139,105,588.81 44,505,805.31 175,129,346.02 168,443,496.35 Investment Difference 39,846,949.03 (23,362,319.94) 34,388,230.53 (30,749,597.69) 3,850,407.40 (23,973,669.33) Payments 507,375.06 667,809.50 520,652.15 Receipts 865,382.74 746,832.11 83,621.86

AttachmentSnapshct: 20111227164353 RunlD: 22082 Biiiing Snapshot: 2011122T112163

Entergy Electric System Date range· 20111201 through 20111231 Attachment 5 Intra-System Billlng-201112RA Service Schedule MSS • 2 /Transmission Equalization Page 41

AR LA MS NO EGSL ETI Total Investment 457,923, 799.10 553,067,455.46 315, 119,324.43 27,811,915.33 382,387,047.05 237,338,942.04 Deferred Taxes 41,509,084.00 66,689,174.00 34,950, 141.00 2,321, 112.00 28,927, 199.00 23,457, 174.00 Depreciation Reserve 170,463, 164.00 212,366,961.00 107,272,787.00 13,895,838.00 185,508,528.00 72, 198,072.00 Net Transmission Investment 245,951,551.10 274,011,320.46 172,896,396.43 11,594,965.33 167,951,320.05 141,683,696.04 Cost of Capital Debt Ratio (DR) 0.474200 0.474400 0.508300 0.431500 0.474500 0.500000 Bond Cost (!) 0.056200 0.064700 0.062000 0.062200 0.058300 0.069800 Preferred Ratio {PR) 0.039700 0.019200 0.031500 0.053800 0.003200 Preferred Cost {p) 0.059900 0.075300 0.056900 0.048200 0.087100 Common Ratio (ER) 0.486200 0.506300 0.460200 0.514700 0.522300 0.500000 Common Cost (c) 0.110000 0.110000 0.110000 0.110000 0.110000 0.110000 Total Cost of Capita! (CM) 0.082510 0.087833 0.083929 0.086049 0.085395 0.089900 Tax Rate {F) 0.036053 0.035736 0.032467 0.037031 0.036106 0.029615 Operating Expenses Depreclatlon,Factor (D) 0.0179350 0.0282680 0.0229150 0.0292230 0.0200840 0.0199850 Insurance Expense (I) 0.0036430 0.0003100 0.0039710 0.0022010 0.0017570 Property Tax (PT) 0.0043920 0.0098170 0.0168800 0.0129480 0.0072380 0.0077710 Franchise Tax (FT) 0.0001400 0.0010400 0.0018540 0.0001760 Operations & Maintenance (OM) 0.0372840 0.0438560 0.0365640 0.0588120 0.0435800 0.0288180 Total Operating Expenses 0.0633940 0.0822510 0.0813700 0.1028370 0.0731030 0.0585070 Net Investment Ratio (K) 0.537101 0.495439 0.548670 0.416906 0.439218 0.596968 Annual Ownership Cost 0.236592 0.289585 0.264700 0.369747 0.287939 0.217521 Net Transmission Investment " AOC 58, 190, 169.00 79,349,568.00 45,765,676.00 4,287,204.00 48,359, 735.00 30,619, 179.00 System Average Annual Ownership Cost 266,771,531.00 1,014,089,249.41 0.2630651 System Average Monthly Ownership Cost 0.2630651 / 12 0.0219221 Responslblllty Ratio 0.2099 0.2636 0.1393 0.0449 0.1745 0.1678 Transmission Responsib!lity 212,857,333.45 267,313,926.14141,262,632.44 45,532,607.30 176,958,574.02 170, 164, 176.05 Investment Difference 33,094,217.65 6,697,394.32 31,633,763.99 (33,937,641.97) (9,007,253.97)(28,480,480.01) Payments 743,984.21 197,457.88 624,351.79 Receipts 725,494.58 146,820.91 693,478.38

AttachmentSnapshc:t: 20120126166421 RunlD: 22492 Bllllng Snapshot: 20120126166421

Entergy Electric System Date range- 20120101through20120131 Attachment 5 Intra-System Billing-201201RA Seivlce Schedule MSS - 21 Transmission Equalization Page 37

AR LA MS NO EGSL ETI Total Investment 459,376,596.35 578,023,878.86 315,198,832.13 27,838,490.60 406,901,848.55 249,029,020.71 Deferred Taxes 41,509,083.72 66,689,174.20 34,950, 140.83 2,321, 111.83 28,927, 199.09 23,457, 174.17 Depreciation Reserve 170,463, 164.00 212,366,961.00 107,272,787.00 13,895,838.00 185,508,528.00 72, 198,072.00 Net Transmission Investment 247,404,348.63 298,967,743.66 172,975,904.30 11,621,540.77 192,466,121.48 153,373,774.54 Cost of Capital Debt Ratio {DR) 0.474200 0.474400 0.508300 0.431500 0.474500 0.500000 Bond Cost 0) 0.056200 0.064700 0.062000 0.062200 0.058300 0.069800 Preferred Ratio (PR} 0.039700 0.019200 0.031500 0.053800 0.003200 Preferred Cost (p) 0.059900 0.075300 0.056900 0.048200 0.087100 Common Ratio (ER) 0.486200 0.506300 0.460200 0.514700 0.522300 0.500000 Common Cost (c) 0.110000 0.110000 0.110000 0.110000 0.110000 0.110000 Total Cost of Capital (CM) 0.082510 0.087833 0.083929 0.086049 0.085395 0.089900 Tax Rate (F) 0.036053 0.035736 0.032467 0.037031 0.036108 0.029615 Operating Expenses Depreciation Factor (D) 0,0179352 0.0282677 0.0229146 0.0292235 0.0200843 0.0199853 Jnsurarice Expense (J) 0.0036433 0.0003102 0.0039709 0.0022009 0.0017573 Property Tax (PT) 0.0043916 0.0098170 0.0168802 0.0129483 0.0072383 0.0077706 Franchise Tax (FT) 0.0001400 0.0010403 0.0018543 0.0001763 Operations & Maintenance (OM) 0.0372840 0.0438563 0.0365643 0.0588118 0.0435803 0.0288184 Total Operating Expenses 0.0633941 0.0822512 0.0813703 0.1028379 0.0731038 0.0585079 Net Investment Ratio (K) 0.538565 0.517224 0.548783 0.417463 0.473004 0.615887 Annual Ownership Cost 0.236272 0.282593 0.264670 0.369420 0.276053 0.214512 Net Transmission Investment,. AOC 58,454,720.00 84,486,192.00 45,781,533.00 4,293,230.00 53, 130,850.00 32,900,515.00 System Average Annual O.Vnership Cost 279,047,040.00 1,076,809,433.36 0.2591424 System Average Monthly Ownership Cost 0.2591424 / 12 0.0215952 Responsib!Jlty Ratio 0.2104 0.2641 0.1390 0,0448 0.1736 0.1681 Transmission Responsibillty 226,560,704.78 284,385,371.35 149,676,511.24 48,241,062.61 186,934, 117.63 181,011,665.75 Investment Difference 20,843,643.85 14,582,372.31 23,299,393.06 (36,619,521.84) 5,532,003.83 (27,637,891.21) Payments 790,806.06 596,845.91 Receipts 450, 122.75 314,909,31 503,155.16 119,464.75

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Entergy Electric System Date range- 20120201 through 20120229 Attachment 5 Intra-System Bllling-201202RA Setvlce Schedule MSS - 21 Transmission Equalization Page 37

AR LA MS NO EGSL ET/ Total Investment 460,071,953.17 577,667,972.08 332,961,761.29 32,031,480.30 406,917,788.37 248,907,519.55 Deferred Taxes 41,509,083.72 66,689,174.20 34,950, 140.83 2,321, 111.83 28,927, 199.09 23,457,174.17 Depreciation Reserve 170,463, 164.00 212,366,961.00 107,272,787.00 13,895,838.00 185,508,528.00 72,198,072.00 Net Transmission Investment 248,099,705.45 298,611,836.88 190,738,833.46 15,814,530.47 192,482,061.28 153,252,273.38 Cost of Capital Debt Ratio (DR) 0.474200 0.474400 0.508300 0.431500 0.474500 0.500000 Bond Cost 0) 0.056200 0.064700 0.062000 0.062200 0.058300 0.069800 Preferred Ratio (PR) 0.039700 0.019200 0.031500 0.053800 0.003200 Preferred Cost (p) 0.059900 0.075300 0.056900 0.048200 0.087100 Common Ratio (ER) 0.486200 0.506300 0.460200 0.514700 0.522300 0.500000 Common Cost (c) 0.110000 0.110000 0.110000 0.110000 0.110000 0.110000 Total Cost of Capita! (CM) 0.082510 0.087833 0.083929 0.086049 0.085395 0.089900 Tax Rate (F) 0.036053 0.035736 0.032467 0,037031 0.036106 0.029615 Operating Expenses Depreciation Factor (D) 0.0179352 0.0282677 0.0229146 0.0292235 0.0200843 0.0199853 Insurance Expense (I) 0.0036433 0.0003102 0.0039709 0.0022009 0.0017573 Property Tax (PT) 0.0043916 0.0098170 0.0168802 0.0129483 0.0072383 0.0077706 Franchise Tax (FT) 0.0001400 0.0010403 0.0018543 0.0001763 Operations & Maintenance (OM) 0.0372840 0.0438563 0.0365643 0.0588118 0.0435803 0.0288184 Total Operating Expenses 0.0633941 0.0822512 0.0813703 0.1028379 0.0731038 0.0585079 Net Investment Ratio (K) 0.539263 0.516926 0.572855 0.493718 0.473024 0.615700 Annual Ownership Cost 0.236119 0.282685 0.258439 0.331372 0.276046 0.214541 Net Transmission Investment* AOC 58,581,054.00 84,413,087.00 49,294,353.00 5,240,493.00 53, 133,903.00 32,878,896.00 System Average Annual ownership Cost 283,541, 786.00 1,098,999,240.92 0.2580000 System Average Monthly Ownership Cost 0.2580000 /12 0.0215000 Responsibility Raflo 0.2104 0.2644 0.1389 0.0446 0.1727 0.1690 Transmission Responsibility 231,229,440.29 290,575,399.30 152,650,994.56 49,015,366.14 189,797, 168.91 185,730,871.72 Investment Difference 16,870,265.16 8,036,437.58 38,087,838.90 (33,200,835.67) 2,684,892.37 (32,478,598.34) Payments 713,817.92 698,289.82 Receipts 362.710.68 172,783.40 818,888.48 57,725.18

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SOAH Docket No. XXX-XX-XXXX PUC Docket No. 39896 ETI 2011 Rate Case ETI EXHIBIT NO. 4 DOCKET NO. 39896

APPLICATION OF ENTERGY § PUBLIC UTILITY COMMISSION TEXAS, INC. FOR AUTHORITY § TO CHANGE RATES AND § OF TEXAS RECONCILE FUEL COSTS §

DIRECT TESTIMONY

OF

JOSEPH F. DOMINO

ON BEHALF OF

ENTERGY TEXAS, INC.

NOVEMBER 2011

2011 ETI Rate Case 3-1 ENTERGY TEXAS, INC. DIRECT TESTIMONY OF JOSEPH F. DOMINO 2011 RATE CASE

TABLE OF CONTENTS Page I. Introduction 1 II. Purpose of Testimony 3 III. Overview of Filing 5 A. Reason for Filing 5 B. Summary of the Filing 8 C. The Company’s Anticipated Future Expenditures 9 IV. Case Presentation and List of Witnesses 11 V. The Utility and Executive Management Class of Affiliate Costs 18 VI. Conclusion 38

EXHIBITS Exhibit JFD-1 Witnesses and Testimony Content Exhibit JFD-A Affiliate Billings by Witness, Class and Department Exhibit JFD-B Affiliate Billings by Witness, Class and Project Exhibit JFD-C Affiliate Billings by Witness, Class, Department and Project Exhibit JFD-D Affiliate Billings Pro Forma Summary by Witness and Class

2011 ETI Rate Case 3-2 Entergy Texas, Inc. Page 1 of 38 Direct Testimony of Joseph F. Domino 2011 Rate Case

1 I. INTRODUCTION Q. PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.

3 A. My name is Joseph F. Domino. My business address is 350 Pine Street, 4 Beaumont, Texas.

6 Q. BY WHOM ARE YOU EMPLOYED AND IN WHAT CAPACITY?

7 A. I am employed by Entergy Texas, Inc. (“ETI” or the “Company”) as 8 President and Chief Executive Officer. ETI is an integrated investor- 9 owned electric utility that provides bundled generation, transmission, 10 distribution, and customer services to approximately 412,000 retail 11 customers in Texas. ETI is a subsidiary of Entergy Corporation (“Entergy 12 Corp.”), which also owns, among other subsidiaries, Entergy Gulf States 13 Louisiana, L.L.C., Entergy Louisiana, LLC, Entergy New Orleans, Inc., 14 Entergy Arkansas, Inc., and Entergy Mississippi, Inc. (along with ETI, the 15 “Operating Companies”).1 Schedule F of the rate filing package describes 16 the Company in more detail.

In the remainder of this testimony, I will use the term “Entergy Companies” to mean Entergy Corp. and its subsidiaries, including ETI, Entergy Services, Inc. (“ESI”), and the other Operating Companies. Each of these subsidiaries is a separate legal entity.

2011 ETI Rate Case 3-3 Entergy Texas, Inc. Page 2 of 38 Direct Testimony of Joseph F. Domino 2011 Rate Case

1 Q. PLEASE BRIEFLY DESCRIBE YOUR EDUCATIONAL AND 2 PROFESSIONAL EXPERIENCE.

3 A. I earned a Bachelor of Science Degree in Electrical Engineering from 4 Louisiana State University, where I graduated in 1970. I was awarded a 5 Master’s Degree in Engineering Science from Lamar University in 1975. I 6 began my utility career of 41 years in 1970 when I joined ETI, formerly 7 Entergy Gulf States, Inc. (“EGSI”), which was formerly Gulf States Utilities 8 Company (“GSU”), as a planning engineer. I have been with the 9 Company since that time.

10 I was named plant manager at Sabine Plant in Bridge City, Texas in 11 1979, and later was promoted to the position of general manager– 12 production with responsibility for the operation of all GSU’s non-nuclear 13 generating plants in both Texas and Louisiana. Following the merger of 14 GSU into Entergy Corp. in 1993, I was appointed director of the Southern 15 Region, overseeing six fossil-fueled power plants. A year later, I was 16 assigned a similar post with responsibility for the Eastern Region, 17 overseeing eleven fossil-fueled power plants. In June of 1997, I became 18 Director–Southwest Franchise in EGSI’s distribution group. I was named 19 to my current position of President and CEO of ETI in October 1998.

20 In my current position, I have financial responsibility for all of ETI’s 21 assets, including generation, transmission, distribution, and customer 22 service. I am directly responsible for the day-to-day operation of ETI’s 23 Distribution and Customer Service Organization, the discrete organization

2011 ETI Rate Case 3-4 Entergy Texas, Inc. Page 3 of 38 Direct Testimony of Joseph F. Domino 2011 Rate Case

1 within ETI that is responsible for the distribution and customer service- 2 related functions in ETI’s service territory. I exercise oversight of 3 distribution operations and customer service from the point of 4 interconnection of ETI’s distribution lines with its transmission lines down 5 to the customer’s meter. My responsibilities also include oversight of 6 economic development, as well as regulatory and governmental affairs.

7 While I have financial responsibility for the generation and 8 transmission assets of ETI, I do not have the day-to-day operational 9 responsibilities for the generation and transmission assets, which assets 10 are managed and operated by separate organizations within the 11 Entergy System.2

13 II. PURPOSE OF TESTIMONY Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY?

15 A. I will discuss why the Company is filing this case, provide a brief 16 description of the major components of the Company’s filing, and present 17 an overview presentation of the case and supporting witnesses. I also 18 sponsor the Utility and Executive Management class of affiliate costs.

The Operating Companies, together with their resources and facilities, are referred to as the “Entergy System.”

2011 ETI Rate Case 3-5 Entergy Texas, Inc. Page 4 of 38 Direct Testimony of Joseph F. Domino 2011 Rate Case

1 Q. DO YOU SPONSOR ANY SPECIFIC RATE FILING PACKAGE (“RFP”) 2 SCHEDULES?

3 A. Yes. The schedules I sponsor are as follows: 4  Schedule F – Description of Company; 5  Schedule H – Engineering Information; 6  Schedule T – Notice; 7  Schedule U – Compliance with PUCT Orders; 8  Schedule V – Request for Waiver of RFP Requirements; and 9  Schedule W – Confidentiality Disclosure Agreement.

11 Q. DO YOU SPONSOR ANY EXHIBITS?

12 A. Yes. I sponsor the exhibits listed in the Table of Contents to my 13 testimony.

15 Q. HOW IS THE REMAINDER OF YOUR TESTIMONY ORGANIZED?

16 A. In Section III, I provide an overview of the filing, including the reasons for 17 the filing, a summary of this filing, and the Company’s anticipated future 18 expenditures. Section IV describes the presentation of the case, including 19 a list of witnesses and the content of their testimony. Section V is the 20 presentation of the affiliate class that I support—the Utility and Executive 21 Management class of services. Section VI concludes my testimony.

2011 ETI Rate Case 3-6 Entergy Texas, Inc. Page 5 of 38 Direct Testimony of Joseph F. Domino 2011 Rate Case

.1 111. OVERVIEW OF FILING Q. WHAT IS THE PURPOSE OF THIS SECTION OF YOUR TESTIMONY?

3 A. In this section, I discuss why the Company is making this filing and 4 provide a brief summary of the filing. also generally discuss the 5 Company's anticipated future expenditures.

7 A. Reason for Filing Q. WHY IS ETI MAKING THIS FILING?

9 A. Since the June 30, 2009 close of the test year in ETl's last base rate case, 10 the Company has made substantial investments in transmission and 11 distribution infrastructure and incurred significant increases in purchased 12 power costs to reliably serve its customers. The Company has also 13 completed a new depreciation study that demonstrates that the 14 Company's current depreciation rates, and resulting annual depreciation 15 expense, are too low. The relief requested in this case is needed to 16 address these substantial and recent incremental costs, and to provide the 17 Company a reasonable opportunity to earn a reasonable return on 18 invested capital.

21 RIDER? 22 A. 2

2011 ETI Rate Case 3-7 Entergy Texas, Inc. Page 6 of 38 Direct Testimony of Joseph F. Domino 2011 Rate Case

1 power CQ~ts Eoi:. the reasor:iS-explained HT-detail by Company wit11es?

2 Phillip R. May and Robert R. Cooper, the Company's resource y,<ottlolio / 3 relies heavily on purchased power contracts to meet its ,incremental / 4 resource requirements. The significant regulatory la~ssociated with /

5 recovering these costs through successive base rC}t{cases is expensive 6 in and of itself, and results in rates that are a~~ stale by the time they //' 7 become effective. A purchased po er rider would address those 8 concerns in that it would avoid t need for serial base rate cases and 9 shield both the Comp/ a its customers from large over- and under- 10 recoveries that are Q sible under the current regulatory system. Further, 11 as Mr. May di usses, timely recovery of purchased power capacity costs 12 will aff flexibility to make use of the variety of resources, suppliers, and

15 Q. IS THE COMPANY ALSO MAKING A PROPOSAL THAT AFFECTS THE 16 WAY IT RECOVERS TRANSMISSION- AND DISTRIBUTION-RELATED 17 COSTS?

18 A. The Company is not proposing a transmission cost recovery factor 19 ("TCRF") or a distribution cost recovery factor ("DCRF") in this case, but ..

20 the Company is seeking to establish baseline values that will be identified 21 and used on a prospective basis in conjunction with later implementation 22 of those factors. Company witness Heather G. LeBlanc addresses these 23 baselines in her direct testimony.

2011 ETI Rate Case 3-8 Entergy Texas, Inc. Page 7 of 38 Direct Testimony of Joseph F. Domino 2011 Rate Case

1 Q. CAN YOU EXPLAIN IN MORE DETAIL WHAT IS DRIVING THE 2 MAGNITUDE OF THE INCREASE, PARTICULARLY GIVEN THAT THE 3 COMPANY RECENTLY IMPLEMENTED A BASE RATE INCREASE?

4 A. The Company’s last base rate change (Docket No. 37744) resulted in a 5 two-step rate increase, the last part of which became effective as of 6 May 2, 2011, and that case was an important step in addressing ETI’s 7 financial health at that time. However, since the end of the test year for 8 that base rate case, ending June 30, 2009, the Company’s projected third- 9 party purchased power costs have more than doubled with an increase of 10 over $36 million. Between July 2009 and June 2011, the Company has 11 completed $113.6 million in transmission capital projects and 12 $148.2 million in distribution line and distribution-related general plant 13 additions.3 At the same time, those increased expenses are outpacing 14 load growth, which has been low since the end of the last test year (on a 15 weather-adjusted basis). In addition, the depreciation study filed in this 16 case shows that current depreciation rates are understated, justifying an 17 addition of $16.2 million to ETI’s revenue requirement.4

Company witnesses Shawn B. Corkran and Mark F. McCulla discuss the additions in distribution and transmission plant since the Company’s last rate case. Mr. Corkran also addresses the Company’s recent reliability statistics.

Company witness Dane Watson discusses the depreciation study.

2011 ETI Rate Case 3-9 Entergy Texas, Inc. Page 8 of 38 Direct Testimony of Joseph F. Domino 2011 Rate Case

1 Q. ARE THERE OTHER FACTORS INDICATIVE OF THE INADEQUACY OF 2 THE COMPANY’S CURRENT RATES?

3 A. Yes, there are. As reported in the Commission’s earnings monitoring 4 report for 2010, ETI had a return on equity of only 7.10%, which is 303 5 basis points short of the 10.125% ROE authorized in the Company’s last 6 rate case.

8 B. Summary of the Filing Q. WHAT RELIEF IS THE COMPANY REQUESTING?

10 A. The Company requests a total annual base rate and rider increase of 11 $111.8 million, which is exclusive of changes in charges for miscellaneous 12 electric services.

14 Q. WHAT ARE THE MAJOR COMPONENTS OF THE COMPANY’S 15 REQUEST?

16 A. The filing is made up of the following major components: 17 1. The total annual rate increase of $111.8 million, or 15.32% (when 18 calculated on base rate and rider revenues), reflecting costs 19 recorded in Test Year July 2010 through June 2011 as adjusted for 20 known and measurable changes.

21 2. Approval to implement a rider to recover all purchased capacity 22 costs and certain other costs, including future incremental amounts.

23 That rider is designed to recover $272.7 million annually. In the

2011 ETI Rate Case 3-10 Entergy Texas, Inc. Page 9 of 38 Direct Testimony of Joseph F. Domino 2011 Rate Case

1 event the Commission rejects the Company’s request to recover 2 purchased power through a rider, the Company requests that the 3 adjusted test year level of expense be included in base rates.

4 Company witness May addresses the need for this rider and the 5 costs to be recovered through this rider.

6 3. The Company is seeking to reconcile approximately $1.3 billion in 7 fuel and purchased power expense in this proceeding, reconciling 8 the period from July 2009 through June 2011.

9 4. Establishing of base line values for future implementation of a 10 TCRF and DCRF as authorized by PURA.

12 Q. WHAT IS THE EFFECT OF THE REQUESTED RATE INCREASE, 13 INCLUSIVE OF BASE RATES AND RIDERS, ON THE TYPICAL 14 RESIDENTIAL CUSTOMER?

15 A. Residential rates will increase $14.37 per month for 1000 kilowatt-hours 16 (“kWh”).

18 C. The Company’s Anticipated Future Expenditures Q. IS THIS CASE IMPORTANT WITH REGARD TO THE COMPANY’S 20 ANTICIPATED FUTURE EXPENDITURES?

21 A. Yes. In order to maintain and further improve its level of service reliability 22 and to facilitate planned upgrades and expansion, the Company will 23 continue to invest in capital projects. ETI’s capital budget reflects plans to

2011 ETI Rate Case 3-11 Entergy Texas, Inc. Page 10 of 38 Direct Testimony of Joseph F. Domino 2011 Rate Case

1 invest approximately $664 million in capital projects over the years 2012 2 through 2014. The Company anticipates substantial investment related to 3 growth in its service area, particularly growth in ETI’s Western Region, 4 which includes Conroe and The Woodlands. Some of those capital 5 projects include costs for “storm hardening” in the coastal areas and other 6 areas that are more susceptible to flooding and/or high winds during 7 severe weather events, and which would benefit from such measures. A 8 primary purpose of storm hardening is to build stronger facilities in an 9 effort to mitigate the damage caused by severe weather, which can speed 10 restoration times. Of the $664 million planned capital expenditures, 11 approximately $388 million is for maintenance of existing assets. The 12 remaining $276 million is associated with other investments such as 13 environmental compliance spending, plant upgrades, and transmission 14 upgrades and system improvements.

15 ETI also must address the continued need for supply-side 16 resources. Granting the rate relief requested in this case will provide 17 important financial support as ETI takes on these new investments and 18 expenditures. ETI’s customers are expected to benefit from a financially 19 healthy company that can access capital markets on favorable terms.

2011 ETI Rate Case 3-12 Entergy Texas, Inc. Page 11 of 38 Direct Testimony of Joseph F. Domino 2011 Rate Case

1 Q. PLEASE PROVIDE FURTHER EXPLANATION REGARDING ETI’S 2 EXPECTED EFFORTS TO OBTAIN SUPPLY-SIDE RESOURCES.

3 A. Resource planning for the Entergy System, including each Operating 4 Company, is designed to achieve the right mix of resources to serve 5 customer load shape requirements at the lowest reasonable costs. As 6 explained by ETI witness Robert R. Cooper, ETI currently projects a need 7 for capacity totaling 260 MW in 2012 and 504 MW in 2013. The System is 8 systematically pursuing resource options to fill these needs and those of 9 the other Operating Companies.

11 IV. CASE PRESENTATION AND LIST OF WITNESSES Q. HOW IS THE PRESENTATION OF THE CASE ORGANIZED?

13 A. The Company’s case is presented through the testimony of 39 witnesses.

14 The witnesses can be grouped generally into nine groups: 15  Financial; 16  Operations and Customer Service; 17  Overview Affiliate; 18  Affiliate Classes; 19  Non-Affiliate Revenue Requirement; 20  Cost of Service and Rate Design; 21  Employee Compensation; 22  Fuel Reconciliation; and

2011 ETI Rate Case 3-13 Entergy Texas, Inc. Page 12 of 38 Direct Testimony of Joseph F. Domino 2011 Rate Case

1  Rate Case Expenses.

2 Some witnesses present testimony in support of more than one 3 subject or component of the case, and, consequently, a witness may 4 appear in more than one of these groups. However, each witness 5 presents only one piece of testimony. A complete listing of all of the 6 witnesses and the subject(s) they address is attached to my testimony as 7 Exhibit JFD-1.

9 Q. PLEASE DESCRIBE THE FINANCIAL GROUP OF WITNESSES.

10 A. The financial group of Company witnesses includes Chris E. Barrilleaux 11 and Dr. Sam Hadaway. Mr. Barrilleaux explains the financial status of the 12 Company and the importance of adequate rates to support the Company’s 13 financial health as the Company moves forward, as well as provides the 14 Company’s proposed capital structure. Dr. Hadaway testifies as to ETI’s 15 proposed return on equity.

17 Q. PLEASE DESCRIBE THE OPERATIONS AND CUSTOMER SERVICE 18 WITNESSES.

19 A. This group includes Company witnesses Corkran, testifying regarding 20 distribution operations, Abdon F. Roman, testifying regarding customer 21 service, H. Vernon Pierce, testifying regarding miscellaneous electric

2011 ETI Rate Case 3-14 Entergy Texas, Inc. Page 13 of 38 Direct Testimony of Joseph F. Domino 2011 Rate Case

1 services,5 Mark F. McCulla, discussing transmission issues, and Winfred 2 W. Garrison, discussing fossil plant operations. Several of these 3 witnesses also address affiliate services and costs associated with 4 distribution operations, customer service, transmission operations and 5 fossil plant operations.

7 Q. PLEASE DESCRIBE THE OVERVIEW AFFILIATE WITNESSES.

8 A. ETI is provided certain services by its affiliates. The bulk of these affiliate 9 services are provided by ESI. In order to provide assurance as to the 10 reasonableness and necessity of these service company charges, and to 11 comply with the requirements of PURA concerning proof of affiliate costs, 12 a large portion of the case is devoted to presenting and supporting the 13 affiliate costs associated with services provided by these affiliates. The 14 Company’s use of a service company affiliate and the treatment of the 15 associated costs are discussed in greater detail elsewhere in my 16 testimony as well as in the testimony of other Company witnesses.

17 The first set of affiliate witnesses are the overview affiliate 18 witnesses: Stephanie B. Tumminello, Jeanne J. Kenney, and Donna S.

19 Doucet.

The proposed changes in miscellaneous electric service charges discussed by Mr. Pierce will result in an approximate revenue increase of $911,000.

2011 ETI Rate Case 3-15 Entergy Texas, Inc. Page 14 of 38 Direct Testimony of Joseph F. Domino 2011 Rate Case

1  Ms. Tumminello supports the propriety of ESI affiliate cost 2 allocation methods, and the necessity for, benefits of, and absence 3 of duplication in the services provided by ESI to the Company.

4 Ms. Tumminello is also the ESI affiliate classes overview witness.

5 She describes the Entergy Corp. corporate structure, explains the 6 ESI billing methods for assigning costs, and explains how affiliate 7 costs are presented in the schedules and exhibits in the case.

8 Finally, Ms. Tumminello addresses benchmarking that applies at 9 the overall service company (ESI) level.

10  Ms. Kenney discusses benchmarking of ETI’s 2008, 2009, and 11 2010 non-production O&M expense compared to the electric utility 12 industry.

13  Ms. Doucet explains and supports the reasonableness of the 14 Entergy Companies’ budgeting process.

16 Q. THE NEXT GROUP IS THE AFFILIATE CLASSES GROUP. PLEASE 17 DESCRIBE THIS GROUP.

18 A. These witnesses, in general, present the explanation and support for the 19 affiliate costs being requested by the Company in this case. As indicated 20 previously, certain witnesses appearing in other groups also support 21 affiliate costs. The affiliate classes group and the respective affiliate 22 classes they support are:

2011 ETI Rate Case 3-16 Entergy Texas, Inc. Page 15 of 38 Direct Testimony of Joseph F. Domino 2011 Rate Case

1  Julie F. Brown—Information Technology; 2  Patrick Cicio—Energy and Fuel Management; 3  Shawn B. Corkran—Transmission and Distribution Support and 4 Distribution Operations; 5  Donna S. Doucet—Financial Services; 6  Walter C. Ferguson—Federal PRG Affairs; 7  Patricia A. Galbraith—Tax Services; 8  Kevin G. Gardner—Human Resources; 9  Winfred W. Garrison—Fossil Plant Operations; 10  Chester N. Herrington—Internal and External Communications; 11  Joseph Hunter—Supply Chain; 12  Phillip R. May—Regulatory Services; 13  Mark F. McCulla—Transmission Operations; 14  Steven C. McNeal—Treasury Operations; 15  Thomas C. Plauché—Administration; 16  Rory Roberts—ESI Income Taxes; 17  Abdon F. Roman—Customer Service Operations, Environmental 18 Services, and Retail Operations; 19  Robert D. Sloan—Legal Services; 20  Stephanie B. Tumminello—Depreciation, Service Company 21 Recipient Offsets, and Other Expenses; and 22  Myself—Utility and Executive Management.

2011 ETI Rate Case 3-17 Entergy Texas, Inc. Page 16 of 38 Direct Testimony of Joseph F. Domino 2011 Rate Case

1 Q. PLEASE DESCRIBE THE NON-AFFILIATE REVENUE REQUIREMENT 2 GROUP OF WITNESSES.

3 A. These witnesses include: 4  Michael P. Considine—Regulatory and Tax Accounting, Revenue 5 Requirement Issues, Pensions and other Post-Retirement Benefits, 6 and Pro Forma Adjustments; 7  Patricia A. Galbraith—ETI Property Tax Pro Forma; 8  Jay Joyce—Lead Lag Study Review; 9  Rory L. Roberts—Income Tax; 10  Dane Watson—Depreciation; and 11  Gregory S. Wilson—Property Insurance Reserve.

13 Q. PLEASE DESCRIBE THE COST OF SERVICE AND RATE DESIGN 14 GROUP.

15 A. Mr. Considine is the overall accounting witness for the Company and 16 presents the Company’s revenue requirement. Heather G. LeBlanc 17 supports the Class Cost of Service study (and the proposed Purchased 18 Power Recovery Rider). Mr. Richard A. Lynch supports the weather- 19 related adjustments to the Test Year billing determinants, and 20 Myra Talkington presents the Company’s rate design, class cost 21 allocation, and rate schedules and tariff.

2011 ETI Rate Case 3-18 Entergy Texas, Inc. Page 17 of 38 Direct Testimony of Joseph F. Domino 2011 Rate Case

1 Q. HOW HAVE YOU ADDRESSED THE ISSUE OF EMPLOYEE 2 COMPENSATION LEVELS?

3 A. Company witness Gardner, who was identified above as addressing 4 Human Resources affiliate charges, also provides benchmarking support 5 for total compensation among the various categories of employees. He 6 demonstrates that total annual compensation for all categories of 7 employees, taken as a whole, is reasonable and necessary, based on 8 market surveys. He also demonstrates that awards under the annual and 9 long-term incentive plan, and employee benefit programs and levels, 10 are reasonable.

11 In addition to Mr. Gardner, the Company presents Dr. Jay C.

12 Hartzell, an outside expert from the University of Texas, who examines the 13 bases of the Commission’s past decisions regarding disallowance of 14 “financially-based” incentive compensation. While the Company is 15 cognizant of those past decisions, it continues to urge further examination 16 of the merits and details of that policy.

18 Q. WHO ARE THE WITNESSES PRESENTING THE FUEL AND 19 PURCHASED POWER RECONCILIATION PORTION OF THE CASE?

20 A. The fuel reconciliation witnesses include: 21  Robert R. Cooper—Long Term Planning and Long-Term Purchased 22 Power; 23  Devon S. Jaycox—Economic Dispatch for the Reconciliation 24 Period;

2011 ETI Rate Case 3-19 Entergy Texas, Inc. Page 18 of 38 Direct Testimony of Joseph F. Domino 2011 Rate Case

1  Karen Macllvoy—Reconcilable Gas Purchases, and Gas and Oil 2 Base Rate Components; 3  Margaret McCloskey—Over/Under Recovery Balance for 4 Reconcilable Fuel; 5  Michelle H. Thiry—Reconcilable Fuel Overview and Short-Term 6 Purchased Power; 7  Ryan Trushenski—Reconcilable and Non-Reconcilable Coal 8 Expense; and 9  Gregory R. Zakrzewski—Fuel Accounting.

11 Q. WHO PRESENTS THE COMPANY’S RATE CASE EXPENSES?

12 A. Mr. Stephen F. Morris presents the Company’s rate case expenses 13 associated with outside attorneys and consultants. Mr. Considine 14 presents the Company’s rate case expenses associated with ETI, ESI 15 employees, and miscellaneous expenses.

17 V. THE UTILITY AND EXECUTIVE MANAGEMENT CLASS OF 18 AFFILIATE COSTS Q. WHAT IS THE PURPOSE OF THIS SECTION OF YOUR TESTIMONY?

20 A. The purpose of this section of my testimony is to support the Company’s 21 request for recovery of affiliate costs associated with the Utility and 22 Executive Management class of affiliate services. I will demonstrate that 23 the costs for this class are reasonable and necessary, and that the 24 amounts billed to ETI for these services are billed to the other affiliates 25 using the same methodology and at prices that are no higher than those

2011 ETI Rate Case 3-20 Entergy Texas, Inc. Page 19 of 38 Direct Testimony of Joseph F. Domino 2011 Rate Case

1 charged to other affiliates for the same or similar services. My testimony 2 will also show that the prices for these services that have been charged to 3 ETI represent the actual cost for these services.

5 Q. PLEASE PROVIDE A BRIEF DESCRIPTION OF THIS CLASS.

6 A. The ESI Utility and Executive Management class is comprised of 7 30 departments. Generally, however, this class can be broken into two 8 groups of services: The Utility Management group and the Executive 9 Management group. As described in more detail below, the Utility 10 Management group provides executive leadership and management for 11 the regulated utility operations, and the Executive Management group 12 provides overall oversight of the operations of all Entergy Companies, 13 including regulated legal entities, and stewardship of the corporate assets.

15 Q. WHAT IS THE TOTAL ETI ADJUSTED AMOUNT FOR THIS CLASS OF 16 SERVICES?

17 A. The Total ETI Adjusted amount for the Utility and Executive Management 18 class of affiliate services is $1,939,228. Table 1 below shows for the class 19 the following information:

2011 ETI Rate Case 3-21 Entergy Texas, Inc. Page 20 of 38 Direct Testimony of Joseph F. Domino 2011 Rate Case

Total Billings Dollar amount of total Test Year billings from ESI to all Entergy Companies, plus the dollar amount of all other affiliate charges that originated from any Entergy Company. This is the amount from Column (C) of the cost exhibits JFD-A, JFD-B, and JFD-C.

Total ETI Adjusted ETI’s adjusted amount for electric cost of Amount service after pro forma adjustments and exclusions. % Direct Billed The percentage of the ETI adjusted test year amount that was billed 100% to ETI. % Allocated The percentage of the ETI adjusted test year amount that was allocated to ETI.

Table 1 Total ETI Adjusted Class Total Billings Amount % Direct % Allocated Utility and Executive $30,702,565 $1,939,228 4.34% 95.66% Management

1 Q. PLEASE DESCRIBE THE EXHIBITS THAT SUPPORT THE 2 INFORMATION INCLUDED IN TABLE 1.

3 A. Attached to my testimony are exhibits showing the calculation of the Total 4 ETI Adjusted amount for the Utility and Executive Management Class. In 5 my Exhibit JFD-A, the information is shown broken down by the 6 departments comprising the class. My Exhibit JFD-B shows the same 7 information broken down by project code and the billing method assigned 8 to each project code. My Exhibit JFD-C shows the information by 9 department, project code, and the billing method assigned to the project

2011 ETI Rate Case 3-22 Entergy Texas, Inc. Page 21 of 38 Direct Testimony of Joseph F. Domino 2011 Rate Case

1 code. For each exhibit, the amounts in the columns represent the 2 following information: Column (A) – Dollar amount of total Test Year billings and Support charges from ESI to all Entergy Business Units to ETI, plus the dollar amount of all other affiliate charges to ETI that originated from any Entergy Business Unit.

Column (B) – Dollar amount that was included in the service Service Company company recipient allocation. Service company Recipient recipient charges are the cost of services that ESI provides to itself, which in turn, are charged to affiliates that receive those services. The service company recipient allocation process is described in the testimony of Company witness Tumminello.

Column (C) – Represents the sum of Columns (A) and (B).

Total Column (D) – That portion of Column (C) that was billed and All Other Business charged to Business Units other than ETI.

Units Column (E) – Represents the difference between Columns (C) ETI Per Books and (D).

Column (F) – Represents amounts that are excluded from ETI Exclusions electric cost of service. The exclusions are described in the testimony of Company witness Tumminello.

Column (G) – Pro Forma Amounts include adjustments for Pro Forma Amount known and measurable changes, and corrections.

Column (H) – ETI adjusted amount requested for recovery in Total ETI Adjusted this case for this class (Column (E) plus Columns (F) and (G)).

2011 ETI Rate Case 3-23 Entergy Texas, Inc. Page 22 of 38 Direct Testimony of Joseph F. Domino 2011 Rate Case

1 In her direct testimony, Ms. Tumminello describes the calculations 2 that take the dollars of support services in Column (E) to the Total ETI 3 Adjusted numbers shown on Column (H).

5 Q. ARE THERE ANY PRO FORMA ADJUSTMENTS TO THIS CLASS?

6 A. Yes. The pro forma adjustments for the Utility and Executive 7 Management class of services are shown on Exhibit JFD-D, which also 8 identifies the Company witnesses who sponsor those pro forma 9 adjustments.

11 Q. WHAT ARE THE MAJOR COST COMPONENTS OF THIS CLASS?

12 A. The major cost components are as follows: Table 2 Cost Component Utility and Executive Management % of Total Payroll and $956,108 49.3% Employee Costs Outside Services $738,073 38.1% Office and $97,947 5.1% Employee Expenses Other $23,427 1.2% Service $123,674 6.4% Company Recipient Total $1,939,228 100%

2011 ETI Rate Case 3-24 Entergy Texas, Inc. Page 23 of 38 Direct Testimony of Joseph F. Domino 2011 Rate Case

1 Q. WHAT IS THE IMPORTANCE OF THESE COST CATEGORIES?

2 A. This breakout provides an additional view of the costs in this class. The 3 breakout is significant, moreover, because other Company witnesses in 4 this case provide additional overall support for the affiliate costs included 5 in several of these categories. For instance, in this class, the Payroll and 6 Employee Costs component is the largest component of the class. With 7 respect to this component, Company witness Gardner supports the market 8 competitiveness and overall reasonableness of salary and benefits costs.

9 “Outside Services” pertains to services provided by non-Entergy 10 Companies employees and firms, such as outside consultants and 11 vendors. This is the second largest component of this class. I later 12 address some of the activities performed by these consultants in my 13 description of the Utility Management and Executive Management groups.

14 “Office and Employee Expenses” covers the costs of maintaining 15 work spaces and office supplies. Company witness Plauché addresses 16 these types of costs in more detail in his direct testimony.

17 The “Service Company Recipient” row of the table pertains to costs 18 common throughout ESI, such as IT, rents, and human resources, which 19 are primarily incurred to support ESI operations. These costs are spread 20 to all affiliate classes as explained by Company witness Tumminello.

2011 ETI Rate Case 3-25 Entergy Texas, Inc. Page 24 of 38 Direct Testimony of Joseph F. Domino 2011 Rate Case

1 Q. WHAT AREAS DO YOU ADDRESS IN THE REMAINDER OF YOUR 2 TESTIMONY IN THIS SECTION?

3 A. I provide further description of the services provided in the two Utility and 4 Executive Management groups of services. I also address the necessity 5 and reasonableness of the services and level of charges associated with 6 this class. Finally, I discuss the predominant billing methods included this 7 class and describe why those methods are reasonable.

9 Q. WHAT TYPES OF SERVICES DOES THE UTILITY MANAGEMENT 10 GROUP PROVIDE?

11 A. This group provides executive leadership and management for the 12 regulated utility operations, including Customer Service Support, Sales 13 and Marketing, the State Presidents, Utility Group Safety and Regulatory 14 Affairs, as well as the operation, engineering, construction and 15 maintenance of the distribution system. This group also provides 16 executive oversight and guidance related to the Fossil, Transmission and 17 System Planning organizations. Also provided by this group are access to 18 consulting services, including the retention of outside consultants, required 19 for federal and state regulatory matters, including those related to open 20 access of the Entergy Companies’ transmission system and the 21 Independent Coordinator of Transmission. The group further provides 22 oversight for Entergy Continuous Improvement, corporate performance 23 measurement efforts and ongoing O&M benchmarking. Consulting

2011 ETI Rate Case 3-26 Entergy Texas, Inc. Page 25 of 38 Direct Testimony of Joseph F. Domino 2011 Rate Case

1 activities for the development of alternate technologies and power 2 generation projects are also part of this group.

3 In summary, activities include providing executive guidance with 4 respect to the development of short-term and long-term plans to ensure 5 the continued reliable operation of the regulated electric system, and 6 performance management to monitor and support improvement in those 7 operations. This function provides guidance and leadership for federal, 8 state and local matters common to all jurisdictions and avoids 9 unnecessary duplication of these management activities. This 10 organizational structure enables management to provide these services in 11 a cost-effective manner.

13 Q. WHAT TYPES OF SERVICES DOES THE EXECUTIVE MANAGEMENT 14 GROUP PROVIDE?

15 A. This group provides overall oversight of the operations of all Entergy 16 Companies, including regulated legal entities, and stewardship of the 17 corporate assets. The class further provides policy direction, including the 18 appropriate use of consulting services, with respect to regulatory, legal 19 and strategic decisions. During the Test Year, this function coordinated 20 the Entergy Companies’ responses to various legal, regulatory, and policy 21 issues. This function provides guidance and leadership for matters 22 common to all jurisdictions and avoids unnecessary duplication of these

2011 ETI Rate Case 3-27 Entergy Texas, Inc. Page 26 of 38 Direct Testimony of Joseph F. Domino 2011 Rate Case

1 management activities. This organizational structure enables 2 management to provide these services in a cost-effective manner.

4 Q. DOES THE UTILITY AND EXECUTIVE MANAGEMENT CLASS 5 PROVIDE NECESSARY SERVICES?

6 A. Yes. The highly integrated and extensively regulated nature of the 7 Entergy Companies’ multi-jurisdictional utility operations requires a 8 centralized management structure that provides leadership, guidance and 9 decision-making as well as making it necessary to coordinate legal, 10 regulatory, and policy matters on a system-wide basis. This supports 11 consistent implementation of operational practices that provide efficiencies 12 and ensures that services are not duplicated within the individual 13 organizations or within the individual Operating Companies. The 14 leadership and direction provided by this centralized management 15 structure have been effective, as shown by the achievement of the 16 operational performance results described by Mr. Corkran.

18 Q. PLEASE ADDRESS THE STAFFING LEVEL TRENDS FOR 2008, 2009, 19 2010, AND THE TEST YEAR.

20 A. Staffing levels for the Utility and Executive Management class that I 21 support are shown in Table 3, below.

2011 ETI Rate Case 3-28 Entergy Texas, Inc. Page 27 of 38 Direct Testimony of Joseph F. Domino 2011 Rate Case

Table 3 Class 20086 2009 2010 Test Year Utility and Executive 36 39 43 42 Management Class

1 Q. WHAT WERE THE COST TRENDS FOR THE UTILITY AND EXECUTIVE 2 MANAGEMENT CLASS THAT YOU SUPPORT FOR THE LAST THREE 3 YEARS AS COMPARED TO THE TEST YEAR?

4 A. Table 4 below shows the total affiliate O&M charges to ETI for each of the 5 past three calendar years and the Test Year for this class of service.

6 These charges have been adjusted to remove costs billed to ETI from 7 nuclear, gas, and “spin off” department codes. Charges to ETI from these 8 departments have also been removed from ETI’s Test Year cost 9 of service.

Table 4 2008 2009 2010 Test Year Total O&M $2.5 $2.1 $2.3 $2.2 (in millions)

10 Q. PLEASE EXPLAIN THE TREND IN STAFFING LEVELS AND COSTS.

11 A. As shown in Tables 3 and 4, there is a cumulative staffing increase of 12 six personnel between 2008 and the Test Year, while O&M costs over that 13 same period have remained relatively level. The higher O&M costs in

The 2008, 2009, and 2010 figures are year-end (December 31) headcounts. The Test Year figure is the headcount as of June 30, 2011.

2011 ETI Rate Case 3-29 Entergy Texas, Inc. Page 28 of 38 Direct Testimony of Joseph F. Domino 2011 Rate Case

1 2008 were primarily due to activities associated with Qualified Power 2 Region regulatory proceedings in Texas.

3 The cumulative increase in staffing levels is the result of occasional 4 reorganizations and the creation of new departments and projects. The 5 majority of the increase in staffing levels is due to the addition of the 6 Critical Infrastructure Protection department in 2010. The Critical 7 Infrastructure Protection department has overall responsibility for leading 8 the Entergy Companies’ implementation of, and adherence to, mandatory 9 North American Electric Reliability Corporation Critical Infrastructure 10 Protection standards designed to protect Entergy Critical Cyber Assets 11 that support the reliable operation of the Bulk Electric System.

13 Q. ARE THESE NECESSARY SERVICES PROVIDED AT A REASONABLE 14 COST?

15 A. Yes. First, the costs reflected in this class are subject to the cost control 16 and monitoring process more fully described in the testimony of Company 17 witness Doucet. The process includes a budgeting process aimed at 18 establishing long-range financial plans, based upon prior year 19 performance and future objectives. The budgeting process, which is a 20 top-down as well as a bottom-up process, includes a detailed budgeting 21 phase that requires the input of each organization within ETI, including my 22 review and input as the President of ETI. The process assures the 23 meaningful input of the ETI organizations utilizing the affiliate services.

2011 ETI Rate Case 3-30 Entergy Texas, Inc. Page 29 of 38 Direct Testimony of Joseph F. Domino 2011 Rate Case

1 The cost control and monitoring process also includes a cost 2 reporting stage that requires evaluation by ETI management of the 3 variance between actual and budgeted amounts. As the executive 4 ultimately accountable for ETI’s costs, including the costs associated with 5 services provided by its affiliate service company, I am responsible for 6 monitoring the reporting stage and reviewing all variances.

7 This budgeting and reporting process supports accountability 8 between ETI and its service company affiliates with respect to its use of 9 affiliate services and the associated costs that are charged to ETI. The 10 process provides assurance that affiliate costs are reasonable, including 11 the costs for this class.

12 In addition, as discussed above, the headcount and cost trends 13 support the reasonableness of these costs. The cumulative increase in 14 staffing levels includes a reasonable increase of six positions over four 15 years, and simply reflects normal corporate activities, which includes 16 occasional reorganizations and new departments — such as the Critical 17 Infrastructure Protection department — and projects to address emerging 18 technologies, environmental and safety issues, and 19 regulatory expectations.

20 Moreover, the reasonableness of the costs associated with the 21 Utility and Executive Management class is supported by the benchmarking 22 analyses sponsored by Company witnesses Kenney. Eighty-nine percent 23 (89%) of the costs associated with this affiliate class are charged to A&G

2011 ETI Rate Case 3-31 Entergy Texas, Inc. Page 30 of 38 Direct Testimony of Joseph F. Domino 2011 Rate Case

1 FERC accounts and included in Ms. Kenney’s analysis of A&G costs 2 among utilities throughout the United States.7 Ms. Kenney’s analysis 3 demonstrates that the level of ETI’s A&G costs was at 68% of the industry 4 average on a cost per MWh basis for 2008, 65% of the industry average 5 on a cost per MWh basis for 2009, and 70% of the industry average on a 6 cost per MWh basis for 2010. Those levels equated to a ranking of 28th, 7 27th, and 33rd, from least cost to the greatest, among the 100-plus utilities 8 included in the benchmarking for the years 2008 through 2010, 9 respectively. That places ETI in the top of the second quartile in each 10 year.

11 Based on the cost control process, the historical cost and staff 12 trends, and the benchmarking performed by Ms. Kenney, in addition to my 13 previous discussion of the benefits of non-duplication of the services 14 provided by a centralized service company, I conclude that the costs 15 associated with the Utility and Executive Management class 16 are reasonable.

As discussed by Ms. Kenney, there were 107 electric operating companies, including ETI, in the study for 2008, and 116 electric operating companies, including ETI, in the study for 2009 and 2010.

2011 ETI Rate Case 3-32 Entergy Texas, Inc. Page 31 of 38 Direct Testimony of Joseph F. Domino 2011 Rate Case

1 Q. IS THE UTILITY AND EXECUTIVE MANAGEMENT CLASS OF 2 AFFILIATE SERVICES DUPLICATED BY ETI?

3 A. No. By having these services provided through a central organization 4 (ESI), ETI and each of the other Entergy Operating Companies avoid the 5 need to maintain their own contingent of personnel to perform these 6 services and avoid the costs associated with maintaining that personnel.

8 Q. HOW ARE THE COSTS OF THIS CLASS OF SERVICES BILLED TO 9 ETI?

10 A. Exhibit JFD-B shows all of the costs included in this class broken down by 11 project code and shows the billing method associated with each 12 project code.

14 Q. ON WHAT BASIS ARE COSTS IN THIS CLASS ALLOCATED?

15 A. The costs for the services included in this class are collected in one or 16 more project codes. As Ms. Tumminello explains, a billing method for the 17 project code is selected based upon cost causation, and while several 18 organizations may bill to a single project code, only one billing method is 19 assigned to each project code. Through the use of a single billing method, 20 the costs of all services performed under a project code are allocated 21 among the Entergy Operating Companies using the same criteria, at cost.

22 This ensures that all Entergy Operating Companies that cause costs to be 23 incurred and benefit from the service pay their appropriate proportion of

2011 ETI Rate Case 3-33 Entergy Texas, Inc. Page 32 of 38 Direct Testimony of Joseph F. Domino 2011 Rate Case

1 the costs. It also ensures that the Entergy Operating Companies are, in 2 total, charged no more and no less than one hundred percent of the costs 3 for services provided under the project code. Finally, the use of a single 4 billing method ensures that each Entergy Operating Company is paying 5 the same price for the same service, and that the price charged to ETI for 6 the services is no higher than the price charged by ESI to other affiliates 7 for the same or similar services and represents the actual cost of 8 the services.

10 Q. ABOVE YOU NOTED THAT 4.34% OF THE COSTS IN THIS CLASS 11 WERE DIRECTLY BILLED TO ETI, AND THE REMAINDER 12 ALLOCATED. PLEASE DISTINGUISH BETWEEN COSTS THAT ARE 13 “DIRECT” BILLED VERSUS COSTS THAT ARE “ALLOCATED” TO THE 14 ENTERGY COMPANIES.

15 A. Whenever appropriate, costs are direct billed to ETI and other affiliates.

16 This means the services provided (and associated costs) are caused by, 17 and benefiting, only ETI or whatever entity is the sole cause of the 18 services, and associated costs, provided. Only when costs are incurred 19 that are caused by ETI and one or more of the other Entergy Companies 20 are such costs billed by ESI to ETI using an allocation method.

2011 ETI Rate Case 3-34 Entergy Texas, Inc. Page 33 of 38 Direct Testimony of Joseph F. Domino 2011 Rate Case

1 Q. WHAT ARE THE PREDOMINANT BILLING METHODS USED FOR THIS 2 CLASS OF SERVICES?

3 A. For this class of services, the following billing methods are used to bill 4 92.57% of the costs for this class of services: 5  “ASSTSALL” – Total Assets (35.58%); 6  “CAPAOPCO” – System Capacity (22.49%); 7  “CUSTEGOP” – Electric and Gas Customers (22.17%); 8  “CUSEOPCO” – Electric Customers (8.01%); 9  “DIRECTTX” – 100% to ETI (4.34%).

11 Q. WHY IS BILLING METHOD “ASSTSALL” APPROPRIATE TO USE FOR 12 THE PROJECT CODES TO WHICH IT IS ASSIGNED?

13 A. For project codes assigned this billing method, costs are allocated based 14 on total assets. For example, Project Code F3PCC08500 — Executive 15 VP, Operations — captures costs associated with the operations of the 16 office of the President and Chief Operating Officer, Domestic Operations, 17 of Entergy Corp. The President/COO and staff provide cross-functional 18 management and direction to the Entergy System, and services provided 19 under this project relate to the oversight of all System Operations and the 20 stewardship of corporate assets. Billing Method “ASSTSALL” is 21 appropriate because it reflects the cause of the costs incurred, in that, 22 services provided relate to the stewardship of all the corporation’s assets.

2011 ETI Rate Case 3-35 Entergy Texas, Inc. Page 34 of 38 Direct Testimony of Joseph F. Domino 2011 Rate Case

1 Q. WHY IS BILLING METHOD “CAPAOPCO” APPROPRIATE TO USE FOR 2 THE PROJECT CODES TO WHICH IT IS ASSIGNED?

3 A. For the project codes assigned this billing method, costs are allocated 4 based on the fossil capacity of each Operating Company relative to the 5 fossil system capacity. For example, Project Code F3PCCEP001 — 6 Corporate Environmental Policy — captures and manages costs 7 associated with developing and implementing environmental policies and 8 programs to support fossil operations company-wide. The primary 9 activities conducted under this project code are the performance of 10 systematic reviews of existing, pending, and proposed environmental 11 regulations impacting the Entergy Operating Companies’ fossil operations.

12 Activities also include the development and implementation of 13 environmental policies, standards, and programs as well as active 14 participation in industry coalition groups to improve environmental 15 regulations that govern the electric industry. Because the costs 16 associated these activities are primarily associated with the Operating 17 Companies’ fossil operations, the relative size and complexity of each 18 entity is appropriately measured by fossil generating capacity, making 19 CAPAOPCO the appropriate billing method.

2011 ETI Rate Case 3-36 Entergy Texas, Inc. Page 35 of 38 Direct Testimony of Joseph F. Domino 2011 Rate Case

1 Q. WHY IS BILLING METHOD “CUSTEGOP” APPROPRIATE TO USE FOR 2 THE PROJECT CODES TO WHICH IT IS ASSIGNED?

3 A. For the project codes assigned this billing method, costs are allocated 4 based on the number of electric and gas customers. For example, Project 5 Code F3PCE99795 — Group President - Utility Operations — captures 6 costs associated with general activities of the office of the Group President 7 - Utility Operations related to executive management and oversight of the 8 Entergy Operating Companies’ regulated utility operations. The activities 9 under this project include meetings with utility company presidents to 10 discuss day-to-day operations of the companies, Board of Directors 11 meetings and activities, and meetings with regulators and their staffs on 12 utility matters, which activities directly relate to regulated utility customers 13 served by each Operating Company. Consequently, Billing Method 14 “CUSTEGOP” is appropriate because the relative level of activities and 15 costs are driven by the number of customers at each company.

17 Q. WHY IS BILLING METHOD “CUSEOPCO” APPROPRIATE TO USE FOR 18 THE PROJECT CODES TO WHICH IT IS ASSIGNED?

19 A. Billing Method “CUSEOPCO” allocates costs based on the number of 20 electric customers. For example, Project Code F3PPE9974S — Utility 21 ECI Continuing Improvement ESI — captures and manages costs 22 associated with the general activities of the Entergy Continuing 23 Improvement (“ECI”) department. That department is related to the

2011 ETI Rate Case 3-37 Entergy Texas, Inc. Page 36 of 38 Direct Testimony of Joseph F. Domino 2011 Rate Case

1 executive management and oversight of the various Strategic Initiatives 2 (e.g., Six Sigma, Benchmarking, ECI) in the Entergy Operating 3 Companies’ regulated utility operations. The primary activities include 4 meetings with utility company presidents and operating departments to 5 review and discuss ECI-Entergy Continuing Improvement and other 6 Strategic Initiatives status and implementation issues. Because the focus 7 of these types of projects is on improvements in the delivery of service to 8 regulated distribution customers, the pertinent cost driver for these 9 services is the number of electric customers, and the appropriate billing 10 method is CUSEOPCO.

12 Q. WHY IS BILLING METHOD “DIRECTTX” APPROPRIATE TO USE FOR 13 THE PROJECT CODES TO WHICH IT IS ASSIGNED?

14 A. This project code directs that 100% of the charges be allocated to ETI.

15 For instance, project codes assigned to this billing method often include 16 activities in which ESI assists with ETI fillings before the Commission. In 17 such instances, it is appropriate that ESI’s charges are allocated (or billed 18 directly) 100% to ETI.

2011 ETI Rate Case 3-38 Entergy Texas, Inc. Page 37 of 38 Direct Testimony of Joseph F. Domino 2011 Rate Case

1 Q. YOU HAVE ADDRESSED THE BILLING METHODS USED TO BILL 2 92.57% OF THE COSTS ASSOCIATED WITH THIS CLASS. WHAT 3 ABOUT THE REMAINING 7.43% OF THE COSTS OF THIS CLASS?

4 A. The remaining costs are billed through the use of other billing methods.

5 Given the number of billing methods, project codes, and relative dollar 6 amounts, I have not gone into detail in this discussion in an effort to keep 7 the discussion at a manageable level. However, the project codes and 8 billing methods used to bill the remaining 7.43% of the costs in this class 9 are provided in Exhibit JFD-B, discussed earlier. A reader may reference 10 this exhibit and then refer to the specific scope statement contained in 11 Ms. Tumminello’s testimony for a discussion of the particular billing 12 method used and the cost drivers for the activities captured in the 13 particular project code.

15 Q. HAVE YOU DETERMINED THAT THE COSTS REFLECTED IN THE 16 REMAINING 7.43% OF COSTS ASSOCIATED WITH THIS CLASS HAVE 17 BEEN BILLED APPROPRIATELY?

18 A. Yes. I have reviewed each of the project codes and the associated billing 19 methods used to bill the remaining 7.43% of the costs of this class. The 20 cost drivers reflected in the billing method used to bill the costs of each 21 project code are consistent with and reflect the cost drivers of the services 22 captured in each respective project code. Therefore, the price charged to 23 ETI represents the costs of the services received by ETI and is no higher

2011 ETI Rate Case 3-39 Entergy Texas, Inc. Page 38 of 38 Direct Testimony of Joseph F. Domino 2011 Rate Case

1 than the price charged to other affiliates for the same or similar types 2 of services.

4 VI. CONCLUSION Q. DOES THIS CONCLUDE YOUR DIRECT TESTIMONY?

6 A. Yes.

2011 ETI Rate Case 3-40 Exhibit JFD-1 2011 TX Rate Case Page 1 of 3 November 2011 Rate Case Witness and Testimony Content Witness Testimony Subject Chris E. Barrilleaux Company’s Financial Status and Importance of Adequate Rates; Capital Structure.

Julie F. Brown Information Technology Affiliate Charges; Information Technology Capital Additions.

Patrick J. Cicio Energy and Fuel Management Affiliate Charges; Energy and Fuel Management Capital Additions; Entergy System Agreement.

Michael P. Considine Regulatory and Tax Accounting; Revenue Requirement Issues; Pension and OPEB Expenses; Pro Forma Adjustments.

Robert R. Cooper Long-Term Resource Planning; Long-Term Purchased Power Contracts.

Shawn B. Corkran Overall Distribution O&M Charges; Distribution Operations Affiliate Charges; Transmission and Distribution Support Affiliate Charges; Distribution Operations Capital Additions; Texas Distribution Operations; Service Quality & Service Quality Improvement; Miscellaneous Electric Services Charges.

Joseph F. Domino Case Overview and Presentation; Executive and Utility Management Affiliate Charges.

Donna S. Doucet Financial Services Affiliate Charges; Budget Process.

Walter C. Ferguson Federal Policy, Regulatory and Governmental Affairs Affiliate Charges.

Patricia A. Galbraith ETI Property Tax Pro Forma; Tax Services Affiliate Charges.

Kevin G. Gardner Compensation, Benefits, and Labor-Related Charges; Human Resources Affiliate Charges.

2011 ETI Rate Case 3-41 Exhibit JFD-1 2011 TX Rate Case Page 2 of 3

Winfred W. Garrison Fossil Plant Capital Additions; Fossil Plant Operations and Nelson 6 Co-Owner Service Affiliate Charges; Fossil Plant Efficiency.

Samuel C. Hadaway Return on Equity.

Jay C. Hartzell Alignment of Incentive Compensation Goals and Customer Benefits.

Chester N. Herrington Communications Affiliate Charges.

Joseph Hunter Supply Chain Affiliate Charges; Supply Chain Capital Additions.

Devon S. Jaycox Reasonableness of Energy Acquisition and Economic Dispatch for the Reconciliation Period.

Jay Joyce Lead Lag Study Review.

Jeanne J. Kenney FERC Form 1 non-production O&M Cost Benchmarking.

Heather G. LeBlanc Class Cost of Service Study; Purchased Power Recovery Rider; REC Rider.

Richard A. Lynch Weather-Normalized Demand and Energy.

Phillip R. May Regulatory Support Affiliate Charges; Regulatory Support Capital Additions; Purchased Power Recovery Rider; Competitive Generation Service Margaret McCloskey Over/(Under)-Recovery Balance for Reconcilable Fuel Expense.

Mark F. McCulla Overall ETI Transmission O&M Charges; Transmission Operations Affiliate Charges; Transmission Operations Capital Additions.

Karen McIlvoy Reconcilable Gas Purchases; Gas and Oil Base Rate Components.

Stephen C. McNeal Treasury Operations Affiliate Charges.

Stephen F. Morris External Rate Case Expenses.

2011 ETI Rate Case 3-42 Exhibit JFD-1 2011 TX Rate Case Page 3 of 3

H. Vernon Pierce Texas Retail Operations; Miscellaneous Electric Services Charges.

Thomas C. Plauché Administration Affiliate Charges; Capital Additions for Administration Services.

Rory L. Roberts ETI FIT Expense; Consolidated Tax Savings Issues; FIT Expense Affiliate Charges.

Abdon F. Roman Affiliate Charges for the Customer Service Operations, Environmental Services, and Retail Operations Classes; Customer Service Operations Capital Additions.

Robert D. Sloan Legal Services Affiliate Charges; Legal Services Capital Additions.

Myra L. Talkington Rate Design; Class Cost Allocation Factors; Rate Schedules and Tariffs.

Michelle H. Thiry Reconcilable Fuel Expense Overview; Short-Term Purchased Power Expense.

Ryan Trushenski Reconcilable and Non-Reconcilable Coal Expense.

Stephanie B. Tumminello Overview of Affiliate Structure and Transactions; FERC Form 60 Benchmarking, Explanation of Affiliate Charges Presentation; Depreciation Affiliate Charges; Service Company Recipient Offsets Affiliate Charges; Other Expenses Affiliate Charges.

Dane Watson Depreciation.

Gregory S. Wilson Recommendation for Insurance Reserve Accrual.

Gregory R. Zakrzewski Non-Reconcilable/Reconcilable Fuel Accounting.

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2011 ETI Rate Case 3-44 ENTERGY TEXAS, INC. EXHIBIT JFD-A 2011 ETI Rate Case

Affiliate Billings - by Witness, Class, and Department 2011 TX Rate Case For the Twelve Months Ended June 30, 2011 Page 1 of 1 Amounts in Dollars (A) (B) (C) (D) (E) (F) (G) (H) Total Billings Billing Service Company ETI Per Pro Forma Total ETI Class Entity Dept Support Recipient Total All Other BU's Books Exclusions Amount Adjusted UTILITY & EXECUTIVE MANAGEMENT ESI CE122 1,289,256 81,310 1,370,566 1,366,479 4,086 - (536) 3,551 UTILITY & EXECUTIVE MANAGEMENT ESI CE12F (19,654) - (19,654) (19,654) - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CE179 1,281,690 105,837 1,387,527 1,387,448 78 (78) - - UTILITY & EXECUTIVE MANAGEMENT ESI CP015 208,351 - 208,351 185,100 23,251 (23,251) - - UTILITY & EXECUTIVE MANAGEMENT ESI CP027 - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CP040 5,400,646 337,276 5,737,922 5,387,064 350,858 (5,438) (7,095) 338,326 UTILITY & EXECUTIVE MANAGEMENT ESI CP050 1,347,769 96,578 1,444,347 1,442,753 1,594 (28) (1,058) 509 UTILITY & EXECUTIVE MANAGEMENT ESI CP083 223,988 23,886 247,874 211,700 36,173 - 479 36,652 UTILITY & EXECUTIVE MANAGEMENT ESI CPCA5 322,809 36,140 358,949 343,256 15,693 - (98) 15,595 UTILITY & EXECUTIVE MANAGEMENT ESI CPCAO 1,434,339 142,884 1,577,223 1,422,591 154,631 (769) (6,288) 147,574 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP7 1,689,442 155,849 1,845,292 1,634,094 211,197 (13,968) 2,448 199,678 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 5,517,075 167,988 5,685,063 5,117,844 567,219 (45) (217,446) 349,728 UTILITY & EXECUTIVE MANAGEMENT ESI CSODW 688 - 688 688 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI FN086 1,233,220 146,323 1,379,544 1,243,365 136,178 - (218) 135,961 UTILITY & EXECUTIVE MANAGEMENT ESI GAF6G 1,183 - 1,183 1,183 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAF6P 429,757 46,171 475,927 475,855 73 - (73) - UTILITY & EXECUTIVE MANAGEMENT ESI GAFH6 995,135 106,776 1,101,911 1,101,858 53 - (53) - UTILITY & EXECUTIVE MANAGEMENT ESI GAG2E 550,596 55,966 606,562 606,458 104 - (104) - UTILITY & EXECUTIVE MANAGEMENT ESI GAG2U 296,789 33,879 330,668 330,541 127 - (127) - UTILITY & EXECUTIVE MANAGEMENT ESI GAG7F 226,639 24,752 251,391 251,199 192 - (192) - UTILITY & EXECUTIVE MANAGEMENT ESI GAH2H 113,151 11,803 124,955 124,955 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAJ2J 132,031 13,670 145,701 145,701 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAJ2K 228,461 17,876 246,337 246,326 10 - (10) - UTILITY & EXECUTIVE MANAGEMENT ESI GAJ3K 208,592 25,135 233,726 233,726 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SGG2D 755,995 87,575 843,570 842,847 723 - (723) - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 3,239,437 143,246 3,382,683 2,924,024 458,659 (373) (3,967) 454,318 UTILITY & EXECUTIVE MANAGEMENT ESI SU085 - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SULSY 1,434,169 151,485 1,585,654 1,366,430 219,224 4,446 3,300 226,970 UTILITY & EXECUTIVE MANAGEMENT ESI SUUOS 14,122 - 14,122 12,175 1,947 - - 1,947 UTILITY & EXECUTIVE MANAGEMENT ESI SUUS1 132,639 1,847 134,487 105,927 28,560 - (141) 28,420 UTILITY & EXECUTIVE MANAGEMENT Total ESI 28,688,315 2,014,250 30,702,565 28,491,933 2,210,631 (39,503) (231,900) 1,939,228 Total UTILITY & EXECUTIVE MANAGEMENT 28,688,315 2,014,250 30,702,565 28,491,933 2,210,631 (39,503) (231,900) 1,939,228 Total for Witness Domino, Joe 28,688,315 2,014,250 30,702,565 28,491,933 2,210,631 (39,503) (231,900) 1,939,228 3-45

Amounts may not add or tie to other schedules due to rounding. EXHIBIT JFD-A Domino, Joe Page 1 of 1 This page has been intentionally left blank.

2011 ETI Rate Case 3-46 ENTERGY TEXAS, INC. EXHIBIT JFD-B 2011 ETI Rate Case

Affiliate Billings - by Witness, Class and Project 2011 TX Rate Case For the Twelve Months Ended June 30, 2011 Page 1 of 6 Amounts in Dollars (A) (B) (C) (D) (E) (F) (G) (H) Total Billings Billing Activity / Project ESI Billing Service Company ETI Per Pro Forma Total ETI Class Entity Code Activity / Project Description Method Support Recipient Total All Other BU's Books Exclusions Amount Adjusted UTILITY & EXECUTIVE MANAGEMENT ESI 80 - 80 80 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI C1PPFI5207 Payroll Time & Labor - Phase I EMPLOYAL (25) (2) (27) (26) (1) 0 1 - UTILITY & EXECUTIVE MANAGEMENT ESI C1PPFIRGTL Regulated Time-LBR & Absence M EMPOPCPE 1,786 246 2,032 1,853 179 (179) - - UTILITY & EXECUTIVE MANAGEMENT ESI C1PPHR8800 PS HCM (Human Cap Mgmt) Upgrd EMPLOYAL (9) (1) (10) (10) (0) 0 0 - UTILITY & EXECUTIVE MANAGEMENT ESI C1PPSP0008 SPO ELL&ENOI Purchase Option I OWNISES2 - (2) (2) (2) - - - - UTILITY & EXECUTIVE MANAGEMENT ESI C5PC449602 GAS FAILURES BLANKET DIRCTENO 35,953 - 35,953 35,953 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI C5PP449606 Gas Serv Storm Rebuild Replace DIRCTENO 109,358 13,157 122,515 122,515 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI C6PCN32144 GRAND GULF EXTENDED POWER UPRA DIRCTSER 796 96 892 892 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI C6PPAMBSGN AMI:BASE Non-Incremental, EGSL DIRECTLG (54) (7) (61) (61) - - - - UTILITY & EXECUTIVE MANAGEMENT ESI C6PPSP0012 SPO Project Gator Transact/Tra DIRCTELI 834 95 928 928 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI C6PPWGP516 SBC CIP Compliance DIRECTTX 12,289 1,679 13,968 - 13,968 (13,968) - - UTILITY & EXECUTIVE MANAGEMENT ESI C6PPWS0534 System Planning Pet Coke Repow DIRCTELI 274 31 305 305 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI C6PPWS0783 Ninemile 6 Development DIRCTELI 8,423 1,072 9,495 9,495 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI C7PPSJ1214 WINTER STORM DL EAI DIST 01/26 DIRCTEAI - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI C7PPSJ1244 STORM DL ARK DIST EAI 1/7/11 I DIRCTEAI 98 13 111 111 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI C7PPSJ1250 STORM DL EAI DIST 4/19/11-4/24 DIRCTEAI 2,890 433 3,323 3,323 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI C7PPSJ1251 TORNADOES DL EAI DIST 4/25/11 DIRCTEAI 5,554 861 6,416 6,416 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI C7PPSJ2462 STORM DMG LA DIST ELL 1/8/11 I DIRCTELI 1,575 260 1,835 1,835 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI C7PPSJ2474 STORM Dmg ELL 4/25 to 4/27/11 DIRCTELI 100 12 112 112 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI C7PPSJ3183 EMI 04/24/10 Tornadoes Distr O DIRCTEMI - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI C7PPSJ3198 EMI Storm Distr Ops 1/7/11Wint DIRCTEMI 20,268 2,733 23,001 23,001 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI C7PPSJ3204 EMI StormTornadoes DistrOps 4/ DIRCTEMI 100 12 112 112 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI C8PPTL5496 Replace Storm Damages DIRCTEAI 20,682 3,097 23,779 23,779 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI E1PCD10064 DISTR WK MGMT-SUBST AOR/COS/SF CUSEOPCO 1 0 1 1 0 - 0 0 UTILITY & EXECUTIVE MANAGEMENT ESI E1PCR56025 CUSTOM SALES & SERVICE UNIT- M DIRCTELI 688 - 688 688 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI E1PCR56226 Sales & Mktg - ALL JURIS MACCTALL 8,492 956 9,448 8,222 1,226 - (23) 1,202 UTILITY & EXECUTIVE MANAGEMENT ESI E1PPNXCRP1 Unwind - Employee DIRECTNI 21,844 3,253 25,096 25,096 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI E2PPLG11DA Logistics Jan 2011 DIST Ark DIRCTEAI 0 (2) (2) (2) - - - - UTILITY & EXECUTIVE MANAGEMENT ESI E2PPLG11DL Logistics Jan 2011 DIST ELL DIRCTELI 0 (15) (15) (15) - - - - UTILITY & EXECUTIVE MANAGEMENT ESI E2PPLG11DM Logistics Jan 2011 DIST Miss DIRCTEMI 0 (25) (25) (25) - - - - UTILITY & EXECUTIVE MANAGEMENT ESI E2PPLG11TL Logistics Jan 2011 TRN ELL DIRCTELI - (0) (0) (0) - - - - UTILITY & EXECUTIVE MANAGEMENT ESI E2PPLG11TM Logistics Jan 2011 TRN Miss DIRCTEMI - (1) (1) (1) - - - - UTILITY & EXECUTIVE MANAGEMENT ESI E2PPSJ1255 T-Grid Storm Tornadoes EAI 4/2 DIRCTEAI 315 44 359 359 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI E2PPSJ2447 T-Grid Storm O&M ELL 1/7/201 I DIRCTELI 11 2 13 13 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI E2PPSJ3188 T-Grid Storm Damage EMI 1/7/11 DIRCTEMI 28 4 31 31 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PC6H0026 NORTHEAST MGMT OVERSITE IP2/IP SPL77N7A 24,988 - 24,988 24,988 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PC6HENNE ENN EQUAL SPLIT DIRCTENU 588 - 588 588 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PCC08500 Executive VP, Operations ASSTSALL 17,701 951 18,652 16,787 1,864 - (96) 1,768 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCC14900 EXPENSES-CHAIRMAN ENTERGY DIRCTETR 448,364 56,234 504,599 504,599 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PCC31255 OPERATIONS-OFFICE OF THE CEO ASSTSALL 3,036,304 193,032 3,229,335 2,909,321 320,015 (645) (4,828) 314,542 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCC31256 LEADERSHIP CONFERENCE EMPLOYAL 186,861 - 186,861 178,151 8,711 - - 8,711 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCC31257 EVENTS ADMINISTRATION DIRCTETR 826,330 - 826,330 826,330 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PCCDVCCN PROJECT GUMBO CUSGOPCO - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PCCDVETR CORP DEV-ANALYSIS STRATEGIC ME ASSTSALL - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PCCE0155 BELOW THE LINE-C ENVIRONMENTAL CAPAOPCO - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PCCEP001 CORPORATE ENVIRONMENTAL POLICY CAPAOPCO 2,196,785 - 2,196,785 1,959,288 237,496 - - 237,496 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCCPM001 CORPORATE PERFORMANCE MANAGEME ASSTSALL 1,197,217 142,793 1,340,010 1,207,839 132,171 - (68) 132,103 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCCSE060 SAFETY & ENVIRONMENTAL SUPPORT EMPLOYAL 747 62 810 770 40 - 1 41 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCCSPUTI SYSTEM PLANNING & STRATEGIC AD LOADOPCO 27,668 3,370 31,038 26,324 4,714 - 98 4,811 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCD10006 FIELD DEVELOPMENT CUSTEGOP 6 1 7 6 1 - 0 1 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCD10010 PROGRAM MANAGEMENT - O&M CUSTEGOP 9 1 10 8 1 - 0 1 3-47

UTILITY & EXECUTIVE MANAGEMENT ESI F3PCD10033 SSS PRELIMINARY PLANNING, SCOP CUSTEGOP 0 0 0 0 0 - 0 0 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCD10049 REGULATED RETAIL SYSTEMS - O&M CUSTEGOP 25 3 28 24 4 - 0 4 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCD10077 REGULATORY AFFAIRS WORLDOX IMP DIRCTENO 4 1 5 5 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PCD10105 CUSTOMER CARE SYSTEM SUPPORT CUSEGXTX 83 10 93 93 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PCDG0004 OPERATOR QUAL DEVELOP & TRAIN DIRCTENO 27,119 2,217 29,336 29,336 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PCDG0005 OPERATOR QUAL DEVELOP & TRAIN DIRECTLG 89,501 8,908 98,409 98,409 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PCE13100 GEN CORP. LEGAL ENTERGY CORP. DIRCTETR 3,792 552 4,344 4,344 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PCE13321 ESI GENERAL LEGAL ADVICE LVLSVCAL 3,792 552 4,344 3,931 413 - 8 421 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCE14420 REGULATORY AFFAIRS - EAI DIRCTEAI 26 - 26 26 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PCE14987 FGA-Climate/Environmental ASSTSALL 47,580 - 47,580 42,787 4,793 (4,793) - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PCE99741 Utl Ops ECI & 6-Sigma Improve CUSEOPCO 249 - 249 212 37 - - 37 Amounts may not add or tie to other schedules due to rounding. EXHIBIT JFD-B Domino, Joe Page 1 of 6 ENTERGY TEXAS, INC. EXHIBIT JFD-B 2011 ETI Rate Case

Affiliate Billings - by Witness, Class and Project 2011 TX Rate Case For the Twelve Months Ended June 30, 2011 Page 2 of 6 Amounts in Dollars (A) (B) (C) (D) (E) (F) (G) (H) Total Billings Billing Activity / Project ESI Billing Service Company ETI Per Pro Forma Total ETI Class Entity Code Activity / Project Description Method Support Recipient Total All Other BU's Books Exclusions Amount Adjusted UTILITY & EXECUTIVE MANAGEMENT ESI F3PCE99750 PRES- ENT. LA-GEN'L OPS-ELI/EG CUSELGLA 1,114,809 70,756 1,185,564 1,185,564 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PCE99751 SPECIAL PROJECTS - LA STATE PR CUSELGLA 71 - 71 71 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PCE99795 GROUP PRES - UTILITY OPERATION CUSTEGOP 2,011,555 130,481 2,142,037 1,845,705 296,332 (373) (3,718) 292,241 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCF07300 CORP PLANNING & ANALYSIS- REGU CUSTEGOP 10,104 1,234 11,338 9,775 1,563 - 31 1,595 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCF10414 ESI TAX SERVICES LVLSVCAL 24 3 27 24 3 - 0 3 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCF10445 ENTERGY CONSOLIDATED TAX SERVI ASSTSALL 2 0 2 2 0 - 0 0 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCF15260 IT - BUSINESS & PROJECT SUPPOR CAPAOPCO 5 1 5 5 1 - 0 1 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCF21600 CORP RPTG ANALYSIS & POLICY AL GENLEDAL 4,616 418 5,035 4,717 317 - 7 324 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCF22511 IR - GENERAL, INQUIRIES & MAIL DIRCTETR 404 - 404 404 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PCF22514 MEETINGS ANALYSTS/INVESTORS/SH DIRCTETR 5,306 - 5,306 5,306 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PCF23033 GENERAL ACCOUNTING - ESI LVLSVCAL 977 135 1,112 1,007 105 - 2 107 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCF23425 ACCOUNTS PAYABLE PROCESSING APTRNALL 190 17 207 188 19 - 0 19 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCF23428 TREASURY SYSTEMS BNKACCTA 69 8 77 75 2 - 0 2 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCF23442 PAYROLL PROCESSING PRCHKALL 89 8 98 93 5 - 0 5 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCF23920 CORP REPORTING ANALYSIS & POLI DIRCTELI 32,744 3,899 36,643 36,643 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PCF239LA CORP RPTNG ANALYSIS/POLICY EGS DIRECTLG 32,690 3,893 36,583 36,583 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PCF24910 PROPERTY ACCOUNTING- FIXED ASS ASSTLOCA 59 7 67 60 7 - 0 7 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCF26910 REVENUE ACCOUNTING ANALYSIS CUSEGALL 40 5 45 38 6 - 0 6 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCF72271 DATA WAREHOUSE GENLEDAL 67 6 74 69 4 - 0 4 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCF72670 GENERAL ACCOUNTING SYSTEM MAIN GENLEDAL 823 76 899 847 52 - 1 53 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCF72901 MOBILE DATA TERMINAL BASELOAD CUSTEGOP 5 1 6 5 1 - 0 1 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCF73027 BUDGET SYSTEM MAINTENANCE GENLEDAL 153 14 168 158 10 - 0 10 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCF73901 AM/FM BASELOAD (SUPPORT) DIRECTTX 3 0 3 - 3 - 0 3 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCF74195 TRANSMISSION APPLICATION SUPPO TRSBLNOP 161 19 180 159 21 - 0 22 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCF74341 ISB MAINT LOADWEPI 5 1 5 5 1 - 0 1 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCF74344 GENERATION PLANNING & DISPATCH LOADOPCO 20 2 22 19 3 - 0 3 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCF74515 FOSSIL MAINTENANCE MANAGEMENT CAPAOPCO 40 5 45 40 5 - 0 5 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCF74585 FOSSIL APPLICATION SUPPORT CAPAOPCO 43 5 48 42 5 - 0 5 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCF99182 RECORDS MANAGEMENT RECDMGNT 11 1 12 10 1 - 0 1 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCFACALL FACILITIES SVCS- ALL COS SQFTALLC 9,149 282 9,431 8,386 1,045 (73) (436) 536 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCFAPWHS POWERHOUSE OPERATIONS EMPLOYAL 123 - 123 117 6 - (6) - UTILITY & EXECUTIVE MANAGEMENT ESI F3PCFBLREG BELOW THE LINE- REGULATED CUSTEGOP - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PCFCPO01 CHIEF PROCUREMENT OFFICER SCPSPALL 8,175 980 9,155 8,049 1,106 - 23 1,128 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCFCQEAI ENTERPRISE APPLICATION INTEGRA APPSUPAL 292 32 323 274 49 - 1 50 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCFCQEXC EXCHANGE PCNUMALL 312 26 338 325 13 - 0 14 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCFCQMVS MAINFRAME APPSMVSX - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PCFCQNTS NT SERVERS APPSWINT - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PCFCQUNX UNIX SERVERS APPSUNIX - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PCFEXETR EXECUTIVE ADVISORY SERVICES - DIRCTETR 44,620 5,822 50,442 50,442 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PCFX2770 HR SERVICE CENTER SUPPORT EMPLOYAL - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PCFX2815 EDMS PRODUCT LINE SUPPORT EMPLOYAL 60 6 66 63 3 - 0 3 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCFX2850 SECRETARIAT LEGAL SUPPORT ASSTSALL 4 0 5 4 1 - 0 1 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCFX3265 POWERBUILDER FRAMEWORK BASELOA APPSUPAL 5 0 5 4 1 - 0 1 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCFX3275 WEB INFRASTRUCTURE MAINTENANCE PCNUMALL 9 1 10 9 0 - 0 0 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCFX3290 IT BUSINESS PLANNING AND GOVER ITSPENDA 3,818 470 4,288 4,002 285 - 6 291 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCFX3350 A/R & BILLING SUPPORT ARTRNALL 72 8 80 71 9 - 0 9 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCFX3355 Property Software Support GENLEDAL 3 0 3 3 0 - 0 0 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCFX3450 CORPORATE REPORTING SYSTEM SUP GENLEDAL 0 - 0 0 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PCFX3620 MMIS MATERIALS MAINT MGMNT INF DIRCTESI 0 - 0 0 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PCFX3625 SUPPLY CHAIN - CDW SYSTEMS SUP SCDSPALL 4 0 4 3 2 - 0 2 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCFX3640 WHITE AMBER & ITILITI SUPPORT SCMATRAN - - - - - - - - 3-48

UTILITY & EXECUTIVE MANAGEMENT ESI F3PCFX3650 WEB PAGE SUPPORT - CORPORATE EMPLOYAL 1 0 1 1 0 - 0 0 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCFX3670 CORPORATE COMMUNICATIONS WEB S DIRCTETR 4 0 4 4 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PCFX3675 BARCODING SYSTEMS SUPPORT SCDSPALL 2 0 2 1 1 - 0 1 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCFX3690 PEARL SUPPORT APTRNALL 1 0 1 1 0 - 0 0 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCFX3695 ATPR SUPPORT APTRNALL 61 6 67 61 6 - 0 6 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCFX3785 ORG, JES, BATS, ACBM SUPPORT GENLEDAL 0 - 0 0 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PCFX3790 ESTER SUPPORT PRCHKALL 96 9 105 99 5 - 0 5 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCFX5555 DATA WAREHOUSE TOOLS SUPPORT APPSUPAL 25 3 28 24 4 - 0 4 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCG10345 GAS DIVISION DIRECTOR - ENOI E DIRCTENO 686,476 70,426 756,902 756,902 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PCG10347 GAS DIVISION DIRECTOR - EGSI E DIRECTLG 552,734 57,006 609,740 609,740 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PCH60959 EXECUTIVE FACILITIES SERVICES DIRCTETR 348 - 348 348 - - - - Amounts may not add or tie to other schedules due to rounding. EXHIBIT JFD-B Domino, Joe Page 2 of 6 ENTERGY TEXAS, INC. EXHIBIT JFD-B 2011 ETI Rate Case

Affiliate Billings - by Witness, Class and Project 2011 TX Rate Case For the Twelve Months Ended June 30, 2011 Page 3 of 6 Amounts in Dollars (A) (B) (C) (D) (E) (F) (G) (H) Total Billings Billing Activity / Project ESI Billing Service Company ETI Per Pro Forma Total ETI Class Entity Code Activity / Project Description Method Support Recipient Total All Other BU's Books Exclusions Amount Adjusted UTILITY & EXECUTIVE MANAGEMENT ESI F3PCHRCALL HR SVCS- CUST SERV SUPT- ALL C EMPLOCSS 196 - 196 181 15 - - 15 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCHRDCSS HR- FRANCHISE OPNS (DIST) SUPT EMPLFRAN 481 - 481 414 66 - - 66 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCHRFOSS HR FOSSIL SUPPORT- ALL COS EMPLOFOS 537 - 537 488 48 - - 48 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCHRPRES HR PRESIDENT/ CEO SUPPORT- ALL EMPLPRES 7 - 7 6 1 - - 1 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCHRSALL HR SERVICES- ALL COMPANIES EMPLOYAL 317,117 33,482 350,598 333,715 16,883 - (72) 16,812 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCHRSDUT HR SVCS - ESI DOMESTIC UTILITY DIRCTESI 8 - 8 8 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PCHRTRAN HUMAN RESOURCE SVCS - TRANSMIS EMPLTRAN 115 - 115 106 9 - - 9 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCMCMSOM MATERIALS & CONTRACTS MGTMT SY SCMATXNU - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PCN20520 WORK MANAGEMENT SYSTEM (WMS) M DIRCTEOI 25 3 28 28 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PCN20521 IDEAS MAINTENANCE DIRCTEOI 76 9 86 86 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PCN20522 PCRS MAINTENANCE DIRCTEOI 133 16 149 149 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PCN20527 NUCLEAR IT QUICK RESPONSE TEAM DIRCTEOI 44 5 49 49 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PCN20528 ERD SUPPORT (MAINTENANCE) DIRCTEOI 617 74 691 691 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PCN20858 NUCLEAR IT QUICK RESPONSE TEAM DIRCTEOI 2 0 3 3 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PCR40085 ENTERGY CORPORATION COMMUNICAT DIRCTETR 10,500 - 10,500 10,500 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PCR40118 UTILITY COMMUNICATIONS CUSTEGOP 83,560 - 83,560 72,040 11,521 - (118) 11,403 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCR40430 EMPLOYEE COMM (REGULATED COMPA EMPLOREG 71,944 - 71,944 67,408 4,535 - - 4,535 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCR40500 EMPLOYEE COMM (REG + UNREG COM EMPLOYAL 4 0 5 5 0 - 0 0 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCR53095 HEADQUARTER'S CREDIT & COLLECT CUSTEGOP 0 - 0 0 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PCR53291 ESI REMITTANCE PROCESSING CUSEOPCO 151 18 170 145 25 - 1 26 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCR73326 CUSTOMER SERVICE CENTER SUPPOR CUSTCALL 130 16 146 130 16 - 0 16 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCR73380 CREDIT SYSTEMS CUSTEGOP 40 5 44 38 6 - 0 6 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCR93300 NORTHEAST NONREG NUCLEAR EXTRN DIRCTENU - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PCRM1021 AUDIT: ESI INFORMATION TECHNO DIRCTESI 3 - 3 3 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PCSYSAGR SYSTEM AGREEMENT-2001 CUSEOPCO 771,530 96 771,625 657,743 113,883 - 4 113,887 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCSYSRAS SYSTEM REGULATORY AFFAIRS-STAT CUSTEGOP 105,291 8 105,299 90,781 14,518 - (10) 14,508 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCT29320 SKILLS TRAINING CUST. SERV- HE CUSEOPCO 163 - 163 139 24 - - 24 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCT29400 OPERATIONS SAFETY - HEADQUARTE CUSTEGOP 689,509 74,343 763,852 658,206 105,647 512 1,807 107,966 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCT29406 OPERATIONS SAFETY - TEXAS DIST DIRECTTX 15,773 - 15,773 - 15,773 - - 15,773 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCT54052 Trans Regulatory Support/Polic TRSBLNOP 9,442 868 10,310 9,099 1,211 - 24 1,235 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCT54065 OPNS OF PURCHASING & CONT-DCS SCMATRAN 0 0 0 0 0 - 0 0 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCTBLLPL BELOW THE LINE - LPL DIRCTELI - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PCTDDS26 CUSTOMER SERVICE SUPPORT - O&M CUSTEGOP 120 - 120 103 17 - - 17 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCTDPQ01 DISTR POWER QUALITY ESI CUSEOPCO 3 0 3 2 0 - 0 0 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCTDS010 PROCESS & SKILLS TRAINING ADMI EMPLFRAN 120,567 14,007 134,574 115,628 18,946 - 389 19,335 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCTDTR08 SKILLS TRAINING - LOUISIANA EL DIRCTELI - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PCTTDS12 TRANSMISSION LINES O&M EXPENS TRALINOP - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PCTTDS17 Substation Maintenance EGSI LA DIRECTLG 1,540 - 1,540 1,540 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PCTTDS19 SUBSTATION/SYSTEM PROT MAINT - DIRCTEAI 10,322 - 10,322 10,322 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PCTTDS21 SUBSTATION/SYSTEM PROT MAINT - DIRCTELI 1,540 - 1,540 1,540 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PCTTDS22 SUBSTATION/SYSTEM PROT MAINT - DIRCTEMI 7,620 - 7,620 7,620 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PCTTDS23 Substation Maintenance - Texas DIRECTTX 15,773 - 15,773 - 15,773 - - 15,773 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCTTDS24 SUBSTATION/SYSTEM PROT MAINT - DIRCTENO 1,540 - 1,540 1,540 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PCTTDS27 DISTRIBUTION O&M EXPENSE -EAI DIRCTEAI 13,605 - 13,605 13,605 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PCTTDS28 DISTRIBUTION O&M EXPENSE -EMI DIRCTEMI 11,088 376 11,464 11,464 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PCTTDS29 DISTRIBUTION O&M EXPENSE -ELI DIRCTELI 9,001 708 9,709 9,709 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PCTTDS30 DISTRIBUTION O&M EXPENSE -EGSI DIRECTLG 1,540 - 1,540 1,540 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PCTTDS31 DISTRIBUTION O&M EXPENSE - ENO DIRCTENO 1,596 - 1,596 1,596 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PCTTDS38 TRANSMISSION O&M MGMT/SUPPORT TRSBLNOP 1,871,582 4,636 1,876,218 1,655,755 220,463 (17) 90 220,536 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCTTDS46 DISTRIBUTION O&M EXP - METRO E CUSEMETR 159 - 159 159 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PCTTDS47 DISTR O&M EXPENSE - LOUISIANA CUSTELLA 943 - 943 943 - - - - 3-49

UTILITY & EXECUTIVE MANAGEMENT ESI F3PCTTDS71 TRANSMISSION MANAGEMENT/SUPPOR DIRCTEAI - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PCW29607 POWER SYSTEM ACCOUNTING LOADWEPI 3 0 4 3 1 - 0 1 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCW29608 TRANSMISSION POWER SYSTEM OPER LOADOPCO 6,950 639 7,589 6,456 1,133 - 22 1,155 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCW55555 VP FOSSIL GENERATION CAPAOPCO 14,414 1,850 16,265 14,506 1,758 - 32 1,791 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCWE0063 EMO APPLICATION SUPPORT LOADOPCO 17 2 19 16 3 - 0 3 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCWE0073 FOSSIL INFORMATION TECHNOLOGY CAPAOPCO 3 0 3 3 0 - 0 0 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCWE0135 NEL. 6 JOINT OWNERSHIP PART. A DIRECTLG 964 108 1,072 1,072 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PCWE0187 FOSSIL IT SUPPORT FOR 2003-200 CAPAOPCO - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PCWS0327 SAIC LABOR CHARGES TO PMDC CAPAOPCO 53 6 60 53 7 - 0 7 UTILITY & EXECUTIVE MANAGEMENT ESI F3PCZGASAG GAS ADMINISTRATIVE CUSGOPCO 1,119,964 119,476 1,239,440 1,239,440 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PCZU1603 LP&L/LPSC EARNINGS REVIEW; DOC DIRCTELI 2,335 298 2,633 2,633 - - - - Amounts may not add or tie to other schedules due to rounding. EXHIBIT JFD-B Domino, Joe Page 3 of 6 ENTERGY TEXAS, INC. EXHIBIT JFD-B 2011 ETI Rate Case

Affiliate Billings - by Witness, Class and Project 2011 TX Rate Case For the Twelve Months Ended June 30, 2011 Page 4 of 6 Amounts in Dollars (A) (B) (C) (D) (E) (F) (G) (H) Total Billings Billing Activity / Project ESI Billing Service Company ETI Per Pro Forma Total ETI Class Entity Code Activity / Project Description Method Support Recipient Total All Other BU's Books Exclusions Amount Adjusted UTILITY & EXECUTIVE MANAGEMENT ESI F3PP1E2EPM End-to-End Process Mgmnt LVLSVCAL 3,230 407 3,637 3,291 347 - 7 354 UTILITY & EXECUTIVE MANAGEMENT ESI F3PP4R9886 TRITIUM DETECTION INVESTIGATIO DIRECT72 23,182 2,309 25,491 25,491 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PP6HHOST ENNE Hosting/server support/SO DIRCTENU 135 16 151 151 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PP6HINDS Indus Passport DIRCTENU 339 41 379 379 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PPAMISTG AMI Strategy Expense CUSEOPCO 223 27 250 213 37 - 1 38 UTILITY & EXECUTIVE MANAGEMENT ESI F3PPAMPDEV Advanced Mgmt Dev Program EMPLOYAL 4,112 - 4,112 3,921 192 - (192) - UTILITY & EXECUTIVE MANAGEMENT ESI F3PPBLANCO Project White DIRCTETR 38,891 5,003 43,894 43,894 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PPC31258 CEO MEETINGS WITH EMPLOYEES EMPLOYAL 350 - 350 334 16 - - 16 UTILITY & EXECUTIVE MANAGEMENT ESI F3PPCAO001 Chief Administrative Officer ASSTSALL 1,431,497 145,499 1,576,996 1,421,598 155,398 (769) (6,899) 147,730 UTILITY & EXECUTIVE MANAGEMENT ESI F3PPCCS010 Climate Consulting Services ASSTSALL 289,337 31,693 321,030 289,415 31,615 - 547 32,162 UTILITY & EXECUTIVE MANAGEMENT ESI F3PPCOO001 CHIEF OPERATING OFFICER ASSTSALL 582,384 63,085 645,469 581,811 63,658 (3) (2,115) 61,540 UTILITY & EXECUTIVE MANAGEMENT ESI F3PPCPMUTL CORPORATE PERFORMANCE MGMT UTL EMPXRTNC 19,531 1,594 21,126 19,133 1,992 - 40 2,032 UTILITY & EXECUTIVE MANAGEMENT ESI F3PPD10115 Dist Work Mgmt O&M-DIS/DSS/ADS CUSTEGOP 176 21 197 170 27 - 1 28 UTILITY & EXECUTIVE MANAGEMENT ESI F3PPD10116 Dist Work Mgmt O&M-LAMP Street CUSEOPCO 1 0 1 1 0 - 0 0 UTILITY & EXECUTIVE MANAGEMENT ESI F3PPD10119 Dist Work Mgmt O&M-CTS Contrac CUSTEGOP 23 3 26 22 4 - 0 4 UTILITY & EXECUTIVE MANAGEMENT ESI F3PPD10120 Dist Oper Appl O&M-AM/FM Suppo CUSTEGOP 269 32 302 260 42 - 1 42 UTILITY & EXECUTIVE MANAGEMENT ESI F3PPD10121 Dist Oper Appl O&M-AutoCAD CUSEOPCO 12 1 14 12 2 - 0 2 UTILITY & EXECUTIVE MANAGEMENT ESI F3PPD10123 Dist Oper Appl O&M-EPO&SAISO S CUSEOPCO 21 3 24 20 4 - 0 4 UTILITY & EXECUTIVE MANAGEMENT ESI F3PPD10124 Dist Oper Appl O&M-PDD/ECOS Sp CUSTEGOP 8 1 9 8 1 - 0 1 UTILITY & EXECUTIVE MANAGEMENT ESI F3PPD10128 ARCS/Itron/MV90 Support CUSTEGOP 73 9 82 71 11 - 0 12 UTILITY & EXECUTIVE MANAGEMENT ESI F3PPD10129 Billing Determinate Proc/Major CUSTEGOP 56 7 62 54 9 - 0 9 UTILITY & EXECUTIVE MANAGEMENT ESI F3PPD10130 Customer Care System Interface CUSEGXTX 98 12 109 109 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PPD10131 CIS/AIS & Core Support DIRECTTX 805 97 902 - 902 - 19 921 UTILITY & EXECUTIVE MANAGEMENT ESI F3PPD10132 Electronic Data Interchange Su CUSEOPCO 20 2 23 19 3 - 0 3 UTILITY & EXECUTIVE MANAGEMENT ESI F3PPD10133 Internet Bill Presentment & Pm CUSEGXTX 15 2 17 17 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PPD10134 MAB Load Research Support CUSTEGOP 19 2 22 19 3 - 0 3 UTILITY & EXECUTIVE MANAGEMENT ESI F3PPD10137 Bill Delivery Support CUSEGXTX 482 58 539 539 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PPD10139 Mobius Support CUSTEGOP 0 0 0 0 0 - 0 0 UTILITY & EXECUTIVE MANAGEMENT ESI F3PPD10140 Large Power Billing System for CUSEOPCO 23 3 25 22 4 - 0 4 UTILITY & EXECUTIVE MANAGEMENT ESI F3PPD10141 CIMS Support CUSEGXTX 2 0 2 2 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PPD10142 Customer Service Field Applica CUSTEGOP 11 1 12 10 2 - 0 2 UTILITY & EXECUTIVE MANAGEMENT ESI F3PPD10146 Dist Work Mgmt-Cyndrus Support VEHCLALL 8 1 9 8 1 - 0 1 UTILITY & EXECUTIVE MANAGEMENT ESI F3PPD10150 TaxWare Support CUSTEGOP 50 6 56 48 8 - 0 8 UTILITY & EXECUTIVE MANAGEMENT ESI F3PPD10158 CCS Agent Care System CUSEGXTX 46 6 52 52 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PPD10161 ePlus (Web Self Service) Suppo CUSTEGOP 146 17 163 141 22 - 0 23 UTILITY & EXECUTIVE MANAGEMENT ESI F3PPE9974S Utl ECI Continuing Improve ESI CUSEOPCO 233,026 23,604 256,630 218,728 37,902 - 387 38,289 UTILITY & EXECUTIVE MANAGEMENT ESI F3PPE9981A Integrated Energy Mgmt EAI DIRCTEAI - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PPE9981S Integrated Energy Mgmt ESI CUSEOPCO 15,986 1,847 17,834 15,206 2,628 - 8 2,636 UTILITY & EXECUTIVE MANAGEMENT ESI F3PPEGSFRP EGSI LPSC Formula Rate Plan Fi DIRECTLG 686 77 763 763 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PPELEGAS ENO Elec & ENO EGS Gas Expense CUSENLGG (9,627) (2,615) (12,242) (12,242) - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PPENOCEO ENO CEO Electric and Gas Expen DIRCTENO - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PPENOFRP ENO Annual FRP Filing 2010-12 DIRCTENO 2,739 312 3,051 3,051 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PPEPI001 Environmental Programs & Infra CAPAOPCO (179) - (179) (160) (19) - (1) (20) UTILITY & EXECUTIVE MANAGEMENT ESI F3PPETEGSL Executive Timesheets- EGSL DIRECTLG 2,215 216 2,430 2,430 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PPETENOI Executive Timesheet- ENOI DIRCTENO 61,975 1,967 63,943 63,943 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PPETRNUC Executive Timesheets- Reg Nuc DIRCTEOI 17,530 1,880 19,410 19,410 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PPETSEAI Executives Time and Expenses-E DIRCTEAI 35,047 3,609 38,656 38,656 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PPETSELI Executive Timesheets- ELI DIRCTELI 83,570 2,603 86,173 86,173 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PPETSEMI Executive Timesheets- EMI DIRCTEMI 17,613 1,500 19,113 19,113 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PPETSETI Executive Time and Expenses-ET DIRECTTX 36,090 3,510 39,601 - 39,601 - 765 40,365 UTILITY & EXECUTIVE MANAGEMENT ESI F3PPETSETR Executive Timesheets-ETR DIRCTETR 737,895 97,043 834,938 834,938 - - - - 3-50

UTILITY & EXECUTIVE MANAGEMENT ESI F3PPETSNRG Executive Timesheets- Non Reg DIRCTENU 10,307 595 10,902 10,902 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PPETSREG Executive Timesheets- Reg Co's CUSTEGOP 12,783 865 13,648 11,767 1,882 - 29 1,911 UTILITY & EXECUTIVE MANAGEMENT ESI F3PPF15115 FGA-VP/General Office CUSTEGOP 199 - 199 171 28 (28) - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PPF72700 Cognos Reporting Support GENLEDAL 22 2 24 23 1 - 0 1 UTILITY & EXECUTIVE MANAGEMENT ESI F3PPFRM127 OCRO - Bus Cont Plan Managemen LBRBILAL - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PPFX3259 Inventory Planning System Supp SCTDSPAL 34 4 38 25 12 - 0 13 UTILITY & EXECUTIVE MANAGEMENT ESI F3PPFX3685 Supply Chain Applications Supp SCMATRAN 61 7 68 58 10 - 0 10 UTILITY & EXECUTIVE MANAGEMENT ESI F3PPFX5307 Compliance Software System Sup ASSTSALL 38 5 42 38 4 - 0 4 UTILITY & EXECUTIVE MANAGEMENT ESI F3PPFXOPMO IT Enterprise Program Manageme ITSPENDA 22 2 25 23 2 - 0 2 UTILITY & EXECUTIVE MANAGEMENT ESI F3PPGRSP10 EGSL RATE STABLIZATN (TY 2009/ DIRECTLG 88 10 98 98 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PPHIPPO1 Project X DIRCTETR 34,735 5,181 39,916 39,916 - - - - Amounts may not add or tie to other schedules due to rounding. EXHIBIT JFD-B Domino, Joe Page 4 of 6 ENTERGY TEXAS, INC. EXHIBIT JFD-B 2011 ETI Rate Case

Affiliate Billings - by Witness, Class and Project 2011 TX Rate Case For the Twelve Months Ended June 30, 2011 Page 5 of 6 Amounts in Dollars (A) (B) (C) (D) (E) (F) (G) (H) Total Billings Billing Activity / Project ESI Billing Service Company ETI Per Pro Forma Total ETI Class Entity Code Activity / Project Description Method Support Recipient Total All Other BU's Books Exclusions Amount Adjusted UTILITY & EXECUTIVE MANAGEMENT ESI F3PPHRSSPC HR SVS - ESI SUPPLY CHAIN DIRCTESI 18 - 18 18 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PPHRTFMN HR Transformation - O&M Costs EMPLOYAL 91,155 9,889 101,043 96,167 4,877 - 100 4,976 UTILITY & EXECUTIVE MANAGEMENT ESI F3PPN20535 P3E Scheduling Software Mainte DIRCTEOI 162 19 182 182 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PPN20536 INDUS Software Maintenance DIRCTEOI 288 34 322 322 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PPN20713 ESI Nuclear - Site Split SNUCSITE 81,152 10,163 91,314 91,314 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PPNPM008 Wholesale C B 50/50 Split - Pi DIRNG000 - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PPNXRECR Enexus Recurring DIRECTNI (2,989) - (2,989) (2,989) - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PPPCS001 Critical Infrastructure Protec CAPAOPCO 1,644,835 151,796 1,796,631 1,602,395 194,236 - 2,391 196,626 UTILITY & EXECUTIVE MANAGEMENT ESI F3PPPGA010 PGA Audit 2010 DIRECTLG 430 50 480 480 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PPPMUPGR Performance Management Sys Upg CUSEOPCO 3 0 4 3 1 - 0 1 UTILITY & EXECUTIVE MANAGEMENT ESI F3PPRC2008 ENOI 2008 RATE CASE DIRCTENO - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PPRES001 Regulated Utility Electric Rel CUSEOPCO 1,993 223 2,216 1,889 327 - 7 333 UTILITY & EXECUTIVE MANAGEMENT ESI F3PPSCOUT1 Project Scout (VY Litigation A DIRECT72 15 - 15 15 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PPSPE003 SPO Summer 2009 RFP Expense LOADOPCO 2,871 350 3,221 2,740 481 - 10 491 UTILITY & EXECUTIVE MANAGEMENT ESI F3PPSPE042 SPO Expense ISES Purchase Opti OWNISES2 543 70 614 614 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PPTDERSD MISO Transition ALL OPCO LOADOPCO 905 111 1,016 847 169 - (169) - UTILITY & EXECUTIVE MANAGEMENT ESI F3PCTTDS38 TRANSMISSION O&M MGMT/SUPPORT TRSBLNOP - - - - - - (215,886) (215,886) UTILITY & EXECUTIVE MANAGEMENT ESI F3PPWCBEAM Wholesale Commodity Business - DIRECTXU 56,322 6,557 62,878 62,878 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PPWCBEPM Wholesale Commodity Business - DIRNG000 350 - 350 350 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PPWCBETC Wholesale Commodity Business - DIRECT66 56,322 6,557 62,879 62,879 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PPWCBNNE Wholesale Commodity Business - SENUCALL 994,973 80,212 1,075,184 1,075,184 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PPWE0292 System Planning Asset Manageme LOADOPCO 278 38 316 263 52 - 1 53 UTILITY & EXECUTIVE MANAGEMENT ESI F3PPWE0375 SAIC Designated Srv for Fossil CAPAOPCO 10 1 11 10 1 - 0 1 UTILITY & EXECUTIVE MANAGEMENT ESI F3PPWE0504 M0000 - CIP Walkdown DIRCTEMI 2,970 209 3,179 3,179 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PPWE0505 N0000 - CIP Walkdown DIRCTENO 2,404 213 2,617 2,617 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PPWE0506 A0000 - CIP Walkdown DIRCTEAI 825 - 825 825 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PPWE0507 L0000 - CIP Walkdown DIRCTELI 5,220 481 5,701 5,701 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F3PPWEOSGN General System-ENG-Tech Suppor CAPAOPCO 1,102 80 1,182 1,054 128 - 1 129 UTILITY & EXECUTIVE MANAGEMENT ESI F4PPEGS148 Mutual Assist EGSL GAS NMGC 2/ DIRECTLG 829 100 929 929 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F4PPENG134 Mutual Assist ENOI Gas NMGC 2/ DIRCTENO 966 117 1,083 1,083 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F5PCD10093 WEB DEVELOPMENT SUPPORT CUSTEGOP 15 2 17 15 2 - 0 2 UTILITY & EXECUTIVE MANAGEMENT ESI F5PCD10108 CCS REMEDY TESTING CUSEGXTX 0 0 1 1 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F5PCDG0168 GAS EMPLOYEE DEVELOPMENT PROGR CUSGOPCO 19 - 19 19 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F5PCE13601 GENERAL LITIGATION-ELI DIRCTELI 271 - 271 271 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F5PCE13751 GENERAL LITIGATION- EGSI-LA DIRECTLG 271 - 271 271 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F5PCEDIVER DIVERSITY TRAINING DIRCTESI 90 - 90 90 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F5PCF96930 BENCHMARKING PHASE II LOADWEOI 4,020 551 4,571 3,817 754 - 16 770 UTILITY & EXECUTIVE MANAGEMENT ESI F5PCLAWELL LA WELLNESS PROGRAM PILOT CUSTELLA 328 - 328 328 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F5PCLIHPPC CONSUMER EDUCATION PROGRAMS CUSEOPCO 3 - 3 3 1 - - 1 UTILITY & EXECUTIVE MANAGEMENT ESI F5PCMCMSCL PASSPORT- SC MATERIALS MANAGEM SCMATRAN 257 31 288 245 43 (43) - - UTILITY & EXECUTIVE MANAGEMENT ESI F5PCSAFTEG SAFTEY TRAINING LOADER GAS CUS CUSGOPCO 82,056 5,482 87,538 87,538 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F5PCSVCAWD SERVICE AWARDS DIRCTESI 2,504 - 2,504 2,504 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F5PCTTDS70 TRANS MAINTENANCE: LINES & SUB TRSBLNOP 475,946 54,604 530,550 468,094 62,456 4,130 1,099 67,685 UTILITY & EXECUTIVE MANAGEMENT ESI F5PCZCDEPT SUPERVISION & SUPPORT - CORPOR LBRCORPT 813 - 813 785 28 - (19) 9 UTILITY & EXECUTIVE MANAGEMENT ESI F5PCZCONOP CONTRIBUTION OPERATIONS - BELO ASSTSALL 1 0 1 1 0 - (0) - UTILITY & EXECUTIVE MANAGEMENT ESI F5PCZECDEV ECONOMIC DEVELOPMENT - BELOW T CUSEOPCO 2 0 2 1 0 - (0) - UTILITY & EXECUTIVE MANAGEMENT ESI F5PCZFCLSR VOICE & VIDEO LOCAL SERVICE TELXGENS 492 - 492 463 29 - - 29 UTILITY & EXECUTIVE MANAGEMENT ESI F5PCZFDSER DESKTOP SERVICES PCNUMALL 15 1 16 16 1 - 0 1 UTILITY & EXECUTIVE MANAGEMENT ESI F5PCZU1425 REGULATORY COORDINAT.-ELI & EG CUSELPSC 19,736 2,153 21,889 21,889 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F5PCZU1573 REGULATORY AFFAIRS -- 100% EGS DIRECTTX 11,275 - 11,275 - 11,275 - - 11,275 UTILITY & EXECUTIVE MANAGEMENT ESI F5PCZU5400 LA GOVERNMENTAL AFFAIRS-100% E DIRCTELI 185 - 185 185 - - - - 3-51

UTILITY & EXECUTIVE MANAGEMENT ESI F5PCZU5402 LOUISIANA GOVERNMENTAL AFFAIRS CUSELGLA 87,279 10,527 97,805 97,805 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F5PCZU5403 LOUISIANA GOVERNMENTAL AFFAIRS CUSTELLA 922,728 95,302 1,018,030 1,018,030 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F5PCZUSETR TRANSITION TO COMPETITION - ET DIRCTETR 79,500 - 79,500 79,500 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F5PCZUSGSL TRANS TO COMPETITION -EGSI LA- DIRECTLG 127,095 - 127,095 127,095 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F5PCZUSLPL TRANS TO COMPETITION -ELI- BEL DIRCTELI 142,455 - 142,455 142,455 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F5PCZZ0150 SHAREHOLDER/DIRECTOR EXPENSES ASSTSALL 502 - 502 451 51 - - 51 UTILITY & EXECUTIVE MANAGEMENT ESI F5PCZZ4070 IMPACT AWARDS DIRCTESI 1,614 - 1,614 1,614 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F5PCZZI04R WORKER'S COMPENSATION- RESERVE DIRCTESI 115,736 - 115,736 115,736 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F5PP10011U Show Cause Docket No. 10-011-U DIRCTEAI 78,782 - 78,782 78,782 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F5PPCIPUNC General Unclassified CIP Costs LOADOPCO 7,719 709 8,428 7,170 1,258 - 25 1,283 UTILITY & EXECUTIVE MANAGEMENT ESI F5PPD10154 MDT Wireless Telecom Serv CUSTEGOP 811 34 845 729 117 - (72) 45 Amounts may not add or tie to other schedules due to rounding. EXHIBIT JFD-B Domino, Joe Page 5 of 6 ENTERGY TEXAS, INC. EXHIBIT JFD-B 2011 ETI Rate Case

Affiliate Billings - by Witness, Class and Project 2011 TX Rate Case For the Twelve Months Ended June 30, 2011 Page 6 of 6 Amounts in Dollars (A) (B) (C) (D) (E) (F) (G) (H) Total Billings Billing Activity / Project ESI Billing Service Company ETI Per Pro Forma Total ETI Class Entity Code Activity / Project Description Method Support Recipient Total All Other BU's Books Exclusions Amount Adjusted UTILITY & EXECUTIVE MANAGEMENT ESI F5PPD10156 Dist. Work Mgmt - DriveCam Sup CUSTELLA 5 1 5 5 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F5PPD10162 Util Ops Cust Data Warehouse S CUSTEGOP 45 5 50 43 7 - 0 7 UTILITY & EXECUTIVE MANAGEMENT ESI F5PPERG100 Systemwide Ergonomics Initiati EMPLOYAL 4,970 94 5,064 4,820 244 (5) 1 240 UTILITY & EXECUTIVE MANAGEMENT ESI F5PPETX009 2009 Texas Rate Case Support DIRECTTX 148 - 148 - 148 - (148) - UTILITY & EXECUTIVE MANAGEMENT ESI F5PPFALCON Project Falcon DIRECTNI 208,516 4,160 212,676 212,676 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F5PPGEFBUS Gas Operations Efficient Busin CUSGOPCO 45,084 5,479 50,562 50,562 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F5PPHREXEC HR Executive Financial Counsel ASSTSALL 46,517 - 46,517 41,790 4,727 - (4,727) - UTILITY & EXECUTIVE MANAGEMENT ESI F5PPLRSOLT System Officer Labor Team EMPLOYAL 2,871 282 3,153 2,998 155 - 3 158 UTILITY & EXECUTIVE MANAGEMENT ESI F5PPORGSSP ESI Direct Enexus Org Costs DIRECTNI - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F5PPSAFTEL SAFETY TRAINING LOADER ELEC LA CUSTELLA 698 78 776 776 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F5PPSPE044 PMO Support Initiative-System- LOADOPCO 1,454 167 1,621 1,352 269 - (269) - UTILITY & EXECUTIVE MANAGEMENT ESI F5PPSUPICT Support of ICT LOADOPCO - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F5PPTHMPSN Norwood Thompson Park Playgrou DIRCTETR 3,514 465 3,980 3,980 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F5PPTRISTE Project Blue DIRCTETR - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F5PPTVPPRO Voluntary Protection Program TRSBLNOP 698 78 776 685 91 - 2 93 UTILITY & EXECUTIVE MANAGEMENT ESI F5PPZCONAR EAI Contributions - BELOW THE DIRCTEAI 54,405 - 54,405 54,405 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F5PPZCONLA ELI Contributions - BELOW THE DIRCTELI 39,524 - 39,524 39,524 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F5PPZCONLS EGSI-LA Contrib - BELOW THE LI DIRECTLG 32,595 - 32,595 32,595 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F5PPZCONMS EMI Contributions - BELOW THE DIRCTEMI 39,120 - 39,120 39,120 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F5PPZCONNO ENOI Contributions - BELOW THE DIRCTENO 19,456 - 19,456 19,456 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI F5PPZCONTG EGSI-TX Contrib - BELOW THE LI DIRECTTX 23,251 - 23,251 - 23,251 (23,251) - - UTILITY & EXECUTIVE MANAGEMENT ESI F5PPZUWELL Entergy Wellness Program EMPLOYAL 3,503 346 3,849 3,660 189 - (44) 145 UTILITY & EXECUTIVE MANAGEMENT ESI SAPCP25910 PC&R OVERHEAD POOL CHARGES CEAOUTAL 0 - 0 0 0 (0) - - UTILITY & EXECUTIVE MANAGEMENT ESI SDPCT30070 CAPITAL SUSPENSE, DISTR WIRES, DIRCTELI 676 75 751 751 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SGPCG59006 GAS DISTRIBUTION ENOI O/H GAS DIRCTENO 713,582 85,639 799,221 799,221 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SGPCR79008 GAS DISTRIBUTION EGSI O/H-CHAR DIRECTLG 452,571 54,724 507,296 507,296 - - - - UTILITY & EXECUTIVE MANAGEMENT Total ESI 28,688,315 2,014,250 30,702,565 28,491,933 2,210,631 (39,503) (231,900) 1,939,228 Total UTILITY & EXECUTIVE MANAGEMENT 28,688,315 2,014,250 30,702,565 28,491,933 2,210,631 (39,503) (231,900) 1,939,228 Total Domino, Joe 28,688,315 2,014,250 30,702,565 28,491,933 2,210,631 (39,503) (231,900) 1,939,228 3-52

Amounts may not add or tie to other schedules due to rounding. EXHIBIT JFD-B Domino, Joe Page 6 of 6 ENTERGY TEXAS, INC. EXHIBIT JFD-C 2011 ETI Rate Case

Affiliate Billings - by Witness, Class, Department and Project 2011 TX Rate Case For the Twelve Months Ended June 30, 2011 Page 1 of 11 Amounts in Dollars (A) (B) (C) (D) (E) (F) (G) (H) Total Billings Activity / Project ESI BIlling Service Company ETI Per Pro Forma Total ETI Class Billing Entity Dept Code Activity / Project Description Method Support Recipient Total All Other BU's Books Exclusions Amount Adjusted UTILITY & EXECUTIVE MANAGEMENT ESI CE122 C1PPSP0008 SPO ELL&ENOI Purchase Option I OWNISES2 - (2) (2) (2) - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CE122 C6PCN32144 GRAND GULF EXTENDED POWER UPRA DIRCTSER 796 96 892 892 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CE122 C6PPSP0012 SPO Project Gator Transact/Tra DIRCTELI 834 95 928 928 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CE122 C6PPWS0534 System Planning Pet Coke Repow DIRCTELI 274 31 305 305 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CE122 F3PCCSPUTI SYSTEM PLANNING & STRATEGIC AD LOADOPCO 10,566 1,170 11,736 9,984 1,752 - 37 1,789 UTILITY & EXECUTIVE MANAGEMENT ESI CE122 F3PCE99750 PRES- ENT. LA-GEN'L OPS-ELI/EG CUSELGLA 1,086,097 67,986 1,154,084 1,154,084 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CE122 F3PCE99751 SPECIAL PROJECTS - LA STATE PR CUSELGLA 71 - 71 71 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CE122 F3PCF07300 CORP PLANNING & ANALYSIS- REGU CUSTEGOP 3,054 356 3,410 2,940 470 - 10 480 UTILITY & EXECUTIVE MANAGEMENT ESI CE122 F3PCF21600 CORP RPTG ANALYSIS & POLICY AL GENLEDAL 4,616 418 5,035 4,717 317 - 7 324 UTILITY & EXECUTIVE MANAGEMENT ESI CE122 F3PCF23033 GENERAL ACCOUNTING - ESI LVLSVCAL 977 135 1,112 1,007 105 - 2 107 UTILITY & EXECUTIVE MANAGEMENT ESI CE122 F3PCF23920 CORP REPORTING ANALYSIS & POLI DIRCTELI 32,744 3,899 36,643 36,643 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CE122 F3PCF239LA CORP RPTNG ANALYSIS/POLICY EGS DIRECTLG 32,690 3,893 36,583 36,583 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CE122 F3PCFACALL FACILITIES SVCS- ALL COS SQFTALLC 1,019 - 1,019 905 113 - - 113 UTILITY & EXECUTIVE MANAGEMENT ESI CE122 F3PCSYSAGR SYSTEM AGREEMENT-2001 CUSEOPCO 823 96 919 783 135 - 4 140 UTILITY & EXECUTIVE MANAGEMENT ESI CE122 F3PCTBLLPL BELOW THE LINE - LPL DIRCTELI - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CE122 F3PCWE0135 NEL. 6 JOINT OWNERSHIP PART. A DIRECTLG 964 108 1,072 1,072 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CE122 F3PCZU1603 LP&L/LPSC EARNINGS REVIEW; DOC DIRCTELI 2,335 298 2,633 2,633 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CE122 F3PPEGSFRP EGSI LPSC Formula Rate Plan Fi DIRECTLG 686 77 763 763 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CE122 F3PPSPE003 SPO Summer 2009 RFP Expense LOADOPCO 2,871 350 3,221 2,740 481 - 10 491 UTILITY & EXECUTIVE MANAGEMENT ESI CE122 F3PPSPE042 SPO Expense ISES Purchase Opti OWNISES2 543 70 614 614 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CE122 F3PPWE0292 System Planning Asset Manageme LOADOPCO 278 38 316 263 52 - 1 53 UTILITY & EXECUTIVE MANAGEMENT ESI CE122 F5PCE13601 GENERAL LITIGATION-ELI DIRCTELI 271 - 271 271 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CE122 F5PCE13751 GENERAL LITIGATION- EGSI-LA DIRECTLG 271 - 271 271 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CE122 F5PCLAWELL LA WELLNESS PROGRAM PILOT CUSTELLA 328 - 328 328 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CE122 F5PCZCDEPT SUPERVISION & SUPPORT - CORPOR LBRCORPT 2 - 2 2 0 - - 0 UTILITY & EXECUTIVE MANAGEMENT ESI CE122 F5PCZFCLSR VOICE & VIDEO LOCAL SERVICE TELXGENS 492 - 492 463 29 - - 29 UTILITY & EXECUTIVE MANAGEMENT ESI CE122 F5PCZU1425 REGULATORY COORDINAT.-ELI & EG CUSELPSC 19,736 2,153 21,889 21,889 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CE122 F5PCZUSETR TRANSITION TO COMPETITION - ET DIRCTETR 79,500 - 79,500 79,500 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CE122 F5PPHREXEC HR Executive Financial Counsel ASSTSALL 5,979 - 5,979 5,371 607 - (607) - UTILITY & EXECUTIVE MANAGEMENT ESI CE122 F5PPZUWELL Entergy Wellness Program EMPLOYAL 439 45 484 460 24 - 0 24 UTILITY & EXECUTIVE MANAGEMENT ESI CE122 Total 1,289,256 81,310 1,370,566 1,366,479 4,086 - (536) 3,551 UTILITY & EXECUTIVE MANAGEMENT ESI CE12F F3PPELEGAS ENO Elec & ENO EGS Gas Expense CUSENLGG (19,654) - (19,654) (19,654) - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CE12F F3PPENOCEO ENO CEO Electric and Gas Expen DIRCTENO - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CE12F F3PPRC2008 ENOI 2008 RATE CASE DIRCTENO - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CE12F F5PCSVCAWD SERVICE AWARDS DIRCTESI - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CE12F F5PPERG100 Systemwide Ergonomics Initiati EMPLOYAL - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CE12F F5PPHREXEC HR Executive Financial Counsel ASSTSALL - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CE12F F5PPZUWELL Entergy Wellness Program EMPLOYAL - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CE12F Total (19,654) - (19,654) (19,654) - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CE179 F3PCE14420 REGULATORY AFFAIRS - EAI DIRCTEAI 26 - 26 26 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CE179 F3PCFACALL FACILITIES SVCS- ALL COS SQFTALLC 686 - 686 613 73 (73) - - UTILITY & EXECUTIVE MANAGEMENT ESI CE179 F3PCTTDS46 DISTRIBUTION O&M EXP - METRO E CUSEMETR 159 - 159 159 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CE179 F3PCTTDS47 DISTR O&M EXPENSE - LOUISIANA CUSTELLA 943 - 943 943 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CE179 F5PCSVCAWD SERVICE AWARDS DIRCTESI 42 - 42 42 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CE179 F5PCZU5400 LA GOVERNMENTAL AFFAIRS-100% E DIRCTELI 185 - 185 185 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CE179 F5PCZU5402 LOUISIANA GOVERNMENTAL AFFAIRS CUSELGLA 87,279 10,527 97,805 97,805 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CE179 F5PCZU5403 LOUISIANA GOVERNMENTAL AFFAIRS CUSTELLA 922,728 95,302 1,018,030 1,018,030 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CE179 F5PCZUSGSL TRANS TO COMPETITION -EGSI LA- DIRECTLG 127,095 - 127,095 127,095 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CE179 F5PCZUSLPL TRANS TO COMPETITION -ELI- BEL DIRCTELI 142,455 - 142,455 142,455 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CE179 F5PPERG100 Systemwide Ergonomics Initiati EMPLOYAL 93 8 101 96 5 (5) - - 3-53

UTILITY & EXECUTIVE MANAGEMENT ESI CE179 Total 1,281,690 105,837 1,387,527 1,387,448 78 (78) - - UTILITY & EXECUTIVE MANAGEMENT ESI CP015 F5PPZCONAR EAI Contributions - BELOW THE DIRCTEAI 54,405 - 54,405 54,405 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CP015 F5PPZCONLA ELI Contributions - BELOW THE DIRCTELI 39,524 - 39,524 39,524 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CP015 F5PPZCONLS EGSI-LA Contrib - BELOW THE LI DIRECTLG 32,595 - 32,595 32,595 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CP015 F5PPZCONMS EMI Contributions - BELOW THE DIRCTEMI 39,120 - 39,120 39,120 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CP015 F5PPZCONNO ENOI Contributions - BELOW THE DIRCTENO 19,456 - 19,456 19,456 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CP015 F5PPZCONTG EGSI-TX Contrib - BELOW THE LI DIRECTTX 23,251 - 23,251 - 23,251 (23,251) - - UTILITY & EXECUTIVE MANAGEMENT ESI CP015 Total 208,351 - 208,351 185,100 23,251 (23,251) - -

Amounts may not add or tie to other schedules due to rounding.

EXHIBIT JFD-C Domino, Joe Page 1 of 11 ENTERGY TEXAS, INC. EXHIBIT JFD-C 2011 ETI Rate Case

Affiliate Billings - by Witness, Class, Department and Project 2011 TX Rate Case For the Twelve Months Ended June 30, 2011 Page 2 of 11 Amounts in Dollars (A) (B) (C) (D) (E) (F) (G) (H) Total Billings Activity / Project ESI BIlling Service Company ETI Per Pro Forma Total ETI Class Billing Entity Dept Code Activity / Project Description Method Support Recipient Total All Other BU's Books Exclusions Amount Adjusted UTILITY & EXECUTIVE MANAGEMENT ESI CP027 F5PCZCDEPT SUPERVISION & SUPPORT - CORPOR LBRCORPT - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CP027 Total - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CP040 F3PCC14900 EXPENSES-CHAIRMAN ENTERGY DIRCTETR 448,364 56,234 504,599 504,599 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CP040 F3PCC31255 OPERATIONS-OFFICE OF THE CEO ASSTSALL 3,036,304 193,032 3,229,335 2,909,321 320,015 (645) (4,828) 314,542 UTILITY & EXECUTIVE MANAGEMENT ESI CP040 F3PCC31256 LEADERSHIP CONFERENCE EMPLOYAL 186,861 - 186,861 178,151 8,711 - - 8,711 UTILITY & EXECUTIVE MANAGEMENT ESI CP040 F3PCC31257 EVENTS ADMINISTRATION DIRCTETR 814,340 - 814,340 814,340 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CP040 F3PCCE0155 BELOW THE LINE-C ENVIRONMENTAL CAPAOPCO - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CP040 F3PCCEP001 CORPORATE ENVIRONMENTAL POLICY CAPAOPCO - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CP040 F3PCE14987 FGA-Climate/Environmental ASSTSALL 47,580 - 47,580 42,787 4,793 (4,793) - - UTILITY & EXECUTIVE MANAGEMENT ESI CP040 F3PCE99750 PRES- ENT. LA-GEN'L OPS-ELI/EG CUSELGLA 28,711 2,769 31,480 31,480 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CP040 F3PCF22511 IR - GENERAL, INQUIRIES & MAIL DIRCTETR 404 - 404 404 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CP040 F3PCF22514 MEETINGS ANALYSTS/INVESTORS/SH DIRCTETR 5,306 - 5,306 5,306 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CP040 F3PCFACALL FACILITIES SVCS- ALL COS SQFTALLC 359 29 388 343 45 - 1 46 UTILITY & EXECUTIVE MANAGEMENT ESI CP040 F3PCFEXETR EXECUTIVE ADVISORY SERVICES - DIRCTETR 22,703 2,858 25,562 25,562 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CP040 F3PCH60959 EXECUTIVE FACILITIES SERVICES DIRCTETR 348 - 348 348 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CP040 F3PCHRSALL HR SERVICES- ALL COMPANIES EMPLOYAL 85,865 8,419 94,283 89,655 4,628 - 96 4,724 UTILITY & EXECUTIVE MANAGEMENT ESI CP040 F3PCR40085 ENTERGY CORPORATION COMMUNICAT DIRCTETR 10,500 - 10,500 10,500 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CP040 F3PP1E2EPM End-to-End Process Mgmnt LVLSVCAL 3,230 407 3,637 3,291 347 - 7 354 UTILITY & EXECUTIVE MANAGEMENT ESI CP040 F3PPBLANCO Project White DIRCTETR 38,891 5,003 43,894 43,894 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CP040 F3PPC31258 CEO MEETINGS WITH EMPLOYEES EMPLOYAL 350 - 350 334 16 - - 16 UTILITY & EXECUTIVE MANAGEMENT ESI CP040 F3PPCAO001 Chief Administrative Officer ASSTSALL 11,990 - 11,990 10,770 1,220 - (1,048) 172 UTILITY & EXECUTIVE MANAGEMENT ESI CP040 F3PPETENOI Executive Timesheet- ENOI DIRCTENO 5,995 - 5,995 5,995 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CP040 F3PPETSELI Executive Timesheets- ELI DIRCTELI 5,995 - 5,995 5,995 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CP040 F3PPETSETI Executive Time and Expenses-ET DIRECTTX 6,980 641 7,621 - 7,621 - 164 7,785 UTILITY & EXECUTIVE MANAGEMENT ESI CP040 F3PPETSETR Executive Timesheets-ETR DIRCTETR 408,416 55,057 463,472 463,472 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CP040 F3PPHIPPO1 Project X DIRCTETR 34,735 5,181 39,916 39,916 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CP040 F3PPHRTFMN HR Transformation - O&M Costs EMPLOYAL 32,084 3,203 35,288 33,559 1,728 - 36 1,764 UTILITY & EXECUTIVE MANAGEMENT ESI CP040 F5PCZCDEPT SUPERVISION & SUPPORT - CORPOR LBRCORPT 190 - 190 184 6 - - 6 UTILITY & EXECUTIVE MANAGEMENT ESI CP040 F5PCZCONOP CONTRIBUTION OPERATIONS - BELO ASSTSALL - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CP040 F5PCZZ0150 SHAREHOLDER/DIRECTOR EXPENSES ASSTSALL 502 - 502 451 51 - - 51 UTILITY & EXECUTIVE MANAGEMENT ESI CP040 F5PCZZI04R WORKER'S COMPENSATION- RESERVE DIRCTESI 115,736 - 115,736 115,736 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CP040 F5PPFALCON Project Falcon DIRECTNI 30,097 4,160 34,257 34,257 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CP040 F5PPHREXEC HR Executive Financial Counsel ASSTSALL 15,000 - 15,000 13,474 1,526 - (1,526) - UTILITY & EXECUTIVE MANAGEMENT ESI CP040 F5PPLRSOLT System Officer Labor Team EMPLOYAL 2,871 282 3,153 2,998 155 - 3 158 UTILITY & EXECUTIVE MANAGEMENT ESI CP040 F5PPZUWELL Entergy Wellness Program EMPLOYAL (61) - (61) (58) (3) - (0) (3) UTILITY & EXECUTIVE MANAGEMENT ESI CP040 Total 5,400,646 337,276 5,737,922 5,387,064 350,858 (5,438) (7,095) 338,326 UTILITY & EXECUTIVE MANAGEMENT ESI CP050 E1PPNXCRP1 Unwind - Employee DIRECTNI 21,844 3,253 25,096 25,096 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CP050 F3PC6H0026 NORTHEAST MGMT OVERSITE IP2/IP SPL77N7A 24,988 - 24,988 24,988 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CP050 F3PC6HENNE ENN EQUAL SPLIT DIRCTENU 588 - 588 588 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CP050 F3PCR93300 NORTHEAST NONREG NUCLEAR EXTRN DIRCTENU - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CP050 F3PP4R9886 TRITIUM DETECTION INVESTIGATIO DIRECT72 - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CP050 F3PPCOO001 CHIEF OPERATING OFFICER ASSTSALL 11,998 - 11,998 10,777 1,221 - (712) 509 UTILITY & EXECUTIVE MANAGEMENT ESI CP050 F3PPF15115 FGA-VP/General Office CUSTEGOP 199 - 199 171 28 (28) - - UTILITY & EXECUTIVE MANAGEMENT ESI CP050 F3PPN20713 ESI Nuclear - Site Split SNUCSITE 981 - 981 981 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CP050 F3PPNPM008 Wholesale C B 50/50 Split - Pi DIRNG000 - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CP050 F3PPNXRECR Enexus Recurring DIRECTNI (2,989) - (2,989) (2,989) - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CP050 F3PPSCOUT1 Project Scout (VY Litigation A DIRECT72 15 - 15 15 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CP050 F3PPWCBEAM Wholesale Commodity Business - DIRECTXU 56,322 6,557 62,878 62,878 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CP050 F3PPWCBEPM Wholesale Commodity Business - DIRNG000 350 - 350 350 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CP050 F3PPWCBETC Wholesale Commodity Business - DIRECT66 56,322 6,557 62,879 62,879 - - - - 3-54

UTILITY & EXECUTIVE MANAGEMENT ESI CP050 F3PPWCBNNE Wholesale Commodity Business - SENUCALL 994,973 80,212 1,075,184 1,075,184 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CP050 F5PCZCDEPT SUPERVISION & SUPPORT - CORPOR LBRCORPT - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CP050 F5PPFALCON Project Falcon DIRECTNI 178,778 - 178,778 178,778 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CP050 F5PPHREXEC HR Executive Financial Counsel ASSTSALL 3,400 - 3,400 3,054 346 - (346) - UTILITY & EXECUTIVE MANAGEMENT ESI CP050 F5PPORGSSP ESI Direct Enexus Org Costs DIRECTNI - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CP050 F5PPTRISTE Project Blue DIRCTETR - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CP050 Total 1,347,769 96,578 1,444,347 1,442,753 1,594 (28) (1,058) 509 UTILITY & EXECUTIVE MANAGEMENT ESI CP083 C7PPSJ1244 STORM DL ARK DIST EAI 1/7/11 I DIRCTEAI 98 13 111 111 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CP083 C7PPSJ2462 STORM DMG LA DIST ELL 1/8/11 I DIRCTELI 1,422 231 1,654 1,654 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CP083 C7PPSJ3198 EMI Storm Distr Ops 1/7/11Wint DIRCTEMI 1,062 144 1,206 1,206 - - - - Amounts may not add or tie to other schedules due to rounding.

EXHIBIT JFD-C Domino, Joe Page 2 of 11 ENTERGY TEXAS, INC. EXHIBIT JFD-C 2011 ETI Rate Case

Affiliate Billings - by Witness, Class, Department and Project 2011 TX Rate Case For the Twelve Months Ended June 30, 2011 Page 3 of 11 Amounts in Dollars (A) (B) (C) (D) (E) (F) (G) (H) Total Billings Activity / Project ESI BIlling Service Company ETI Per Pro Forma Total ETI Class Billing Entity Dept Code Activity / Project Description Method Support Recipient Total All Other BU's Books Exclusions Amount Adjusted UTILITY & EXECUTIVE MANAGEMENT ESI CP083 E2PPLG11DA Logistics Jan 2011 DIST Ark DIRCTEAI 0 (2) (2) (2) - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CP083 E2PPLG11DL Logistics Jan 2011 DIST ELL DIRCTELI 0 (15) (15) (15) - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CP083 E2PPLG11DM Logistics Jan 2011 DIST Miss DIRCTEMI 0 (25) (25) (25) - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CP083 E2PPLG11TL Logistics Jan 2011 TRN ELL DIRCTELI - (0) (0) (0) - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CP083 E2PPLG11TM Logistics Jan 2011 TRN Miss DIRCTEMI - (1) (1) (1) - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CP083 E2PPSJ2447 T-Grid Storm O&M ELL 1/7/201 I DIRCTELI 11 2 13 13 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CP083 E2PPSJ3188 T-Grid Storm Damage EMI 1/7/11 DIRCTEMI 28 4 31 31 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CP083 F3PCE99741 Utl Ops ECI & 6-Sigma Improve CUSEOPCO 249 - 249 212 37 - - 37 UTILITY & EXECUTIVE MANAGEMENT ESI CP083 F3PPE9974S Utl ECI Continuing Improve ESI CUSEOPCO 221,118 23,536 244,654 208,517 36,137 - 479 36,615 UTILITY & EXECUTIVE MANAGEMENT ESI CP083 Total 223,988 23,886 247,874 211,700 36,173 - 479 36,652 UTILITY & EXECUTIVE MANAGEMENT ESI CPCA5 F3PCFACALL FACILITIES SVCS- ALL COS SQFTALLC 2,881 254 3,135 2,784 350 - 7 357 UTILITY & EXECUTIVE MANAGEMENT ESI CPCA5 F3PCFEXETR EXECUTIVE ADVISORY SERVICES - DIRCTETR 21,917 2,963 24,880 24,880 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CPCA5 F3PCHRSALL HR SERVICES- ALL COMPANIES EMPLOYAL 230,926 25,032 255,958 243,721 12,238 - (168) 12,069 UTILITY & EXECUTIVE MANAGEMENT ESI CPCA5 F3PPETSETR Executive Timesheets-ETR DIRCTETR 8,835 1,266 10,101 10,101 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CPCA5 F3PPHRTFMN HR Transformation - O&M Costs EMPLOYAL 58,251 6,624 64,875 61,770 3,105 - 63 3,168 UTILITY & EXECUTIVE MANAGEMENT ESI CPCA5 Total 322,809 36,140 358,949 343,256 15,693 - (98) 15,595 UTILITY & EXECUTIVE MANAGEMENT ESI CPCAO F3PPCAO001 Chief Administrative Officer ASSTSALL 1,419,507 145,499 1,565,006 1,410,828 154,178 (769) (5,851) 147,559 UTILITY & EXECUTIVE MANAGEMENT ESI CPCAO F3PPELEGAS ENO Elec & ENO EGS Gas Expense CUSENLGG 10,027 (2,615) 7,412 7,412 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CPCAO F5PCSVCAWD SERVICE AWARDS DIRCTESI 171 - 171 171 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CPCAO F5PPERG100 Systemwide Ergonomics Initiati EMPLOYAL 325 - 325 309 16 - - 16 UTILITY & EXECUTIVE MANAGEMENT ESI CPCAO F5PPHREXEC HR Executive Financial Counsel ASSTSALL 4,308 - 4,308 3,871 437 - (437) - UTILITY & EXECUTIVE MANAGEMENT ESI CPCAO Total 1,434,339 142,884 1,577,223 1,422,591 154,631 (769) (6,288) 147,574 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP7 C6PPWGP516 SBC CIP Compliance DIRECTTX 12,289 1,679 13,968 - 13,968 (13,968) - - UTILITY & EXECUTIVE MANAGEMENT ESI CPOP7 F3PCT54052 Trans Regulatory Support/Polic TRSBLNOP 9,442 868 10,310 9,099 1,211 - 24 1,235 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP7 F3PCW29608 TRANSMISSION POWER SYSTEM OPER LOADOPCO 6,950 639 7,589 6,456 1,133 - 22 1,155 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP7 F3PPPCS001 Critical Infrastructure Protec CAPAOPCO 1,639,281 151,034 1,790,314 1,596,762 193,553 - 2,377 195,930 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP7 F3PPWE0504 M0000 - CIP Walkdown DIRCTEMI 2,970 209 3,179 3,179 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CPOP7 F3PPWE0505 N0000 - CIP Walkdown DIRCTENO 2,404 213 2,617 2,617 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CPOP7 F3PPWE0506 A0000 - CIP Walkdown DIRCTEAI 825 - 825 825 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CPOP7 F3PPWE0507 L0000 - CIP Walkdown DIRCTELI 5,220 481 5,701 5,701 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CPOP7 F3PPWEOSGN General System-ENG-Tech Suppor CAPAOPCO 598 - 598 533 65 - - 65 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP7 F5PCEDIVER DIVERSITY TRAINING DIRCTESI 90 - 90 90 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CPOP7 F5PCSVCAWD SERVICE AWARDS DIRCTESI 78 - 78 78 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CPOP7 F5PCZZ4070 IMPACT AWARDS DIRCTESI 1,399 - 1,399 1,399 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CPOP7 F5PPCIPUNC General Unclassified CIP Costs LOADOPCO 7,719 709 8,428 7,170 1,258 - 25 1,283 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP7 F5PPZUWELL Entergy Wellness Program EMPLOYAL 177 18 194 185 10 - 0 10 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP7 Total 1,689,442 155,849 1,845,292 1,634,094 211,197 (13,968) 2,448 199,678 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 C1PPFI5207 Payroll Time & Labor - Phase I EMPLOYAL (24) (2) (27) (26) (1) 0 1 - UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 C1PPHR8800 PS HCM (Human Cap Mgmt) Upgrd EMPLOYAL (9) (1) (10) (10) (0) 0 0 - UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 C6PPAMBSGN AMI:BASE Non-Incremental, EGSL DIRECTLG (53) (7) (60) (60) - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 C6PPWS0783 Ninemile 6 Development DIRCTELI 8,423 1,072 9,495 9,495 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 E1PCD10064 DISTR WK MGMT-SUBST AOR/COS/SF CUSEOPCO 1 0 1 1 0 - 0 0 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCC08500 Executive VP, Operations ASSTSALL 17,701 951 18,652 16,787 1,864 - (96) 1,768 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCC31257 EVENTS ADMINISTRATION DIRCTETR 11,990 - 11,990 11,990 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCCEP001 CORPORATE ENVIRONMENTAL POLICY CAPAOPCO 2,196,785 - 2,196,785 1,959,288 237,496 - - 237,496 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCCPM001 CORPORATE PERFORMANCE MANAGEME ASSTSALL 2,768 372 3,140 2,824 316 - 7 323 3-55

UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCCSE060 SAFETY & ENVIRONMENTAL SUPPORT EMPLOYAL 747 62 810 770 40 - 1 41 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCCSPUTI SYSTEM PLANNING & STRATEGIC AD LOADOPCO 17,102 2,200 19,302 16,340 2,962 - 61 3,022 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCD10006 FIELD DEVELOPMENT CUSTEGOP 6 1 7 6 1 - 0 1 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCD10010 PROGRAM MANAGEMENT - O&M CUSTEGOP 9 1 10 8 1 - 0 1 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCD10033 SSS PRELIMINARY PLANNING, SCOP CUSTEGOP 0 0 0 0 0 - 0 0 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCD10049 REGULATED RETAIL SYSTEMS - O&M CUSTEGOP 25 3 28 24 4 - 0 4 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCD10077 REGULATORY AFFAIRS WORLDOX IMP DIRCTENO 4 1 5 5 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCD10105 CUSTOMER CARE SYSTEM SUPPORT CUSEGXTX 83 10 93 93 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCE13100 GEN CORP. LEGAL ENTERGY CORP. DIRCTETR 3,792 552 4,344 4,344 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCE13321 ESI GENERAL LEGAL ADVICE LVLSVCAL 3,792 552 4,344 3,931 413 - 8 421 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCF07300 CORP PLANNING & ANALYSIS- REGU CUSTEGOP 6,572 804 7,376 6,359 1,017 - 21 1,038 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCF10414 ESI TAX SERVICES LVLSVCAL 24 3 27 24 3 - 0 3 Amounts may not add or tie to other schedules due to rounding.

EXHIBIT JFD-C Domino, Joe Page 3 of 11 ENTERGY TEXAS, INC. EXHIBIT JFD-C 2011 ETI Rate Case

Affiliate Billings - by Witness, Class, Department and Project 2011 TX Rate Case For the Twelve Months Ended June 30, 2011 Page 4 of 11 Amounts in Dollars (A) (B) (C) (D) (E) (F) (G) (H) Total Billings Activity / Project ESI BIlling Service Company ETI Per Pro Forma Total ETI Class Billing Entity Dept Code Activity / Project Description Method Support Recipient Total All Other BU's Books Exclusions Amount Adjusted UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCF10445 ENTERGY CONSOLIDATED TAX SERVI ASSTSALL 2 0 2 2 0 - 0 0 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCF15260 IT - BUSINESS & PROJECT SUPPOR CAPAOPCO 5 1 5 5 1 - 0 1 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCF23425 ACCOUNTS PAYABLE PROCESSING APTRNALL 190 17 207 188 19 - 0 19 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCF23428 TREASURY SYSTEMS BNKACCTA 69 8 77 75 2 - 0 2 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCF23442 PAYROLL PROCESSING PRCHKALL 89 8 98 93 5 - 0 5 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCF24910 PROPERTY ACCOUNTING- FIXED ASS ASSTLOCA 59 7 67 60 7 - 0 7 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCF26910 REVENUE ACCOUNTING ANALYSIS CUSEGALL 40 5 45 38 6 - 0 6 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCF72271 DATA WAREHOUSE GENLEDAL 67 6 74 69 4 - 0 4 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCF72670 GENERAL ACCOUNTING SYSTEM MAIN GENLEDAL 823 76 899 847 52 - 1 53 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCF72901 MOBILE DATA TERMINAL BASELOAD CUSTEGOP 5 1 6 5 1 - 0 1 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCF73027 BUDGET SYSTEM MAINTENANCE GENLEDAL 153 14 168 158 10 - 0 10 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCF73901 AM/FM BASELOAD (SUPPORT) DIRECTTX 3 0 3 - 3 - 0 3 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCF74195 TRANSMISSION APPLICATION SUPPO TRSBLNOP 161 19 180 159 21 - 0 22 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCF74341 ISB MAINT LOADWEPI 5 1 5 5 1 - 0 1 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCF74344 GENERATION PLANNING & DISPATCH LOADOPCO 20 2 22 19 3 - 0 3 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCF74515 FOSSIL MAINTENANCE MANAGEMENT CAPAOPCO 40 5 45 40 5 - 0 5 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCF74585 FOSSIL APPLICATION SUPPORT CAPAOPCO 43 5 48 42 5 - 0 5 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCF99182 RECORDS MANAGEMENT RECDMGNT 11 1 12 10 1 - 0 1 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCFCPO01 CHIEF PROCUREMENT OFFICER SCPSPALL 8,175 980 9,155 8,049 1,106 - 23 1,128 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCFCQEAI ENTERPRISE APPLICATION INTEGRA APPSUPAL 292 32 323 274 49 - 1 50 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCFCQEXC EXCHANGE PCNUMALL 312 26 338 325 13 - 0 14 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCFCQMVS MAINFRAME APPSMVSX - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCFCQNTS NT SERVERS APPSWINT - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCFCQUNX UNIX SERVERS APPSUNIX - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCFX2770 HR SERVICE CENTER SUPPORT EMPLOYAL - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCFX2815 EDMS PRODUCT LINE SUPPORT EMPLOYAL 60 6 66 63 3 - 0 3 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCFX2850 SECRETARIAT LEGAL SUPPORT ASSTSALL 4 0 5 4 1 - 0 1 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCFX3265 POWERBUILDER FRAMEWORK BASELOA APPSUPAL 5 0 5 4 1 - 0 1 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCFX3275 WEB INFRASTRUCTURE MAINTENANCE PCNUMALL 9 1 10 9 0 - 0 0 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCFX3290 IT BUSINESS PLANNING AND GOVER ITSPENDA 3,818 470 4,288 4,002 285 - 6 291 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCFX3350 A/R & BILLING SUPPORT ARTRNALL 72 8 80 71 9 - 0 9 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCFX3355 Property Software Support GENLEDAL 3 0 3 3 0 - 0 0 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCFX3450 CORPORATE REPORTING SYSTEM SUP GENLEDAL 0 - 0 0 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCFX3620 MMIS MATERIALS MAINT MGMNT INF DIRCTESI 0 - 0 0 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCFX3625 SUPPLY CHAIN - CDW SYSTEMS SUP SCDSPALL 4 0 4 3 2 - 0 2 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCFX3640 WHITE AMBER & ITILITI SUPPORT SCMATRAN - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCFX3650 WEB PAGE SUPPORT - CORPORATE EMPLOYAL 1 0 1 1 0 - 0 0 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCFX3670 CORPORATE COMMUNICATIONS WEB S DIRCTETR 4 0 4 4 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCFX3675 BARCODING SYSTEMS SUPPORT SCDSPALL 2 0 2 1 1 - 0 1 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCFX3690 PEARL SUPPORT APTRNALL 1 0 1 1 0 - 0 0 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCFX3695 ATPR SUPPORT APTRNALL 61 6 67 61 6 - 0 6 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCFX3785 ORG, JES, BATS, ACBM SUPPORT GENLEDAL 0 - 0 0 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCFX3790 ESTER SUPPORT PRCHKALL 95 9 104 99 5 - 0 5 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCFX5555 DATA WAREHOUSE TOOLS SUPPORT APPSUPAL 25 3 28 24 4 - 0 4 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCHRFOSS HR FOSSIL SUPPORT- ALL COS EMPLOFOS 537 - 537 488 48 - - 48 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCHRSALL HR SERVICES- ALL COMPANIES EMPLOYAL 326 31 357 339 17 - 0 18 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCHRTRAN HUMAN RESOURCE SVCS - TRANSMIS EMPLTRAN 115 - 115 106 9 - - 9 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCMCMSOM MATERIALS & CONTRACTS MGTMT SY SCMATXNU - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCN20520 WORK MANAGEMENT SYSTEM (WMS) M DIRCTEOI 25 3 28 28 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCN20521 IDEAS MAINTENANCE DIRCTEOI 76 9 86 86 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCN20522 PCRS MAINTENANCE DIRCTEOI 133 16 149 149 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCN20527 NUCLEAR IT QUICK RESPONSE TEAM DIRCTEOI 44 5 49 49 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCN20528 ERD SUPPORT (MAINTENANCE) DIRCTEOI 617 74 691 691 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCN20858 NUCLEAR IT QUICK RESPONSE TEAM DIRCTEOI 2 0 3 3 - - - - 3-56

UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCR40500 EMPLOYEE COMM (REG + UNREG COM EMPLOYAL 4 0 5 5 0 - 0 0 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCR53095 HEADQUARTER'S CREDIT & COLLECT CUSTEGOP 0 - 0 0 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCR53291 ESI REMITTANCE PROCESSING CUSEOPCO 151 18 170 145 25 - 1 26 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCR73326 CUSTOMER SERVICE CENTER SUPPOR CUSTCALL 130 16 146 130 16 - 0 16 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCR73380 CREDIT SYSTEMS CUSTEGOP 40 5 44 38 6 - 0 6 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCRM1021 AUDIT: ESI INFORMATION TECHNO DIRCTESI 3 - 3 3 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCSYSRAS SYSTEM REGULATORY AFFAIRS-STAT CUSTEGOP - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCT54065 OPNS OF PURCHASING & CONT-DCS SCMATRAN 0 0 0 0 0 - 0 0 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCTDPQ01 DISTR POWER QUALITY ESI CUSEOPCO 3 0 3 2 0 - 0 0 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCTTDS38 TRANSMISSION O&M MGMT/SUPPORT TRSBLNOP 1,871,437 4,636 1,876,073 1,655,627 220,446 - 90 220,536 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCW29607 POWER SYSTEM ACCOUNTING LOADWEPI 3 0 4 3 1 - 0 1 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCW55555 VP FOSSIL GENERATION CAPAOPCO 14,414 1,850 16,265 14,506 1,758 - 32 1,791 Amounts may not add or tie to other schedules due to rounding.

EXHIBIT JFD-C Domino, Joe Page 4 of 11 ENTERGY TEXAS, INC. EXHIBIT JFD-C 2011 ETI Rate Case

Affiliate Billings - by Witness, Class, Department and Project 2011 TX Rate Case For the Twelve Months Ended June 30, 2011 Page 5 of 11 Amounts in Dollars (A) (B) (C) (D) (E) (F) (G) (H) Total Billings Activity / Project ESI BIlling Service Company ETI Per Pro Forma Total ETI Class Billing Entity Dept Code Activity / Project Description Method Support Recipient Total All Other BU's Books Exclusions Amount Adjusted UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCWE0063 EMO APPLICATION SUPPORT LOADOPCO 17 2 19 16 3 - 0 3 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCWE0073 FOSSIL INFORMATION TECHNOLOGY CAPAOPCO 3 0 3 3 0 - 0 0 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCWE0187 FOSSIL IT SUPPORT FOR 2003-200 CAPAOPCO - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCWS0327 SAIC LABOR CHARGES TO PMDC CAPAOPCO 53 6 60 53 7 - 0 7 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PP4R9886 TRITIUM DETECTION INVESTIGATIO DIRECT72 23,182 2,309 25,491 25,491 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PP6HHOST ENNE Hosting/server support/SO DIRCTENU 135 16 151 151 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PP6HINDS Indus Passport DIRCTENU 339 41 379 379 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PPAMISTG AMI Strategy Expense CUSEOPCO 222 27 249 212 37 - 1 37 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PPCCS010 Climate Consulting Services ASSTSALL 289,337 31,693 321,030 289,415 31,615 - 547 32,162 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PPCOO001 CHIEF OPERATING OFFICER ASSTSALL 570,386 63,085 633,471 571,034 62,437 (3) (1,403) 61,032 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PPD10115 Dist Work Mgmt O&M-DIS/DSS/ADS CUSTEGOP 176 21 197 170 27 - 1 28 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PPD10116 Dist Work Mgmt O&M-LAMP Street CUSEOPCO 1 0 1 1 0 - 0 0 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PPD10119 Dist Work Mgmt O&M-CTS Contrac CUSTEGOP 23 3 26 22 4 - 0 4 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PPD10120 Dist Oper Appl O&M-AM/FM Suppo CUSTEGOP 269 32 302 260 42 - 1 42 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PPD10121 Dist Oper Appl O&M-AutoCAD CUSEOPCO 12 1 14 12 2 - 0 2 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PPD10123 Dist Oper Appl O&M-EPO&SAISO S CUSEOPCO 21 3 24 20 4 - 0 4 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PPD10124 Dist Oper Appl O&M-PDD/ECOS Sp CUSTEGOP 8 1 9 8 1 - 0 1 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PPD10128 ARCS/Itron/MV90 Support CUSTEGOP 73 9 82 71 11 - 0 12 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PPD10129 Billing Determinate Proc/Major CUSTEGOP 56 7 62 54 9 - 0 9 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PPD10130 Customer Care System Interface CUSEGXTX 98 12 109 109 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PPD10131 CIS/AIS & Core Support DIRECTTX 805 97 902 - 902 - 19 921 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PPD10132 Electronic Data Interchange Su CUSEOPCO 20 2 23 19 3 - 0 3 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PPD10133 Internet Bill Presentment & Pm CUSEGXTX 15 2 17 17 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PPD10134 MAB Load Research Support CUSTEGOP 19 2 22 19 3 - 0 3 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PPD10137 Bill Delivery Support CUSEGXTX 482 58 539 539 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PPD10139 Mobius Support CUSTEGOP 0 0 0 0 0 - 0 0 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PPD10140 Large Power Billing System for CUSEOPCO 23 3 25 22 4 - 0 4 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PPD10141 CIMS Support CUSEGXTX 2 0 2 2 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PPD10142 Customer Service Field Applica CUSTEGOP 11 1 12 10 2 - 0 2 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PPD10146 Dist Work Mgmt-Cyndrus Support VEHCLALL 8 1 9 8 1 - 0 1 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PPD10150 TaxWare Support CUSTEGOP 50 6 56 48 8 - 0 8 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PPD10158 CCS Agent Care System CUSEGXTX 46 6 52 52 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PPD10161 ePlus (Web Self Service) Suppo CUSTEGOP 146 17 163 141 22 - 0 23 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PPEPI001 Environmental Programs & Infra CAPAOPCO (179) - (179) (160) (19) - (1) (20) UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PPETRNUC Executive Timesheets- Reg Nuc DIRCTEOI 17,530 1,880 19,410 19,410 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PPETSETR Executive Timesheets-ETR DIRCTETR 320,645 40,720 361,365 361,365 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PPETSNRG Executive Timesheets- Non Reg DIRCTENU 10,307 595 10,902 10,902 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PPETSREG Executive Timesheets- Reg Co's CUSTEGOP 12,783 865 13,648 11,767 1,882 - 29 1,911 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PPF72700 Cognos Reporting Support GENLEDAL 22 2 24 23 1 - 0 1 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PPFRM127 OCRO - Bus Cont Plan Managemen LBRBILAL - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PPFX3259 Inventory Planning System Supp SCTDSPAL 34 4 38 25 12 - 0 13 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PPFX3685 Supply Chain Applications Supp SCMATRAN 61 7 68 58 10 - 0 10 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PPFX5307 Compliance Software System Sup ASSTSALL 38 5 42 38 4 - 0 4 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PPFXOPMO IT Enterprise Program Manageme ITSPENDA 22 2 25 23 2 - 0 2 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PPHRSSPC HR SVS - ESI SUPPLY CHAIN DIRCTESI 18 - 18 18 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PPN20535 P3E Scheduling Software Mainte DIRCTEOI 162 19 182 182 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PPN20536 INDUS Software Maintenance DIRCTEOI 288 34 322 322 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PPN20713 ESI Nuclear - Site Split SNUCSITE 80,170 10,163 90,333 90,333 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PPPCS001 Critical Infrastructure Protec CAPAOPCO 5,554 762 6,316 5,633 683 - 14 697 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PPPMUPGR Performance Management Sys Upg CUSEOPCO 3 0 4 3 1 - 0 1 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PPRES001 Regulated Utility Electric Rel CUSEOPCO 1,993 223 2,216 1,889 327 - 7 333 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PCTTDS38 TRANSMISSION O&M MGMT/SUPPORT TRSBLNOP - - - - - - (215,886) (215,886) UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PPWE0375 SAIC Designated Srv for Fossil CAPAOPCO 10 1 11 10 1 - 0 1 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F3PPWEOSGN General System-ENG-Tech Suppor CAPAOPCO 504 80 584 521 63 - 1 64 3-57

UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F5PCD10093 WEB DEVELOPMENT SUPPORT CUSTEGOP 15 2 17 15 2 - 0 2 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F5PCD10108 CCS REMEDY TESTING CUSEGXTX 0 0 1 1 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F5PCEDIVER DIVERSITY TRAINING DIRCTESI - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F5PCMCMSCL PASSPORT- SC MATERIALS MANAGEM SCMATRAN 257 31 288 245 43 (43) - - UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F5PCZCDEPT SUPERVISION & SUPPORT - CORPOR LBRCORPT 4 - 4 4 0 - - 0 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F5PCZCONOP CONTRIBUTION OPERATIONS - BELO ASSTSALL 1 0 1 1 0 - (0) - UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F5PCZECDEV ECONOMIC DEVELOPMENT - BELOW T CUSEOPCO 2 0 2 1 0 - (0) - UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F5PCZFDSER DESKTOP SERVICES PCNUMALL 15 1 16 16 1 - 0 1 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F5PPD10154 MDT Wireless Telecom Serv CUSTEGOP 286 34 321 276 44 - 1 45 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F5PPD10156 Dist. Work Mgmt - DriveCam Sup CUSTELLA 5 1 5 5 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F5PPD10162 Util Ops Cust Data Warehouse S CUSTEGOP 45 5 50 43 7 - 0 7 UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F5PPFALCON Project Falcon DIRECTNI (358) - (358) (358) - - - - Amounts may not add or tie to other schedules due to rounding.

EXHIBIT JFD-C Domino, Joe Page 5 of 11 ENTERGY TEXAS, INC. EXHIBIT JFD-C 2011 ETI Rate Case

Affiliate Billings - by Witness, Class, Department and Project 2011 TX Rate Case For the Twelve Months Ended June 30, 2011 Page 6 of 11 Amounts in Dollars (A) (B) (C) (D) (E) (F) (G) (H) Total Billings Activity / Project ESI BIlling Service Company ETI Per Pro Forma Total ETI Class Billing Entity Dept Code Activity / Project Description Method Support Recipient Total All Other BU's Books Exclusions Amount Adjusted UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F5PPHREXEC HR Executive Financial Counsel ASSTSALL 7,102 - 7,102 6,380 722 - (722) - UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 F5PPSPE044 PMO Support Initiative-System- LOADOPCO 1,176 129 1,305 1,088 217 - (217) - UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 SAPCP25910 PC&R OVERHEAD POOL CHARGES CEAOUTAL 0 - 0 0 0 (0) - - UTILITY & EXECUTIVE MANAGEMENT ESI CPOP8 Total 5,517,075 167,988 5,685,063 5,117,844 567,219 (45) (217,446) 349,728 UTILITY & EXECUTIVE MANAGEMENT ESI CSODW E1PCR56025 CUSTOM SALES & SERVICE UNIT- M DIRCTELI 688 - 688 688 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI CSODW Total 688 - 688 688 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI FN086 E1PCR56226 Sales & Mktg - ALL JURIS MACCTALL 8,197 920 9,118 7,935 1,183 - 20 1,202 UTILITY & EXECUTIVE MANAGEMENT ESI FN086 F3PCCPM001 CORPORATE PERFORMANCE MANAGEME ASSTSALL 1,194,449 142,420 1,336,870 1,205,015 131,855 - (74) 131,781 UTILITY & EXECUTIVE MANAGEMENT ESI FN086 F3PCF07300 CORP PLANNING & ANALYSIS- REGU CUSTEGOP 479 74 553 477 76 - 1 77 UTILITY & EXECUTIVE MANAGEMENT ESI FN086 F3PCFACALL FACILITIES SVCS- ALL COS SQFTALLC - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI FN086 F3PP1E2EPM End-to-End Process Mgmnt LVLSVCAL - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI FN086 F3PPCPMUTL CORPORATE PERFORMANCE MGMT UTL EMPXRTNC 19,531 1,594 21,126 19,133 1,992 - 40 2,032 UTILITY & EXECUTIVE MANAGEMENT ESI FN086 F3PPHRTFMN HR Transformation - O&M Costs EMPLOYAL 819 61 880 837 43 - 1 44 UTILITY & EXECUTIVE MANAGEMENT ESI FN086 F3PPTDERSD MISO Transition ALL OPCO LOADOPCO 905 111 1,016 847 169 - (169) - UTILITY & EXECUTIVE MANAGEMENT ESI FN086 F5PCF96930 BENCHMARKING PHASE II LOADWEOI 4,020 551 4,571 3,817 754 - 16 770 UTILITY & EXECUTIVE MANAGEMENT ESI FN086 F5PCZCDEPT SUPERVISION & SUPPORT - CORPOR LBRCORPT 28 - 28 27 1 - - 1 UTILITY & EXECUTIVE MANAGEMENT ESI FN086 F5PPERG100 Systemwide Ergonomics Initiati EMPLOYAL - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI FN086 F5PPSPE044 PMO Support Initiative-System- LOADOPCO 278 38 317 264 53 - (53) - UTILITY & EXECUTIVE MANAGEMENT ESI FN086 F5PPTHMPSN Norwood Thompson Park Playgrou DIRCTETR 3,514 465 3,980 3,980 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI FN086 F5PPZUWELL Entergy Wellness Program EMPLOYAL 999 87 1,086 1,033 53 - 1 54 UTILITY & EXECUTIVE MANAGEMENT ESI FN086 Total 1,233,220 146,323 1,379,544 1,243,365 136,178 - (218) 135,961 UTILITY & EXECUTIVE MANAGEMENT ESI GAF6G F3PCZGASAG GAS ADMINISTRATIVE CUSGOPCO 1,183 - 1,183 1,183 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAF6G Total 1,183 - 1,183 1,183 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAF6P 80 - 80 80 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAF6P F3PCG10345 GAS DIVISION DIRECTOR - ENOI E DIRCTENO 43,653 3,334 46,987 46,987 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAF6P F3PCG10347 GAS DIVISION DIRECTOR - EGSI E DIRECTLG 13,465 - 13,465 13,465 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAF6P F3PCZGASAG GAS ADMINISTRATIVE CUSGOPCO 7,610 - 7,610 7,610 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAF6P F5PCSAFTEG SAFTEY TRAINING LOADER GAS CUS CUSGOPCO 10,786 739 11,525 11,525 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAF6P F5PCZZ4070 IMPACT AWARDS DIRCTESI 215 - 215 215 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAF6P F5PPD10154 MDT Wireless Telecom Serv CUSTEGOP 525 - 525 452 73 - (73) - UTILITY & EXECUTIVE MANAGEMENT ESI GAF6P F5PPZUWELL Entergy Wellness Program EMPLOYAL - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAF6P SGPCG59006 GAS DISTRIBUTION ENOI O/H GAS DIRCTENO 240,285 28,421 268,706 268,706 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAF6P SGPCR79008 GAS DISTRIBUTION EGSI O/H-CHAR DIRECTLG 113,137 13,677 126,814 126,814 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAF6P Total 429,757 46,171 475,927 475,855 73 - (73) - UTILITY & EXECUTIVE MANAGEMENT ESI GAFH6 - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAFH6 F3PCDG0004 OPERATOR QUAL DEVELOP & TRAIN DIRCTENO 226 - 226 226 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAFH6 F3PCFACALL FACILITIES SVCS- ALL COS SQFTALLC 98 - 98 87 11 - (11) - UTILITY & EXECUTIVE MANAGEMENT ESI GAFH6 F3PCFAPWHS POWERHOUSE OPERATIONS EMPLOYAL 123 - 123 117 6 - (6) - UTILITY & EXECUTIVE MANAGEMENT ESI GAFH6 F3PCG10345 GAS DIVISION DIRECTOR - ENOI E DIRCTENO 455,541 48,381 503,922 503,922 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAFH6 F3PCG10347 GAS DIVISION DIRECTOR - EGSI E DIRECTLG 446,592 47,126 493,718 493,718 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAFH6 F3PCZGASAG GAS ADMINISTRATIVE CUSGOPCO 25 - 25 25 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAFH6 F5PCSAFTEG SAFTEY TRAINING LOADER GAS CUS CUSGOPCO 5,570 806 6,376 6,376 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAFH6 F5PCSVCAWD SERVICE AWARDS DIRCTESI 1,060 - 1,060 1,060 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAFH6 F5PCZCDEPT SUPERVISION & SUPPORT - CORPOR LBRCORPT 318 - 318 305 13 - (13) - 3-58

UTILITY & EXECUTIVE MANAGEMENT ESI GAFH6 F5PPZUWELL Entergy Wellness Program EMPLOYAL 427 43 470 447 23 - (23) - UTILITY & EXECUTIVE MANAGEMENT ESI GAFH6 SGPCG59006 GAS DISTRIBUTION ENOI O/H GAS DIRCTENO 42,644 5,218 47,862 47,862 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAFH6 SGPCR79008 GAS DISTRIBUTION EGSI O/H-CHAR DIRECTLG 42,510 5,202 47,713 47,713 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAFH6 Total 995,135 106,776 1,101,911 1,101,858 53 - (53) - UTILITY & EXECUTIVE MANAGEMENT ESI GAG2E C5PP449606 Gas Serv Storm Rebuild Replace DIRCTENO 36,405 4,363 40,768 40,768 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAG2E F3PCFACALL FACILITIES SVCS- ALL COS SQFTALLC 934 - 934 831 104 - (104) - UTILITY & EXECUTIVE MANAGEMENT ESI GAG2E F3PCG10345 GAS DIVISION DIRECTOR - ENOI E DIRCTENO 56,490 4,045 60,535 60,535 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAG2E F3PCG10347 GAS DIVISION DIRECTOR - EGSI E DIRECTLG 47,226 4,429 51,654 51,654 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAG2E F3PCZGASAG GAS ADMINISTRATIVE CUSGOPCO 190,744 19,573 210,317 210,317 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAG2E F3PPAMPDEV Advanced Mgmt Dev Program EMPLOYAL - - - - - - - - Amounts may not add or tie to other schedules due to rounding.

EXHIBIT JFD-C Domino, Joe Page 6 of 11 ENTERGY TEXAS, INC. EXHIBIT JFD-C 2011 ETI Rate Case

Affiliate Billings - by Witness, Class, Department and Project 2011 TX Rate Case For the Twelve Months Ended June 30, 2011 Page 7 of 11 Amounts in Dollars (A) (B) (C) (D) (E) (F) (G) (H) Total Billings Activity / Project ESI BIlling Service Company ETI Per Pro Forma Total ETI Class Billing Entity Dept Code Activity / Project Description Method Support Recipient Total All Other BU's Books Exclusions Amount Adjusted UTILITY & EXECUTIVE MANAGEMENT ESI GAG2E F4PPENG134 Mutual Assist ENOI Gas NMGC 2/ DIRCTENO 138 17 154 154 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAG2E F5PCDG0168 GAS EMPLOYEE DEVELOPMENT PROGR CUSGOPCO 19 - 19 19 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAG2E F5PCSAFTEG SAFTEY TRAINING LOADER GAS CUS CUSGOPCO 33,725 1,205 34,930 34,930 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAG2E F5PCSVCAWD SERVICE AWARDS DIRCTESI 285 - 285 285 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAG2E F5PPGEFBUS Gas Operations Efficient Busin CUSGOPCO 45,084 5,479 50,562 50,562 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAG2E SDPCT30070 CAPITAL SUSPENSE, DISTR WIRES, DIRCTELI 676 75 751 751 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAG2E SGPCG59006 GAS DISTRIBUTION ENOI O/H GAS DIRCTENO 69,440 8,391 77,830 77,830 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAG2E SGPCR79008 GAS DISTRIBUTION EGSI O/H-CHAR DIRECTLG 69,433 8,390 77,823 77,823 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAG2E Total 550,596 55,966 606,562 606,458 104 - (104) - UTILITY & EXECUTIVE MANAGEMENT ESI GAG2U F3PCFACALL FACILITIES SVCS- ALL COS SQFTALLC 930 - 930 827 103 - (103) - UTILITY & EXECUTIVE MANAGEMENT ESI GAG2U F3PCG10345 GAS DIVISION DIRECTOR - ENOI E DIRCTENO 44,059 4,862 48,922 48,922 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAG2U F3PCG10347 GAS DIVISION DIRECTOR - EGSI E DIRECTLG 41,423 4,773 46,196 46,196 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAG2U F3PCZGASAG GAS ADMINISTRATIVE CUSGOPCO 82,739 9,065 91,804 91,804 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAG2U F4PPEGS148 Mutual Assist EGSL GAS NMGC 2/ DIRECTLG 829 100 929 929 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAG2U F4PPENG134 Mutual Assist ENOI Gas NMGC 2/ DIRCTENO 829 100 929 929 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAG2U F5PCSAFTEG SAFTEY TRAINING LOADER GAS CUS CUSGOPCO 6,872 775 7,647 7,647 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAG2U F5PCSVCAWD SERVICE AWARDS DIRCTESI 269 - 269 269 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAG2U F5PPZUWELL Entergy Wellness Program EMPLOYAL 439 45 484 460 24 - (24) - UTILITY & EXECUTIVE MANAGEMENT ESI GAG2U SGPCG59006 GAS DISTRIBUTION ENOI O/H GAS DIRCTENO 57,962 6,941 64,902 64,902 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAG2U SGPCR79008 GAS DISTRIBUTION EGSI O/H-CHAR DIRECTLG 60,438 7,218 67,656 67,656 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAG2U Total 296,789 33,879 330,668 330,541 127 - (127) - UTILITY & EXECUTIVE MANAGEMENT ESI GAG7F F3PCCDVETR CORP DEV-ANALYSIS STRATEGIC ME ASSTSALL - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAG7F F3PCG10345 GAS DIVISION DIRECTOR - ENOI E DIRCTENO 85,531 9,803 95,334 95,334 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAG7F F3PCZGASAG GAS ADMINISTRATIVE CUSGOPCO 5,877 - 5,877 5,877 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAG7F F3PPAMPDEV Advanced Mgmt Dev Program EMPLOYAL 4,112 - 4,112 3,921 192 - (192) - UTILITY & EXECUTIVE MANAGEMENT ESI GAG7F F5PCSAFTEG SAFTEY TRAINING LOADER GAS CUS CUSGOPCO 17,545 1,247 18,792 18,792 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAG7F SGPCG59006 GAS DISTRIBUTION ENOI O/H GAS DIRCTENO 113,573 13,702 127,275 127,275 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAG7F Total 226,639 24,752 251,391 251,199 192 - (192) - UTILITY & EXECUTIVE MANAGEMENT ESI GAH2H F3PCDG0004 OPERATOR QUAL DEVELOP & TRAIN DIRCTENO 22,082 2,217 24,299 24,299 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAH2H F3PCDG0005 OPERATOR QUAL DEVELOP & TRAIN DIRECTLG 84,690 8,908 93,598 93,598 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAH2H F3PCG10347 GAS DIVISION DIRECTOR - EGSI E DIRECTLG 3,585 678 4,264 4,264 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAH2H F3PCZGASAG GAS ADMINISTRATIVE CUSGOPCO 2,794 - 2,794 2,794 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAH2H Total 113,151 11,803 124,955 124,955 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAJ2J C7PPSJ3198 EMI Storm Distr Ops 1/7/11Wint DIRCTEMI 1,060 196 1,256 1,256 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAJ2J F3PCG10345 GAS DIVISION DIRECTOR - ENOI E DIRCTENO - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAJ2J F3PCZGASAG GAS ADMINISTRATIVE CUSGOPCO 130,972 13,473 144,445 144,445 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAJ2J Total 132,031 13,670 145,701 145,701 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAJ2K C5PC449602 GAS FAILURES BLANKET DIRCTENO 35,953 - 35,953 35,953 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAJ2K C7PPSJ2462 STORM DMG LA DIST ELL 1/8/11 I DIRCTELI 153 28 181 181 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAJ2K F3PCDG0004 OPERATOR QUAL DEVELOP & TRAIN DIRCTENO 4,811 - 4,811 4,811 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAJ2K F3PCDG0005 OPERATOR QUAL DEVELOP & TRAIN DIRECTLG 4,811 - 4,811 4,811 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAJ2K F3PCFACALL FACILITIES SVCS- ALL COS SQFTALLC 94 - 94 84 10 - (10) - UTILITY & EXECUTIVE MANAGEMENT ESI GAJ2K F3PCG10345 GAS DIVISION DIRECTOR - ENOI E DIRCTENO 415 - 415 415 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAJ2K F3PCG10347 GAS DIVISION DIRECTOR - EGSI E DIRECTLG 415 - 415 415 - - - - 3-59

UTILITY & EXECUTIVE MANAGEMENT ESI GAJ2K F3PCZGASAG GAS ADMINISTRATIVE CUSGOPCO 149,109 14,184 163,294 163,294 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAJ2K F5PCSAFTEG SAFTEY TRAINING LOADER GAS CUS CUSGOPCO 2,739 98 2,837 2,837 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAJ2K F5PCSVCAWD SERVICE AWARDS DIRCTESI 369 - 369 369 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAJ2K SGPCG59006 GAS DISTRIBUTION ENOI O/H GAS DIRCTENO 26,092 3,146 29,238 29,238 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAJ2K SGPCR79008 GAS DISTRIBUTION EGSI O/H-CHAR DIRECTLG 3,499 419 3,918 3,918 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAJ2K Total 228,461 17,876 246,337 246,326 10 - (10) - UTILITY & EXECUTIVE MANAGEMENT ESI GAJ3K C5PP449606 Gas Serv Storm Rebuild Replace DIRCTENO 72,953 8,794 81,747 81,747 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAJ3K F3PCCDVCCN PROJECT GUMBO CUSGOPCO - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAJ3K F3PCZGASAG GAS ADMINISTRATIVE CUSGOPCO 31,354 3,770 35,124 35,124 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAJ3K F5PCSAFTEG SAFTEY TRAINING LOADER GAS CUS CUSGOPCO 1,274 161 1,435 1,435 - - - - Amounts may not add or tie to other schedules due to rounding.

EXHIBIT JFD-C Domino, Joe Page 7 of 11 ENTERGY TEXAS, INC. EXHIBIT JFD-C 2011 ETI Rate Case

Affiliate Billings - by Witness, Class, Department and Project 2011 TX Rate Case For the Twelve Months Ended June 30, 2011 Page 8 of 11 Amounts in Dollars (A) (B) (C) (D) (E) (F) (G) (H) Total Billings Activity / Project ESI BIlling Service Company ETI Per Pro Forma Total ETI Class Billing Entity Dept Code Activity / Project Description Method Support Recipient Total All Other BU's Books Exclusions Amount Adjusted UTILITY & EXECUTIVE MANAGEMENT ESI GAJ3K F5PCSVCAWD SERVICE AWARDS DIRCTESI - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAJ3K SGPCG59006 GAS DISTRIBUTION ENOI O/H GAS DIRCTENO 51,505 6,205 57,711 57,711 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAJ3K SGPCR79008 GAS DISTRIBUTION EGSI O/H-CHAR DIRECTLG 51,505 6,205 57,710 57,710 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI GAJ3K Total 208,592 25,135 233,726 233,726 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SGG2D E1PCR56226 Sales & Mktg - ALL JURIS MACCTALL 294 36 330 287 43 - (43) - UTILITY & EXECUTIVE MANAGEMENT ESI SGG2D F3PCCDVCCN PROJECT GUMBO CUSGOPCO - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SGG2D F3PCFACALL FACILITIES SVCS- ALL COS SQFTALLC 1,975 - 1,975 1,759 216 - (216) - UTILITY & EXECUTIVE MANAGEMENT ESI SGG2D F3PCG10345 GAS DIVISION DIRECTOR - ENOI E DIRCTENO 786 - 786 786 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SGG2D F3PCG10347 GAS DIVISION DIRECTOR - EGSI E DIRECTLG 28 - 28 28 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SGG2D F3PCSYSRAS SYSTEM REGULATORY AFFAIRS-STAT CUSTEGOP 62 8 70 60 10 - (10) - UTILITY & EXECUTIVE MANAGEMENT ESI SGG2D F3PCZGASAG GAS ADMINISTRATIVE CUSGOPCO 517,556 59,411 576,967 576,967 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SGG2D F3PPE9974S Utl ECI Continuing Improve ESI CUSEOPCO 552 68 620 529 92 - (92) - UTILITY & EXECUTIVE MANAGEMENT ESI SGG2D F3PPENOFRP ENO Annual FRP Filing 2010-12 DIRCTENO 2,739 312 3,051 3,051 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SGG2D F3PPGRSP10 EGSL RATE STABLIZATN (TY 2009/ DIRECTLG 88 10 98 98 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SGG2D F3PPPGA010 PGA Audit 2010 DIRECTLG 430 50 480 480 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SGG2D F5PCSAFTEG SAFTEY TRAINING LOADER GAS CUS CUSGOPCO 3,545 452 3,997 3,997 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SGG2D F5PCSVCAWD SERVICE AWARDS DIRCTESI 98 - 98 98 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SGG2D F5PCZCDEPT SUPERVISION & SUPPORT - CORPOR LBRCORPT 211 - 211 205 6 - (6) - UTILITY & EXECUTIVE MANAGEMENT ESI SGG2D F5PPHREXEC HR Executive Financial Counsel ASSTSALL 3,500 - 3,500 3,144 356 - (356) - UTILITY & EXECUTIVE MANAGEMENT ESI SGG2D SGPCG59006 GAS DISTRIBUTION ENOI O/H GAS DIRCTENO 112,081 13,617 125,697 125,697 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SGG2D SGPCR79008 GAS DISTRIBUTION EGSI O/H-CHAR DIRECTLG 112,048 13,613 125,661 125,661 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SGG2D Total 755,995 87,575 843,570 842,847 723 - (723) - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 C1PPFI5207 Payroll Time & Labor - Phase I EMPLOYAL (0) - (0) (0) (0) 0 - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 C1PPHR8800 PS HCM (Human Cap Mgmt) Upgrd EMPLOYAL (0) - (0) (0) - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 C6PPAMBSGN AMI:BASE Non-Incremental, EGSL DIRECTLG (1) - (1) (1) - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PC6H0026 NORTHEAST MGMT OVERSITE IP2/IP SPL77N7A - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PCCPM001 CORPORATE PERFORMANCE MANAGEME ASSTSALL - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PCD10006 FIELD DEVELOPMENT CUSTEGOP - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PCD10049 REGULATED RETAIL SYSTEMS - O&M CUSTEGOP - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PCD10077 REGULATORY AFFAIRS WORLDOX IMP DIRCTENO - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PCD10105 CUSTOMER CARE SYSTEM SUPPORT CUSEGXTX - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PCE99750 PRES- ENT. LA-GEN'L OPS-ELI/EG CUSELGLA - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PCE99795 GROUP PRES - UTILITY OPERATION CUSTEGOP 1,997,434 130,481 2,127,915 1,833,530 294,385 (373) (3,718) 290,294 UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PCF10414 ESI TAX SERVICES LVLSVCAL - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PCF23425 ACCOUNTS PAYABLE PROCESSING APTRNALL - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PCF23428 TREASURY SYSTEMS BNKACCTA - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PCF23442 PAYROLL PROCESSING PRCHKALL - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PCF26910 REVENUE ACCOUNTING ANALYSIS CUSEGALL - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PCF72271 DATA WAREHOUSE GENLEDAL - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PCF72670 GENERAL ACCOUNTING SYSTEM MAIN GENLEDAL - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PCF72901 MOBILE DATA TERMINAL BASELOAD CUSTEGOP - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PCF73027 BUDGET SYSTEM MAINTENANCE GENLEDAL - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PCF73901 AM/FM BASELOAD (SUPPORT) DIRECTTX - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PCF74195 TRANSMISSION APPLICATION SUPPO TRSBLNOP - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PCF74344 GENERATION PLANNING & DISPATCH LOADOPCO - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PCF74515 FOSSIL MAINTENANCE MANAGEMENT CAPAOPCO - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PCF74585 FOSSIL APPLICATION SUPPORT CAPAOPCO - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PCF99182 RECORDS MANAGEMENT RECDMGNT - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PCFCQEAI ENTERPRISE APPLICATION INTEGRA APPSUPAL - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PCFCQEXC EXCHANGE PCNUMALL - - - - - - - - 3-60

UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PCFCQMVS MAINFRAME APPSMVSX - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PCFCQNTS NT SERVERS APPSWINT - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PCFCQUNX UNIX SERVERS APPSUNIX - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PCFX2815 EDMS PRODUCT LINE SUPPORT EMPLOYAL - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PCFX3275 WEB INFRASTRUCTURE MAINTENANCE PCNUMALL - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PCFX3290 IT BUSINESS PLANNING AND GOVER ITSPENDA - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PCFX3350 A/R & BILLING SUPPORT ARTRNALL - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PCFX3625 SUPPLY CHAIN - CDW SYSTEMS SUP SCDSPALL - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PCFX3640 WHITE AMBER & ITILITI SUPPORT SCMATRAN - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PCFX3650 WEB PAGE SUPPORT - CORPORATE EMPLOYAL - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PCFX3670 CORPORATE COMMUNICATIONS WEB S DIRCTETR - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PCFX3690 PEARL SUPPORT APTRNALL - - - - - - - - Amounts may not add or tie to other schedules due to rounding.

EXHIBIT JFD-C Domino, Joe Page 8 of 11 ENTERGY TEXAS, INC. EXHIBIT JFD-C 2011 ETI Rate Case

Affiliate Billings - by Witness, Class, Department and Project 2011 TX Rate Case For the Twelve Months Ended June 30, 2011 Page 9 of 11 Amounts in Dollars (A) (B) (C) (D) (E) (F) (G) (H) Total Billings Activity / Project ESI BIlling Service Company ETI Per Pro Forma Total ETI Class Billing Entity Dept Code Activity / Project Description Method Support Recipient Total All Other BU's Books Exclusions Amount Adjusted UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PCFX3790 ESTER SUPPORT PRCHKALL 0 - 0 0 0 - - 0 UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PCFX5555 DATA WAREHOUSE TOOLS SUPPORT APPSUPAL - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PCHRCALL HR SVCS- CUST SERV SUPT- ALL C EMPLOCSS 196 - 196 181 15 - - 15 UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PCHRDCSS HR- FRANCHISE OPNS (DIST) SUPT EMPLFRAN 481 - 481 414 66 - - 66 UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PCHRPRES HR PRESIDENT/ CEO SUPPORT- ALL EMPLPRES 7 - 7 6 1 - - 1 UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PCHRSALL HR SERVICES- ALL COMPANIES EMPLOYAL 0 - 0 0 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PCHRSDUT HR SVCS - ESI DOMESTIC UTILITY DIRCTESI 8 - 8 8 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PCMCMSOM MATERIALS & CONTRACTS MGTMT SY SCMATXNU - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PCN20520 WORK MANAGEMENT SYSTEM (WMS) M DIRCTEOI - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PCN20521 IDEAS MAINTENANCE DIRCTEOI - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PCN20522 PCRS MAINTENANCE DIRCTEOI - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PCN20527 NUCLEAR IT QUICK RESPONSE TEAM DIRCTEOI - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PCN20528 ERD SUPPORT (MAINTENANCE) DIRCTEOI - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PCR40118 UTILITY COMMUNICATIONS CUSTEGOP 83,560 - 83,560 72,040 11,521 - (118) 11,403 UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PCR40430 EMPLOYEE COMM (REGULATED COMPA EMPLOREG 71,944 - 71,944 67,408 4,535 - - 4,535 UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PCR40500 EMPLOYEE COMM (REG + UNREG COM EMPLOYAL - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PCR53291 ESI REMITTANCE PROCESSING CUSEOPCO - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PCR73326 CUSTOMER SERVICE CENTER SUPPOR CUSTCALL - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PCR73380 CREDIT SYSTEMS CUSTEGOP - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PCRM1021 AUDIT: ESI INFORMATION TECHNO DIRCTESI - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PCSYSAGR SYSTEM AGREEMENT-2001 CUSEOPCO 770,707 - 770,707 656,959 113,747 - - 113,747 UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PCWE0063 EMO APPLICATION SUPPORT LOADOPCO - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PCWE0187 FOSSIL IT SUPPORT FOR 2003-200 CAPAOPCO - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PCWS0327 SAIC LABOR CHARGES TO PMDC CAPAOPCO - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PP6HHOST ENNE Hosting/server support/SO DIRCTENU - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PP6HINDS Indus Passport DIRCTENU - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PPAMISTG AMI Strategy Expense CUSEOPCO 1 - 1 1 0 - - 0 UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PPD10115 Dist Work Mgmt O&M-DIS/DSS/ADS CUSTEGOP - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PPD10119 Dist Work Mgmt O&M-CTS Contrac CUSTEGOP - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PPD10120 Dist Oper Appl O&M-AM/FM Suppo CUSTEGOP - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PPD10121 Dist Oper Appl O&M-AutoCAD CUSEOPCO - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PPD10123 Dist Oper Appl O&M-EPO&SAISO S CUSEOPCO - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PPD10124 Dist Oper Appl O&M-PDD/ECOS Sp CUSTEGOP - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PPD10128 ARCS/Itron/MV90 Support CUSTEGOP - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PPD10129 Billing Determinate Proc/Major CUSTEGOP - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PPD10130 Customer Care System Interface CUSEGXTX - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PPD10131 CIS/AIS & Core Support DIRECTTX - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PPD10132 Electronic Data Interchange Su CUSEOPCO - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PPD10133 Internet Bill Presentment & Pm CUSEGXTX - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PPD10134 MAB Load Research Support CUSTEGOP - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PPD10137 Bill Delivery Support CUSEGXTX - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PPD10140 Large Power Billing System for CUSEOPCO - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PPD10141 CIMS Support CUSEGXTX - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PPD10142 Customer Service Field Applica CUSTEGOP - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PPD10146 Dist Work Mgmt-Cyndrus Support VEHCLALL - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PPD10150 TaxWare Support CUSTEGOP - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PPD10158 CCS Agent Care System CUSEGXTX - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PPD10161 ePlus (Web Self Service) Suppo CUSTEGOP - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PPE9974S Utl ECI Continuing Improve ESI CUSEOPCO 11,356 - 11,356 9,682 1,674 - - 1,674 UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PPETEGSL Executive Timesheets- EGSL DIRECTLG 2,215 216 2,430 2,430 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PPETENOI Executive Timesheet- ENOI DIRCTENO 55,980 1,967 57,948 57,948 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PPETSEAI Executives Time and Expenses-E DIRCTEAI 35,047 3,609 38,656 38,656 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PPETSELI Executive Timesheets- ELI DIRCTELI 77,575 2,603 80,178 80,178 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PPETSEMI Executive Timesheets- EMI DIRCTEMI 17,613 1,500 19,113 19,113 - - - - 3-61

UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PPETSETI Executive Time and Expenses-ET DIRECTTX 29,110 2,869 31,979 - 31,979 - 601 32,580 UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PPF72700 Cognos Reporting Support GENLEDAL - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PPFX5307 Compliance Software System Sup ASSTSALL - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PPFXOPMO IT Enterprise Program Manageme ITSPENDA - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PPN20535 P3E Scheduling Software Mainte DIRCTEOI - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PPN20536 INDUS Software Maintenance DIRCTEOI - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F3PPPMUPGR Performance Management Sys Upg CUSEOPCO - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F5PCD10093 WEB DEVELOPMENT SUPPORT CUSTEGOP - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F5PCLIHPPC CONSUMER EDUCATION PROGRAMS CUSEOPCO 3 - 3 3 1 - - 1 UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F5PCMCMSCL PASSPORT- SC MATERIALS MANAGEM SCMATRAN - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F5PCSVCAWD SERVICE AWARDS DIRCTESI 131 - 131 131 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F5PCZCDEPT SUPERVISION & SUPPORT - CORPOR LBRCORPT 60 - 60 59 2 - - 2 Amounts may not add or tie to other schedules due to rounding.

EXHIBIT JFD-C Domino, Joe Page 9 of 11 ENTERGY TEXAS, INC. EXHIBIT JFD-C 2011 ETI Rate Case

Affiliate Billings - by Witness, Class, Department and Project 2011 TX Rate Case For the Twelve Months Ended June 30, 2011 Page 10 of 11 Amounts in Dollars (A) (B) (C) (D) (E) (F) (G) (H) Total Billings Activity / Project ESI BIlling Service Company ETI Per Pro Forma Total ETI Class Billing Entity Dept Code Activity / Project Description Method Support Recipient Total All Other BU's Books Exclusions Amount Adjusted UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F5PCZCONOP CONTRIBUTION OPERATIONS - BELO ASSTSALL - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F5PCZFDSER DESKTOP SERVICES PCNUMALL - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F5PP10011U Show Cause Docket No. 10-011-U DIRCTEAI 78,782 - 78,782 78,782 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F5PPD10154 MDT Wireless Telecom Serv CUSTEGOP - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F5PPD10156 Dist. Work Mgmt - DriveCam Sup CUSTELLA - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F5PPD10162 Util Ops Cust Data Warehouse S CUSTEGOP - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F5PPHREXEC HR Executive Financial Counsel ASSTSALL 7,227 - 7,227 6,495 733 - (733) - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 F5PPSUPICT Support of ICT LOADOPCO - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU084 Total 3,239,437 143,246 3,382,683 2,924,024 458,659 (373) (3,967) 454,318 UTILITY & EXECUTIVE MANAGEMENT ESI SU085 F3PCE99795 GROUP PRES - UTILITY OPERATION CUSTEGOP - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SU085 Total - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SULSY C1PPFIRGTL Regulated Time-LBR & Absence M EMPOPCPE 1,786 246 2,032 1,853 179 (179) - - UTILITY & EXECUTIVE MANAGEMENT ESI SULSY C7PPSJ1214 WINTER STORM DL EAI DIST 01/26 DIRCTEAI - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SULSY C7PPSJ1250 STORM DL EAI DIST 4/19/11-4/24 DIRCTEAI 2,890 433 3,323 3,323 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SULSY C7PPSJ1251 TORNADOES DL EAI DIST 4/25/11 DIRCTEAI 5,554 861 6,416 6,416 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SULSY C7PPSJ2474 STORM Dmg ELL 4/25 to 4/27/11 DIRCTELI 100 12 112 112 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SULSY C7PPSJ3183 EMI 04/24/10 Tornadoes Distr O DIRCTEMI - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SULSY C7PPSJ3198 EMI Storm Distr Ops 1/7/11Wint DIRCTEMI 18,147 2,392 20,539 20,539 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SULSY C7PPSJ3204 EMI StormTornadoes DistrOps 4/ DIRCTEMI 100 12 112 112 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SULSY C8PPTL5496 Replace Storm Damages DIRCTEAI 20,682 3,097 23,779 23,779 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SULSY E2PPSJ1255 T-Grid Storm Tornadoes EAI 4/2 DIRCTEAI 315 44 359 359 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SULSY F3PCFACALL FACILITIES SVCS- ALL COS SQFTALLC 172 - 172 153 19 - - 19 UTILITY & EXECUTIVE MANAGEMENT ESI SULSY F3PCFAPWHS POWERHOUSE OPERATIONS EMPLOYAL - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SULSY F3PCT29320 SKILLS TRAINING CUST. SERV- HE CUSEOPCO 163 - 163 139 24 - - 24 UTILITY & EXECUTIVE MANAGEMENT ESI SULSY F3PCT29400 OPERATIONS SAFETY - HEADQUARTE CUSTEGOP 689,509 74,343 763,852 658,206 105,647 512 1,807 107,966 UTILITY & EXECUTIVE MANAGEMENT ESI SULSY F3PCT29406 OPERATIONS SAFETY - TEXAS DIST DIRECTTX 15,773 - 15,773 - 15,773 - - 15,773 UTILITY & EXECUTIVE MANAGEMENT ESI SULSY F3PCTDDS26 CUSTOMER SERVICE SUPPORT - O&M CUSTEGOP 120 - 120 103 17 - - 17 UTILITY & EXECUTIVE MANAGEMENT ESI SULSY F3PCTDS010 PROCESS & SKILLS TRAINING ADMI EMPLFRAN 120,567 14,007 134,574 115,628 18,946 - 389 19,335 UTILITY & EXECUTIVE MANAGEMENT ESI SULSY F3PCTDTR08 SKILLS TRAINING - LOUISIANA EL DIRCTELI - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SULSY F3PCTTDS12 TRANSMISSION LINES O&M EXPENS TRALINOP - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SULSY F3PCTTDS17 Substation Maintenance EGSI LA DIRECTLG 1,540 - 1,540 1,540 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SULSY F3PCTTDS19 SUBSTATION/SYSTEM PROT MAINT - DIRCTEAI 10,322 - 10,322 10,322 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SULSY F3PCTTDS21 SUBSTATION/SYSTEM PROT MAINT - DIRCTELI 1,540 - 1,540 1,540 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SULSY F3PCTTDS22 SUBSTATION/SYSTEM PROT MAINT - DIRCTEMI 7,620 - 7,620 7,620 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SULSY F3PCTTDS23 Substation Maintenance - Texas DIRECTTX 15,773 - 15,773 - 15,773 - - 15,773 UTILITY & EXECUTIVE MANAGEMENT ESI SULSY F3PCTTDS24 SUBSTATION/SYSTEM PROT MAINT - DIRCTENO 1,540 - 1,540 1,540 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SULSY F3PCTTDS27 DISTRIBUTION O&M EXPENSE -EAI DIRCTEAI 13,605 - 13,605 13,605 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SULSY F3PCTTDS28 DISTRIBUTION O&M EXPENSE -EMI DIRCTEMI 11,088 376 11,464 11,464 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SULSY F3PCTTDS29 DISTRIBUTION O&M EXPENSE -ELI DIRCTELI 9,001 708 9,709 9,709 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SULSY F3PCTTDS30 DISTRIBUTION O&M EXPENSE -EGSI DIRECTLG 1,540 - 1,540 1,540 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SULSY F3PCTTDS31 DISTRIBUTION O&M EXPENSE - ENO DIRCTENO 1,596 - 1,596 1,596 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SULSY F3PCTTDS38 TRANSMISSION O&M MGMT/SUPPORT TRSBLNOP 145 - 145 128 17 (17) - - UTILITY & EXECUTIVE MANAGEMENT ESI SULSY F3PCTTDS71 TRANSMISSION MANAGEMENT/SUPPOR DIRCTEAI - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SULSY F5PCTTDS70 TRANS MAINTENANCE: LINES & SUB TRSBLNOP 475,946 54,604 530,550 468,094 62,456 4,130 1,099 67,685 UTILITY & EXECUTIVE MANAGEMENT ESI SULSY F5PPERG100 Systemwide Ergonomics Initiati EMPLOYAL 4,552 85 4,638 4,414 224 - 1 224 UTILITY & EXECUTIVE MANAGEMENT ESI SULSY F5PPSAFTEL SAFETY TRAINING LOADER ELEC LA CUSTELLA 698 78 776 776 - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SULSY F5PPTVPPRO Voluntary Protection Program TRSBLNOP 698 78 776 685 91 - 2 93 UTILITY & EXECUTIVE MANAGEMENT ESI SULSY F5PPZUWELL Entergy Wellness Program EMPLOYAL 1,083 109 1,192 1,134 58 - 1 59 UTILITY & EXECUTIVE MANAGEMENT ESI SULSY Total 1,434,169 151,485 1,585,654 1,366,430 219,224 4,446 3,300 226,970 3-62

UTILITY & EXECUTIVE MANAGEMENT ESI SUUOS F3PCE99795 GROUP PRES - UTILITY OPERATION CUSTEGOP 14,122 - 14,122 12,175 1,947 - - 1,947 UTILITY & EXECUTIVE MANAGEMENT ESI SUUOS Total 14,122 - 14,122 12,175 1,947 - - 1,947 UTILITY & EXECUTIVE MANAGEMENT ESI SUUS1 F3PCFBLREG BELOW THE LINE- REGULATED CUSTEGOP - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SUUS1 F3PCSYSRAS SYSTEM REGULATORY AFFAIRS-STAT CUSTEGOP 105,229 - 105,229 90,721 14,508 - - 14,508 UTILITY & EXECUTIVE MANAGEMENT ESI SUUS1 F3PPE9981A Integrated Energy Mgmt EAI DIRCTEAI - - - - - - - - UTILITY & EXECUTIVE MANAGEMENT ESI SUUS1 F3PPE9981S Integrated Energy Mgmt ESI CUSEOPCO 15,986 1,847 17,834 15,206 2,628 - 8 2,636 UTILITY & EXECUTIVE MANAGEMENT ESI SUUS1 F5PCZU1573 REGULATORY AFFAIRS -- 100% EGS DIRECTTX 11,275 - 11,275 - 11,275 - - 11,275 UTILITY & EXECUTIVE MANAGEMENT ESI SUUS1 F5PPETX009 2009 Texas Rate Case Support DIRECTTX 148 - 148 - 148 - (148) -

Amounts may not add or tie to other schedules due to rounding.

EXHIBIT JFD-C Domino, Joe Page 10 of 11 ENTERGY TEXAS, INC. EXHIBIT JFD-C 2011 ETI Rate Case

Affiliate Billings - by Witness, Class, Department and Project 2011 TX Rate Case For the Twelve Months Ended June 30, 2011 Page 11 of 11 Amounts in Dollars (A) (B) (C) (D) (E) (F) (G) (H) Total Billings Activity / Project ESI BIlling Service Company ETI Per Pro Forma Total ETI Class Billing Entity Dept Code Activity / Project Description Method Support Recipient Total All Other BU's Books Exclusions Amount Adjusted UTILITY & EXECUTIVE MANAGEMENT ESI SUUS1 Total 132,639 1,847 134,487 105,927 28,560 - (141) 28,420 UTILITY & EXECUTIVE MANAGEMENT Total ESI 28,688,315 2,014,250 30,702,565 28,491,933 2,210,631 (39,503) (231,900) 1,939,228 Total UTILITY & EXECUTIVE MANAGEMENT 28,688,315 2,014,250 30,702,565 28,491,933 2,210,631 (39,503) (231,900) 1,939,228 Total Domino, Joe 28,688,315 2,014,250 30,702,565 28,491,933 2,210,631 (39,503) (231,900) 1,939,228 3-63

Amounts may not add or tie to other schedules due to rounding.

EXHIBIT JFD-C Domino, Joe Page 11 of 11 This page has been intentionally left blank.

2011 ETI Rate Case 3-64 ENTERGY TEXAS, INC. EXHIBIT JFD-D 2011 ETI Rate Case

Affiliate Billings - Pro Forma Summary - By Witness, Class, & Pro Forma 2011 TX Rate Case For the Twelve Months Ended June 30, 2011 Page 1 of 1 Amounts in Dollars Billing Pro Forma Class Entity Number Pro Forma Description Supporting Witness Pro Forma UTILITY & EXECUTIVE MANAGEMENT ESI AJ16 Remove MISO Costs Considine, Michael P (216,324) UTILITY & EXECUTIVE MANAGEMENT ESI AJ21-01 Remove Company Aircraft Costs Barrilleaux, Chris (1,589) UTILITY & EXECUTIVE MANAGEMENT ESI AJ21-03 Remove Rate Case Support Costs Considine, Michael P (148) UTILITY & EXECUTIVE MANAGEMENT ESI AJ21-05 Remove Ticket Costs Barrilleaux, Chris (20,554) UTILITY & EXECUTIVE MANAGEMENT ESI AJ21-07 Remove Non-Recoverable Costs Barrilleaux, Chris (13,637) UTILITY & EXECUTIVE MANAGEMENT ESI AJ21-08 Remove costs from the Gas Operations organization. Barrilleaux, Chris (1,281) UTILITY & EXECUTIVE MANAGEMENT ESI AJ21-11 Correct Capital Projects Tumminello, Stephanie B 1 UTILITY & EXECUTIVE MANAGEMENT ESI AJ22 Affiliate Portion of Employee Changes and Wage Increases Considine, Michael P 21,631 ESI (231,900) UTILITY & EXECUTIVE MANAGEMENT Total (231,900) Total (231,900) 3-65

Amounts may not add or tie to other schedules due to rounding. EXHIBIT JFD-D Domino, Joe Page 1 of 1 This page has been intentionally left blank.

2011 ETI Rate Case 3-66 SOAH Docket No. XXX-XX-XXXX PUC Docket No. 39896 ETI 2011 Rate Case ETI EXHIBIT NO. 34 DOCKET NO. 39896

APPLICATION OF ENTERGY § PUBLIC UTILITY COMMISSION TEXAS, INC. FOR AUTHORITY § TO CHANGE RATES AND § OF TEXAS RECONCILE FUEL COSTS §

DIRECT TESTIMONY

OF

ROBERT R. COOPER

ON BEHALF OF

ENTERGY TEXAS, INC.

NOVEMBER 2011

2011 ETI Rate Case 8-1 ENTERGY TEXAS, INC. DIRECT TESTIMONY OF ROBERT R. COOPER 2011 RATE CASE TABLE OF CONTENTS Page I. Introduction and Purpose 1 II. The Entergy System Planning Principles and Objectives 4 III. Resources Acquired through Planning Analysis Processes in this Reconciliation Period 11 A. Resources Acquired Through an RFP Process 12 B. Resources Acquired Through Bilateral Negotiations 16 IV. Determination of Allocation for Power Purchases 18

EXHIBITS Exhibit RRC-1 PPR Capacity Costs (Highly Sensitive)

2011 ETI Rate Case 8-2 Entergy Texas, Inc Page 1 of 25 Direct Testimony of Robert R. Cooper 2011 Rate Case

1 I. INTRODUCTION AND PURPOSE 2 Q. PLEASE STATE YOUR NAME AND CURRENT BUSINESS ADDRESS.

3 A. My name is Robert R. Cooper. My business address is Parkwood II Bldg., 4 Suite 300, 10055 Grogans Mill Road, The Woodlands, Texas 77380.

6 Q. BY WHOM ARE YOU EMPLOYED AND IN WHAT CAPACITY?

7 A. I am employed by Entergy Services, Inc. (“ESI”), the service company for 8 the Entergy Operating Companies (“Operating Companies”), as Manager, 9 Generation Planning & Models. In that capacity, among other activities, I 10 provide resource planning services to the Operating Companies, which 11 include Entergy Texas, Inc. (“ETI” or “the Company”), Entergy Gulf States 12 Louisiana, L.L.C. (“EGSL”), Entergy Arkansas, Inc. (“EAI”), Entergy 13 Louisiana, LLC (“ELL”), Entergy Mississippi, Inc. (“EMI”), and Entergy New 14 Orleans, Inc. (“ENOI”). These six Operating Companies, along with ESI, 15 acting as agent, are collectively referred to as the “System.” I work in the 16 System Planning and Operations (“SPO”) department, which is an 17 organization within ESI.

19 Q. PLEASE DESCRIBE YOUR CURRENT JOB RESPONSIBILITIES.

20 A. My current job responsibilities include long-term supply-side resource 21 planning for the Operating Companies, including ETI. In this function, I 22 direct a staff that performs engineering and economic analyses of the

2011 ETI Rate Case 8-3 Entergy Texas, Inc Page 2 of 25 Direct Testimony of Robert R. Cooper 2011 Rate Case

1 power and fuel supply requirements of the System in order to provide a 2 reliable and economical resource portfolio.

4 Q. PLEASE DESCRIBE YOUR EDUCATION AND BUSINESS 5 EXPERIENCE.

6 A. I have a Masters Degree in Business Administration from the University of 7 New Orleans and a Bachelor of Science Degree in Engineering from 8 Southern Illinois University. After receiving my Bachelor’s degree, I 9 worked for four years with Illinois Power Company in Decatur, Illinois, as a 10 Planning Engineer in the Load Management Research Department. I 11 began working for Entergy in 1984 as a Research Analyst in the 12 Forecasting department of Middle South Services, Inc., where I performed 13 economic analyses of end-use energy consumption. I have worked for 14 Entergy Services, Inc., or its predecessors, in various planning capacities 15 over the last 27 years. In the ensuing years, I progressed into positions of 16 increasing responsibility in roles that involved engineering, economic and 17 market analysis. In 1996, I was promoted to Segment Manager 18 responsible for the development, implementation and measurement of 19 demand-side programs for small business markets. In July of 1999, I took 20 the position as Manager of Generation Planning in the Energy 21 Management Organization. In February of 2004, that position was 22 expanded to include responsibility for the activities, staff and planning 23 models of production cost analysis.

2011 ETI Rate Case 8-4 Entergy Texas, Inc Page 3 of 25 Direct Testimony of Robert R. Cooper 2011 Rate Case

1 Q. ON WHOSE BEHALF ARE YOU FILING THIS DIRECT TESTIMONY?

2 A. I am filing this Direct Testimony on behalf of ETI.

4 Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY?

5 A. My testimony provides the following: 6 • A description of the planning principles and objectives utilized by 7 the System in determining the resources that were necessary to 8 meet its load requirements, and how the selected products fulfill 9 those objectives; 10 • A discussion of the types of resources that were acquired in 11 furtherance of the System’s planning principles to meet the 12 System’s incremental resource needs since the Company’s last 13 base rate case. 1 As a part of this discussion, I describe the 14 evaluation process that was conducted for the formal Requests for 15 Proposals (“RFPs”) that were issued for the System during the 16 Reconciliation Period. I also identify resources acquired through 17 bilateral negotiations resulting from unsolicited offers; 18 • A discussion of the allocation among the Operating Companies of 19 the purchased power resources included in this reconciliation filing; 20 • The identification and quantification of capacity costs the Company 21 requests be recovered through a Purchased Power Recovery In the Company’s last base rate case, Docket No. 37744, I discussed resources that became effective during the rate year for that case (July 2009 through June 2010), which period is included in the current fuel reconciliation period.

2011 ETI Rate Case 8-5 Entergy Texas, Inc Page 4 of 25 Direct Testimony of Robert R. Cooper 2011 Rate Case

1 Rider. As part of this discussion, I discuss new contracts beginning 2 after the Test Year and effective during the Rate Year.

4 II. THE ENTERGY SYSTEM PLANNING PRINCIPLES 5 AND OBJECTIVES 6 Q. WILL YOU PLEASE PROVIDE A SUMMARY OF THE ENTERGY 7 SYSTEM’S PLANNING PRINCIPLES AND OBJECTIVES?

8 A. The System’s planning principles, planning objectives, and resource 9 supply strategies are applied by the Operating Committee with the intent 10 to produce a portfolio of resources to match the needs of the customers of 11 the Operating Companies. They include the following six basic resource 12 supply objectives: 13 • Reliability – Provide adequate resources to meet customer peak 14 demands with adequate reliability.

15 • Production Cost – Baseload Supply Requirements – Provide low- 16 cost baseload resources to serve baseload requirements (the load 17 level that is expected to be exceeded for at least 85% of all hours of 18 the year).

19 • Production Cost – Load-following Supply Requirements – Provide 20 efficient, dispatchable load-following resources to serve the time- 21 varying load shape levels that are above the baseload requirement 22 load levels.

2011 ETI Rate Case 8-6 Entergy Texas, Inc Page 5 of 25 Direct Testimony of Robert R. Cooper 2011 Rate Case

1 • Generation Portfolio Enhancement – Improve the efficiency of the 2 generation portfolio and avoid an over-reliance on aging resources.

3 • Risk Mitigation – Price Stability – Mitigate the effects on production 4 costs of price volatility associated with uncertainties in fuel and 5 purchased power costs.

6 • Risk Mitigation – Supply Diversity – Mitigate the effects on 7 production costs of major supply disruptions that could occur from 8 concentrated or systematic risks, for example outages of a single 9 generation facility.

11 Q. WILL YOU PLEASE DESCRIBE THE BACKGROUND FOR THE 12 ENTERGY SYSTEM’S RESOURCE SUPPLY STRATEGY?

13 A. The generation and bulk transmission facilities of the Operating 14 Companies are planned and operated as a single, integrated electric 15 system, pursuant to the Entergy System Agreement (“System 16 Agreement”), which has been approved by the Federal Energy Regulatory 17 Commission (“FERC”). When planning for the System, the Operating 18 Committee is guided by the System’s current planning principles, planning 19 objectives, and resource supply strategies for short- and long-term 20 planning. The System Agreement charges the Operating Committee with 21 the responsibility for, among other things, determining generation addition 22 or acquisition plans that provide capacity to meet System load projections 23 and reliable service to customers at a reasonable cost consistent with

2011 ETI Rate Case 8-7 Entergy Texas, Inc Page 6 of 25 Direct Testimony of Robert R. Cooper 2011 Rate Case

1 sound business practice and operational constraints. Consistent with the 2 System Agreement, the resource supply plans that serve as the basis for 3 acquisition of the resources must necessarily address the System needs 4 as a whole.

5 The current planning objectives and principles were approved 6 initially by the Operating Committee in June 2002 and subsequently 7 refined and adopted in January 2003 as the Strategic Supply Resource 8 Plan. Guided by these principles and objectives, the Operating 9 Committee periodically approves updates to the resource plan developed 10 by the SPO organization which address the current and future needs of 11 the Operating Companies’ retail customers. Beginning in 2009, the 12 Strategic Supply Resource Plan was renamed the Strategic Resource 13 Plan (“SRP”) in order to more accurately reflect the full scope of the 14 planning effort; however, the basic set of principles and objectives that 15 guide long-term portfolio design remains unchanged.

17 Q. WILL YOU PLEASE EXPLAIN HOW THE SRP GUIDES THE TYPES OF 18 PURCHASES MADE BY SPO?

19 A. The SRP is a set of principles and processes that gives SPO guidance on 20 the mix of owned generation and different types of power purchases that 21 best meet customers’ needs for reliable service at a reasonable cost. The 22 SRP includes three major planning horizons: strategic (20-year horizon), 23 tactical (3-year horizon), and annual (1-year horizon). First, my group, the

2011 ETI Rate Case 8-8 Entergy Texas, Inc Page 7 of 25 Direct Testimony of Robert R. Cooper 2011 Rate Case

1 SPO Planning Analysis Group, periodically assesses the capability of the 2 generating resources available to the System. This group also develops a 3 load forecast, which is updated periodically or when significant changes 4 occur to the System. A comparison of the load forecast and the resource 5 capability is used to identify the needs of the System and guide the 6 planning processes for obtaining additional resources. As provided in the 7 SRP, the additional resource needs are initially met through the strategic 8 planning process with the solicitation of proposals for long-term resources.

9 The results of the strategic planning process influence the quantity and 10 type of resources solicited in the next phase, the tactical planning process.

11 The tactical planning process solicits proposals for “limited-term” products 12 that meet the criteria set to satisfy the System’s needs for this horizon.

13 After these limited-term products have been secured, the remainder of the 14 System’s needs is met through the annual planning process, with short- 15 term power purchases of one year or less. The use of these different 16 planning processes is designed to result in a diversified portfolio of reliable 17 resources at a reasonable cost.

19 Q. WHY DOES THE SYSTEM NEED A MIX OF GENERATION TYPES?

20 A. The planning process seeks to provide a portfolio of resources that, in 21 total, achieve the planning objectives in a balanced and cost effective 22 manner. Because the cost and performance characteristics of 23 technologies differ, no single technology or generation type economically

2011 ETI Rate Case 8-9 Entergy Texas, Inc Page 8 of 25 Direct Testimony of Robert R. Cooper 2011 Rate Case

1 meets the diverse planning objectives of the SRP. For example, baseload 2 resources typically cost more to construct on a per-megawatt (“MW”) basis 3 than peaking resources but operate with relatively low variable cost.

4 Despite its relatively high construction cost, a base load resource can be 5 the most economic alternative to serve the base load supply role, because 6 the resource is expected to operate in most hours at high utilization levels 7 due to its relatively lower fuel cost. Consequently, the capital cost of a 8 base load resource is spread over many megawatt hours (“MWh”) of 9 output, resulting in a relatively low total production cost on a $/MWh basis.

10 Conversely, a peaking unit is expected to operate at low capacity 11 utilization levels. As such, the most economic alternatives for peaking and 12 reserve capacity would be units with a relatively low capital cost, even if 13 their variable costs were higher. In both cases, the unique cost structure 14 of a resource allows it to be the lowest reasonable cost alternative for the 15 particular supply role that the unit will fulfill. This is why the SRP seeks to 16 match generation supply to customer load shape requirements.

18 Q. HOW DOES THE SYSTEM DETERMINE THE CAPABILITY OF ITS 19 GENERATION RESOURCES FOR THE SRP PLANNING PROCESSES?

20 A. The System uses seasonal ratings for its generating units to reflect the 21 fact that the output of units may vary depending on the season of the year 22 and the condition of the generating unit. In the heat of the summer, the 23 output of a unit on the System may not be equal to the Maximum

2011 ETI Rate Case 8-10 Entergy Texas, Inc Page 9 of 25 Direct Testimony of Robert R. Cooper 2011 Rate Case

1 Demonstrated Capability of that unit. The seasonal capability of the 2 System’s units is reassessed semi-annually. In addition to resources 3 owned by the Operating Companies, the System includes in its planning 4 assumptions any commitments for resources resulting from wholesale 5 transactions that commenced prior to the applicable SRP planning 6 process. This includes, for example, East Texas Electric Cooperative 7 Inc.’s (“ETEC”) approximately 230 MW of generating resources that ETI 8 obtains as part of the partial requirements agreement between ETEC and 9 ETI.

11 Q. PLEASE DESCRIBE THE PROCESS THAT THE SYSTEM USES TO 12 DEVELOP THE LOAD FORECAST FOR THE SRP PLANNING 13 PROCESSES.

14 A. The load forecasting process used by the System is designed to forecast 15 hourly data for each study year, jurisdiction, and customer class. Metrix 16 LT is used to prepare the load forecast, using numerous sources of input 17 data. The sources of input data that are used in the Metrix LT model 18 include an energy sales forecast, historical weather data, historical load 19 shape data, historical curtailment information for curtailable/interruptible 20 customers, and transmission loss estimates. The load forecast also

2011 ETI Rate Case 8-11 Entergy Texas, Inc Page 10 of 25 Direct Testimony of Robert R. Cooper 2011 Rate Case

1 includes a projection of the amount of load that is expected to be served 2 under full or partial requirements wholesale customers, such as ETEC. 2

4 Q. WHAT IS THE NET EFFECT THAT ETEC LOAD PLACES ON ETI’S 5 SYSTEM NEED AT THE SAME TIME ETEC PROVIDES RESOURCES 6 TO ETI?

7 A. ETEC’s partial requirements load is netted against the ETEC resources 8 credited to ETI and placed under the control of the Entergy System 9 Operator. ETEC’s incremental partial requirements demand is projected 10 to be less than the 150 MW minimum billing demand under the partial 11 requirements contract, which is further discussed by Company witness 12 Phillip May.

14 Q. BASED ON THE ASSESSMENT OF LOAD REQUIREMENTS AND 15 GENERATING CAPABILITY, WHAT IS THE COMPANY’S NET 16 RESOURCE NEED?

17 A. In addition to owned resources as well as resources currently under 18 contract and the resources I discuss in my testimony, ETI projects an 19 incremental need of 260 MW in 2012 and 504 MW in 2013.

ETEC’s partial requirements contract with ETI provides for a minimum billing demand of 150 MW.

2011 ETI Rate Case 8-12 Entergy Texas, Inc Page 11 of 25 Direct Testimony of Robert R. Cooper 2011 Rate Case

1 III. RESOURCES ACQUIRED THROUGH PLANNING ANALYSIS 2 PROCESSES IN THIS RECONCILIATION PERIOD 3 Q. HOW IS THIS SECTION OF YOUR TESTIMONY ORGANIZED?

4 A. The System generally acquires the resources necessary to satisfy the 5 forecasted load requirements of the System either through some type of 6 RFP process to solicit competitive bids for resources or bi-lateral 7 negotiations when the System receives unsolicited offers. Accordingly, I 8 have divided the resources discussed in this section into those acquired 9 through an RFP process and those acquired through bilateral negotiations 10 following an unsolicited offer.

12 Q. WOULD SPO ACQUIRE A RESOURCE THOUGH BILATERAL 13 NEGOTIATIONS RATHER THAN AN RFP PROCESS?

14 A. Yes. As a practical matter, SPO cannot control whether an interested 15 party makes an unsolicited offer outside the context of an RFP or the 16 timing of such an offer. It is appropriate that such offers be evaluated in 17 the context of the needs of the System. SPO generally employs the same 18 criteria as that used in an RFP to determine the need for the resource and 19 the reasonableness of the price.

2011 ETI Rate Case 8-13 Entergy Texas, Inc Page 12 of 25 Direct Testimony of Robert R. Cooper 2011 Rate Case

1 Q. OTHER THAN YOUR TESTIMONY, DOES THE COMPANY’S FILING 2 INCLUDE OTHER SUPPORT FOR THE TRANSACTIONS YOU 3 DISCUSS IN YOUR TESTIMONY?

4 A. Yes. The workpapers to Schedule I-15 includes portions of Entergy 5 Operating Committee minutes and attachments that support the resources 6 discussed and the allocation of those resources among the Operating 7 Companies. My workpapers, discussed below, also provide support for 8 the selection of these resources.

10 A. Resources Acquired Through an RFP Process 11 Q. PLEASE PROVIDE AN OVERVIEW OF THE ACQUISITION OF 12 RESOURCES THROUGH THE RFP PROCESS.

13 A. The formal RFP process begins with the identification of the resource 14 needs for the System, as I discussed above, which results in the 15 determination of which products the RFP will request. SPO then oversees 16 the design, development, and implementation of the RFP. As further 17 described below, an Independent Monitor is typically involved with this 18 process. The objectives, products sought, process and other details 19 unique to each RFP are reduced to writing and publicly posted on ESI’s 20 RFP website, and interested parties are notified of the posting. I include in 21 my workpapers the Main Body of the RFP conducted during the 22 Reconciliation Period and discussed in my testimony.

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1 Once the proposals have been received, the Planning Analysis 2 group evaluates the proposals under strict confidentiality protocols, and 3 recommends to the Operating Committee which proposals should be 4 placed on the short list for further negotiation. After the Operating 5 Committee approves the proposals to be included on the short list, SPO’s 6 Supply Procurement group manages the negotiations with the short-listed 7 bidders. The resource planning principles, planning objectives, and 8 resource supply strategies that the Operating Committee adopted to guide 9 the overall planning process were described in detail in each formal RFP 10 issued by ESI on behalf of the Operating Companies.

12 Q. WHAT IS THE ROLE OF AN INDEPENDENT MONITOR (IM) IN THE 13 RFP PROCESS?

14 A. ESI’s RFP process typically involves the retention of an IM to ensure that 15 the RFP is conducted in a fair and impartial manner. The IM (1) oversees 16 the design and implementation of the RFP solicitation, evaluation, 17 selection, and contract negotiations process to ensure that it will be 18 impartial and objective, and (2) provides an objective, third-party 19 perspective concerning ESI’s efforts to ensure that all proposals are 20 treated in a consistent fashion and that no undue preference is provided to 21 any Bidder. The IM’s responsibilities for each RFP are set out in a Scope 22 of Work made available on the Company’s RFP website. The Main Body 23 of the RFP discussed in my testimony and the IM report corresponding to

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1 that RFP is made part of my workpapers. Although I have attached these 2 IM reports as workpapers, it is important to note that the content of that 3 report is solely the work of the IM, who is entirely independent of the 4 Company and not a consultant to the Company.

6 Q. IN GENERAL, HOW ARE RFP PROPOSALS EVALUATED?

7 A. For the RFP, the evaluation process considers the effect of each of the 8 proposals on the overall expected production costs of the System. The 9 evaluation of life-of-unit (“LOU”) and day-ahead MUCCO and MUCPA 10 proposals include production cost simulations to account for the fact that 11 each of the resources has different characteristics, such as cost, 12 availability, and duration. 3 The objective of the production costing 13 evaluation process is to identify the resources that produced the lowest 14 reasonable total System production cost for each incremental 15 kilowatt added.

16 Qualitative evaluations of various non-economic factors are also 17 performed. As the field of viable candidates narrowed, further 18 negotiations with bidders are held to secure the most favorable 19 terms possible.

A MUCCO is a Multi-year Unit-Contingent Call Option. A MUCPA is a Multi-year Unit- Contingent Purchase Agreement for a generating resource.

2011 ETI Rate Case 8-16 Entergy Texas, Inc Page 15 of 25 Direct Testimony of Robert R. Cooper 2011 Rate Case

1 Generally, the evaluation of day-ahead MUCCO and dispatchable 2 MUCPA products, the two most prevalent RFP products requested, use a 3 process that included the following three major steps: 4 1. initial individual proposal screening and production cost 5 analysis which result in individual candidate proposal 6 selection, and individual candidate proposal deliverability 7 evaluation; 8 2. verification of individual candidate proposals considering 9 deliverability evaluation; and 10 3. portfolio identification, portfolio production cost analysis, 11 portfolio deliverability evaluation, and portfolio selection.

13 Q. WHAT ROLE DOES THE OPERATING COMMITTEE SERVE IN THE 14 DETERMINATION OF WHICH RFP OFFERS ARE ACCEPTED?

15 A. As Company witness Patrick J. Cicio testifies, the Operating Committee 16 has been delegated the authority through the System Agreement to 17 determine which resources should be acquired for the System to meet its 18 load obligations and serve its customers at a reasonable cost. As such, 19 the Operating Committee determines which RFP offers are accepted once 20 they have been evaluated through the RFP process.

2011 ETI Rate Case 8-17 Entergy Texas, Inc Page 16 of 25 Direct Testimony of Robert R. Cooper 2011 Rate Case

1 Q. DID ESI CONDUCT AN RFP DURING THE RECONCILIATION PERIOD 2 OR TEST YEAR THAT RESULTED IN THE ACQUISITION OR 3 PROCUREMENT OF RESOURCES OR CONTRACTS THAT WERE 4 ALLOCATED TO ETI?

5 A. Yes. During 2009 and 2010, ESI conducted the Summer 2009 Request 6 for Proposals for Long-Term Supply-Side Resources (“Summer 2009 7 RFP”), seeking combined-cycle gas turbine (“CCGT”), combustion turbine 8 (“CT”), and solid fuel resources. The Summer 2009 RFP resulted in a ten- 9 year power purchase agreement (“PPA”) between Calpine Energy 10 Services, L.P. (“Calpine”) and ETI for the purchase of 485 megawatts 11 (“MW”) of capacity and energy from Calpine’s Carville Energy Center in 12 St. Gabriel, Louisiana (the “Carville Contract”). Purchases pursuant to the 13 Carville Contract will begin during the Rate Year, on June 1, 2012, and will 14 be discussed in Section V of my testimony.

16 B. Resources Acquired Through Bilateral Negotiations 17 Q. WHAT RESOURCES WERE ACQUIRED THROUGH BI-LATERAL 18 NEGOTIATIONS OUTSIDE OF A FORMAL RFP PROCESS?

19 A. The following resources were acquired through bi-lateral negotiations in 20 the Reconciliation Period and Test Year: 21 • a 75 MW one-year call option between ETI and NRG for capacity 22 and energy from the Exxon facility in Beaumont, Texas, with a 23 delivery period that began on March 1, 2011; and

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1 • a 100 MW MUCCO between ETI and Dow Pipeline for capacity and 2 energy from the Dow Pipeline facility in Iberville Parish, Louisiana 3 with a three-year delivery term that began in April 1, 2011.

4 In addition, as discussed later in my testimony, ETI contracted with Sam 5 Rayburn Municipal Power Agency ("SRMPA") for 225 MW of SRMPA 6 system resources for a delivery term of twenty-five years. Deliveries are 7 scheduled to begin on December 1, 2011.

9 Q. PLEASE DISCUSS GENERALLY THE DECISIONS TO ENTER INTO 10 THESE BILATERAL PURCHASES.

11 A. The 75 MW purchase from NRG resulted from SPO’s ongoing 12 communications with generators in the ETI service area regarding 13 opportunities to address ETI’s continuing need for capacity. The 100 MW 14 purchase from Dow Pipeline was an extension of a then-existing contract 15 for the same level of capacity that first began on January 1, 2008. The 225 16 MW purchase from SRMPA will provide benefits to ETI as a source of 17 much-needed long-term base load capacity at an economically attractive 18 price.

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1 IV. DETERMINATION OF ALLOCATION FOR POWER PURCHASES 2 Q. HOW DOES THE ENTERGY SYSTEM DETERMINE THE ALLOCATION 3 OF NEW RESOURCES AMONG THE OPERATING COMPANIES?

4 A. As discussed in Company witness Cicio’s Direct Testimony, the System 5 Agreement (Section 4.02) allows the Operating Committee to allocate 6 certain power purchases on a System-wide basis to all the Operating 7 Companies by their responsibility ratios, or to directly assign a purchase to 8 less than all of the Operating Companies, and do so on a basis other than 9 responsibility ratio. The following factors have been considered by the 10 Operating Committee in recent resource allocation decisions: 11 • Relative Total Production Costs – Long-term total production cost 12 trends among the Operating Companies.

13 • Peak Load + 10% Capacity Deficit – Each Operating Company’s 14 resource capability position relative to its peak load plus a minimum 15 reserve level of 10%.

16 • Supply Role Capacity Deficit – Each Operating Company’s 17 resource position with regard to its capacity requirements by supply 18 role.

19 • Responsibility Ratio – Each Operating Company’s resource 20 position relative to its responsibility ratio.

21 • Supply Risks – Each Operating Company’s supply risks associated 22 with generation unit availability and price volatility.

2011 ETI Rate Case 8-20 Entergy Texas, Inc Page 19 of 25 Direct Testimony of Robert R. Cooper Revised - Errata No. 2 2011 Rate Case ,, \ 1 Q. WHAT IS ETl'S ALLOCATION OF THE CONTRACTS YOU IDENTIFY 2 ABOVE?

3 A The contracts were allocated by the Operating Committee to ETI as 4 follows: 5 • the 485 MW Carville Contract was allocated 50% to ETI and 50% to 6 EGSL, pursuant to ETl's sale of 50% of the associated capacity 7 and energy to EGSL under Service Schedule MSS-4 of the Entergy 8 System Agreement; 4 9 • the 75 MW purchase from NRG was allocated 100% to ETI; 10 • the 100 MW purchase from Dow Pipeline was allocated 50% to 11 ETI; and 12 • the 225 MW purchase from SRMPA was allocated 100% to ETI.

13 As discussed previously, the allocation decisions associated with 14 these transactions are recorded in Minutes from the Entergy Operating 15 Committee meetings, which minutes and attachment are included in the 16 workpapers to Schedule 1-15 of the filing.

18 " PUROi IASED POWER RECOVERY RIDER __.fl_.

19 Q. WHAT IS THE PURPOSE OF THIS SECTION OF YOUR TESTIMONY?

20 A Af:. elesc1 ibed ii 1 ti 1e testil 11011y ef Philli13 R. May, the Gem pa Ry is 21 ~es-ting tnat all purchased capacity costs, i11cludi11g Se1vice Schedule Company witness Cicio describes the Entergy System Agreement and its associated schedules.

2011 ET! Rate Case 8-21 Entergy Texas, Inc Page 20 of 25 Direct Testimony of Robert R. Cooper 2011 Rate Case i

2 through a Purchased Power Recovery Rider ("PPR"). T · section of my 3 testimony addresses the following: 4 • I provide an adjusted Year level of purchased capacity 5 Company requests authority to recover

7 • My update of the Test Year purchased capacity costs includes a 8 description of new purchased power contracts that become 9 effective after the Test Year and will be effective during the Rate 10 Year.

11 As explained by Company witness May, if the PPR is not approved by the 12 Commission, the Company requests that the adjusted Test Year amounts 13 be included for recovery in base rates.

15 Q. WHAT ARE THE ADJUSTED TEST YEAR PURCHASED CAPACITY 16 COSTS TO BE RECOVERED IN THE PPR?

17 A. The total adjusted Test Year purchased capacity costs for the Company is 18 roughly $276 million. This level of expense represents Test Year costs 19 adjusted for known and measurable changes that will occur in the Rate 20 Year. Highly Sensitive Exhibit RRC-1, attached hereto, provides a break 21 down of this amount. The exhibit separates capacity costs into four 22 categories: (1) third-party contracts, (2) legacy affiliate contracts (or 23 Service Schedule MSS-4 agreements), (3) other affiliate contracts, and (4)

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1 Service Schedule MSS-1 costs. The term “legacy affiliate contracts” 2 refers to those affiliate contracts resulting from the December 31, 2007 3 jurisdictional separation of Entergy Gulf States, Inc. (“EGSI”) into ETI and 4 EGSL, pursuant to which ETI purchases its allocated share of natural gas 5 power plants located in Louisiana and owned by EGSL as a result of the 6 separation. “Other affiliate contracts” refers to all other affiliate contracts 7 whereby ETI purchases capacity and associated energy from another 8 Entergy Operating Company.

10 Q. PLEASE DISCUSS THE NEW THIRD-PARTY CONTRACTS THAT 11 WERE NOT IN PLACE DURING THE TEST YEAR, BUT WILL BE IN 12 PLACE DURING THE RATE YEAR.

13 A. The following new third-party contracts are included in this category: 14 • The 485 MW Carville Contract—As discussed previously, this ten- 15 year PPA resulted from the Summer 2009 RFP and is allocated 16 50% to ETI. Purchases under the Carville Contract will begin on 17 June 1, 2012. ETI participates in the Carville Contract as the only 18 counterparty to Calpine for the full level of capacity and associated 19 energy supplied under the contract. ETI then sells EGSL 50% of 20 the capacity and energy for the full term of the contract in return for 21 EGSL paying ETI half of all costs under the contract, pursuant to 22 Service Schedule MSS-4 of the Entergy System Agreement. ETI 23 (along with EGSL) previously received capacity and energy from

2011 ETI Rate Case 8-23 Entergy Texas, Inc Page 22 of 25 Direct Testimony of Robert R. Cooper 2011 Rate Case

1 the Carville Energy Center pursuant to a one-year contract from 2 June 1, 2008 through May 31, 2009.

3 • A twenty-five year PPA between SRMPA and ETI for 225 MW of 4 capacity and associated energy. Deliveries under the SRMPA PPA 5 are scheduled to begin on December 1, 2011. SRMPA is a joint 6 powers agency composed of the municipalities of Liberty, 7 Livingston and Jasper, Texas and the City of Vinton, Louisiana. In 8 a recent filing at FERC, SRMPA indicated that it restructured its 9 long-term supply portfolio (some of which is obtained from affiliates 10 of ETI) so that it could reduce its annual debt service obligations, 11 which restructuring left SRMPA with additional resources that it 12 offered to ETI. 5 The SRMPA PPA will be a “system contingent” 13 transaction, meaning SRMPA is required to deliver energy from its 14 system resources to the extent its resources are available.

16 Q. WHAT ARE THE SERVICE SCHEDULE MSS-1 COSTS INCLUDED IN 17 THE EXHIBIT RRC-1?

18 A. As described by Company witness Cicio, ETI’s MSS-1 (Reserve 19 Equalization) costs are a function of the level of resources owned or 20 controlled by ETI relative to its share of System load. The MSS-1 costs 21 included in Highly Sensitive Exhibit RRC-1 reflect the known and

Entergy Services, Inc., Docket No. ER11-4415. See also EWO Marketing, Inc., Docket No. ER11-4410.

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1 measurable changes to ETI’s resources as discussed above relative to 2 ETI’s projected share of System load for the same time period.

4 Q. DO THE PPAS YOU HAVE DISCUSSED ABOVE HELP SATISFY 5 IDENTIFIED RELIABILITY NEEDS OF THE SYSTEM, INCLUDING ETI?

6 A. Yes, for the reasons discussed above and as further set out in the 7 presentations to the Operating Committee contained in the workpapers to 8 Schedule I-15.

10 Q. DOES ETI EXPECT TO PLACE A SIGNIFICANT RELIANCE ON 11 PURCHASED POWER RESOURCES BEYOND THE RATE YEAR?

12 A. Yes. My Exhibit RRC-1 demonstrates that ETI’s current resource mix 13 places a significant reliance on purchased power, more than doubling the 14 amount of third-party capacity purchases reflected in the rate year for 15 ETI’s last rate case (rate year of July 2010 – June 2011), for an increase 16 of more than $36 million. I expect that consideration of and reliance on 17 third-party purchases will continue.

19 Q. DO THE COMPANY'S RECENT RESOURCE COMMITMENTS TAKE 20 INTO CONSIDERATION ENVIRONMENTAL INTEGRITY?

21 A. Yes. For example, two recent long-term transactions resulting from RFPs 22 include express terms requiring the seller's compliance with all applicable

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1 environmental laws, including compliance with changes in environmental 2 laws and regulations.

4 Q. ARE THE PPAS EXPECTED TO IMPROVE SERVICE OR LOWER 5 COSTS TO CUSTOMERS?

6 A. Yes. As discussed above, the purchases are intended to help meet the 7 Company’s (and the System's) reliability needs, including those of ETI, at 8 a cost lower than other alternatives. RFPs and negotiations conducted on 9 behalf of the Company and the other Entergy Operating Companies are 10 designed specifically to realize that objective. As a typical Entergy 11 Operating Company RFP puts it: a primary objective of the RFP is “to 12 solicit competitive proposals to…meet customer’s needs in a reliable and 13 economical manner.” The evaluation process is designed “to…select 14 proposals that meet ESI’s resource planning and risk management 15 objectives at the lowest reasonable cost.” The primary objective of the 16 economic evaluation is to “procure resources that balance the System’s 17 objectives, including reliability, lowest reasonable cost.” This process 18 includes a net System Benefits analysis that “relies on production cost 19 modeling to assess the effects of each proposal, or combination 20 of…proposals on total System cost.” Based on this production cost 21 analysis, a portion of the energy from the resources described above is 22 expected to displace energy from higher cost system-owned generation.

23 These objectives and analyses guided the procurement of the resources

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1 described previously in my testimony—whether obtained through RFP 2 solicitation and or bilateral (unsolicited) negotiations.

4 Q. DOES THIS CONCLUDE YOUR TESTIMONY?

5 A. Yes.

2011 ETI Rate Case 8-27 This page has been intentionally left blank.

2011 ETI Rate Case 8-28 Exhibit RRC-1 2011 TX Rate Case Page 1 of 1 (Public Version)

This exhibit contains information that is confidential and will be provided under the terms of the terms of the Protective Order (Confidentiality Disclosure Agreement) entered in this case.

2011 ETI Rate Case 8-29 This page has been intentionally left blank.

2011 ETI Rate Case 8-30 SOAH Docket No. XXX-XX-XXXX PUC Docket No. 39896 ETI 2011 Rate Case ETI EXHIBIT NO. 39 DOCKET NO. 39896

APPLICATION OF ENTERGY § PUBLIC UTILITY COMMISSION TEXAS, INC. FOR AUTHORITY § TO CHANGE RATES AND § OF TEXAS RECONCILE FUEL COSTS §

DIRECT TESTIMONY

OF

PATRICK J. CICIO

ON BEHALF OF

ENTERGY TEXAS, INC.

NOVEMBER 2011

2011 ETI Rate Case 9-1 ENTERGY TEXAS, INC. DIRECT TESTIMONY OF PATRICK J. CICIO 2011 RATE CASE

TABLE OF CONTENTS Page I. Introduction 1 II. costs associated with The Entergy System Agreement 5 A. Summary 5 B. The Entergy System Agreement 6 C. Billing for Entergy System Agreement-Related Revenues and Costs 31 III. The Energy and Fuel Management Class of Costs 37 A. The SPO Organization 39 B. Overview of Costs – Energy and Fuel Management Class 43 C. Necessity of Services 48 D. Reasonableness of Energy and Fuel Management Charges 58 E. Billing of Energy and Fuel Management Charges 64 F. Summary of SPO Capital Charges 71 IV. Conclusion 75

2011 ETI Rate Case 9-2 EXHIBITS Exhibit PJC-1 Entergy System Agreement Exhibit PJC-2 July 2008 Intra-System Bill Exhibit PJC-3 Families and Functions Chart Exhibit PJC-4 Functions and Classes Chart Exhibit PJC-5 SPO Organization Chart Exhibit PJC-6 Summary of SPO Capital Charges

Exhibit PJC-A Affiliate Billings by Witness, Class and Department Exhibit PJC-B Affiliate Billings by Witness, Class and Project Exhibit PJC-C Affiliate Billings by Witness, Class, Department and Project Exhibit PJC-D Pro Forma Summary

2011 ETI Rate Case 9-3 Entergy Texas, Inc. Page 1 of 75 Direct Testimony of Patrick J. Cicio 2011 Rate Case

1 I. INTRODUCTION Q. PLEASE STATE YOUR NAME AND CURRENT BUSINESS ADDRESS.

3 A. My name is Patrick J. Cicio. My business address is Parkwood II Bldg., 4 Suite 100, 10055 Grogan’s Mill Road, The Woodlands, Texas 77380.

6 Q. ON WHOSE BEHALF ARE YOU PROVIDING THIS TESTIMONY?

7 A. I am testifying on behalf of Entergy Texas, Inc. (“ETI” or the “Company”).

9 Q. BY WHOM ARE YOU EMPLOYED AND IN WHAT CAPACITY?

10 A. I am Director, Regulatory Affairs and Energy Settlements for the System 11 Planning and Operations (“SPO”) organization of Entergy Services, Inc. 12 (“ESI”), the service company affiliate of the Entergy Operating 13 Companies, which coordinate, plan, and operate their electric generation 14 and bulk transmission facilities as a single, integrated electric system (the 15 “Entergy System” or the “System”). As Director, Regulatory Affairs and 16 Energy Settlements, I am responsible for administering the Intra-System 17 Billing associated with the Entergy System Agreement, overseeing fuel

ESI is the services company affiliate of the Entergy Operating Companies that provides engineering, planning, accounting, technical, regulatory, and other administrative support services to each of the Entergy Operating Companies.

In addition to ETI, the Entergy Operating Companies are Entergy Arkansas, Inc. (“EAI”); Entergy Mississippi, Inc. (“EMI”); Entergy New Orleans, Inc. (“ENO”); Entergy Gulf States Louisiana, L.L.C. (“EGSL”); and Entergy Louisiana, LLC (“ELL”). On December 19, 2005, EAI gave notice that it will terminate its participation in the System Agreement effective December 18, 2013. Entergy Mississippi provided similar notice to the Operating Companies on November 8, 2007 that it would terminate its participation effective November 7, 2015.

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1 and power settlements and reporting, as well as compliance with the 2 electric reliability standards, directing the department budgets, and giving 3 guidance to the Regulatory Affairs Group which coordinates the SPO 4 regulatory support function.

6 Q. PLEASE DESCRIBE YOUR EDUCATIONAL BACKGROUND AND 7 PROFESSIONAL EXPERIENCE.

8 A. I joined Gulf States Utilities Company (subsequently, Entergy Gulf States, 9 Inc. (“EGSI”)) in June 1981 as an accountant. In April 1983, I was 10 transferred to the Regulatory Affairs Department and held a variety of 11 positions from September 1986 until December 1993, including 12 Supervisor, Rate Regulation; Director, Technical and Administrative 13 Support; Director, Regulation-Louisiana. In January 1994, I joined ESI as 14 Manager, Regulations where I was responsible for coordinating 15 merger-related human resource issues and for ensuring the timely and 16 consistent implementation of related policies. I also provided oversight to 17 all merger-related proceedings. In May 1996, I became a Senior Lead 18 Analyst in the Plant Operations Business Support group where I was 19 responsible for preparing financial analyses and performing other 20 business support functions for the Plant Operations organization. In 21 January 1997, I moved to the SPO as a Senior Staff Analyst in the 22 Resource Planning Department. In that role, I was responsible for 23 coordinating all regulatory activities (rate filings, requests for information,

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1 etc.). In December 1998, I became the Manager – Planning Models and 2 Analysis, where I was responsible for producing production costing studies 3 and load and energy forecasts for the Entergy Operating Companies. In 4 February 2004, I became the Manager – Energy Analysis and Reporting, 5 where I was responsible for the preparation of the intra-system bill and the 6 settlement of gas, oil and power transactions for all Entergy Operating 7 Companies. In February 2008, I became the Director of Supply 8 Procurement and Asset Optimization, where I was responsible for the 9 preparation of long-term requests for proposals and the negotiation of 10 long-term purchased power contracts and power plant acquisitions. In 11 February 2010, I became the Director of Compliance and Business 12 Support, where I was responsible for compliance with the electric reliability 13 standards, and SPO’s budget and information technology departments. In 14 February 2011 I accepted my current role. I graduated from Texas A&M 15 University in 1981 with a Bachelor of Business Administration degree in 16 Finance. I am a Certified Public Accountant in the State of Texas, 17 Certificate Number 49910.

19 Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY?

20 A. My testimony has two major purposes: (1) I support the costs and 21 revenues associated with ETI’s participation in the Entergy System 22 Agreement during the test year of July 1, 2010 to June 30, 2011 (the “Test 23 Year”) and during the fuel-related Reconciliation Period (July 2009 through

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1 June 2011); and (2) I present the Energy and Fuel Management Class of 2 affiliate costs that were billed to ETI during the Test Year. In the first part 3 of my testimony, I discuss how ETI coordinates its generation and bulk 4 transmission functions with the other Entergy Operating Companies via 5 the Entergy System Agreement, a Federal Energy Regulatory 6 Commission (“FERC”)-approved tariff that includes seven FERC-approved 7 rate schedules. I will also explain the various Service Schedules and 8 provisions referenced in the Entergy System Agreement. In general, this 9 part of my testimony addresses the box labeled “Intra-System Bill” on 10 Figure MHT-3 of Company witness Michelle H. Thiry’s testimony.

11 With respect to the second part of my testimony, I demonstrate that 12 costs included in the Energy and Fuel Management Class of affiliate costs 13 that were billed to ETI during the Test Year are necessary and 14 reasonable; that the price charged to ETI for these affiliate services is not 15 higher than the prices charged by ESI for the same item or class of items 16 to other affiliates or non-affiliates; and that these costs represent the 17 actual cost of these services. I also sponsor certain capital costs 18 associated with the services of the SPO from July 2009 through the end of 19 the Test Year (June 30, 2011).

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1 11. COSTS ASSOCIATED WITH THE ENTERGY SYSTEM AGREEMENT 2 A. Summary Q. PLEASE SUMMARIZE THE COSTS AND REVENUES INCURRED 4 PURSUANT TO THE ENTERGY SYSTEM AGREEMENT THAT ARE 5 INCLUDED IN THIS PROCEEDING.

6 A. Costs allocated to ETI pursuant to the terms of the Entergy System 7 Agreement relate to the following three components of the Company's 8 filing: 9 • Reconciliation of Past Costs: With respect to the Company's fuel 1O factor, the Company will be reconciling costs incurred under 11 Service Schedules MSS-3 and MSS-4, costs allocated to ETI from 12 Joint Account Purchases, and the net balance from Joint Account 13 Sales under the terms of Service Schedule MSS-5.

14 • 15 sponsors the of

19 • Base Rates: The Company requests base rate recovery of the Test 20 Year amount of Service Schedule MSS-2 costs. Additionally, in the 21 event the Commission does not approve the PPR, Service I describe each of these service schedules in more detail later in my testimony.

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1 Schedule MSS-1 and MSS-4 costs that would have been included 2 in the PPR would be included in the Company’s base rates.

4 B. The Entergy System Agreement Q. WHAT IS THE ENTERGY SYSTEM AGREEMENT?

6 A. The Entergy System Agreement is a FERC-approved tariff which 7 mandates that the Operating Companies operate as a single, integrated 8 System. As stated in Section 3.01 of the Entergy System Agreement, its 9 purpose is “to provide the contractual basis for the continued planning, 10 construction, and operation of the electric generation, transmission and 11 other facilities of the Operating Companies in such a manner as to 12 achieve economies consistent with the highest practicable reliability of 13 service, subject to financial considerations, reasonable utilization of 14 natural resources and minimization of the effect on the environment.” The 15 Entergy System Agreement also provides a basis for the equalization 16 among the Operating Companies of any imbalances of costs arising from 17 the construction, ownership, or operation of facilities that are used for the 18 collective benefit of all the Operating Companies.

19 Consistent with the above discussion, the Commission has 20 characterized the Entergy System Agreement as: 21 the tariff approved by the FERC that provides the basis for 22 the operation and planning of the Entergy System, including 23 the [then] five Operating Companies. The System 24 Agreement governs the wholesale-power transactions 25 among the Operating Companies by providing for joint

2011 ETI Rate Case 9-9 Entergy Texas, Inc. Page 7 of 75 Direct Testimony of Patrick J. Cicio 2011 Rate Case

1 operation and establishing the bases for equalization among 2 the Operating Companies, the costs associated with the 3 construction ownership and operation of the Entergy System 4 facilities.

5 The current version of the Entergy System Agreement was entered 6 into on April 23, 1982, and, as subsequently amended, is among ESI and 7 each of the Operating Companies. It was initially approved by the FERC on June 13, 1985, in Opinion No. 234, Middle South Energy, Inc., 31 9 FERC (C.C.H.) ¶ 61,305 (1985). Exhibit PJC-1 is a copy of the current 10 version of the Entergy System Agreement.

12 Q. WHAT ENTITY ADMINISTERS THE ENTERGY SYSTEM AGREEMENT?

13 A. The tariff states that the overall administration of the Entergy System 14 Agreement is to be carried out by the Entergy Operating Committee.

15 During the Reconciliation Period and Test Year, ETI’s operations were 16 represented on the Operating Committee by Mr. Joseph F. Domino, the 17 President and CEO of Entergy Texas. During the Reconciliation Period 18 and Test Year, the daily administration of the Entergy System Agreement 19 was carried out by the SPO under the direction of the Operating 20 Committee. The SPO was also responsible for the administration of 21 billings between the Operating Companies in accordance with certain 22 Service Schedules of the Entergy System Agreement.

Docket No. 32710, Order on Rehearing at 8 (Finding of Fact 39).

2011 ETI Rate Case 9-10 Entergy Texas, Inc. Page 8 of 75 Direct Testimony of Patrick J. Cicio 2011 Rate Case

1 Q. WHAT ARE THE DUTIES OF THE OPERATING COMMITTEE?

2 A. Section 5.06 of the Entergy System Agreement sets forth the duties of the 3 Operating Committee. In part, those duties include being responsible for 4 the day-to-day administration of the Entergy System Agreement, making 5 decisions with respect to the installation of generation and bulk power 6 transmission facilities, determining the amount and timing of generating 7 reserves sufficient to ensure the reliable supply of capacity and energy to 8 the Operating Companies’ customers, providing supervision for the 9 System Operator, studying and determining additions and changes in 10 facilities necessary to keep abreast of the production and transmission 11 requirements of the System, and coordinating arrangements to procure or 12 sell power outside of the System. The Entergy System Agreement 13 empowers the Operating Committee to make the key decisions regarding 14 the acquisition and allocation of generating resources and electric energy 15 for the Operating Companies.

17 Q. WHY DO THE OPERATING COMPANIES JOINTLY PLAN AND 18 OPERATE THEIR ELECTRIC SYSTEMS?

19 A. By jointly planning and operating their electric systems, the Operating 20 Companies are able to aggregate their loads and jointly dispatch their 21 resources to serve that aggregated load. The Entergy System resources 22 are economically dispatched, subject to reliability and operating 23 constraints that exist at any given time, to achieve the lowest cost of

2011 ETI Rate Case 9-11 Entergy Texas, Inc. Page 9 of 75 Direct Testimony of Patrick J. Cicio 2011 Rate Case

1 energy for the combined System as a whole. The aggregation of load and 2 resources into a single system means that the combined resources of the 3 Operating Companies can be optimally dispatched, allowing each 4 Operating Company’s load to be supplied with the most economical 5 resources available to the System. In addition, the Operating Companies 6 experience increased reliability on both a planning and an operating basis 7 as a result of coordinated operations. Through the combined reliance on 8 many diverse generating units, fuel sources, and bulk power 9 interconnections, each Operating Company is better protected from 10 service interruptions or disturbances caused by the loss of generating 11 units, fuel supply disruptions, and/or transmission outages or constraints.

12 The FERC recognized the benefits of System-wide planning and 13 operations in its Opinion 234-A (Order Denying Rehearing and Granting 14 Interventions), wherein the FERC held: 15 We reaffirm that the Middle South [now Entergy] companies 16 appropriately approach power planning on a systemwide 17 basis, whereby the individual companies’ needs are the 18 component parts of the System power plan. Implementation 19 of the System plan, however, requires that the individual 20 companies’ needs be subsumed by the greater interest of 21 the entire system.

22 This finding by the FERC was quoted with approval by the United 23 States Supreme Court. This confirms that planning and operating

32 F.E.R.C. ¶ 61,425 at 61,958 (1985).

Miss. Power & Light v. Miss. Ex. Rel. Moore, 487 U.S. 354, 376,108 S.Ct. 2428, 2441 (1988).

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1 decisions were and are to be made on a system-wide basis for the benefit 2 of the System as a whole, recognizing the fact that such system-wide 3 basis for decisions might cause the interests of an individual Operating 4 Company in a particular decision to be outweighed by the overall good of 5 the System over time.

7 Q. PLEASE EXPLAIN HOW THE COSTS OF PROVIDING AND 8 TRANSMITTING THE ELECTRICITY TO SERVE THE AGGREGATED 9 SYSTEM’S LOAD ARE ALLOCATED AMONG THE OPERATING 10 COMPANIES.

11 A. These costs are allocated pursuant to the terms of the Entergy System 12 Agreement and its Service Schedules, which I describe below. The 13 Supreme Court has held that FERC's exclusive jurisdiction applies to 14 power allocations that affect wholesale rates. It is my understanding that 15 these allocations are binding on States, and States must treat those 16 allocations as fair and reasonable when determining retail rates.

See Entergy Louisiana, Inc. v. Louisiana Public Service Commission, 539 U.S. 39, 123 S. Ct. 2050 (2003); Mississippi Power v. Miss. Ex. Rel. Moore, 487 U.S. 354, 371, 108 S. Ct. 2428, 2441 (1988).

2011 ETI Rate Case 9-13 Entergy Texas, Inc. Page 11 of 75 Direct Testimony of Patrick J. Cicio 2011 Rate Case

1 Q. WHAT ARE THE SERVICE SCHEDULES ASSOCIATED WITH THE 2 ENTERGY SYSTEM AGREEMENT?

3 A. There are seven Service Schedules, each of which is a FERC-filed rate 4 schedule, associated with the Entergy System Agreement. They are: 5 MSS-1 - Reserve Equalization; 6 MSS-2 - Transmission Equalization; 7 MSS-3 - Exchange of Electric Energy Among the Companies; 8 MSS-4 - Unit Power Purchase; 9 MSS-5 - Distribution of Revenue from Sales Made for the Joint 10 Account of All Companies; 11 MSS-6 - Distribution of Operating Expenses of System Operations 12 Center; and 13 MSS-7 - Merger Fuel Protection Procedure.

15 Q. PLEASE DESCRIBE SERVICE SCHEDULE MSS-1.

16 A. Service Schedule MSS-1 (which is called “Reserve Equalization” in the 17 Entergy System Agreement) prescribes a method for sharing some of the 18 fixed costs of generating capability among Operating Companies. One of 19 the benefits of participating in a pooling arrangement such as the Entergy 20 System Agreement is the ability to rely on System reserves. (The term 21 “reserves” in this context refers to the difference between MW of capability 22 and MW of peak load; it can be measured either for the System or for an 23 Operating Company.) Each Operating Company owns or controls its own

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1 capability, but all Companies can draw upon the aggregate capability of 2 the System in determining the adequacy of reserves. However, some 3 Operating Companies own more than their share of the System’s total 4 capability relative to their load, and thus own more than their share of 5 System reserves. Other Companies own less than their share. These 6 Operating Companies are known as “long” and “short” Operating 7 Companies, respectively. “Long” Companies are those with more 8 generation capability, relative to their monthly peak load. “Short” 9 Companies are those with less generation relative to their monthly peak 10 load. A company’s position and the extent to which it is “long” or “short” 11 can change over time. The Service Schedule MSS-1 formula provides for 12 payments by “short” Companies to “long” Companies.

14 Q. WHAT IS THE BASIS FOR DETERMINING AN OPERATING 15 COMPANY’S SHARE OF SYSTEM RESERVES?

16 A. An Operating Company’s share of System reserves is determined using a 17 concept defined in the Entergy System Agreement as “Responsibility 18 Ratio,” which is an allocator that reflects the relative contribution of each 19 Operating Company to the System’s coincident peak load – in other 20 words, an Operating Company’s coincident peak load divided by the 21 System peak load, calculated on a rolling twelve-month average. An 22 Operating Company’s share of System reserves is the product of that

2011 ETI Rate Case 9-15 Entergy Texas, Inc. Page 13 of 75 Direct Testimony of Patrick J. Cicio 2011 Rate Case

1 Operating Company’s Responsibility Ratio and the total level of 2 System reserves.

4 Q. HOW ARE MSS-1 PAYMENTS DETERMINED?

5 A. A short Company makes a payment only for the MW by which it is “short.”

6 The payments are computed monthly by multiplying the Company’s MW 7 shortfall times a $/MW rate for the cost of owning reserve capability. The 8 rate is based on the fixed operating cost of certain oil- and gas-fired 9 generating units owned by the “long” Companies .

11 Q. ARE RESERVE EQUALIZATION PAYMENTS DISCRETIONARY 12 AMONG THE OPERATING COMPANIES?

13 A. No. The FERC-approved Entergy System Agreement mandates that the 14 Operating Companies make and receive Reserve Equalization payments 15 in accordance with Service Schedule MSS-1.

16 In a prior ETI reconciliation case, the Commission found: 17 By approving Service Schedule MSS-1, the FERC has 18 approved the method by which the Operating Companies 19 share the cost of maintaining sufficient reserves to provide 20 reliability for the Entergy System as a whole.

Docket No. 32710, Order on Rehearing at 9 (Finding of Fact 42).

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1 Q. DOES ETI PAY ANY MORE FOR RESERVE EQUALIZATION 2 PAYMENTS MADE PURSUANT TO SERVICE SCHEDULE MSS-1 THAN 3 ANY OTHER OPERATING COMPANY?

4 A. No. Service Schedule MSS-1 is a formula rate, and ETI’s payments or 5 receipts in any particular month will be the same as any other similarly 6 situated Operating Company. In any given month, all of the Operating 7 Companies that are “short” and which must make MSS-1 payments will 8 pay the same rate, based on a weighted average of the rates for each of 9 the “long” Operating Companies, for each MW of capability for which it 10 is responsible.

12 Q. DO RESERVE EQUALIZATION PAYMENTS RESULT FROM 13 RESOURCES REQUIRED TO MEET THE ENTERGY SYSTEM’S LOAD 14 REQUIREMENTS?

15 A. Yes. As I explained above, the Entergy System is planned and operated 16 as a single, integrated electric system to satisfy the combined load 17 requirements of the Operating Companies. An essential element of 18 providing reliable and efficient delivery of electricity to customers is 19 maintaining an adequate level of capability through ownership or control of 20 generation. ETI’s Reserve Equalization payments reflect its allocated 21 share of the cost of maintaining adequate capability for the System as 22 a whole.

2011 ETI Rate Case 9-17 Entergy Texas, Inc. Page 15 of 75 Direct Testimony of Patrick J. Cicio 2011 Rate Case

1 Q. WHERE ARE SERVICE SCHEDULE MSS-1 AMOUNTS IDENTIFIED IN 2 THIS PROCEEDING?

3 A. Amounts allocated pursuant to Service Schedule MSS-1 are shown in 4 Schedule H-12.4 a-g. Mr. Cooper, in his Exhibit RRC-1, identifies the total 5 rate year amount of Service Schedule MSS-1 costs sought to be included 6 in rates.

8 Q. PLEASE DESCRIBE SERVICE SCHEDULE MSS-2.

9 A. Service Schedule MSS-2 prescribes the method for equalizing the 10 ownership costs associated with certain transmission systems facilities 11 owned and operated by each Operating Company. Service Schedule 12 MSS-2 determines each Operating Company’s Transmission 13 Responsibility by summing the System’s Net Inter-Transmission 14 Investments and multiplying that total by each Operating Company’s 15 Responsibility Ratio.

17 Q. HOW ARE THE PAYMENT AMOUNTS FOR SERVICE SCHEDULE 18 MSS-2 DETERMINED?

19 A. Each Operating Company’s Net Inter-Transmission Investment is 20 subtracted from its Transmission responsibility. The result is multiplied by 21 the System Average Ownership Cost (“AOC”) in order to calculate the 22 amount that each Operating Company should pay or receive each month.

23 The AOC develops ownership costs of certain transmission investments.

2011 ETI Rate Case 9-18 Entergy Texas, Inc. Page 16 of 75 Direct Testimony of Patrick J. Cicio 2011 Rate Case

1 Q. HOW IS THE AOC DETERMINED?

2 A. The AOC rate consists of capital costs, federal and state income tax rates, 3 and operating expenses scaled by investment costs. Section 20.06 of the 4 Entergy System Agreement shows the AOC formula. This formula uses 5 financial factors similar to those used in the Service Schedule MSS-1 6 calculation.

8 Q. ARE TEST YEAR SERVICE SCHEDULE MSS-2 EXPENSES INCLUDED 9 IN ETI’S COST OF SERVICE?

10 A. Yes. ETI’s MSS-2 expenses are identified in Schedule A as discussed by 11 Company witness Michael P. Considine.

13 Q. HAS THE COMMISSION PREVIOUSLY CONSIDERED SERVICE 14 SCHEDULE MSS-2 PAYMENTS?

15 A. Yes. In its Second Order on Rehearing dated October 13, 1998, in Docket 16 No. 16705, Finding of Fact No. 96N, the Commission stated: 17 The FERC has approved the relevant parts of the ESA 18 (Entergy System Agreement) as amended to reflect the 19 inclusion of EGS. In Opinion No. 385, the FERC expressly 20 accepted an amendment to the ESA which added Gulf 21 States to the ESA as an operating subsidiary. EGS’ MSS-2 22 expenses are therefore mandated by the FERC.

Service Schedule MSS-2 billing parameters are in effect from June 1 to the succeeding May 31 based on the preceding year’s results.

2011 ETI Rate Case 9-19 Entergy Texas, Inc. Page 17 of 75 Direct Testimony of Patrick J. Cicio 2011 Rate Case

1 Furthermore, as the Commission ordered in Docket No. 16705, 2 Conclusion of Law No. 11D, "under Mississippi Power & Light Co. v. 3 Mississippi, 487 U.S. 354, 369-370, 108 S.Ct. 2428 (1988), a state utility 4 commission must treat FERC-mandated system agreement payments as 5 reasonably incurred operating expenses for the purpose of setting retail 6 rates." The Commission went on to say that Mississippi Power & Light 7 Co. preempts the Commission from disallowing Service Schedule MSS-2 8 expenses.

10 Q. PLEASE DESCRIBE SERVICE SCHEDULE MSS-3.

11 A. Service Schedule MSS-3 serves two functions. It first mandates how 12 energy will be allocated and priced among the Operating Companies. The 13 second function is to provide for payments and receipts in accordance 14 with the provisions of Opinion Nos. 480 and 480-A.

16 Q. IS THERE A FUNDAMENTAL PRINCIPLE AT WORK BEHIND THE 17 OPERATION OF SERVICE SCHEDULE MSS-3 AS IT RELATES TO 18 ENERGY ALLOCATION?

19 A. Yes. The fundamental principle of the Entergy System Agreement is that, 20 subject to the operational and reliability constraints imposed on the 21 System, the lowest-cost resources available to the System Dispatcher are 22 the first resources used to meet the aggregate System load, without 23 regard to which Operating Company owns the resource or which

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1 Operating Company’s load is being served. Although the economic 2 dispatch of the entire System will result in total System generation output 3 matching total System load, in any given hour the generating output of 4 some Operating Companies will be greater than their individual load, and 5 the generating output of other Operating Companies will be less than their 6 individual load. Therefore, after the System is economically dispatched, 7 an energy accounting process is conducted to, in effect, have the 8 Operating Companies that are “short” on energy in an hour compensate 9 the “long” Companies for the energy that was used to meet the short 10 Companies’ needs.

11 Because this calculation is performed for each hour, in any given 12 hour, an Operating Company may either be taking exchange energy or 13 supplying exchange energy, but not both. This exchange energy 14 accounting is set out in Service Schedule MSS-3.

16 Q. HOW DOES SERVICE SCHEDULE MSS-3 WORK WITH RESPECT TO 17 THE OPERATIONS OF EXCHANGE ACCOUNTING?

18 A. Service Schedule MSS-3 allocates all of the System’s energy resources 19 among the Operating Companies. Under MSS-3, an Operating Company 20 retains the energy (and the associated costs) actually produced from its 21 lowest-cost resources if those resources are needed to meet the loads of 22 its customers. Only after the needs of an Operating Company’s own 23 customers have been met will the excess energy that the Operating

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1 Company generated in a particular hour, and the associated costs, be 2 allocated to other Operating Companies. This allocation of excess energy 3 pursuant to Service Schedule MSS-3 is referred to as “Exchange Energy” 4 or “Pool Energy.” Operating Companies whose resources provided an 5 amount of energy that was greater than their load in an hour furnish 6 energy to the Entergy Energy Exchange (the “Exchange”), and 7 Companies whose load is greater than the amount of energy provided by 8 their resources in an hour are allocated energy from the Exchange.

9 However, it is important to note that, in total, MSS-3 is a zero-sum game.

10 The sum of the MSS-3 payments and receipts for all of the Operating 11 Companies for any individual hour is zero.

13 Q. HOW IS THE MSS-3 ACCOUNTING PERFORMED?

14 A. Service Schedule MSS-3 is an automated, after-the-fact allocation 15 mechanism. That allocation of energy and associated costs required by 16 the System Agreement is performed within a computer program known as 17 the Intra-System Bill. For a more detailed discussion of the ISB, see the 18 next section.

19 The process that is used to allocate System energy is sometimes 20 known as a “stacking” process. An example of the stacking process is 21 shown in the following Figure PJC-1. As may be seen in that example, the 22 underlying process is to stack the amount of energy produced by each 23 Operating Company’s resources from lowest cost to highest cost in

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1 separate stacks for each Operating Company. Then, again within each 2 hour, the amount of energy resources within each Operating Company’s 3 stack is compared to the amount of energy consumed by its customers. If, 4 for an individual company, the amount of energy produced is greater than 5 the amount of energy used by its customers, the energy (and associated 6 costs) at the top end of the stack (in essence, above the level needed for 7 that Company’s own customers) is allocated to the Exchange. A 8 Company whose resources produced less energy than the amount of 9 energy its own customers used is allocated the deficit amount of energy 10 from the Exchange. Each of these transactions occurs at cost. Operating 11 Companies that have excess energy that is allocated to the Exchange 12 receive a payment, as defined in Section 30.08 of the Entergy System 13 Agreement, that is based on average fuel costs (plus an O&M- and SO2 - 14 based adder), and the Companies that have energy allocated to them 15 from the Exchange pay the weighted average cost of all of the energy 16 allocated to the Exchange in that hour.

2011 ETI Rate Case 9-23 Entergy Texas, Inc. Page 21 of 75 Direct Testimony of Patrick J. Cicio 2011 Rate Case

Figure PJC - 1 MSS - 3 EXCHANGE ENERGY ACCOUNTING EXAMPLE Stack by ILLUSTRATIVE cost; Allocate excess, at cost, to the Exchange Exchange Purchase at $40/MWH Company 1 Gas at Gas at $60/MWH $60/MWH Company 2 Gas at $75/MWH Allocate at Coal at average cost $20/MWH of MW Exchange Energy Company 1 Coal at $20/MWH Company 2 Coal at $25/MWH

Company 1 Company 2 Nuclear at Nuclear at $10/MWH $10/MWH

Resources Load To Resources Load From Exchange Exchange

Operating Company 1 Operating Company 2

1 Q. HAS THE COMMISSION PREVIOUSLY ADDRESSED WHETHER 2 COSTS INCURRED BY ETI UNDER SERVICE SCHEDULE MSS-3 ARE 3 REASONABLE?

4 A. Yes. In its Order on Rehearing in Docket No. 15102, the Commission 5 addressed costs incurred under Service Schedule MSS-3 in the following 6 Findings of Fact:

2011 ETI Rate Case 9-24 Entergy Texas, Inc. Page 22 of 75 Direct Testimony of Patrick J. Cicio 2011 Rate Case

1 202. Schedule MSS-3 of the ESA (Entergy System Agreement) 2 determined the pricing and exchange of energy among EGS and 3 the affiliate EOCs (Entergy Operating Companies) during the 4 reconciliation period.

5 203. By approving Schedule MSS-3 and the ESA, the Federal Energy 6 Regulatory Commission (FERC) has determined how the EOCs will 7 be reimbursed for energy sold to the exchange pool and how the 8 EOCs, including EGS, will purchase energy from the 9 exchange pool.

10 207. The FERC has determined that the ESA and Schedule MSS-3 is a 11 just and reasonable way of allocating energy costs and revenues 12 among the EOCs, including EGS, and has determined that the 13 charges imposed on EGS by operation of the ESA are fair and 14 reasonable in comparison to the charges imposed on the 15 other EOCs.

16 As these Findings of Fact demonstrate, the Commission has already 17 concluded that costs incurred pursuant to Service Schedule MSS-3 18 are reasonable.

See also Docket No. 15102, Proposal for Decision at 94-96; Docket No. 16705, Second Order on Rehearing at 138 (Conclusion of Law 11D); Docket No. 32710, Order at 9 (Finding of Fact 43).

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1 Q. ARE THE COSTS THAT ETI INCURS UNDER SERVICE SCHEDULE 2 MSS-3 ANY MORE THAN THE COSTS INCURRED BY ANY OTHER 3 ENTERGY OPERATING COMPANY UNDER THAT SERVICE 4 SCHEDULE?

5 A. No. ETI incurs the exact same cost per kWh for energy from the Service 6 Schedule MSS-3 Exchange pool as does any other Entergy Operating 7 Company that is allocated energy from the Service Schedule MSS-3 8 Exchange in the same hour.

10 Q. ARE SERVICE SCHEDULE MSS-3 EXPENSES INCLUDED IN THIS 11 CASE?

12 A. Yes. Service Schedule MSS-3 Exchange revenue and expense is 13 identified in Schedules H-12.4 a-g and H-12.5 b-e.

15 Q. ARE ANY OTHER TRANSFERS OF ENERGY GOVERNED BY SERVICE 16 SCHEDULE MSS-3?

17 A. Yes. The allocation of energy for sales to off-system companies made for 18 the joint account of all the Operating Companies (Joint Account Sales) is 19 made pursuant to Service Schedule MSS-3. According to Service 20 Schedule MSS-3, any costs incurred by the Operating Companies whose 21 sources supplied the sale are paid out of the gross revenue received for 22 such sales. Then, the remaining revenue from such sales (the “net

2011 ETI Rate Case 9-26 Entergy Texas, Inc. Page 24 of 75 Direct Testimony of Patrick J. Cicio 2011 Rate Case

1 balance”) is divided among the Operating Companies in accordance with 2 Service Schedule MSS-5.

4 Q. PLEASE DESCRIBE SERVICE SCHEDULE MSS-4.

5 A. Service Schedule MSS-4 prescribes a method for determining the 6 payment for a unit power purchase between Operating Companies and/or 7 the sale of power purchased by another Operating Company. A unit 8 power purchase is defined as the purchase of a portion of a Designated 9 Generating Unit’s capability, which entitles the purchaser to receive each 10 hour that portion of the total energy generated by that unit.

12 Q. PLEASE EXPLAIN HOW AFFILIATED POWER PURCHASES ARE 13 MADE PURSUANT TO SERVICE SCHEDULE MSS-4.

14 A. An Operating Company may enter into a resource-specific power 15 transaction with another Operating Company pursuant to Service 16 Schedule MSS-4. Service Schedule MSS-4 is a cost-based formula rate 17 that bills the buyer a monthly per-kilowatt rate relating to the non-fuel cost 18 and a per kWh rate relating to the actual energy cost for the participating 19 unit subject to the transaction. During the term of a Service Schedule 20 MSS-4 transaction, the resource is considered to be under the control of 21 the purchasing Operating Company for purposes of cost responsibility and 22 allocation of energy under the Entergy System Agreement.

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1 Q. HAS THE COMMISSION ADDRESSED SERVICE SCHEDULE MSS-4 2 COSTS?

3 A. Yes. The Commission previously recognized: 4 Service Schedule MSS-4 of the System Agreement sets 5 forth the method for determining the payment for unit power 6 purchases between Operating Companies. By approving 7 Service Schedule MSS-4, the FERC has approved the 8 methodology for pricing Inter-Operating Company unit power 9 purchases.

11 Q. ARE THE RATES PAID BY ETI UNDER SERVICE SCHEDULE MSS-4 12 ANY MORE THAN THE RATES CHARGED TO ANY OTHER ENTERGY 13 OPERATING COMPANY UNDER THAT SERVICE SCHEDULE?

14 A. No. Service Schedule MSS-4 is a cost-based formula rate. That same 15 formula rate is applied to each Service Schedule MSS-4 transaction 16 between Operating Companies. The cost structure for the underlying 17 resource will be unique to each resource, but the rate charged is the same 18 for all Operating Companies.

20 Q. ARE SERVICE SCHEDULE MSS-4 AMOUNTS ADDRESSED IN THIS 21 PROCEEDING?

22 A. Yes. Service schedule MSS-4 energy and capacity costs are identified in 23 Schedule H-12.4 a-g. For purposes of this proceeding MSS-4 contracts

Docket No. 32710, Order at 9 (Finding of Fact 44).

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1 have been labeled as either “legacy” (those transactions involving the 2 purchase of power from generating resources owned by ETI’s 3 predecessor, Entergy Gulf States, Inc.), or “other” (all other MSS-4 4 transactions).

6 Q. PLEASE DESCRIBE SERVICE SCHEDULE MSS-5.

7 A. Service Schedule MSS-5 prescribes the method for distributing the net 8 balance from Joint Account Sales, which are wholesale sales to third 9 parties made by the System on behalf of all of the Operating Companies.

10 The System makes such sales when they can be made at a price that is 11 expected to exceed the System’s incremental cost. As mentioned above, 12 in accordance with Service Schedule MSS-3, any costs associated with 13 these Joint Account Sales first are deducted from the gross revenue 14 received for such sales and distributed to the Operating Companies 15 whose sources supplied the sale. Service Schedule MSS-5 provides that 16 the remainder of the revenues or deficit in revenues (the “Net Balance”) is 17 distributed among the Operating Companies in proportion to the 18 Responsibility Ratio of each Operating Company.

20 Q. ARE SERVICE SCHEDULE MSS-5 REVENUES INCLUDED IN THIS 21 CASE?

22 A. Yes. Those revenues shown in Schedule H-12.5 b-e are credited to ETI’s 23 fuel balance as revenues from off-system sales.

2011 ETI Rate Case 9-29 Entergy Texas, Inc. Page 27 of 75 Direct Testimony of Patrick J. Cicio 2011 Rate Case

1 Q. PLEASE DESCRIBE SERVICE SCHEDULE MSS-6.

2 A. Service Schedule MSS-6 sets forth a method by which the costs incurred 3 in providing and operating the System Operations Center may be 4 distributed among the Entergy Operating Companies. During the Test 5 Year, these costs were included in the ESI affiliate billings.

7 Q. PLEASE DESCRIBE SERVICE SCHEDULE MSS-7.

8 A. Service Schedule MSS-7 is entitled “Merger Fuel Protection Procedure” 9 and resulted from the merger between Gulf States Utilities Company and 10 Entergy. This service schedule expired by its own terms prior to the 11 Reconciliation Period.

13 Q. DOES THE ENTERGY SYSTEM AGREEMENT PERMIT PURCHASES 14 OF POWER FROM THE WHOLESALE MARKET?

15 A. Yes. In particular, the Entergy System Agreement addresses wholesale 16 market purchases in Sections 5.06(p), 4.02 and 4.03. Section 5.06(p) of 17 the Entergy System Agreement requires the Operating Committee to 18 coordinate the procurement of power for one or more of the Operating 19 Companies for either reliability or economic purposes.

Gulf States Utilities Company was renamed Entergy Gulf States, Inc. and was subsequently separated into EGSL and ETI.

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1 Section 4.02 of the Entergy System Agreement, entitled 2 “Purchased Capacity and Energy,” empowers the Operating Committee to 3 specify the conditions under which one or more individual Operating 4 Companies can purchase capacity for their own account, which is then 5 treated as a resource included in the purchasing Company’s (or 6 Companies’) capacity as if it was an owned resource. Generally, as 7 described in more detail in Company witness Robert R. Cooper’s 8 testimony, the Operating Committee has adopted a broad set of planning 9 principles and objectives that drive the resource allocation process.

10 However, the factors that the Operating Committee considers when 11 evaluating the allocation of limited or long-term resources – such as 12 System reliability, relative production costs, and the match between an 13 Operating Company’s load profile and the mix of supply types – are rooted 14 in the requirements of, among others, Sections 3.01 and 3.05 of the 15 Entergy System Agreement. All of the power purchase agreements 16 discussed in Company witness Cooper’s testimony were purchased 17 pursuant to Section 4.02 of the Entergy System Agreement.

18 Section 4.03, “Energy Purchased by Services,” of the Entergy 19 System Agreement dictates when and how ESI may make purchases from 20 third parties on behalf of the Operating Companies. It provides that ESI 21 “may purchase energy under economic dispatch or emergency conditions 22 for the joint account of all the Operating Companies. The energy 23 purchased shall be allocated to each Operating Company in proportion to

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1 its Responsibility Ratio in effect at the end of the preceding month.” Most 2 of the purchases described in the testimony of Company witness Michelle 3 H. Thiry, especially those purchases with a term of one month or less, are 4 such purchases that are made for the benefit of the System when ESI, 5 who is delegated the authority under the Entergy System Agreement to 6 make the purchases, deems such purchases economical or necessary.

7 When such purchases are made for the joint account of all the Operating 8 Companies, ETI is allocated its Responsibility Ratio share of all of those 9 purchases in each hour.

11 Q. DOES THE ENTERGY SYSTEM AGREEMENT PROVIDE THE 12 OPERATING COMPANIES ANY DISCRETION IN ACCEPTING AN 13 ALLOCATED PORTION OF PURCHASES?

14 A. No. The Operating Companies are required to take their respective 15 allocated share of purchased power because those purchases arise out of 16 the joint economic dispatch of the System. Each Operating Company 17 must bear responsibility for its share of purchases made for the benefit of 18 the System. Moreover, the joint planning obligations of the Entergy 19 System Agreement require each Operating Company to accept its 20 allocated share of purchased capacity and energy, when so allocated by 21 the Operating Committee.

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1 Q. ARE THE PURCHASES ALLOCATED TO ETI ALWAYS USED TO 2 SERVE ETI’S CUSTOMERS’ NEEDS?

3 A. No, not necessarily. ETI’s allocated share of purchases is considered an 4 ETI source for the purposes of allocating energy and costs under Service 5 Schedule MSS-3. Therefore, in any given hour, if ETI has resources in 6 excess of its needs and a wholesale power purchase is among the lowest 7 cost resources, that purchase stays with ETI’s customers for that hour.

8 However, if ETI has resources in excess of its needs and its allocated 9 share of a purchase is more costly than other ETI resources, ETI’s 10 allocated share of the purchase is assigned to the Exchange for that hour, 11 for which ETI is compensated.

13 Q. CAN ETI EVER RECEIVE MORE THAN ITS ALLOCATED SHARE OF A 14 PURCHASE?

15 A. No, not directly. However, as described above, purchases are treated as 16 an Operating Company resource under Service Schedule MSS-3.

17 Therefore, if ETI’s needs were in excess of its resources in any given hour 18 and thus ETI was purchasing energy from the Exchange, it may receive 19 some purchased energy that was originally allocated to another Entergy 20 Operating Company that later flowed through the Exchange. However, 21 under the terms of the Entergy System Agreement, such allocations are 22 considered to be from the Exchange and are not considered a Joint 23 Account Purchase allocation.

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1 C. Billing for Entergy System Agreement-Related Revenues and Costs Q. HOW ARE OPERATING COMPANIES BILLED FOR THE COSTS 3 INCURRED PURSUANT TO THE ENTERGY SYSTEM AGREEMENT?

4 A. The Operating Companies are billed through a monthly Intra-System 5 Bill (“ISB”).

7 Q. WHAT IS THE ISB?

8 A. The ISB is a program that creates inter-company invoices prepared by 9 ESI. The ISB details the costs to be paid and revenues to be received by 10 each Operating Company for the transactions that occurred pursuant to 11 the Entergy System Agreement.

13 Q. HOW IS THE ISB PREPARED?

14 A. The ISB is prepared by a custom computer program that incorporates the 15 algorithms specified in the Entergy System Agreement. On an hourly 16 and/or daily basis, fuel cost, unit generation, Operating Company load, 17 and wholesale transactions data are collected and compiled into the ISB’s 18 database records.

The Intra-System Bill is distinct from the intra-system affiliate billing process discussed in the Direct Testimony of Company witness Stephanie B. Tumminello.

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1 Q. HOW IS THE MONTHLY ISB ORGANIZED?

2 A. The monthly ISB is divided into attachments, with each attachment 3 containing multiple pages, if necessary. These are the current 4 attachments, as of July 2010: 5  Attachment 1 - kWh Disposition by Operating Company, Joint 6 Account Purchases and Individual Company Purchases by 7 Operating Company; 8  Attachment 2 - Exchange Energy (to/from), Unit power Purchases, 9 AECC Excess Energy; 10  Attachment 3 - Joint Account Sales and Net Balance; 11  Attachment 4 - Peak Load Data and Responsibility Ratios; 12  Attachment 5 – Owned or Contracted Capacity, Reserve & 13 Transmission Equalization; 14  Attachment 6 - Operating Company Summaries and System Total; 15  Attachment 11 – Summary of Joint Account Purchases and 16 Individual Company Purchases; and 17  Attachment 12 - Fiber Optics Equalization.

19 Q. PLEASE BRIEFLY DESCRIBE EACH ATTACHMENT OF THE 20 MONTHLY ISB.

21 A. Attachment 1 shows the monthly totals of energy allocated to each 22 Operating Company by source and the disposition of that energy.

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1 This attachment shows the allocation of kWh from each Operating 2 Company’s own sources (net generation and off-system purchases) to 3 each Operating Company’s net area, to the Exchange, to inadvertent 4 energy or to sales. It also shows Joint Account Purchases allocated to 5 each Operating Company based on Responsibility Ratios. Toward the 6 end of Attachment 1 is a one-page summary of the allocation of the total 7 kWh for each Operating Company and for the total System and a 8 summary listing the allocation to each Operating Company of purchases 9 made during the month.

10 Attachment 2 is a summary, by Operating Company, of the kWh 11 and the associated cost of the sources furnishing energy to the Exchange 12 during that month. Only Operating Companies furnishing Exchange 13 energy during the month are included in this section of Attachment 2.

14 Following the summary of sources by each Operating Company furnishing 15 energy to the Exchange is a summary, by Operating Company, of the 16 allocations of energy from the Exchange during the month. This page lists 17 each Operating Company, the kWh allocated to it during the month, the 18 total dollars charged for those allocations, and the average cost of the 19 kWh allocated. Each Operating Company that is allocated Exchange 20 energy in a given hour pays the same price per kWh for that energy; 21 however, this summary is prepared on a monthly basis, so the dollars per 22 kWh paid by each Operating Company will necessarily be different. For

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1 example, consider the following data contained in Attachment 2 in the July 2 2010 ISB that is attached as Exhibit PJC-2.

Figure PJC-2 July 2010 Company KWh Charge ($) Average Charge (mills/KWh) EAI 131,563,443 8,545,539.76 64.95 ELL 42,272,082 2,134,170.65 50.49 EMI 165,417,337 10,587,664.98 64.01 ENOI 45,025,369 2,623,552.75 58.27 EGSL 8,681,301 328,900.36 37.89 ETI 328,392,353 19,143,734.58 58.30 Total 721,351,885 43,363,563.08 60.11 Note: Dollars may not add due to rounding.

3 As may be seen, the use of averages can be misleading. The 4 average cost for the total of all of the Operating Companies for this month 5 is $60.11/MWh. ELL, ENOI, EGSL, and ETI pay less than the average 6 cost, but EAI and EMI pay more. However, in each of the hours 7 comprising the average, each Operating Company allocated energy from 8 the Exchange paid exactly the same price for that energy.

9 The next page shows the energy amounts sold to each Operating 10 Company under service schedule MSS-4. At the end of Attachment 2 is a 11 summary of the kWh and dollars allocated to each Operating Company 12 from the Arkansas Electric Cooperative Corporation (“AECC”) excess 13 energy purchase. The kWh from this purchase are allocated using the 14 previous month’s responsibility ratio, as specified in the Entergy 15 System Agreement.

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1 Attachment 3 relates to off-system Joint Account Sales.

2 Attachment 3 lists the purchasing entity, type of sale, total kWh sold, total 3 dollars charged, and the average cost for each sale. Next is a listing of 4 the sources used by each Operating Company to supply the off-system 5 Joint Account Sales during the month, the kWh supplied, and the cost that 6 the Operating Companies were credited for having supplied the energy.

7 Next is a summary of the off-system Joint Account Sales, sources 8 supplying the sales. The next page reflects revenue from the sales and 9 the calculated net balance, profit or loss, from the sales.

10 Attachment 4 shows the monthly coincident peak loads for the 11 previous twelve months and shows the calculation of responsibility ratios.

12 Attachment 5 reflects the owned or contracted MW ratings for each 13 Operating Company. These ratings are approved by Entergy’s Operating 14 Committee for the purpose of calculating Reserve Equalization (MSS-1).

15 Attachment 6 is a summary of transactions for each of the 16 Operating Companies. It shows the Purchases and Sales from 17 Associated Companies, including Exchange energy and dollars and Unit 18 Power Purchases, Sales to Non-Associated Companies (Joint Account 19 Sales), Purchases from Non-Associated Companies (Joint Account 20 Purchases), and Other Revenues or Costs, including Transmission 21 Service Revenue.

22 Attachment 11 is a monthly summary of the joint account 23 purchases by Seller and Contract Name/Type indicating the net payable

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1 for each Operating Company. Each entry shows the breakdown of 2 energy, dollars, and an average cost of the purchase(s) by Operating 3 Company. Attachment 11 also shows the allocation of capacity charges 4 for purchased power contracts by contract and by Operating Company.

5 Attachment 12 is a summary of the fiber optics equalization.

6 Billings under this Attachment are not part of the Entergy System 7 Agreement, and are included in the ISB only as a convenience.

9 Q. IS IT YOUR OPINION THAT THE ISB PROPERLY IMPLEMENTS THE 10 ALLOCATION OF COSTS PURSUANT TO THE ENTERGY SYSTEM 11 AGREEMENT?

12 A. Yes, the ISB properly implements the FERC-approved allocation of costs 13 among the Operating Companies as specified in the Entergy System 14 Agreement.

16 Q. CAN THE COSTS ALLOCATED THROUGH THE ISB BE REVISED 17 SOLELY FOR THE BENEFIT OF A SINGLE OPERATING COMPANY OR 18 JURISDICTION?

19 A. Any revision to the allocation of energy and/or costs reflected in an ISB 20 will necessarily affect the other Operating Companies. It is my 21 understanding that FERC is the only regulatory authority with jurisdiction 22 to review the multi-jurisdictional effects of such a revision.

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1 III. THE ENERGY AND FUEL MANAGEMENT CLASS OF COSTS Q. WHAT IS THE RELATIONSHIP BETWEEN THE SPO ORGANIZATION 3 AND THE ENERGY AND FUEL MANAGEMENT CLASS OF SERVICES 4 THAT YOU SPONSOR?

5 A. Exhibits PJC-3 and PJC-4 show the division of affiliate classes. The 6 Generation Function is one of the Functions in the Operations Family of 7 affiliate services (Exhibit PJC-3) and the Energy and Fuel Management 8 Class falls within the Generation Function (Exhibit PJC-4). Within ESI’s 9 organizational structure, all of the Test Year expenses relating to the 10 Energy and Fuel Management Class of services relate to tasks performed 11 by the SPO organization. Furthermore, the SPO is the only organization 12 within ESI or Entergy that performs the services included in this class.

14 Q. DO YOU SPONSOR ANY OF ETI’S NON-AFFILIATE COSTS?

15 A. Not with respect to the Operations & Maintenance (“O&M”) services and 16 costs that I sponsor. Those services, the personnel performing those 17 services, and the associated costs are entirely associated with ESI. ETI 18 does not provide or contract on its own for any of the services I describe; 19 rather, ETI and the other EOCs receive these services solely from ESI 20 and, more specifically, from the SPO organization. The capital costs that I 21 sponsor contain affiliate costs as well as non-affiliate costs, which the 22 SPO organization procures for ETI.

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1 Q. WILL YOU BE ADDRESSING THE COSTS OF THE FUEL, ENERGY 2 AND CAPACITY PRODUCTS PROCURED BY THE SPO 3 ORGANIZATION ON BEHALF OF ETI?

4 A. No. My testimony addresses only the services provided by SPO for ETI 5 (and certain capital expenditures associated with those services), which 6 services, as described below, include the procurement of energy, fuel and 7 capacity products for the EOCs (including ETI); however, the 8 reasonableness of the costs for such energy, fuel and capacity products is 9 addressed by other witnesses.

11 Q. PLEASE EXPLAIN HOW THE REMAINING PARTS OF YOUR 12 TESTIMONY ADDRESSING AFFILIATE COSTS ARE ORGANIZED.

13 A. Section III.A of my testimony provides a brief description of the SPO 14 organization. In Section III.B, I summarize the total O&M affiliate charges 15 for the Energy and Fuel Management Class. In Section III.C, I explain 16 why the costs in this class are necessary. Section III.D explains why 17 these affiliate costs are reasonable, why they meet the “not higher than” 18 standard, and why they represent the actual cost of providing these 19 services. Section III.E addresses the Energy and Fuel Management- 20 related Capital Additions.

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1 A. The SPO Organization Q. WHERE DOES THE SPO FIT INTO ENTERGY’S UTILITY GROUP 3 OPERATIONS?

4 A. System Planning & Operations is one of several operating departments 5 that compose the Utility Operations Group. During the Test Year, the 6 SPO, led by the Vice President, System Planning and Operations, was 7 staffed by 117 ESI employees who provided services to the EOCs.

9 Q. PLEASE PROVIDE AN OVERVIEW OF THE PURPOSE AND 10 ORGANIZATION OF THE SPO.

11 A. All employees of the SPO organization, which provides the services 12 associated with the Energy and Fuel Management Class of services, are 13 employed to accomplish three distinct, but interrelated tasks.

14 First, the SPO acquires fuel and fuel transportation services for the 15 EOCs’ fossil-fueled generating units. The SPO also procures wholesale 16 purchased power for the EOCs. The fuel purchasing task is one that any 17 utility which operates generating facilities must perform—someone must 18 negotiate for and buy fuel and then arrange for its delivery to the power 19 plants. The SPO performs that function for the Entergy System. Similarly, 20 every utility has the choice of generating power for itself or buying it from 21 others, and if the choice is to purchase power, someone must negotiate 22 the terms and conditions of power contracts and arrange for the delivery of 23 the purchased power. The SPO performs these functions as agent for the

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1 EOCs. Related to these very broad tasks are a variety of complex sub- 2 tasks such as selling excess power when available and ensuring that 3 invoices for power sales are issued and invoices for fuel and power 4 purchases are paid and that contract terms and conditions are fulfilled.

5 The SPO performs these tasks as well.

6 Second, the SPO dispatches the generation in the Entergy Control 7 Area. Every utility system is required by the North American Electric 8 Reliability Council (“NERC”) operating guidelines to either operate a 9 Control Area or make arrangements to be included in a Control Area or a 10 regional transmission organization. The Entergy System currently 11 operates its own Control Area that consists of the service areas of all of 12 the EOCs. The task of dispatching the generation (nuclear and non- 13 nuclear) within Entergy's Control Area is performed by the SPO.

14 Third, the SPO plans for the future resource requirements of the 15 Entergy System, and manages the procurement of limited and long-term 16 resources pursuant to those plans. Every utility must consider future 17 system requirements and determine the kinds of resources that it will need 18 in order to meet its prospective obligation to provide reliable and economic 19 power to its customers, and then must procure the supplemental 20 resources identified in the plan. Additionally, regulators and other

The control area is defined to be the geographic area over which the responsible agent is required to match supply to total electric demand at every instant of time, within a tolerance set by the NERC.

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1 governmental organizations frequently require electrical utility systems to 2 provide detailed information about their future plans. Someone must 3 develop and implement resource plans and then prepare the 4 documentation, supporting studies and related regulatory filings that are 5 required. The SPO also performs these functions for the EOCs. All three 6 tasks are distinct, but highly interrelated.

7 In order to accomplish these tasks, during the Test Year, the SPO 8 was divided into seven groups, which are indicated in the organizational 9 chart presented in Exhibit PJC-5. The individuals in charge of each of 10 these groups report directly to the Vice President in charge of the SPO.

11 The seven groups within the SPO, and a brief description of the services 12 performed by each, are: 13 (1) Energy Management Organization (“EMO”), which is responsible 14 for planning for and procurement of short-term fuel and purchased 15 power resources to meet customers’ needs, and the dispatch of the 16 entire Entergy Control Area generation fleet to provide reliable, 17 economic electric service; 18 (2) Asset Operations group, which is responsible for the procurement 19 of limited- and long-term supply resources to meet the electric utility 20 needs of the Entergy System and the responsibility for coal 21 commodity and transportation contracts for the System’s coal 22 plants;

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1 (3) Planning Analysis group, which is responsible for long-term 2 planning and analysis in support of additional resources required to 3 provide reliable and economic electric service to the EOCs’ 4 customers; 5 (4) Regulatory Affairs and Energy Settlements group, which is 6 responsible for providing business, compliance and regulatory 7 support services to the SPO, developing and managing SPO’s 8 budget and cost control initiatives, ensuring that SPO’s activities 9 are compliant with the Sarbanes-Oxley Act, and administering the 10 Intra-System Bill associated with the Entergy System Agreement; 11 (5) Project and Performance Management group, which is responsible 12 for coordinating the development of SPO’s business plan and key 13 performance measures, managing the Entergy Continuous 14 Improvement initiative for SPO, overseeing internal approval 15 processes for major SPO projects, and performing special projects 16 as needed; 17 (6) Strategic Initiatives group, which is primarily responsible for 18 activities associated with SPO’s evaluation of future operating 19 environments, including the benefits of participating in an RTO and 20 now, membership in and the transition of the Entergy System to 21 MISO; and 22 (7) Power Delivery and Technical Services group which is responsible 23 for managing the SPO’s evaluation of transmission deliverability

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1 associated with existing or new generating facilities, and managing 2 the SPO’s transmission service agreements.

3 A more detailed description of the services provided by each of 4 these groups and their necessity to ETI’s responsibilities as a bundled 5 electric utility are further described below.

7 B. Overview of Costs – Energy and Fuel Management Class Q. WHAT ARE THE TOTAL ETI ADJUSTED TEST YEAR CHARGES FOR 9 THE ENERGY AND FUEL MANAGEMENT CLASS THAT YOU 10 SPONSOR?

11 A. As shown in Table 1 below, the total affiliate charges for the Energy and 12 Fuel Management Class that I sponsor are $3,742,314. The table shows 13 the following information: 14 Total Billings Dollar amount of total Test Year billings from 15 ESI to all Entergy companies, plus the dollar 16 amount of all other affiliate charges that 17 originated from any Entergy company. This is 18 the amount from Column (C) of the cost 19 exhibits PJC-A, PJC -B, and PJC -C.

20 Total ETI Adjusted ETI’s adjusted amount for electric cost of 21 service after pro forma adjustments and 22 exclusions.

23 % Direct Billed The percentage of the ETI adjusted Test Year 24 amount that was billed 100% to ETI.

25 % Allocated The percentage of the ETI adjusted Test Year 26 amount that was allocated to ETI.

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Table 1: Total ETI Affiliate Charges for the Energy and Fuel Management Class for July 1, 2010-June 30, 2011 Total ETI Adjusted % % Class Total Amount Direct Billed Allocated Billings Energy and Fuel $25,253,856 $3,742,314 8.70% 91.30% Management Class

1 Q. WHAT ARE THE MAJOR COST COMPONENTS OF THE CHARGES 2 FOR THE ENERGY AND FUEL MANAGEMENT CLASS?

3 A. The major cost components are reflected in Table 2 below.

Table 2: Major Components of ETI Affiliate Charges for the Energy and Fuel Management Class for July 1, 2010-June 30, 2011 Cost Component Total ETI % of Total Adjusted Payroll and Employee Benefits $2,901,624 77.5% Outside Services $300,650 8.0% Office & Employee Expenses $286,221 7.6% Service Company Recipient $254,236 6.8% Other $(417) 0.0% Total $3,742,314 100%

4 Q. WHAT IS THE PURPOSE OF THIS TABLE AND ITS COST 5 CATEGORIES?

6 A. I directly sponsor the costs shown in this table because they comprise the 7 Total ETI Adjusted amount for the Energy and Fuel Management Class for 8 the Test Year. This breakout of costs provides an additional “view” of the 9 components of this class. I also identify other witnesses in this case who 10 also support these costs because they address the corporate structures

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1 and practices that underlie these costs. For example, the table 2 demonstrates that 77.5% of the costs in the Energy and Fuel Management 3 Class are labor-related costs (Payroll and Employee Benefits). Company 4 witness Kevin G. Gardner discusses ESI’s overall payroll and benefits- 5 related structure and practices. “Outside Services” reflect the services 6 provided by non-Entergy employees and firms, such as the independent 7 monitors overseeing resource procurement processes. “Office and 8 Employee Expenses” includes: office and general expenses (e.g., paper, 9 postage, and other general office expenses); employee expenses (e.g., 10 car mileage, local travel expenses, training and business travel airfare); 11 moving and relocation expenses (e.g., costs to relocate new and/or 12 existing employees to new job locations); telecommunications expenses 13 (e.g., long distance telephone charges, conference calls, and cellular 14 phone expenses); and rent expenses for ETI. These types of costs are 15 addressed in more detail by Company witness Thomas C. Plauché.

16 Finally, the costs for “Service Company Recipient,” which are services that 17 ESI provides to itself, are in turn spread to all affiliates that receive ESI 18 services. Company witness Stephanie B. Tumminello explains this 19 service company recipient process. Other miscellaneous costs and 20 credits are included in the “Other” cost components. My testimony 21 addresses the necessity and reasonableness of the amounts for these 22 costs.

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1 Q. PLEASE DESCRIBE THE EXHIBITS THAT SUPPORT THE 2 INFORMATION INCLUDED IN TABLE 1 HEREIN.

3 A. Attached to my direct testimony are exhibits showing the calculation of the 4 Total ETI Adjusted amount for the Energy and Fuel Management Class.

5 In Exhibit PJC-A, the information is shown broken down by the 6 departments comprising the class. Exhibit PJC-B shows the same 7 information broken down by project code and by the billing method 8 assigned to each project code. Exhibit PJC-C shows the information by 9 class, department and project code. For each exhibit, the amounts in the 10 columns represent the following information: Column (A) – Dollar amount of total Test Year billings and Support charges from ESI to all Entergy Business Units, plus the dollar amount of all other affiliate charges to ETI that originated from any Entergy Business Unit.

Column (B) – Dollar amount that was included in the Service Company service company recipient allocation.

Recipient Service company recipient charges are the cost of services that ESI provides to itself, which in turn are charged to affiliates that receive those services. The service company recipient allocation process is described in the testimony of Company witness Tumminello.

Column (C) – Represents the sum of Columns (A) and (B).

Total Column (D) – That portion of Column (C) that was billed All Other Business Units and charged to Business Units other than ETI.

Column (E) – Represents the difference between Columns ETI Per Books (C) and (D).

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Column (F) – Represents amounts that are excluded from Exclusions ETI electric cost of service. The exclusions are described in the testimony of Company witness Tumminello.

Column (G) – Pro Forma Amounts include adjustments for Pro Forma Amount known and measurable changes, and corrections.

Column (H) – ETI adjusted amount requested for recovery Total ETI Adjusted in this case for this class (Column (E) plus Columns (F) and (G)).

1 In her direct testimony, Ms. Tumminello describes the calculations that 2 take the dollars of support services in Column (E) to the Total ETI 3 Adjusted Numbers shown in Column (H).

5 Q. PLEASE DESCRIBE THE “EXCLUSIONS” COLUMN SHOWN IN YOUR 6 EXHIBITS PJC -A, PJC -B, and PJC -C.

7 A. This column includes items charged to capital accounts, below the line 8 accounts and other balance sheet accounts. These excluded amounts 9 are discussed in the direct testimony of Company witness Tumminello.

11 Q. ARE THERE ANY PRO FORMA ADJUSTMENTS APPLICABLE TO THIS 12 AFFILIATE CLASS?

13 A. Yes. Pro Formas and their sponsoring witnesses are shown in 14 Exhibit PJC-D.

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1 Q. PLEASE DESCRIBE THE TYPES OF SERVICES PROVIDED BY THE 2 SPO AND INCLUDED IN THE ENERGY AND FUEL MANAGEMENT 3 CLASS OF SERVICES.

4 A. Generally, the SPO provides services related to making, accounting for, 5 and defending decisions regarding the procurement of new generation, 6 decisions regarding which System generating units are to be committed 7 and operated, how those units are operated, and how much wholesale 8 energy and fuel is purchased.

9 As previously discussed, seven major groups comprise the SPO: 10 EMO; Asset Operations; Planning Analysis; Regulatory Affairs and Energy 11 Settlements; Power Delivery and Technical Services; Project and 12 Performance Management; and Strategic Initiatives.

14 C. Necessity of Services Q. WHAT DOES THE EMO DO?

16 A. The EMO is responsible for planning for and procuring short-term 17 resources to meet customers’ needs, and the dispatch of the entire 18 Entergy Control Area generation fleet to provide reliable, economic electric 19 service. The EMO includes the following major sections and functions: 20  The Operations Planning section, which is responsible for the 21 development of monthly, weekly and daily energy plans, as well as 22 the development of generating unit commitment plans, and

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1 maintenance schedules, to ensure that reliable and economic 2 supplies of energy are available to the System on a daily basis.

3  The Gas, Oil, and Wholesale Power sections, which deal with gas 4 and oil procurement and ensures that the utility’s gas and fuel oil 5 supply and transportation agreements are administered in an 6 effective and efficient manner. This section purchases natural gas 7 and fuel oil for delivery to the Entergy System's generating plants 8 that consume natural gas and/or fuel oil. During the Test Year, the 9 Gas and Oil Supply section procured 151.3 million MMBtus of 10 natural gas for ETI’s generating plants.

11 The Wholesale Power section also continuously monitors 12 bulk power markets in order to purchase short term energy when 13 such power is available at a lower cost than the cost of self- 14 generation and to seek opportunities to sell energy off-system for 15 all time periods other than the current 24 hours, which is the 16 responsibility of the Generation Dispatch and Current Day 17 Marketing function. During the Test Year, the Power Marketing 18 section supported the procurement of over 27.7 million MWh of 19 wholesale power on behalf of ETI.

See Schedule I-16.1.

See Schedule H-12.4a-g.

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1  The Power Transactions & Dispatch section, which is responsible 2 for meeting projected electric demand reliably and at the lowest 3 reasonable cost. Specifically, this section dispatches available 4 generation capacity and other resources to meet the Entergy 5 System’s real-time electric demand. This section is also 6 responsible for marketing of excess generation and purchasing 7 additional resources on a real-time basis.

8 During the Test Year, the Power Transactions & Dispatch 9 section was responsible for the commitment and dispatch of 10 approximately 3,500 MW of ETI-owned or ETI-allocated capacity on 11 a coordinated basis with the capacity owned by the other EOCs.

12  The Operations Support section, which provides support of various 13 planning and regulatory issues that affect real-time dispatch 14 and operations.

16 Q. ARE THE SERVICES PROVIDED BY THE EMO NECESSARY?

17 A. Yes. It is common practice for those utilities that operate a Control Area 18 or procure electric energy from wholesale resources to employ a short 19 term planning function, a dispatch function and a power marketing function 20 in order to achieve the goal of meeting such utility’s projected electric 21 demand reliably and at the lowest reasonable cost. Furthermore, it is also 22 common practice for those utilities that operate gas- and oil-fired power 23 plants to have a gas and oil supply function in order to meet their

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1 projected gas and oil demand and to ensure that such utility’s gas and fuel 2 oil supply and transportation agreements are administered in an effective 3 and efficient manner.

5 Q. WHAT DOES THE ASSET OPERATIONS GROUP DO?

6 A. This group is responsible for the procurement of limited- and long-term 7 fuel and generation resources to meet the electric utility needs of the 8 Entergy System. The Asset Operations group is responsible for the formal 9 Requests for Proposals (“RFP”) process by which the Entergy System 10 solicits proposals for purchased power agreements or acquires new or 11 existing power plants. This group also negotiates bi-lateral purchased 12 power agreements when such opportunities arise. Finally, the group also 13 has the responsibility for dealing with issues under the fuel provisions of 14 the Joint Ownership and Operating Agreement governing the Big Cajun II, 15 Unit 3 generating unit.

16 During the Test Year, the Asset Operations group was responsible 17 for executed agreements procuring 660 MW of limited- and long-term 18 wholesale power which was allocated either in whole or in part to ETI.

19 Additionally, the Asset Operations group was also responsible for 20 significant activity outside of the Test Year that affected power purchases 21 during the Test Year, as discussed in the testimony of Company witness 22 Robert R. Cooper.

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1 The Asset Operations group is also responsible for the 2 procurement of coal for the EOCs’ coal-fired power plants, administering 3 coal supply contracts and managing the maintenance of the rail car fleet 4 leased by EGSL and EAI, including the transportation of coal to the Roy S.

5 Nelson Power Plant near Lake Charles, Louisiana (in which ETI is a co- 6 owner), and to the two other coal-fired power plants on the System – the 7 Independence Steam Electric Station and the White Bluff Steam Electric 8 Station in Arkansas.

9 During the Test Year, this group procured the coal supply and 10 arranged the transportation of approximately 2.4 million tons of coal that 11 were delivered to the Roy S. Nelson plant. Comparably, it also received 12 approximately 1.0 million tons of coal during the Test Year for ETI and 13 EGSL’s share of the output of Big Cajun II, Unit 3.

15 Q. ARE THESE SERVICES NECESSARY?

16 A. Yes. Integrated utilities procure limited- and long-term resources to meet 17 the electric utility needs of their customers. It is common practice for 18 utilities to utilize a competitive solicitation process when procuring 19 purchased power or acquiring new or existing power plants to facilitate the 20 utility’s procurement of the resource at a reasonable price. It is also 21 common practice for those utilities that operate coal-fired power plants to 22 have a coal supply function in order to meet their projected coal demand 23 and to ensure that such utility’s coal supply, railcar maintenance, and coal

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1 transportation agreements are administered in an effective and efficient 2 manner.

4 Q. WHAT DOES THE PLANNING ANALYSIS GROUP DO?

5 A. The Planning Analysis group is responsible for planning for the long-term 6 resource requirements necessary to provide reliable and economic electric 7 service to the EOCs’ customers. That group ensures that the utility’s 8 generation and wholesale transactions resources are planned pursuant to 9 consistent and accepted planning criteria. Specifically, this group is 10 responsible for the development of long-term Strategic Resource Plans, 11 which result in the matching of the Entergy System’s long-term projected 12 load and resources. In addition to the analysis of potential resource 13 acquisitions, the Planning Analysis group performs long-term fuels 14 planning and analysis, peak load forecasting and production 15 cost forecasting.

16 During the Test Year, the Planning Analysis group developed 17 capacity and energy plans that support ETI’s objective to achieve the 18 lowest reasonable energy costs for its customers consistent with the 19 Entergy System Agreement and known and reasonably anticipated 20 System conditions.

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1 Q. ARE THE SERVICES PROVIDED BY THE PLANNING ANALYSIS 2 GROUP NECESSARY?

3 A. Yes. It is common practice for those utilities that have an obligation to 4 provide reliable generation supplies to customers to employ a long-term 5 planning and analysis function in order to achieve the goal of meeting 6 such utility’s projected electric demand at a reasonable cost and to ensure 7 that such utility’s generation and wholesale transactions resources are 8 planned pursuant to consistent and accepted planning criteria.

10 Q. WHAT DOES THE REGULATORY AFFAIRS AND ENERGY 11 SETTLEMENTS GROUP DO?

12 A. The Regulatory Affairs and Energy Settlements group is responsible for 13 providing business and regulatory support services to the SPO, and, in 14 turn, for the EOCs. These services include bulk power energy accounting, 15 administering the Intra-System Bill associated with the Entergy System 16 Agreement and the administration and accounting related to wholesale 17 energy and fuel invoices.

18 During the Test Year, fuel and electricity-related invoices totaling 19 approximately $2.7 billion, were verified and processed by the Energy 20 Analysis and Reporting section to ensure proper payment and/or billing.

21 The group prepared numerous reports required by federal and state 22 administrative agencies and assisted in the preparation of monthly 23 estimated and actual accounting entries for ETI. These services provide

2011 ETI Rate Case 9-57 Entergy Texas, Inc. Page 55 of 75 Direct Testimony of Patrick J. Cicio 2011 Rate Case

1 benefits to ETI’s customers by providing to internal and external groups 2 accurate and timely fuel and energy data and invoice processing in a cost 3 effective manner.

4 The Regulatory Affairs and Energy Settlements group also supports 5 the filing requirements of various state and federal regulators, develops 6 and manages SPO’s budget, including the monitoring of related activities 7 and costs, and identifies and implements cost control initiatives. Lastly, 8 the Regulatory Affairs and Energy Settlements group monitors compliance 9 with the electric reliability standards for SPO and ensures that SPO’s 10 activities are compliant with the Sarbanes-Oxley Act.

12 Q. ARE THE SERVICES PROVIDED BY THE REGULATORY AFFAIRS 13 AND ENERGY SETTLEMENTS GROUP NECESSARY?

14 A. Yes. It is common practice for those utilities that operate power plants, 15 buy and sell electricity, and operate in a multi-jurisdictional and multi-utility 16 environment as part of a larger combined system concept, to maintain an 17 organization to provide: (1) business and regulatory support services; 18 (2) bulk power energy accounting; (3) administration of billing associated 19 with the combined system; (4) administration and accounting related to 20 wholesale energy and fuel invoices, for the purpose of enhancing the 21 efficiency and effectiveness of the other fuel, energy and dispatch 22 related functions and (5) a compliance function to ensure compliance with 23 the electric reliability standards.

2011 ETI Rate Case 9-58 Entergy Texas, Inc. Page 56 of 75 Direct Testimony of Patrick J. Cicio 2011 Rate Case

1 As part of the overall management of SPO’s fuel and energy 2 management activities the budgeting and cost control measures provided 3 by the SPO Regulatory Affairs and Settlements group helps ensure the 4 reasonableness and necessity of the costs incurred and that such 5 expenditures are managed within the approved budget.

7 Q. WHAT DOES THE PROJECT AND PERFORMANCE MANAGEMENT 8 GROUP DO?

9 A. The Project and Performance Management group is responsible for 10  coordination of the development of SPO’s business plan and key 11 performance measures; and 12  oversight of the internal approval processes for major SPO projects 13 and performing special projects as needed.

14 This group is also responsible for overseeing the Entergy Continuous 15 Improvement (“ECI”) initiative for SPO that I discuss later in my testimony.

17 Q. ARE THESE SERVICES NECESSARY?

18 A. Yes. The efficient and cost effective performance of the necessary fuel 19 and energy management activities enumerated earlier in my testimony 20 requires attention to the performance measures provided by the SPO 21 Project and Performance Management group.

2011 ETI Rate Case 9-59 Entergy Texas, Inc. Page 57 of 75 Direct Testimony of Patrick J. Cicio 2011 Rate Case

1 Q. WHAT DOES THE STRATEGIC INITIATIVES GROUP DO?

2 A. This group was formed for the purpose of focusing on and supporting 3 several key initiatives facing the regulated Operating Companies, primarily 4 the activities related to the evaluation of future operating environments, 5 including the benefits of participating in an RTO, and now, membership in 6 and the transition of the Entergy System to MISO.

8 Q. ARE THESE SERVICES NECESSARY?

9 A. Yes. The System’s decision to join an RTO – specifically, MISO – has 10 far-reaching implications for how the Operating Companies will plan and 11 operate their generation systems. The Strategic Initiatives group is 12 responsible for evaluating issues and situations that will affect future 13 operations, and the Strategic Initiatives group will play a key role in 14 ensuring ETI’s future operations are consistent with reliable and economic 15 service.

17 Q. WHAT DOES THE POWER DELIVERY AND TECHNICAL SERVICES 18 DO?

19 A. The Power Delivery and Technical Services group is responsible for 20 managing the SPO’s evaluation of transmission deliverability associated 21 with existing or new generating facilities, and managing the SPO’s 22 transmission service agreements.

2011 ETI Rate Case 9-60 Entergy Texas, Inc. Page 58 of 75 Direct Testimony of Patrick J. Cicio 2011 Rate Case

1 Q. ARE THESE SERVICES NECESSARY?

2 A. Yes. The separation of the merchant and transmission functions directed 3 by the FERC requires that the SPO have the ability to study and manage 4 transmission service associated with the System’s existing and proposed 5 generating resources.

7 D. Reasonableness of Energy and Fuel Management Charges Q. PLEASE DESCRIBE THE STAFFING LEVELS ASSOCIATED WITH THE 9 ENERGY AND FUEL MANAGEMENT CLASS OVER THE PERIOD 2008 10 THROUGH THE TEST YEAR.

11 A. SPO’s staffing levels for 2008, 2009. 2010 and the Test Year is reflected 12 in Table 3 below. The increase in Test Year staffing levels over 2008 and 13 2009 is consistent with the addition of the new Strategic Initiatives group 14 as well as the addition of a dispatcher position in the EMO group, required 15 by an increased workload in the Power Transactions and Dispatch 16 section.

Table 3: SPO Headcount 2008 2009 2010 Test Year 110 115 116 118

2011 ETI Rate Case 9-61 Entergy Texas, Inc. Page 59 of 75 Direct Testimony of Patrick J. Cicio 2011 Rate Case

1 Q. HAS SPO PERFORMED ANY BENCHMARKING TO SUPPORT THE 2 REASONABLENESS OF ITS COSTS?

3 A. No, but as discussed by Company witness Jeanne F. Kenney, the 4 Company has provided benchmarking analysis of both non-production 5 O&M costs, including A&G costs, which include SPO costs. This high 6 level view further supports the reasonableness of costs in the Energy and 7 Fuel Management Class.

9 Q. WHAT WERE THE ACTUAL COST TRENDS FOR THE ENERGY AND 10 FUEL MANAGEMENT CLASS FOR THE LAST THREE YEARS AS 11 COMPARED TO THE TEST YEAR?

12 A. Table 4 below presents the total affiliate O&M costs for the class as a 13 whole for the last three years and the Test Year.

Table 4: ESI Energy and Fuel Management Cost Trends 2008 2009 2010 Test Year $3,072,925 $3,527,979 $3,140,089 $3,736,054

14 Q. DO THE FIGURES IN THIS COST TREND TABLE INCLUDE ALL 15 COSTS INCURRED BY ESI FOR THE ENERGY AND FUEL 16 MANAGEMENT CLASS DURING THE LISTED PERIODS?

17 A. No. The ESI O&M cost trend figures have been adjusted primarily to 18 exclude certain costs incurred by ESI to support efforts to spin off

2011 ETI Rate Case 9-62 Entergy Texas, Inc. Page 60 of 75 Direct Testimony of Patrick J. Cicio 2011 Rate Case

1 Entergy's non-regulated nuclear operations because such costs are not 2 representative of ESI's ongoing cost of supporting ETI utility service.

3 Company witness Tumminello provides further explanation regarding the 4 adjustments to the cost trend data in her direct testimony.

6 Q. WHAT DO THESE COST TRENDS REFLECT?

7 A. These cost trends reflect a reasonable increase in overall costs for the 8 class from 2008 through the Test Year. The increase in Test Year costs 9 over previous annual periods largely reflects new or increased costs 10 associated with: (1) the new Strategic Initiatives group, including the 11 addition of a new Vice President position to lead that group; (2) the 12 considerable increase in compliance activity—required by federal law—for 13 which SPO is responsible; and (3) the addition of a dispatcher position 14 addressed above. In summary, Table 4 reflects a reasonable increase in 15 SPO costs over recent years and a reasonable level of costs in the Test 16 Year.

18 Q. PLEASE DESCRIBE THE WORKLOAD FACED BY THE SPO.

19 A. SPO workload continues to increase significantly and is appropriate to 20 consider when evaluating the reasonableness of its overall costs. Efforts 21 continue with respect to the transformation of the EOCs’ generation 22 portfolios and the procurement of additional resources. Since the last rate 23 case, SPO has initiated and completed, or is in the process of conducting,

2011 ETI Rate Case 9-63 Entergy Texas, Inc. Page 61 of 75 Direct Testimony of Patrick J. Cicio 2011 Rate Case

1 three RFPs—the Summer 2009 RFP, the 2010 Renewable RFP and, 2 more recently, the ongoing 2011 Western Region RFP, which seeks a 3 resource for 2017, already pre-allocated to ETI by the Entergy Operating 4 Committee. Further, the Planning Analysis group currently forecasts the 5 need to obtain even additional resources to serve the Western Region in 6 2020. Moreover, additional complexities continue to be added to SPO’s 7 functions due to the planned exit of EAI and EMI from the System 8 Agreement, effective 2013 and 2015, and the recent announcement that 9 the Entergy System will join MISO. Both of these future events require 10 SPO’s planning teams to consider and plan for a wider array of possible 11 outcomes while the overall SPO organization prepares to incorporate new 12 structures and processes. Finally, as is the case with other similarly 13 situated utilities, SPO continues to face and respond to increases in 14 regulatory compliance requirements and significant changes in 15 environmental laws and regulations. This increasing workload further 16 supports the reasonableness of costs in this class.

18 Q. DOES THE SPO HAVE IN PLACE A BUDGETING PROCESS TO 19 CONTROL COSTS?

20 A. Yes. The SPO undergoes an extensive annual budget preparation and 21 review process. Within this process, a proposed budget is finalized for the 22 following year. As an input to the budget, the SPO is allocated a certain 23 percentage increase in wages for the organization’s employees. This

2011 ETI Rate Case 9-64 Entergy Texas, Inc. Page 62 of 75 Direct Testimony of Patrick J. Cicio 2011 Rate Case

1 allows for the flexibility to reward individual performance in any given year, 2 but also ensures that total labor costs continue to track labor market 3 conditions. Further, non-labor costs are reviewed for necessity and cost 4 effectiveness. Annual budgets are prepared within SPO, approved by 5 SPO executive management, corporate management and, ultimately, the 6 board of directors of Entergy Corporation.

8 Q. IS COMPLIANCE WITH THE BUDGET MONITORED?

9 A. Yes. SPO management continually monitors incurred expenses against 10 budget, and frequently approves expenses prior to expenses being 11 incurred. For example, the SPO management generally pre-approves 12 employee training (e.g., seminars, travel) prior to an employee’s 13 registration for such training. Likewise, most employee business travel is 14 also discussed and approved by SPO management prior to travel costs 15 being incurred. Additionally, on a monthly basis, the SPO expenditures 16 are reviewed by executive management to ensure that they are on track 17 with the annual budget. To the extent that there are deviations within the 18 budget year, discretionary projects may either be advanced or postponed, 19 with the approval of the SPO executive management, to ensure that the 20 SPO expenditures are reasonable.

2011 ETI Rate Case 9-65 Entergy Texas, Inc. Page 63 of 75 Direct Testimony of Patrick J. Cicio 2011 Rate Case

1 Q. ARE SPO EMPLOYEES HELD ACCOUNTABLE FOR DEVIATIONS 2 FROM BUDGET?

3 A. Most employee expenses are pre-approved by the appropriate level of 4 SPO management. Any significant unbudgeted cost must be pre- 5 approved by the Vice President, System Planning and Operations.

6 Adherence to budget is a priority for all SPO staff. Compliance with 7 approved budgets is also included in the performance goals of the 8 employees.

10 Q. HAS SPO UNDERTAKEN OTHER MEASURES OR INITIATIVES TO 11 ENSURE THAT ITS COSTS ARE REASONABLE?

12 A. SPO, on an ongoing basis, actively seeks to discover new ways to 13 improve processes within the organization through the Entergy 14 Continuous Improvement (“ECI”) initiative, a process which also is 15 overseen by the Project and Performance Management group and which 16 encourages employees to seek out areas where practices, processes and 17 procedures related to their organizations can be improved upon to 18 enhance effectiveness and efficiency. Improvements identified through 19 the ECI process often result in reduced costs. During the Test Year, SPO, 20 given its focus on buying both fuel and power for the EOCs, was 21 successful in discovering and implementing a number of improvements 22 that resulted in fuel and purchased power cost reductions, as presented in 23 Schedule I-21. SPO also streamlined and automated a number of regular

2011 ETI Rate Case 9-66 Entergy Texas, Inc. Page 64 of 75 Direct Testimony of Patrick J. Cicio 2011 Rate Case

1 work processes, allowing labor redeployment and reducing or delaying the 2 need to increase O&M expenses to keep up with the increasingly 3 demanding workload that I discussed earlier in my testimony.

5 E. Billing of Energy and Fuel Management Charges Q. HOW ARE SPO’S COSTS BILLED TO ETI?

7 A. Please refer to Exhibits PJC-B and PJC-C. These exhibits show all the 8 costs included in the Energy and Fuel Management Class by project code 9 and reflect the ESI billing method assigned to each project code. 10 The affiliate billing process is explained by Company witness 11 Tumminello. Where appropriate, costs are billed directly to ETI and other 12 affiliates. Costs that are billed directly to ETI reflect the fact that certain 13 Energy and Fuel Management Class activities are for the specific benefit 14 of ETI. Only when incurred costs benefit more than one of the EOCs are 15 such costs billed through an allocation. With respect to the Energy and 16 Fuel Management Class, some costs are billed to ETI through an 17 allocation, which reflects the fact that more than one of the EOCs 18 benefited from the services delivered. Therefore, ESI costs are billed to 19 ETI both directly and through various allocation methods.

2011 ETI Rate Case 9-67 Entergy Texas, Inc. Page 65 of 75 Direct Testimony of Patrick J. Cicio 2011 Rate Case

1 Q. ON WHAT BASIS ARE COSTS OF THESE ENERGY AND FUEL 2 MANAGEMENT SERVICES BILLED?

3 A. Each ESI affiliate class of service, including the Energy and Fuel 4 Management Class, comprises one or more project codes. As Company 5 witness Tumminello explains, only one billing method is assigned to each 6 project code. Several organizations may bill to a single project code. 7 However, the billing method for each project code remains the same, 8 regardless of which organization charges to that project code. A billing 9 method is selected based on cost causation. This procedure ensures that 10 the price charged to ETI for the services is no higher than the price 11 charged to other affiliates for the same or similar services, and represents 12 the actual cost of the services.

14 Q. PLEASE EXPLAIN WHAT IS REFERRED TO BY COSTS BEING 15 “BILLED DIRECTLY” OR “ALLOCATED?”

16 A. Affiliate charges are incurred by ETI when ESI employees or employees of 17 other affiliate companies provide services to ETI. Affiliate costs are 18 charged to ETI through one of two methods. The costs are either billed 19 directly to ETI or the costs are allocated to ETI based on the primary cost 20 driver of the activity or project. The SPO function has consolidated, on a 21 system-wide basis, those activities that are common to all EOCs for which 22 scale and scope efficiencies can be realized. I will use the example of 23 Planning Analysis to explain whether an ESI charge will be billed directly

2011 ETI Rate Case 9-68 Entergy Texas, Inc. Page 66 of 75 Direct Testimony of Patrick J. Cicio 2011 Rate Case

1 to ETI or allocated to ETI. If a Planning Analysis employee is working on 2 a specific ETI project, such as a Texas fuel reconciliation, then ETI is the 3 only EOC that benefits from this regulatory activity and all of the resulting 4 costs will be billed directly to ETI. Conversely, if the same Planning 5 Analysis employee was working on the Strategic Resource Plan for the 6 Entergy System, all EOCs would benefit and the resulting costs would be 7 allocated based on the primary cost driver – in this case, the load 8 responsibility ratio. These rules apply to all of the work performed by 9 SPO employees.

11 Q. HOW DID SPO DETERMINE WHICH ENTITY SHOULD BE BILLED?

12 A. As a necessary part of accurately apportioning costs to the various 13 Entergy affiliates, a billing method is assigned to each project code that 14 first identifies the entities to which the cost is to be apportioned. When a 15 project code is established, a billing method is selected by SPO based on 16 the factors driving SPO to incur the expense; these factors are frequently 17 referred to as “cost drivers.” The billing method that is initially assigned by 18 the staff member is reviewed for appropriateness by SPO management.

19 In addition, billing methods assigned to project codes also are reviewed 20 periodically by budget coordinators and SPO management for 21 appropriateness. Each SPO project code has only one billing method 22 assigned to it and the billing method is selected to ensure that every 23 affiliate receiving service receives the appropriate allocation. Therefore,

2011 ETI Rate Case 9-69 Entergy Texas, Inc. Page 67 of 75 Direct Testimony of Patrick J. Cicio 2011 Rate Case

1 the costs of all services performed under a project code are allocated 2 among the EOCs using the same criteria, at cost without profit or markup.

3 The use of a single billing method for each project code ensures that all 4 EOCs causing costs to be incurred and benefiting from the service pay an 5 appropriate proportion of the costs. It also ensures that the EOCs are, in 6 total, charged no more and no less than one hundred percent of the costs 7 for services provided under the project code. Finally, the use of a single 8 billing method, which is assigned based on cost causation principles, 9 ensures that each EOC is paying the same price for the same service, 10 and, that the prices charged to ETI are no higher than the prices charged 11 by ESI to the other EOCs for similar services.

13 Q. PLEASE DESCRIBE THE PREDOMINANT BILLING METHODS 14 EMPLOYED IN THE ENERGY AND FUEL MANAGEMENT CLASS OF 15 SERVICES.

16 A. The predominant billing methods for the Energy and Fuel Management 17 Class are “LOADOPCO” (Responsibility Ratio), “DIRECTTX” (100% to 18 ETI), and “CAPXCOPC” (System Capacity without Coal). These three 19 billing methods make up 94.49% of the billings to ETI for the Energy and 20 Fuel Management Class. “LOADOPCO” makes up 81.12%; “DIRECTTX” 21 makes up 8.70%; and “CAPXCOPC” makes up 4.67%. Of these three 22 billing methods, “LOADOPCO” and “CAPXCOPC” allocate (rather than 23 direct bill) costs to ETI through the allocation method.

2011 ETI Rate Case 9-70 Entergy Texas, Inc. Page 68 of 75 Direct Testimony of Patrick J. Cicio 2011 Rate Case

1 Q. WHY IS BILLING METHOD “LOADOPCO” APPROPRIATE FOR 2 CERTAIN ENERGY AND FUEL MANAGEMENT EXPENSES 3 ALLOCATED TO ETI?

4 A. The majority of SPO services relate to the procurement, planning, 5 commitment, and dispatch of the Entergy System’s generating resources 6 and its wholesale power transactions. The need for SPO’s services is 7 driven by the necessity to obtain resources for the Entergy System as a 8 whole and each EOC’s need for such services is a part of and relative to 9 the Entergy System’s need for such services. Accordingly, for the majority 10 of SPO’s services, it is appropriate to apportion the corresponding cost in 11 a manner that relates the need of the EOC for resources to the need of 12 the Entergy System as a whole. “LOADOPCO,” which is based upon the 13 Responsibility Ratio (the ratio of each EOC’s load at the time of the 14 Entergy System peak load to the Entergy System’s peak load), 15 accomplishes this. For instance, Project Code F3PCW15830 captures 16 cost associated with planning activities performed for the Entergy System 17 and the EOCs. Associated costs are driven by the load responsibility 18 ration of each of the System’s generating plants. Accordingly, 19 “LOADOPCO,” which apportions cost based on load responsibility ratio, is 20 an appropriate billing method for this type of project.

Responsibility Ratio is a defined allocator in the Entergy System Agreement.

2011 ETI Rate Case 9-71 Entergy Texas, Inc. Page 69 of 75 Direct Testimony of Patrick J. Cicio 2011 Rate Case

1 Q. WHY IS BILLING METHOD “DIRECTTX” APPROPRIATE FOR THE 2 ENERGY AND FUEL MANAGEMENT EXPENSES ALLOCATED TO ETI?

3 A. “DIRECTTX” bills cost 100% to ETI and is appropriate when the services 4 performed relate directly to and benefit only ETI. For example, Project 5 Code F3PPWET306 captures costs associated with the 2011 Western 6 Region RFP as part of the resource planning process for ETI. The 7 associated costs are caused by and are directly related to ETI, and are 8 therefore assigned to ETI, pursuant to billing method DIRECTTX.

10 Q. WHY IS BILLING METHOD “CAPXCOPC” APPROPRIATE FOR 11 CERTAIN ENERGY AND FUEL MANAGEMENT EXPENSES 12 ALLOCATED TO ETI?

13 A. “CAPXCOPC” is based on the power level, in kilowatts, that could be 14 achieved if all non-coal and non-nuclear generating units were operating 15 at maximum capability simultaneously. It is appropriate to use this billing 16 method when the cost for SPO services relate to an EOC’s ownership of 17 non-coal and non-nuclear generation. For instance, Project Code 18 F3PCW18100 captures costs associated with payroll and office expenses 19 incurred in the planning and purchase of gas and oil for operating the 20 System’s natural gas and oil-fired power plants. Billing Method 21 “CAPXCOPC” was selected for this project code because the 22 corresponding costs related to SPO’s services under this project are 23 driven by the amount of natural gas and oil capacity owned by an EOC.

2011 ETI Rate Case 9-72 Entergy Texas, Inc. Page 70 of 75 Direct Testimony of Patrick J. Cicio 2011 Rate Case

1 Q. YOU HAVE ADDRESSED THE DIRECT COSTS AND ALLOCATED 2 COSTS USED TO BILL 94.49% OF THE TOTAL ETI ADJUSTED 3 AMOUNT ASSOCIATED WITH THE ENERGY AND FUEL 4 MANAGEMENT CLASS. WHY HAVE YOU NOT SPECIFICALLY 5 ADDRESSED THE REMAINING 5.51% OF THE COSTS OF THIS 6 CLASS?

7 A. The remaining costs are billed through a number of other project codes 8 and billing methods. Given the number of billing methods, project codes 9 and relative dollar amounts, I have not gone into detail in this discussion in 10 an effort to keep the discussion at a manageable level. However, the 11 project codes and billing methods used to bill the remaining 5.51% of the 12 costs in this class are provided in my Exhibits PJC-B and PJC-C. A 13 reader may reference these exhibits and then refer to the specific project 14 code summary contained in exhibits to the testimony of Company witness 15 Tumminello for a discussion of the particular billing method used and the 16 cost drivers for the activities captured in the particular project code.

18 Q. HAVE YOU DETERMINED THAT THE COSTS REFLECTED IN THE 19 REMAINING 5.51% OF COSTS ASSOCIATED WITH THIS CLASS HAVE 20 BEEN BILLED APPROPRIATELY?

21 A. Yes, I have reviewed each of the project codes and the associated billing 22 methods used to bill the remaining 5.51% of the costs of this class. The 23 cost drivers reflected in the billing method used to bill the costs of each

2011 ETI Rate Case 9-73 Entergy Texas, Inc. Page 71 of 75 Direct Testimony of Patrick J. Cicio 2011 Rate Case

1 project code are consistent with and reflect the cost drivers of the services 2 captured in each respective project code. Therefore, the costs billed to 3 ETI reasonably reflect the costs of the services received by ETI and are 4 no higher than the costs charged to other EOCs for the same or similar 5 types of services.

7 Q. DO ANY OTHER ENTITIES DUPLICATE THE ENERGY AND FUEL 8 MANAGEMENT CLASS OF SERVICES?

9 A. No. The SPO is the only group within Entergy that provides the Energy 10 and Fuel Management Class of services. ETI does not duplicate 11 these services.

13 F. Summary of SPO Capital Charges Q. ARE YOU SUPPORTING ANY CAPITAL ADDITIONS INCLUDED IN THE 15 COMPANY’S REQUEST IN THIS PROCEEDING?

16 A. Yes. I am supporting the Company’s request for $219,406 in capital 17 charges associated with SPO-related services. These capital projects 18 were closed to plant in service during the period July 2009 through June 19 2011 and are reasonable and necessary costs incurred for projects that 20 are used and useful in providing electric service. A detail of these charges 21 and the corresponding projects to which these charges were assigned, are 22 listed on Exhibit PJC-6, which reflects the following information:

2011 ETI Rate Case 9-74 Entergy Texas, Inc. Page 72 of 75 Direct Testimony of Patrick J. Cicio 2011 Rate Case

1 Column A Project Code Number 2 Column B Project Code Description 3 Column C Asset Class 4 Column D In-service Date 5 Column E Asset Location Description 6 Column F State Location 7 Column G Business Unit (“BU”) 8 Column H Non-Affiliate Charges Excluding Capital Suspense 9 and Reimbursements 10 Column I Reimbursements 11 Column J Represents capital suspense overhead costs 12 associated with administrators, engineers and 13 supervisors to the capital projects for which they 14 provide services. Each function charges their capital 15 suspense to a "Capital Suspense" project, which is 16 then allocated out to the appropriate capital projects.

17 Capital Suspense costs and the subsequent 18 allocation is separated by BU and function 19 combination to more accurately match such costs on 20 the actual projects worked on for each function within 21 a BU.

22 Column K Represents the portion of capital suspense overhead 23 costs (in Column J) from an affiliate.

24 Column L Represents the portion of capital suspense overhead 25 costs (in Column J) that are charged to the project by 26 ETI employees.

27 Column M Represents charges incurred by the ESI service 28 company and allocated out to the appropriate BUs 29 based on the ESI billing method assigned to the 30 project plus loaned resource charges incurred at one 31 BU and charged to another BU for services rendered 32 on behalf of that BU.

2011 ETI Rate Case 9-75 Entergy Texas, Inc. Page 73 of 75 Direct Testimony of Patrick J. Cicio 2011 Rate Case

1 Column N Represents the total affiliate portion of the charges 2 included in Column O, and is the total of Columns K, 3 and M.

4 Column O Represents the total amount of capital additions 5 closed to plant in service.

6 All of these costs relate to the capitalization of IT projects and research 7 and data services and modeling tools that support SPO’s activities.

9 Q. PLEASE DESCRIBE THE CAPITAL PROJECTS THAT YOU SPONSOR 10 AS PART OF THE ENERGY AND FUEL MANAGEMENT CLASS.

11 A. The 11 Project Codes shown on Exhibit PJC-6 are all IT capital projects 12 and research and data services and modeling tools that are related to 13 dispatch and operations.

14 These capital projects relate to and support EMO’s dispatch and 15 operation responsibilities to meet projected electric demand reliably and at 16 the lowest reasonable cost, including, for example, enhancements to 17 various data systems and the development of tools to maintain 18 compliance with the Sarbanes-Oxley Act.

20 Q. ARE ANY AFFILIATE COSTS INCLUDED IN THE REQUESTED 21 CAPITAL CHARGES?

22 A. Yes, the necessary affiliate costs totaled $125,383 for SPO capital 23 projects shown in Column N of Exhibit PJC-6.

2011 ETI Rate Case 9-76 Entergy Texas, Inc. Page 74 of 75 Direct Testimony of Patrick J. Cicio 2011 Rate Case

1 Q. WHY ARE AFFILIATE COSTS NECESSARY IN THE DEVELOPMENT 2 OF SPO IT APPLICATIONS?

3 A. These costs are the result of employees of ESI (or an outside contractor of 4 ESI) providing design, implementation and project management services 5 for the various SPO IT capital projects. These charges are necessary in 6 order to design and implement IT systems that meet the needs of Entergy 7 System customers, including customers of ETI.

9 Q. WHAT TYPES OF COSTS ARE INCURRED FOR THESE CAPITAL 10 PROJECTS?

11 A. Expenses incurred as part of a capital project include equipment, 12 software, materials, supplies and any labor required to complete the 13 project. All costs are subject to the budget and cost control processes I 14 describe above. The ESI labor costs are generally similar to those 15 incurred as O&M expense except that the labor is directly related to the 16 capital project, and the cost is capitalized as part of the total project cost.

17 These affiliate charges are reasonable for the same reasons discussed 18 above, are billed to ETI pursuant to the same principles and practices 19 previously discussed in my testimony and are at cost and are no higher 20 than the charges made to other affiliates for the same or similar services.

2011 ETI Rate Case 9-77 Entergy Texas, Inc. Page 75 of 75 Direct Testimony of Patrick J. Cicio 2011 Rate Case

1 IV. CONCLUSION Q. DOES THIS CONCLUDE YOUR DIRECT TESTIMONY?

3 A. Yes.

2011 ETI Rate Case 9-78 Exhibit PJC-1 2011 TX Rate Case Page 1 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 1 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181

ENTERGY System Agreement Agreement Among: Entergy Arkansas, Inc. Entergy Gulf States Louisiana, L.L.C. Entergy Louisiana, LLC Entergy Mississippi, Inc. Entergy New Orleans, Inc. Entergy Texas, Inc. Entergy Services, Inc.

Little Rock

Jackson

Beaumont New Orleans

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-79 Exhibit PJC-1 2011 TX Rate Case Page 2 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 2 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181

AGREEMENT Among ENTERGY ARKANSAS, INC. ENTERGY GULF STATES LOUISIANA, L.L.C. ENTERGY LOUISIANA, LLC ENTERGY MISSISSIPPI, INC. ENTERGY NEW ORLEANS, INC. ENTERGY TEXAS, INC. ENTERGY SERVICES, INC.

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-80 Exhibit PJC-1 2011 TX Rate Case Page 3 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 3 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181 INDEX Sheet No. Preface.......................................................................................................................................... 4 Article I Term of Agreement............................................................................... 6 Article II Definitions ............................................................................................. 7 Article III Objectives ............................................................................................ 13 Article IV Obligations .......................................................................................... 16 Article V Composition and Duties of the Operating Committee ...................... 23 Article VI System Operations Center .................................................................. 27 Signatory .............................................................................................................. 29 Service Schedule MSS-1 Reserve Equalization .......................................................................... 30 Service Schedule MSS-2 Transmission Equalization.................................................................. 38 Service Schedule MSS-3 Exchange of Electric Energy Among the Companies....................... 44 Service Schedule MSS-4 Unit Power Purchase........................................................................... 61 Service Schedule MSS-5 Distribution of Revenue from Sales Made for the Joint Account of All Companies ................................................................................ 71 Service Schedule MSS-6 Distribution of Operating Expenses of System Operations Center .. 74 Service Schedule MSS-7 Merger Fuel Protection Procedure ..................................................... 76

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-81 Exhibit PJC-1 2011 TX Rate Case Page 4 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 4 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181

AGREEMENT Among ENTERGY ARKANSAS, INC. ENTERGY GULF STATES LOUISIANA, L.L.C. ENTERGY LOUISIANA, LLC ENTERGY MISSISSIPPI, INC. ENTERGY NEW ORLEANS, INC. ENTERGY TEXAS, INC. ENTERGY SERVICES, INC.

THIS AGREEMENT, first made and entered into on the 23rd day of April 1982, and subsequently amended, is by and among Entergy Arkansas, Inc., herein-after called EAI; Entergy Gulf States Louisiana, L.L.C., herein-after called EGSL or Gulf States Louisiana; Entergy Louisiana, LLC, hereinafter called ELL; Entergy Mississippi Inc., hereinafter called EMI; Entergy New Orleans Inc., hereinafter called ENOI; Entergy Texas Inc., hereinafter called ETI, and Entergy Services, Inc., hereinafter called Services, all of whose common stock is wholly owned by Entergy Corporation, hereinafter called Parent Company.

WITNESSETH 0.01 WHEREAS, EAI, EGSL, ELL, EMI, ENOI, and ETI hereinafter called Companies, are the owners and operators of electric generation, transmission and distribution facilities with which they are engaged in the business of generating, transmitting and selling electric energy to the general public and to other electric distributing agencies; and

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-82 Exhibit PJC-1 2011 TX Rate Case Page 5 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 5 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181

0.02 WHEREAS, Services is an associated Service Company acting as the Agent for the Companies under the terms of the Middle South Utilities System Agency Agreement and the Middle South Utilities System Agency Coordination Agreement dated the 11th day of December 1970; and 0.03 WHEREAS, the Companies have been achieving substantial benefits for their customers by operating within the framework of an interconnection agreement dated April 11, 1973; and 0.04 WHEREAS, the individual Companies are interconnected by transmission lines and operated as a coordinated system from a central dispatching center; and 0.05 WHEREAS, technological progress and changed economic conditions have necessitated the updating of the aforementioned interconnection agreement to continue to obtain the maximum benefits for them and their respective customers;

NOW THEREFORE, the Parties hereto mutually understand and agree as follows:

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-83 Exhibit PJC-1 2011 TX Rate Case Page 6 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 6 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181 ARTICLE I TERM OF AGREEMENT

1.01 This Agreement shall become effective on August 1, 1982, or such later date as may be fixed by any requisite regulatory approval or acceptance for filing and shall continue in full force and effect until terminated by mutual agreement of the Companies. Notwithstanding this, any Company may terminate its participation in this Agreement by ninety-six (96) months written notice to the other Companies hereto; and effective upon and after the date of implementation of retail open access in Texas, ETI shall terminate its participation in this Agreement, except as to Service Schedule MSS-2 (Transmission Equalization), consistent with Section 2.02 below.

1.02 This Agreement shall supersede the agreement listed below: Agreement among Arkansas Power & Light Company, Arkansas-Missouri Power Company, Louisiana Power & Light Company, Mississippi Power & Light Company, New Orleans Public Service Inc. and Middle South Services, Inc. dated the 16th day of April 1973 in FPC Docket No. E-8130 as amended in FERC Docket No. ER79-277, FERC Docket No. ER80-366, and FERC Docket No. ER 81-405.

1.03 This Agreement will be reviewed periodically by the Operating Committee to determine whether revisions are necessary to meet changing conditions. In the event that revisions are made by the parties hereto, and after requisite approval or acceptance for filing by the appropriate regulatory authorities, the Operating Committee will thereafter, for the purpose of ready reference to a single document, prepare for distribution to the Companies an amended document reflecting all changes in and additions to this Agreement with notations thereon of the date amended.

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-84 Exhibit PJC-1 2011 TX Rate Case Page 7 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 7 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181 ARTICLE II DEFINITIONS For the purpose of this Agreement and of the Service schedules which are a part hereof, the following definitions shall apply: 2.01 Agreement shall be this Agreement together with all attachments and service schedules applying thereto and any amendments made hereafter.

2.02 Company shall be one of the Entergy System Operating Companies (EAI, ELL, EMI, ENOI, EGSL, ETI).

2.03 Parent Company shall be Entergy Corporation.

2.04 Agent shall be Entergy Services, Inc. which shall act as Agent for one or more of the Companies whenever appropriate.

2.05 System shall be the interconnected coordinated systems of the Companies.

2.06 Operating Committee shall be the administrative organization created under this Agreement to administer its provisions.

2.07 Generating Unit shall be an electric generator, together with its prime mover and all auxiliary and appurtenant devices and equipment designed to be operated as a unit for the production of electric power and energy or as otherwise determined by the Operating Committee.

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-85 Exhibit PJC-1 2011 TX Rate Case Page 8 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 8 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181

2.08 Base Generating Units - shall be all generating units included in FERC accounts 310 through 316 and whose fuel supply is coal and all generating units included in FERC accounts through 325 whose fuel supply is nuclear respectively, and such other generating units as may be designated from time to time by the Operating Committee.

2.09 Intermediate Generating Units - shall be all generating units included in FERC accounts 310 through 316 and whose fuel supply is gas or oil and such other generating units as may be designated from time to time by the Operating Committee.

2.10 Peaking Generating Units - shall be all generating units included in FERC accounts through 346 and such other generating units as may be designated from time to time by the Operating Committee.

2.11 Hydraulic Production Units - shall be all generating units included in FERC accounts 330 through 336.

2.12 Qualified Cogeneration Capacity shall be any capacity available from a cogeneration facility that qualifies under Subpart B of Part 292 of the Regulations of the FERC, 18 C.F.R. § 292.201, et seq., as amended, or any successor provisions issued pursuant to Section 3(18)(B)of the Federal Power Act, and which, in accordance with Section 4.08 of this Agreement is under the control of the System Operator, to the extent practicable, and where the State or local regulatory body having jurisdiction over any Company which establishes the rate for a particular purchase also determines that the purchase will permit non-qualifying facility capacity costs to be avoided or, in the absence of such determination, to the extent that the Operating Committee determines that, in accordance with Section 4.01 of this Agreement and pursuant to Section 292.304 of the FERC Regulations or any successor provision, the capacity will be employed to postpone generation that would otherwise be installed and thereby benefit the customers of all Companies. Individual Qualified Cogeneration Capacity below 10 mW will not be considered as

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-86 Exhibit PJC-1 2011 TX Rate Case Page 9 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 9 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181

a power or energy source to any party to the System Agreement but will be considered as a negative load.

2.13 Qualified Small Power Production Capacity shall be any capacity available from a small power production facility that qualifies under Subpart B of Part 292 of the FERC Regulations, 18 C.F.R. § 292.201, et seq., as amended, or any successor provisions issued pursuant to Section 3(17)(C) of the Federal Power Act, and which, in accordance with Section 4.08 of this Agreement, is under the control of the System Operator, to the extent practicable, and where the State or local regulatory body having jurisdiction over any Company which establishes the rate for a particular purchase also determines that the purchase will permit non- qualifying facility capacity costs to be avoided or, in the absence of such determination, to the extent that the Operating Committee determines that, in accordance with Section 4.01 of this Agreement and pursuant to Section 292.304 of the FERC Regulations or any successor provision, the capacity will be employed to postpone generation that would otherwise be installed and thereby benefit the customers of all Companies. Individual Qualified Small Power Production Capacity below 10 mW will not be considered as a power or energy source to any party to the System Agreement but will be considered as a negative load.

2.14 Capability shall be the net output in megawatts that can be produced by a generating unit under conditions specified by the Operating Committee, that is devoted to serving System load but excluding that portion of any unit the output of which has been sold to another Company (other than through MSS-3), or the input in megawatts available under contract from a supplying source, excluding the portion of such supply that has been sold to another Company (other than through MSS-3), including any capacity determined in Sections 2.12 or 2.13 above, plus the contractual amount of firm purchases with reserves available during the month from other systems adjusted upward by the ratio of Seller's Capability and Seller's Load Responsibility as determined in Section 10.02C.

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-87 Exhibit PJC-1 2011 TX Rate Case Page 10 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 10 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181

2.15 System Capability shall be the arithmetical sum in megawatts of the individual Company Capabilities.

2.16 Company Load Responsibility shall be determined as follows: (a) To be used in conjunction with Service Schedules MSS-2 and MSS-6: (i) The average of the sum of the Company's twelve monthly hourly loads coincident with the System's monthly peak hour load for the period ended with the current month measured in megawatts. Each demand shall represent the simultaneous hourly input from all sources into the system of a Company, less the sum of the simultaneous hourly outputs to the systems of other interconnected utilities. (ii) Less the power supplied to others as sales for the joint account of all Companies. (b) As of April 1, 2004,* to be used in conjunction with Service Schedules MSS-1 and MSS-5 and in conjunction with the allocation of a purchase of capacity and energy for the joint account of all Companies under Section 4.02: (i) The average of the sum of the Company's twelve monthly hourly loads coincident with the System's monthly peak hour load for the period ended with the current month measured in megawatts.

Each demand shall represent the simultaneous hourly input from all sources into the system of a Company, less the sum of the simultaneous hourly outputs to the systems of other interconnected utilities. (ii) Less the power supplied to others as sales for the joint account of all Companies. * In the calculation pursuant to Section 2.16(b)(iii), the full amount of the interruptible load has been removed as of April 1, 2004 (as opposed to phased-in over a twelve month period).

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-88 Exhibit PJC-1 2011 TX Rate Case Page 11 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 11 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181 (iii) Less loads served under interruptible tariffs or contracts, where the interruptible load excluded at the time of the system’s monthly peak hour load (which does not include the excludable interruptible load determined herein) is to be that load that, pursuant to said tariff or contract, is subject to interruption.

To the extent practical the determination of what loads are interruptible shall be based on actual data and if it is not practical, shall be based on reasonable estimates.

2.17 System Load Responsibility: (a) To be used in conjunction with Service Schedules MSS-2 and MSS-6 shall be the arithmetical sum in megawatts of the individual Company Load Responsibilities derived pursuant to Section 2.16(a). (b) As of April 1, 2004, to be used in conjunction with Service Schedules MSS-1 and MSS-5 and in conjunction with the allocation of a purchase of capacity and energy for the joint account of all Companies under Section 4.02 shall be the arithmetical sum in megawatts of the individual Company Load Responsibilities derived pursuant to Section 2.16(b).

2.18 Responsibility Ratio of a Company shall be the ratio obtained by dividing the load responsibility of that company by the System Load Responsibility.

2.19 Capability Responsibility of a Company shall be the System Capability multiplied by the Responsibility Ratio for that Company.

2.20 Pool Energy shall be the energy generated by a Company in excess of its own requirements, or acquired by any Company under economic dispatch or as directed by the System Operator, that goes to supply requirements of other Companies. Such energy shall in all cases be nonfirm, that is, it has no guaranteed or assured availability.

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-89 Exhibit PJC-1 2011 TX Rate Case Page 12 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 12 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181

2.21 Cogeneration or Small Power Production Energy shall be the energy acquired by any Company from qualified facilities whether or not acquired under economic dispatch.

2.22 Transmission Responsibility of a Company shall be the System Net Inter-Transmission Investment multiplied by the Responsibility Ratio for that Company.

2.23 System Net Inter-Transmission Investment shall be the arithmetical sum of the individual Company Net Inter-Transmission Investments.

* 2.24 * Typographical error - 2.24 not used in numbering of definitions.

2.25 Day shall be a continuous 24-hour period beginning at midnight CST, or such other time as may be agreed upon by the Operating Committee.

2.26 Month shall be a calendar month.

2.27 Year shall be calendar year.

2.28 Power shall be the rate of doing work and shall be expressed in kilowatts (kW), megawatts (mW), or gigawatts (gW).

2.29 Energy shall be work and shall be expressed in kilowatt hours (kWh), megawatt-hours (mWh), or gigawatt-hours (gWh).

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-90 Exhibit PJC-1 2011 TX Rate Case Page 13 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 13 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181 ARTICLE III OBJECTIVES

3.01 The purpose of this Agreement is to provide the contractual basis for the continued planning, construction, and operation of the electric generation, transmission and other facilities of the Companies in such a manner as to achieve economies consistent with the highest practicable reliability of service, subject to financial considerations, reasonable utilization of natural resources and minimization of the effect on the environment. This Agreement also provides a basis for equalizing among the Companies any imbalance of costs associated with the construction, ownership and operation of such facilities as are used for the mutual benefit of all the Companies.

3.02 It is recognized by the Companies that economies of scale and integrated operations require that the planning, construction and operation of the bulk power supply and related facilities of the Companies be on a coordinated basis.

3.03 It is recognized that the Companies have traditionally used natural gas as their primary boiler fuel and that curtailments by suppliers have necessitated a conversion to oil as boiler fuel. Minimizing current and future costs of electricity and reducing energy dependence on oil and gas require the Companies to move toward a new fuel base of coal and nuclear.

3.04 It is recognized that these new coal and nuclear units will be Base Generating Units as defined in 2.08 and will be units of the larger ratings in generating stations of large size, strategically located with regard to fuel, water supply and electric load.

3.05 It is the long term goal of the Companies that each Company have its proportionate share of Base Generating Units available to serve its customers either by ownership or purchase.

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-91 Exhibit PJC-1 2011 TX Rate Case Page 14 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 14 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181

Any Company which has generating capacity above its requirements, which desires to sell all or any portion of such excess generating capacity and associated energy, shall offer the right of first refusal for this capacity and associated energy to the other Companies under Service Schedule MSS-4 Unit Power Purchase.

3.06 It is recognized that the installation of large base generating stations at locations, in many cases necessarily remote from major load centers, will require the installation of additional major high voltage and extra high voltage transmission lines and substations to connect these large generating stations to the major load centers in a manner to assure the highest practicable reliability of service.

3.07 It is recognized that reliability of service and economy of operation require that the energy supply to the system be controlled, to the extent practicable, from a centralized dispatching office and that this will require adequate communication facilities and the provision of economic dispatch computer facilities and automatic controls of generation.

3.08 By jointly planning on a systemwide basis for the construction and operation of these major facilities: (a) The combined loads of the Companies can be supplied with less aggregate installed capacity; and (b) Installations of additional capacity can be made at lower cost per kW because of the large unit sizes; and (c) The new installations will be more economical and require less operating labor and maintenance per kW because of the larger unit sizes; and (d) The strengthened transmission system will make possible a fuller utilization of the capability of the lower cost generating units of the System; and

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-92 Exhibit PJC-1 2011 TX Rate Case Page 15 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 15 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181

(e) Emergency conditions in any part of the System or other systems in adjacent areas can be met with less probability of impairment of service to the general public.

3.09 It is intended that each Company shall be willing and able to provide its portion of the major facilities determined to be necessary and each Company shall share in the benefits and pay its share of the costs of coordinated operations as agreed upon in accordance with Service Schedules to be attached hereto from time to time and made a part hereof.

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-93 Exhibit PJC-1 2011 TX Rate Case Page 16 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 16 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181 ARTICLE IV OBLIGATIONS

4.01 Production Facilities Each Company shall normally own, or have available to it under contract, such generating capability and other facilities as are necessary to supply all of the requirements of its own customers.

Each Company shall furnish the Operating Committee, at the time and in the manner designated, estimates of its annual peak load for the next succeeding 10-year period, or such period as may be required, together with estimates of its capability available from generating units in operation, under construction or already approved, capability available from other sources under contract and Qualified Cogeneration Capacity or Qualified Small Power Production Capacity in accordance with Sections 2.12 and 2.13 of this Agreement.

The Operating Committee shall then determine a generation addition plan to provide capacity for the projected system load and furnish reliable service to customers at the lowest cost consistent with sound business practice. Any anticipated large blocks of power sales not previously submitted to the Operating Committee shall be submitted to the Operating Committee as soon as load information is available so that appropriate capacity can be scheduled into the generation addition plan.

Each Company that installs a Generating Unit will make the necessary financial arrangements and promptly proceed with the design and construction of the unit to meet the "in-service" date of the generation addition plan.

Any Capability in excess of the Capability Responsibility of a Company that may exist in the system of one or more Companies as a result of installation of facilities in accordance with the provisions of the generation addition plan shall be equalized among the Companies in accordance with the provisions of the applicable Service Schedule.

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-94 Exhibit PJC-1 2011 TX Rate Case Page 17 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 17 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181

4.02 Purchased Capacity & Energy The Companies, with the consent of or under conditions specified by the Operating Committee, may agree to a contract by one or more of them, for the purchase of capacity and/or energy from outside sources for the account of a Company or Companies.

If purchased by a Company for its own account, the capacity shall be included by the purchasing Company in its Capability to the extent provided by the applicable Service Schedule.

The energy purchased shall be considered as part of the purchasing Company's energy supply.

If purchased by a Company for the joint account of less than all of the Companies, the capacity and energy shall be allocated among the purchasing Companies in any manner mutually agreeable to them.

If purchased by a Company for the joint account of all the Companies, the capacity and energy shall be allocated to each Company in proportion to its Responsibility Ratio based on Sections 2.16(b) and 2.17(b) in effect at the end of the preceding month. Each Company shall include its allocated portion of the capacity, so purchased, in its Capability to the extent provided by the applicable Service Schedule and shall include its portion of the energy so purchased in its energy supply. Each Company shall pay for capacity and energy allocated to it hereunder at the rates paid by the Company making the purchase.

4.03 Energy Purchased by Services Services, through the System Operations Center, may purchase energy under economic dispatch or emergency conditions, in accordance with Article VI paragraph 6.02 of this Agreement, for the joint account of all the Companies. The energy purchased shall be allocated to each Company in proportion to its Responsibility Ratio in effect at the end of the preceding month.

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-95 Exhibit PJC-1 2011 TX Rate Case Page 18 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 18 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181

4.04 Capacity and Energy Exchanged with Outside Systems Capacity and energy may be delivered to or received from an outside system under agreements providing for a return in kind. The accounting for such deliveries and receipts shall be as follows: (a) If the System supplies first, the obligations to supply shall be prorated to each Company, in proportion to its Responsibility Ratio in effect as of the preceding October 31st, and the capacity and energy which each Company is entitled to receive in return shall be equal to the obligation to supply. (b) If the System receives first, the capacity and energy to be received shall be prorated to each Company in proportion to its Responsibility Ratio in effect as of the preceding October 31st, and each Company shall be obligated to supply in return the amount of capacity and energy that it was entitled to receive.

4.05 Sales to Others for the Joint Account of All the Companies Sales of capacity and energy to others for which any Company does not wish to assume sole responsibility, shall, with the consent of or under conditions specified by the Operating Committee, be made by the Company having direct connection with such others, for the joint account of all the Companies, and the net balance derived from such sales shall be divided among the Companies as provided in the applicable Service Schedule.

4.06 Transmission Facilities The Companies own and operate extensive transmission systems traversing their operating areas and interconnecting with each other, as well as with the transmission systems of adjacent utilities.

It is agreed that portions of each Company's bulk power transmission system shall be equalized in accordance with the applicable Service Schedule so that the ownership costs of those transmission facilities shall be distributed equitably among the Companies.

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-96 Exhibit PJC-1 2011 TX Rate Case Page 19 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 19 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181 The Operating Committee shall make studies of bulk power transmission facilities and agree upon the facilities that will be required to transmit the power supply from generating or other sources to the load centers. The facilities agreed upon shall be built to comply with a time schedule determined by the Operating Committee and shall be adequate to provide the bulk power transmission system requirements with due allowances for contingencies that may reasonably be expected. The Operating Committee shall agree on the general routes of bulk power transmission lines, the voltages and conductor sizes, and the location of substations which are covered by this Agreement.

4.07 Communication and Other Facilities The Companies shall provide communication and other facilities, determined by the Operating Committee to be necessary for metering, control, protection and dispatch of the production and transmission facilities, and for such other purposes as may be necessary or desirable for the operation of the Companies' Systems.

4.08 Dispatch Under general direction of the Operating Committee, Services will operate a centralized operations center properly equipped and staffed to dispatch the capacity and energy capability of the Companies, in the efficient, economical, and reliable manner as provided in this Agreement.

All generating units, included in System Capability under this Agreement, presently in operation or installed in the future, shall be equipped with such controls as may be determined by the Operating Committee to be necessary to accomplish such centralized economic dispatch.

It is recognized by the Companies that, because of such economic dispatch, a Company may not, at all times, be supplying the energy requirements of its system, but may be taking energy from the resources of the other Companies or supplying energy to the other Companies.

The payments or charges for such energy exchange shall be as provided in the applicable Service Schedule.

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-97 Exhibit PJC-1 2011 TX Rate Case Page 20 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 20 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181

4.09 Records and Reports Services shall keep such records as may be necessary for the efficient administration of the Agreement, and shall make such records available to any Company on request. Each Company shall make all reports requested by the Operating Committee within the time prescribed.

4.10 Regulatory Authorization This Agreement is subject to certain regulatory approvals and each Company shall diligently seek all necessary regulatory authorization for this Agreement and the performance of its obligations thereunder.

4.11 Effect on Other Agreements This Agreement shall not modify the obligations of any Company under any Agreement between that Company and others not parties to this Agreement in effect at the date of this Agreement.

4.12 Service Schedules The basis of compensation for the use of facilities and for the capacity and energy provided or supplied by a Company to another Company or Companies under this Agreement shall be in accordance with arrangements agreed upon from time to time among the Companies.

Such arrangements shall be in the form of Service Schedules, each of which, when signed by the parties hereto, and approved or accepted for filing by appropriate regulatory authority shall be attached to and become a part of this Agreement.

Each Company reserves the right to unilaterally seek amendments or changes in the terms and conditions of service and increases or decreases in the rates and charges provided in any of the Service Schedules from any regulatory body having or acquiring jurisdiction thereover.

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-98 Exhibit PJC-1 2011 TX Rate Case Page 21 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 21 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181

4.13 Measurements All capacity and energy measurements, such as between the systems of the Companies, shall be made at or corrected to the points of interconnection unless otherwise agreed to by the Operating Committee.

4.14 Billings Bills for services rendered hereunder shall be calculated in accordance with applicable Service Schedules, and shall be issued on the fifth working day of the month following that in which such service was rendered and shall be payable on or before the 15th day of such month.

After the 20th day, interest shall accrue on any balance due at the rate as determined in Section 35.19a(2)iii of the FERC Regulations, or at such other rate established by the Operating Committee.

4.15 Waivers Any waiver at any time by a Company of its rights with respect to a default by any other Company under this Agreement, shall not be deemed a waiver with respect to any subsequent default.

4.16 Successors and Assigns This Agreement shall inure to the benefit of and be binding upon the successors and assigns of the respective Companies here to, but shall not be assignable by any Company without the written consent of the other Companies, except upon foreclosure of a mortgage or deed of trust.

4.17 Amendment This Agreement may be changed, amended, or supplemented, only by an instrument in writing, signed by all the Companies.

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-99 Exhibit PJC-1 2011 TX Rate Case Page 22 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 22 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181

4.18 Independent Contractors It is agreed among the Companies that by entering into this Agreement providing for the coordinated planning, construction and operation of power production, transmission, communications and other facilities of the Companies, the Companies shall not become partners, but as to each other and to third persons, the Companies shall remain independent contractors in all matters relating to this Agreement.

4.19 Responsibility for Loss or Damage Each Company shall defend, indemnify, and save harmless the other Companies, against liability, loss, costs and expenses on account of any injury or damage to persons or property occurring on or in connection with its facilities on its side of any of the points of interconnection, except to the extent such injury or damage was caused by the sole or contributory negligence of another Company, its agent or employees.

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-100 Exhibit PJC-1 2011 TX Rate Case Page 23 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 23 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181 ARTICLE V COMPOSITION AND DUTIES OF THE OPERATING COMMITTEE

5.01 Operating Committee An Operating Committee shall be the administrative organization of this Agreement and shall consist of members designated by the chief executive officers of each Company and by the chief executive officer of the Parent Company. Such designation shall be by written notice to the Secretary of the Operating Committee with copies to each of the other Companies. The Companies and the Parent Company may change its designated members at any time by written notice to the Secretary of the Operating Committee and each of the other Companies.

5.02 Officers of the Operating Committee The Operating Committee shall have the following officers with duties as designated: (a) Chairman - The Chairman shall issue calls for and shall preside at meetings of the Operating Committee. He shall have responsibility for the general coordination of the Operating Committee functions among the various members. (b) Vice Chairman - The Vice Chairman shall perform the duties of the Chairman in his absence or incapacity. (c) Secretary - The Secretary shall be responsible for keeping the minutes of the meetings of the Operating Committee and for preparing copies thereof and for distributing them to the Companies. The Secretary shall be responsible for obtaining written approval from the Companies for any acts or decisions of the Operating Committee which may require such written approval, and shall be responsible for distributing copies of such approvals to the Companies.

The Chairman and Vice Chairman shall be elected from the members by majority vote at the first meeting held in each calendar year and shall take office immediately upon being elected.

The Secretary shall be designated by the Operating Committee.

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-101 Exhibit PJC-1 2011 TX Rate Case Page 24 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 24 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181

5.03 Meeting Dates The Operating Committee shall hold meetings at least quarterly and at any time upon the request of a member, and shall keep minutes of its proceedings.

5.04 Decisions All decisions of the Operating Committee shall be by a majority vote. For the purposes of voting, the Parent Company shall have twenty (20) percent of the vote and the remaining eighty (80) percent shall be divided among the Companies in proportion to each Company's Responsibility Ratio in effect as of the preceding December 31st.

5.05 Attendance at Meetings Each Company and the Parent Company shall be represented at each Operating Committee meeting by their members on the Committee or a proxy designated by the member or chief executive officer. Such proxy member need not be an employee of the Company represented.

5.06 Duties The Operating Committee shall: (a) Be responsible for the day-to-day administration of the Agreement and for the filing of this Agreement and any amendments thereto with the Federal Energy Regulatory Commission for approval or acceptance for filing and for distributing copies of such filings to the Companies. (b) Make the studies required to fulfill the obligations agreed to in the Article IV of this Agreement, and its decisions shall become the basis for the installation of generation, bulk power transmission, communication, and other facilities necessary for the supply of capacity and energy to the System.

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-102 Exhibit PJC-1 2011 TX Rate Case Page 25 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 25 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181

(c) Determine the amount of and require installation of adequate reserves of System Capability to assure, insofar as practicable, the continuous supply of capacity and energy to the major load centers of the System. (d) Establish safe loading criteria for generating units, transmission lines and any other facilities necessary for the supply of power and energy to the major load centers of the System. (e) Promulgate whatever standards may be required for the safe and reliable operation of the System. (f) Consult with and provide general supervision for Services in employing and supervising a System Operator and provide for such assistance as needed. (g) Determine the need for and generally supervise the keeping of records and the making of such reports as are deemed necessary or appropriate. (h) Determine the need for and generally supervise communications, interchange and automatic generation control, metering, economic dispatch and relaying facilities necessary for the purpose of this Agreement. (i) Make any determinations required for the purpose of administering any schedules subject to its administration. (j) Study and determine from time to time additions or changes in facilities necessary to keep abreast of the production and transmission requirements of the System. (k) Provide for and coordinate safe dispatching, switching and other routine procedures. (l) Provide for proper distribution of spinning reserves and the supply of reactive kVa.

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-103 Exhibit PJC-1 2011 TX Rate Case Page 26 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 26 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181

(m) Establish, amend, supplement or terminate from time to time rules, procedures or practices as necessary to insure functioning of the System within the scope of this Agreement. (n) Coordinate negotiations with others from time to time for interchange and sale of power and energy. (o) Coordinate arrangements for the sale and delivery to others on a profitable basis, of power and energy not required for System purposes. (p) Coordinate arrangements from time to time to procure for the Companies, or for their account, such power and energy from external sources as may be required or will result in savings to the Companies. (q) Keep abreast of all environmental factors as they affect the operation of the System in order to comply with all established criteria for minimizing pollution. (r) Undertake any other duties that may from time to time be assigned to it or deemed appropriate.

5.07 Employment of Consultants The Operating Committee, in the performance of its duties, may employ such technical and consulting services as warranted.

5.08 Expenses of Committee Each Company (except the Parent Company) shall pay the expenses of its representatives on the Operating Committee. The expenses of the representatives of the Parent Company shall be paid by Services. Any other expenses of the Committee shall be prorated among the Companies as determined by the Operating Committee.

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-104 Exhibit PJC-1 2011 TX Rate Case Page 27 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 27 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181 ARTICLE VI SYSTEM OPERATIONS CENTER

6.01 System Operations Center The operation of the System shall be controlled by the System Operations Center which is operated by Services.

6.02 Duties Services through the System Operations Center shall: (a) Determine the most effective scheduling of sources for the reliable supply of power and energy on an economical basis to the Companies. (b) Supervise the operation and maintenance of computer facilities specified by the Operating Committee for the following purposes: 1. Economic system dispatch, 2. Determination of billing information, and 3. Determination of other data required by the Operating Committee. (c) Supervise safe switching procedures and other routine procedures in the system. (d) Determine the availability of energy for purchase from or sale to outside systems on an economical basis under effective contracts and arrange for and schedule such transactions. (e) Coordinate the operation of communication facilities owned or leased by the Companies to provide the communication essential to the safe, reliable and economical operation of the System. (f) Maintain such records and prepare such reports as the Operating Committee designates.

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-105 Exhibit PJC-1 2011 TX Rate Case Page 28 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 28 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181

6.03 Expenses All expenses of the Systems Operations Center shall be paid by Services and billed monthly to each Company in accordance with the applicable Service Schedule.

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-106 Exhibit PJC-1 2011 TX Rate Case Page 29 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 29 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181

IN WITNESS WHEREOF each of the Companies has caused these presents to be signed in its name and on its behalf by its President, attested by its Secretary, both being duly authorized.

Attest ARKANSAS POWER & LIGHT COMPANY Original signed by Original signed by R. J. Estrada Jerry Maulden Assistant Secretary President

Attest LOUISIANA POWER & LIGHT COMPANY Original signed by Original signed by W. H. Talbot J. M. Wyatt Secretary President

Attest MISSISSIPPI POWER & LIGHT COMPANY Original Signed by Original signed by R. J. Estrada D. C. Lutken Assistant Secretary President

Attest NEW ORLEANS PUBLIC SERVICE INC. Original signed by Original signed by William C. Nelson James M. Cain Secretary President

Attest MIDDLE SOUTH SERVICES, INC. Original signed by Original signed by D. E. Stapp Frank G. Smith Secretary President

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-107 Exhibit PJC-1 2011 TX Rate Case Page 30 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 30 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181

SERVICE SCHEDULE MSS-1 RESERVE EQUALIZATION 10.01 Purpose The purpose of this Service Schedule is to provide the basis for equalizing the capability and ownership cost incidental to such capability among the Companies in such a manner that the capability and reserves of each Company after equalization shall be equal to its Capability Responsibility.

10.02 Company Capability A Company's Capability shall be determined monthly and shall be the sum of available owned or leased generating units, purchases and seasonal or other energy exchange from demonstrated reliable sources as follows: (a) The total capability of available generating units owned, operated under Operating Agreements for its own benefit, or leased by such Company, devoted to serving System load but excluding that portion of any unit owned or leased by such Company that has been sold or leased to another Company (other than through MSS-3). Such units shall be included at their demonstrated net output measured in megawatts under conditions established by the Operating Committee.

A unit is considered available to the extent the capability can be demonstrated and (1) is under the control of the System Operator, or (2) is down for maintenance or nuclear refueling, or (3) is in extended reserve shutdown (ERS) with the intent of returning the unit to service at a future date in order to meet Entergy System requirements. The Operating Committee's decision to consider an ERS unit to be available to meet future System requirements shall be evidenced in the minutes of the Operating Committee and shall be based on consideration of current and future resource needs, the projected length of time the unit would be in ERS status, the projected cost of maintaining such unit, and the projected cost of returning the unit to service. A unit is considered unavailable if in the judgment

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-108 Exhibit PJC-1 2011 TX Rate Case Page 31 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 31 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181 of the Operating Committee it is of insufficient value in supplying system loads because of (1) obsolescence, (2) physical condition, (3) reliability, (4) operating cost, (5) start-up time required, or (6) lack of due-diligence in effecting repairs or nuclear refueling in the event of a scheduled or unscheduled outage.

The generating units of Gulf States that were in extended reserve shutdown on the date of the merger of Entergy and Gulf States, shall not be considered available for the purpose of determining Capability in the Service Schedule MSS-1 Reserve Equalization calculation until the units are brought into service.

If, as part of a settlement or judgment adverse to Gulf States in Cajun Electric Power Cooperative, Inc. v. Gulf States Utilities Co., Civil Action No. 89-474-B (M.D. La.) and/or Southwest Louisiana Electric Membership Corp. and Dixie Electric Membership Corp. v. Gulf States Utilities Co., Civil Action No. 92-2129 (W.D. La.), Gulf States acquires Cajun Electric Power Cooperative, Inc.’s 30 percent share of the River Bend Nuclear Generating Facility (River Bend) (or any portion thereof), then the net output in megawatts associated with such share shall not be considered available for the purpose of determining Capability in the Service Schedule MSS-1 Reserve Equalization calculation. (b) The contract quantity of capacity in megawatts purchased without reserves by the Company. (c) The contract quantity of firm capacity in megawatts purchased plus an additional amount as developed from the following formula: A = FP x SC - FP (SL - FP) where: A= Amount, in megawatts (mW), to be added to contract quantity of firm capacity purchased.

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-109 Exhibit PJC-1 2011 TX Rate Case Page 32 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 32 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181 FP = Amount of firm purchase in Mw SL = Seller's load responsibility in mW, determined by calculating the average of the Seller's monthly hour peak loads for the twelve month period ending with the current month. Each such peak load shall represent the simultaneous hourly input from all sources into the Seller's system, less the sum of the simultaneous hourly outputs to the systems of other interconnected utilities.

SC = Seller’s total capability which shall be determined monthly and shall be the sum of the net demonstrated capabilities of Seller’s owned or leased generating units and the contract quantity of capacity purchased by Seller, all measured in mW. (d) That portion of the contract quantity of capacity in megawatts purchased with or without reserves, for the joint account of all the Companies as allocated to the Company on the basis of Section 4.02. (e) That portion of the contract quantity of capacity in megawatts received under any seasonal or other exchange with outside suppliers for the joint account of all Companies, as allocated to the Company on the basis of its Responsibility Ratio. (f) Cogeneration or Small Power Production Capacity in accordance with Sections 2.12 and 2.13. The Operating Committee shall have the authority to allocate any such capacity to one or more of the Companies in accordance with FERC Opinion Nos. 246 and 246-A.

10.03 Basis of Reserve Equalization Company Capability in excess of the Capability Responsibility of any Company shall be allocated among the Companies so that the resultant capability and reserves of each Company shall be equal to its Capability Responsibility.

ER = CC - SC x CLR SLR

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-110 Exhibit PJC-1 2011 TX Rate Case Page 33 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 33 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181 where: ER = Equalized Reserve CC = Company Capability (Section 2.14) SC = System Capability (Section 2.15) CLR = Company Load Responsibility (Section 2.16 (b)) SLR = System Load Responsibility (Section 2.17 (b))

If more than one Company has Company Capability in excess of its Capability Responsibility, the excess of each such Company from its Intermediate Generating Units, as defined in Section 2.09 shall be allocated to each deficient Company in the ratio of such Company's deficiency to the sum of the deficiencies of the deficient Companies.

10.04 Reserve Equalization Payment For the reserve allocated in accordance with Section 10.03, the Company or Companies having an excess shall receive, from the Company or Companies having a deficiency, an equalization payment, determined in accordance with the method hereinafter described, for such reserve so allocated each month.

10.05 Investment in Intermediate Reserve Generating Units The generating units to be reflected in determining the costs to be billed under this Service Schedule are those that serve as reserves to the System and shall be defined by reference to their average annual heat rate. The Reserve Generating Units for each Party (based on Federal Energy Regulatory Commission's Uniform System of Accounts Prescribed for Public Utilities and Licensees) shall be those gas- and oil-fired units that had an annual average heat rate in the preceding calendar year of at least 10,000 Btu per kilowatt=hour. For Reserve Generating Units that were not in commercial operation for all of the preceding calendar year, the heat rate used to determine eligibility under this provision shall be specified by the Operating Committee. The

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-111 Exhibit PJC-1 2011 TX Rate Case Page 34 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 34 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181 investment in such Reserve Generating Units shall be determined as follows: (a) The cost includable for all such units in Accounts 310, 311, 312, 313, 314, 315 and 316. (b) The cost of step-up transformers, circuit breakers, and switching equipment etc. included in Account 353 and required to connect all such units to the transmission system.

10.06 Determination of Monthly Billing Charge _ The Monthly Charge (MC) per kW for billings under Reserve Equalization shall be determined for each Company based upon the previous year's operating results. The MC will be based on the average of all units included as Intermediate Generating Units as included in Sections 10.05 (a) and (b).

MC = (1/12) RB x (CM + F) + D + PT + I + FT + OM C where: CM = the weighted average cost of capital as determined in the following manner: CM = (DR x i) + (PR x p) + (ER x c) C = The sum of capacity in kW for the generating units in RB DR = Ratio of Debt Capital at Dec. 31 of the previous year PR = Ratio of Preferred Stock at Dec. 31 of the previous year ER = Ratio of Common Stock at Dec. 31 of the previous year i = Average embedded cost of debt capital outstanding at Dec. 31 of the previous year p = Average embedded cost of preferred stock outstanding at Dec. 31 of the previous year c = Return on Common Equity at 11.0%

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-112 Exhibit PJC-1 2011 TX Rate Case Page 35 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 35 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181 D = The amount of depreciation for the preceding year as reported on page 429 of the Company FERC Form No. 1 report as related to Intermediate Generating Units and associated equipment required to connect generating equipment to the transmission system.

F = Federal and State Income Taxes determined from the following formulae: F = T x (CM - DR x i) (1 - T) where: T = f + s - fs when federal tax is not deductible in computing state tax, and T = (f + s - 2fs) when federal tax is deductible in computing (1 - fs) state tax, and f = Federal Income Tax Rate s = State Income Tax Rate RB = The amount as of December 31, of the preceding year reflected in Plant Accounts 310, 311, 312, 313, 314, 315 and 316 for gas or oil fired Steam Production Plants, plus an amount included in Account 353 which represents the investment in step-up transformers, circuit breakers, and switching equipment, etc. required to connect all such units to the transmission system, less the accumulated provision for depreciation for the gas or oil fired units in the Steam Production plants and the accumulated provision for depreciation associated with the equipment included in Account 353 described above, and less the proportionate amount of Account 282 Accumulated Deferred Income Taxes.

I= Preceding year insurance premium for Intermediate Generating Units included in RB PT = Ad Valorem taxes for the preceding year for Intermediate Generating Units Included in RB FT = Applicable Corporation Franchise Tax for the preceding year for Intermediate Generating Units included in RB

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-113 Exhibit PJC-1 2011 TX Rate Case Page 36 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 36 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181 OM = Operation and maintenance expenses plus the applicable general and administrative expenses. These combined expenses will be determined annually by taking the applicable accounts for each Company related to their owned generating capacity, together with the applicable general and administrative expenses, proportioned to the direct labor expenses.

Fossil Fueled Units Direct - Accounts 500, 502, 503, 504, 505, 506, 507, 510, 511, 512, 513 and 514.

Allocable - Accounts 920, 921, 922, 923, 924, 925, 926, 927, 928, 929, 930, 931 and 932.

10.07 Adjustment for Tax Changes The Reserve Equalization Payment as determined above shall be adjusted to reflect the imposition of any applicable new taxes not included in the above formula, or for any increase or decrease in taxes included as of the date of this Agreement.

10.08 Billing Procedure The billing parameters will be in effect from June 1 to the succeeding May 31 based on the preceding year's results.

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-114 Exhibit PJC-1 2011 TX Rate Case Page 37 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 37 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181

This Service Schedule MSS-1 shall be attached to and become a part of the Agreement dated the 23rd day of April , 1982 and shall be effective with said Agreement or at such later date as may be fixed by any requisite regulatory approval or acceptance for filing.

Attest ARKANSAS POWER & LIGHT COMPANY Original signed by Original signed by R.J. Estrada Jerry Maulden Assistant Secretary President

Attest LOUISIANA POWER & LIGHT COMPANY

Original signed by Original signed by W. H. Talbot J. M. Wyatt Secretary President

Attest MISSISSIPPI POWER & LIGHT COMPANY

Original signed by Original signed by R. J. Estrada D. C. Lutken Assistant Secretary President

Attest NEW ORLEANS PUBLIC SERVICE INC.

Original signed by Original signed by William C. Nelson James M. Cain Secretary President

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-115 Exhibit PJC-1 2011 TX Rate Case Page 38 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 38 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181

SERVICE SCHEDULE MSS-2 TRANSMISSION EQUALIZATION 20.01 Purpose The purpose of this Service Schedule is to provide the basis for equalizing among the Companies the ownership costs associated with Inter-Transmission Investment in such a manner that each Company will bear a portion of these costs proportional to its Responsibility Ratio.

20.02 Inter-Transmission Investment A Company's Inter-Transmission Investment for the purpose of this schedule shall consist of: (a) All of the investment in transmission lines operated at 230 kV or higher voltage to the extent that such investment is not included in billings under other agreements. (b) Investment in transmission substations with three or more lines operated at a voltage of 230 kV or higher to the extent that such investment is not included in billings under other agreements. Investment in such substations shall include facilities down to but not including the high side disconnecting device of the transformer, 50% of common facilities, and other facilities as approved by the Operating Committee. Common substation facilities are those facilities not directly associated with any of the major power supplying voltages of the substation. They include but are not limited to land, roadway, lighting, control house, fill, fencing, supervisory equipment, etc. (c) All lines 115 kV and higher from the owning Company's last substation to the connecting point of another Company (either Entergy System Company or nonsystem Company) not included in (a), or not included in billings under other agreements.

The investment in a generating unit step-up transformer and associated switchgear, necessary to connect the generating unit to the lines or all buses, shall not be included in subsection (b).

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-116 Exhibit PJC-1 2011 TX Rate Case Page 39 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 39 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181 In determining the investments above referred to under subsections (a) and (c), only those transmission line costs includable in Accounts 350, 352, 354, 355, 356, 357, 358 and 359 of the Federal Energy Regulatory Commission's Uniform System of Accounts Prescribed for Public Utilities and Licensees.

The investments above referred to under subsection (b) are amounts includable in the accounts listed in the preceding paragraph plus Account 353.

The investment in new transmission facilities included under this Service Schedule shall be added to a Company's Inter-Transmission Investment on the first day of the month following the "in service" date of the facilities. Each Company's Inter-Transmission Investment shall be revised as of the end of each month to adjust for any additions or retirements.

20.03 Company Net Inter-Transmission Investment - Company Net Inter-Transmission Investment shall be the sum of the Company Inter-Transmission Investments reduced for the Accumulated Provision for Depreciation and Deferred Taxes as adjusted at each December 31.

20.04 Transmission Responsibility - A Company's Transmission Responsibility shall be the sum of the System Net Inter-Transmission Investments multiplied by that Company's Responsibility Ratio.

20.05 Transmission Equalization Payments - Each Company shall pay or receive each month, as appropriate, an amount in dollars determined by the following formula: Dollars ($) = 1/12 (TR - TI) (AOC) where: TR = The Company's Transmission Responsibility as defined in Section 20.04 TI = The Company's Net Inter-Transmission Investment as defined in Section 20.03 AOC = System Average Annual Ownership Cost

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-117 Exhibit PJC-1 2011 TX Rate Case Page 40 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 40 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181 20.06 Development of Company's Annual Ownership Cost - (AOCc) - The Annual Ownership Cost, expressed as a decimal, shall be determined as follows: AOCc = (CM + F) + | D + I + PT + FT + OM | | K | where: CM = the weighted average cost of capital determined as follows: CM = (DR x i) + (PR x p) + (ER x c) DR = Ratio of Debt Capital at Dec. 31 of the previous year PR = Ratio of Preferred Stock at Dec. 31 of the previous year ER = Ratio of Common Stock at Dec. 31 of the previous year i = Average embedded cost of debt capital outstanding at Dec. 31 of the previous year p = Average embedded cost of preferred stock outstanding at Dec. 31 of the previous year c = Return on common equity at 11.0% F = Federal and State Income Taxes as determined from the formulas: F= T x [CM - DR x i] (1 - T) T = f + s - fs when federal tax is not deductible in computing state tax, and T = f + s - 2fs when federal tax is deductible in - fs computing state tax, and f = Federal Income Tax Rate s = State Income Tax Rate weighted on prior year jurisdictional revenues if two or more state jurisdictions are served K= The ratio of a Company's Net Inter-Transmission Investment and Inter- Transmission Investment (i.e., Section 20.03 ÷ Section 20.02) D= Book depreciation as used by each Company expressed as a decimal of Inter- Transmission Investment (Section 20.02).

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-118 Exhibit PJC-1 2011 TX Rate Case Page 41 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 41 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181 I= Annual insurance cost expressed as a decimal of Inter-Transmission Investment (Section 20.02).

PT = Average ad valorem taxes based on preceding year's tax rates and assessments for the Inter-Transmission Investment expressed as a decimal of Inter-Transmission Investment (Section 20.02).

FT = Corporate Franchise Tax based on preceding year's Inter-Transmission Investment expressed as a decimal of Inter-Trans-mission Investment (Section 20.02).

OM = Operating and maintenance expenses plus the applicable general and administrative expenses expressed as a decimal of Inter-Transmission Investment (Section 20.02). These combined expenses will be determined annually by taking the applicable accounts for each Company, related to their total transmission investment, together with the applicable general and administrative expenses and proportioned to the direct labor expenses.

Direct - Accounts 560, 561, 562, 563, 564, 565, 566, 567, 568, 569, 570, 571, 572 and Allocable - Accounts 920, 921, 922, 923, 924, 925, 926, 927, 928, 929, 930, 931 and 20.07 Development of System Average Annual Ownership Cost The System Average Annual Ownership Cost to be applied to this Service Schedule shall be developed from the following formula:

AOC = (A x AOCA)+(G x AOCG)+(L x AOCL)+(M x AOCM)+(N x AOCN) + (T x AOCT) A+G+L+M+N+T where: AOC = System Average Annual Ownership Cost A = EAI Net Inter-Transmission Investment G = EGSL Net Inter-Transmission Investment L = ELL Net Inter-Transmission Investment

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-119 Exhibit PJC-1 2011 TX Rate Case Page 42 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 42 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181 M = EMI Net Inter-Transmission Investment N = ENOI Net Inter-Transmission Investment T = ETI Net Inter-Transmission Investment AOCA = EAI - Annual Ownership Cost AOCG = EGSL - Annual Ownership Cost AOCL = ELL - Annual Ownership Cost AOCM = EMI - Annual Ownership Cost AOCN = ENOI - Annual Ownership Cost AOCT = ETI - Annual Ownership Cost

20.08 Adjustment for Tax Changes The Transmission Equalization Payment as determined in Section 20.05 shall be adjusted to reflect the imposition of any applicable new taxes not included in the above formula, or for any increase or decrease in taxes included as of the date of this Agreement.

20.09 Billing Procedure The billing parameters will be in effect from June 1 to the succeeding May 31, based on the preceding year's results.

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-120 Exhibit PJC-1 2011 TX Rate Case Page 43 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 43 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181

This Service Schedule MSS-2 shall be attached to and become a part of the Agreement dated the 23rd day of April, 1982 and shall be effective with said Agreement or at such later date as may be fixed by any requisite regulatory approval or acceptance for filing.

Attest ARKANSAS POWER & LIGHT COMPANY

Original signed by Original signed by R. J. Estrada Jerry Maulden Assistant Secretary President Attest LOUISIANA POWER & LIGHT COMPANY

Original signed by Original signed by W. H. Talbott J. M. Wyatt Secretary President Attest MISSISSIPPI POWER & LIGHT COMPANY

Original signed by Original signed by R. J. Estrada D. C. Lutken Assistant Secretary President Attest NEW ORLEANS PUBLIC SERVICE INC.

Original signed by Original signed by William C. Nelson James M. Cain Secretary President

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-121 Exhibit PJC-1 2011 TX Rate Case Page 44 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 44 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181 SERVICE SCHEDULE MSS-3 EXCHANGE OF ELECTRIC ENERGY AMONG THE COMPANIES 30.01 Purpose The purpose of this Service Schedule is to provide the method of pricing energy exchanged among the Companies and to provide for payments and receipts in accordance with the provisions of Opinion Nos. 480 and 480-A.

30.02 Scheduling of Energy Sources The System Capability shall be operated as scheduled and/or controlled by the System Operator to obtain the lowest reasonable cost of energy to all the Companies consistent with the requirements of daily operating generation reserve, voltage control, electrical stability, loading of facilities and continuity of service to the customers of each Company.

In no event shall the remaining margin payment obligations of ETI to Southwestern Electric Power Corporation under Section 9.1 of the Restated and Amended Interconnection Agreement between ETI and Southwestern Electric Power Company, be included, considered or otherwise taken into account by the System Operator under Section 30.02 of the System Agreement, except for the circumstance where the lowest reasonable cost energy available to the System Operator is identical in price to that offered to ETI under such Section 9.1.

30.03 Allocation of Energy The energy from the lowest cost source available and scheduled as in Section 30.02 above shall be allocated on an hourly basis, in the order of the following priorities: (a) first to the loads of the Company having such sources available, except that in the case of energy generated by a Designated Generating Unit, each Company to which a portion of the Capability of the Designated Generating Unit as defined in Section 40.02 has been sold shall be entitled to receive each hour that portion of the total energy generated by the Designated Generating Unit that the capability sold to the Company bears to the total capability of the Designated Generating Unit.

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-122 Exhibit PJC-1 2011 TX Rate Case Page 45 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 45 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181 (b) second to supply the requirements of the other Companies' Loads (Pool Energy).

30.04 Energy for Sales to Others Energy used to supply others will be provided in accordance with rate schedules on file with the Federal Energy Regulatory Commission. A Company will be reimbursed for the current estimated cost of fuel used by the specific unit or units supplying the energy together with the adder determined in Section 30.08(f) on an hour by hour basis.

30.05 Unscheduled Energy Energy produced by generating units not scheduled for system energy requirements but operated at the request of a Company beyond what is deemed necessary for overall system purposes by the System Operator, shall not be considered as part of Sections 30.03 or 30.04 above, but shall be for the use, and at the expense of the Company requesting the operation of such generating units.

30.06 Fuel Contract Energy Energy produced by generating units for system energy requirements shall be allocated as follows: (a) When operated to satisfy "take or pay" minimums under fuel contracts negotiated for System benefit as approved by the Operating Committee shall be shared by all companies in proportion to their current Responsibility Ratio. (b) When operated with fuel acquired for the benefit of two or more of the Companies shall be shared in proportion to their participation in such contracts. (c) When operated pursuant to fuel purchases negotiated for System benefit as approved by the Operating Committee, the Company owning the units utilizing the fuel has a one-time option to either assume responsibility for purchase of the fuel for its own account or to allow the fuel to be purchased for the System's joint account in accordance with 30.06(a) or (b) as appropriate.

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-123 Exhibit PJC-1 2011 TX Rate Case Page 46 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 46 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181

30.07 Cogeneration or Small Power Production Energy Energy received by any Company from Cogeneration or Small Power Production Sources that is included as a part of Inter-Company billings shall be priced under this Agreement in accordance with rates established by the appropriate regulatory authority. The Operating Committee shall have the authority to allocate such energy to one or more of the Companies or to determine that the energy is for the use, and at the expense of, the Company making the purchase from such Source in accordance with FERC Opinion Nos. 246 and 246-A.

30.08 Payments to be Received for Energy Supplied Each Company shall receive, for energy furnished in accordance with Sections 30.03 (a),(b) and 30.04 in excess of its load requirements, on an hourly basis: (a) For each kWh generated as short term purchase energy from a Designated Generating Unit in accordance with Section 30.03(a), whether or not taken by the Company or Companies making the purchase, the cost of fuel consumed. (b) For each kWh generated by use of fossil fuel, in accordance with Sections 30.03(b) and 30.04, the cost of fuel consumed plus an adder as determined in Section 30.08 (f). (c) For each kWh generated as Fuel Contract Energy, in accordance with Section 30.06, the cost of fuel consumed plus an adder as determined in Section 30.08(f). (d) For purchased energy, the actual cost of such purchased energy. The "actual cost" of purchased energy for ETI shall not include the remaining margin payment obligation of ETI to Southwestern Electric Power Company, under Section 9.1 of the Restated and Amended Interconnection Agreement between ETI and Southwestern Electric Power Company. (e) For each kWh received as Cogeneration or Small Power Production energy in accordance with Section 30.07, the price established in Section 30.07.

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-124 Exhibit PJC-1 2011 TX Rate Case Page 47 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 First Revised Sheet No. 47 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Superseding Original Sheet No. 47 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181 (f) The adder for Sections 30.08(b) and 30.08(c) shall be determined pursuant to the following formula.

Adder = A + B + C where: A = .5563 O&M (current) ÷ NSGC O&M (base) ÷ NSGB where, A= O&M adder in mills/kWh adjusted annually O&M = Accounts 500, 502, 503, 504, 505, 506, 507, 510, 511, 512, 513 and 514 Current = Three years ending with preceding year NSGC = Net steam generation in kWh for the three years ending with preceding year Base = Three years of 1978, 1979 and 1980 NSGB = Net steam generation in kWh for 1978, 1979 and 1980 base period .5563 = The amount applicable at the date of this agreement ∴ O&M (base) ÷ NSGB = 1.6724

B = AC x HR x (SR/2,000,000) where, B= Incremental replacement SO2 cost (in mills/kWh) for the particular generating unit, adjusted weekly AC = allowance cost (in $/allowance), adjusted weekly based on the average cost of purchasing an emission allowance from an index accepted by FERC within a test block approximately equal to the amount of emission allowances needed to support wholesale transactions under this System Agreement and power sales arrangements between the Companies and others.

HR = heat rate (in Btu/kWh) SR = SO2 rate for fuel (in lb SO2/MMBtu)

Issued by: Kimberly Despeaux Effective: July 1, 2009 Associate General Counsel Issued on: May 1, 2009 2011 ETI Rate Case 9-125 Exhibit PJC-1 2011 TX Rate Case Page 48 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 47A Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181

C = NC x HR x (NR/2,000,000) where, C= incremental replacement NOx cost (in mills/kWh) for the particular generating unit, adjusted weekly NC = allowance cost (in $/allowance), adjusted weekly based on the average cost of purchasing a NOx emission allowance from an index accepted by FERC within a test block approximately equal to the amount of emission allowances needed to support wholesale transactions under this System Agreement and power sales arrangements between the Companies and others.

HR = heat rate (in Btu/kWh) NR = NOx rate for fuel (in lb NOx/MMBtu)

Issued by: Kimberly Despeaux Effective: July 1, 2009 Associate General Counsel Issued on: May 1, 2009 2011 ETI Rate Case 9-126 Exhibit PJC-1 2011 TX Rate Case Page 49 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 48 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181

30.09 Payments Made for Energy (a) Each Company shall pay for energy allocated to it from a Designated Generating Unit as purchased energy the cost of fuel consumed per kWh. (b) Each Company shall pay for energy received from the energy allocated in accordance with the provisions of Section 30.03(b) above, the weighted average cost per kWh of energy, as provided under Section 30.08(b) above, accumulated and distributed on a hourly basis. (c) Each Company shall pay for energy received from the energy allocated in accordance with the provisions of Section 30.06 above, the cost per kWh of energy as provided under Section 30.08(c) above, accumulated and distributed on a hourly basis. (d) Each Company shall pay or receive funds to the extent required to maintain Rough Production Cost Equalization in accordance with the provisions of Sections 30.11 through 30.14 below.

30.10 Cost of Fuel Per kWh Cost of fuel per kWh shall be determined for each generating unit by multiplying the BTU consumed per kWh of net generation during the preceding calendar year by the current estimated cost per BTU of the fuel used as furnished by each Company monthly. For the first year of operation of a new unit, BTU consumed per kWh of net generation shall be based on the design heat rate at 60% of full load capability at anticipated average annual back pressure.

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-127 Exhibit PJC-1 2011 TX Rate Case Page 50 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 49 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181

30.11 Rough Production Cost Equalization To maintain Rough Production Cost Equalization (RPCE) among the Companies, each Company’s actual Production Cost (PC) as determined in accordance with Section 30.12, shall be compared to its respective allocation of the System Average Production Cost (APC), as determined in accordance with Section 30.13, to determine if a Company’s PC deviates from its APC by more than +/-11%. where: Paying Company(ies) is a Company or Companies with a negative Disparity that could make payments under this provision; Receiving Company(ies) is a Company or Companies with a positive Disparity that could receive payments under this provision; and, Disparity (D) equals the ratio of PC to APC expressed in terms of the divergence from 100% D = (PC/APC - 1)* 100% (a) If one or more Companies has a positive Disparity greater than eleven percent (11%), but no Company(ies) has a negative Disparity greater than 11%, then a payment shall be made by the Paying Company(ies) to the Receiving Company(ies) such that the positive Disparity of any Receiving Company(ies) after reflecting such payment is equal to 11% and the negative Disparity of any Paying Company(ies) after reflecting such payment is no less than the negative Disparity of any other Paying Company. (b) If one or more Companies has a negative Disparity greater than 11%, but no Company has a positive Disparity greater than 11%, then a payment shall be made by the Paying Company(ies) to the Receiving Company(ies) such that after reflecting such payment, any Paying Company(ies) has a negative Disparity equal to 11% and that the positive Disparity of any Receiving Company(ies), after reflecting such payment, is no less than another Receiving Company.

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-128 Exhibit PJC-1 2011 TX Rate Case Page 51 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 50 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181 (c) If one or more Receiving Companies has a positive Disparity greater than 11% and one or more Companies has a negative Disparity greater than 11%, then a payment shall be made by the Paying Company(ies) with a negative Disparity greater than 11% to the Receiving Company(ies) with a positive Disparity greater than 11% such that after reflecting such payments, all Receiving Company(ies) will not have a Disparity exceeding 11% and the payment obligation shall be distributed among Paying Companies such that no Company that will be making payments has a negative Disparity after reflecting such payments less than that of any other Paying Company. In the event that the payments made reduce the positive Disparity of a Receiving Company(ies) to 11% but that one or more Paying Companies has a negative Disparity after reflecting such payments that is greater than 11%, then payments shall be made such that no Paying Company has a negative Disparity that is greater than 11% and that the positive Disparity of any Receiving Company, after reflecting such payments, is no less than another Receiving Company.

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-129 Exhibit PJC-1 2011 TX Rate Case Page 52 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 51 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181 30.12 Actual Production Cost The actual production cost (PC) is the sum of the actual variable production cost (VPC) and the actual fixed production cost (FPC) and shall be determined for each Company.1 The formula for developing the actual production cost is as follows: PC = VPC + FPC where: VPC = Variable Production Cost = VPRB * (CM + F) + VPX where: VPRB = Variable Production Rate Base 2 = NPP – NAD – (ADIT * NPPR) NPP = Nuclear Production Plant in Service as recorded in FERC Plant Accounts 320 through 325 and FERC Account 101.1 excluding Asset Retirement Obligations (ARO) recorded in FERC Plant Account 326, if any All Rate Base, Revenue and Expense items shall be based on the actual amounts on the Company’s books for the twelve months ended December 31 of the previous year as reported in FERC Form 1 or such other supporting data as may be appropriate for each Company; and shall include certain retail regulatory adjustments pursuant to the production cost methodology set forth in Exhibit ETR-26/ETR-28 filed in Docket No. EL01-88-001, including but not limited to: (1) the Deregulated Asset Plan adjustment for EGSL, (2) the regulated portion (70%) of River Bend for EGSL, (3) repricing of energy associated with the Vidalia purchase power contract for ELL based on the average annual Service Schedule MSS-3 rate paid by ELL, including the exclusion of the income tax savings of the Vidalia purchase power contract from ADIT and reflecting the reversal of the Vidalia capital transaction, and the debt rate associated with the Waterford 3 Sale/Leaseback for ELL, (4) exclusion of the EAI and EMI retail approved Grand Gulf Accelerated Recovery Tariff effects on purchased power on EAI’s and EMI’s production cost and (5) exclusion of any increased costs resulting from the amended Toledo Bend Power Sales Agreement accepted for filing in Docket No. ER07-984.

Rate Base values shall be based on the actual balances on the Company’s books as of December 31 of the previous year except for Fuel Inventory, Materials & Supplies and Prepayments which shall be based on the average of the beginning and ending actual balances on the Company’s books.

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-130 Exhibit PJC-1 2011 TX Rate Case Page 53 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 52 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181 NAD = Nuclear Accumulated Provision for Depreciation and Amortization excluding ARO associated with NPP above, as recorded in FERC Accounts 108 and 111 (consistent with the accounting relating to Statement of Financial Accounting Standards (SFAS) 143 approved by the retail regulator having jurisdiction over the Company, unless the FERC determines otherwise) ADIT = Net Accumulated Deferred Income Taxes (ADIT) recorded in FERC Accounts 190, 281 and 282 (as reduced by amounts not generally and properly includable for FERC cost of service purposes, including but not limited to, SFAS 109 ADIT amounts and ADIT amounts arising from retail ratemaking decisions) plus Accumulated Deferred Income Tax Credit-3% portion only recorded in FERC Account 255 NPPR = Ratio of Nuclear Production Plant excluding Waterford Capital Lease to Total Plant excluding Intangible Plant and Waterford 3 Capital Lease 3 = NPPXW3L / PXIW3L where: NPPXW3L = Nuclear Production Plant in Service excluding Waterford 3 Capital Lease as recorded in FERC Account 101.1 PXIW3L = Electric Plant in Service which includes the sum of the Company’s Production, Transmission, Distribution and General Plant in Service recorded in FERC Plant Accounts 310 through 399, Property under Capital Lease excluding Waterford 3 Capital Lease as recorded in FERC Account 101.1 and Completed Construction not yet Classified as recorded in FERC Account 106 excluding ARO, if any Plant ratios shall be determined based on plant in service balances exclusive of associated ARO as of December 31 of the previous year.

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-131 Exhibit PJC-1 2011 TX Rate Case Page 54 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 53 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181 CM = The weighted average cost of capital determined as follows: = (DR * i) + (PR * p) + (ER * c) where: DR = Ratio of Debt Capital and Preferred Stock with tax deductible dividends (QUIPS) at Dec. 31 of the previous year PR = Ratio of Preferred Stock without tax deductible dividends at Dec. 31 of the previous year ER = Ratio of Common Stock at Dec. 31 of the previous year i= Average embedded cost of debt capital and preferred stock with tax deductible dividends (QUIPS) outstanding at Dec. of the previous year p= Average embedded cost of preferred stock outstanding at Dec. 31 of the previous year c= Simple average of the Companies’ approved retail return on common equity rates at Dec. 31 of the previous year F= Federal and State Income Taxes determined from the following: = T / (1-T) * (CM – DR * i) where: T= f + s - fs when federal tax is not deductible in computing state tax, and T= (f + s - 2fs) / 1 – (fs) when federal tax is deductible in computing state tax, and f= Federal Income Tax Rate s= State Income Tax Rate VPX = Variable Production Expense = NPOMNF + FE + PURP – RC + NDE where: NPOMNF = Nuclear Production Operation and Maintenance (O&M) Non-Fuel Expense, recorded in FERC Accounts 517 through 532 excluding Nuclear Fuel in FERC Account 518

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-132 Exhibit PJC-1 2011 TX Rate Case Page 55 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 First Revised Sheet No. 54 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181

FE = Production O&M Fuel Expense recorded in FERC Accounts 501, 518 and 547 PURP = Purchased Power Expense recorded in FERC Account 555, but excluding payments made pursuant to Section 30.09(d) of this Service Schedule and excluding the effects, debits and credits, resulting from a regulatory decision that causes the deferral of the recovery of current year costs or the amortization of previously deferred costs RC = Revenue Credits resulting from revenue received from customers outside the Company’s Net Area for Production Service recorded in FERC Account 447, but excluding receipts received pursuant to Section 30.09(d) of this Service Schedule NDE = Nuclear Depreciation and Amortization Expense associated with (NPP) as recorded in Accounts 403 and 404 and Decommissioning Expense, as approved by Retail Regulators, unless the jurisdiction for determining the depreciation and/or decommissioning rate is vested in the FERC under otherwise applicable law FPC = Fixed Production Cost = FPRB * (CM + F) + FPX – [(ITC / TX) * PPR] where: FPRB = Fixed Production Rate Base = PPXN + CME – ADXN + FI - (ADIT * PPRXN) + [(GP – GAD + IP – IAA) * PLR] + (MS + P) * PPREG where: PPXN = Production Plant in Service excluding Nuclear Plant recorded in FERC Plant Accounts 310 through 317, Accounts 330 through 346, and FERC Account 101.1 excluding ARO recorded in FERC Plant Accounts 317 and 337, if any CME = Coal Mining Equipment in FERC Plant Account owned by the Company

Issued by: Kimberly Despeaux Effective: May 31, 2009 Associate General Counsel Issued on: May 21, 2009 2011 ETI Rate Case 9-133 Exhibit PJC-1 2011 TX Rate Case Page 56 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 55 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181 ADXN = Accumulated Provision for Depreciation and Amortization associated with PPXN and CME above, as recorded in FERC Accounts 108 and 111, excluding ARO associated with PPXN and CME, if any, (consistent with the accounting relating to SFAS 143 approved by the retail regulator having jurisdiction over the Company, unless the FERC determines otherwise) FI = Fuel Inventory recorded in FERC Account 151 ADIT = Net Accumulated Deferred Income Taxes plus Accumulated Deferred Income Tax Credit PPRXN = Ratio of Production Plant in Service excluding Nuclear Plant to Total Plant excluding Intangible Plant and Waterford 3 Capital Lease = PPXN / PXIW3L GP = General Plant in Service recorded in FERC Plant Accounts 389 through 398 excluding ARO, if any GAD = General Plant Accumulated Provision for Depreciation, as recorded in FERC Account 108 excluding ARO associated with GP above, if any, (consistent with the accounting relating to SFAS approved by the retail regulator having jurisdiction over the Company, unless the FERC determines otherwise) IP = Intangible Plant in Service recorded in FERC Plant Accounts 301 through 303 IAA = Intangible Plant Accumulated Provision for Amortization associated with IP above recorded in FERC Account 111

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-134 Exhibit PJC-1 2011 TX Rate Case Page 57 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 56 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181

PLR = Ratio of Production Labor to Total Labor excluding A&G Labor4 = PL / LXAG where: PL = Production Labor charged to O&M Expense LXAG = Total Labor charged to O&M Expense excluding A&G Labor MS = Materials and Supplies recorded in FERC Account P= Prepayments as recorded in FERC Account 165 PPREG = Ratio of Production Plant in Service to Electric and Gas Plant in Service excluding Intangible Plant = PP / EGPXI where: PP = Production Plant in Service as recorded in FERC Plant Accounts 310 through and FERC Account 101.1 excluding ARO recorded in FERC Plant Accounts 317, 326 and 337, if any EGPXI = Electric and Gas Plant in Service defined as PXIW3L above plus Waterford 3 Capital Lease as recorded in FERC Account 101.1 and Gas Plant as recorded in FERC Account 118 excluding ARO, if any Labor ratios shall be determined based on the payroll expense for each Operating Company, including those payroll expenses billed to it by EOI and ESI, for the twelve months ended December 31 of the previous year.

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-135 Exhibit PJC-1 2011 TX Rate Case Page 58 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 57 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181

FPX = Fixed Production Expense = NFPOMXN + DEXN + [(AG + GDX + IAX) * PLR] + OT * PPR where: NFPOMXN=Non-Fuel Production O&M Expense excluding Nuclear; i.e. costs recorded in FERC Accounts 500 through 514 plus Accounts 535 through 554 plus Account 556 less Accounts 501 and 547 DEXN = Depreciation and Amortization Expense associated with the plant investment in PPXN as recorded in FERC Accounts 403 and 404, as approved by Retail Regulators unless the jurisdiction for determining the depreciation rate is vested in the FERC under otherwise applicable law.

AG = Administrative and General (A&G) O&M Expense recorded in FERC Accounts 920 through 935 excluding Storm Accrual Expense recorded in FERC Account 924 GDX = General Plant Depreciation Expense recorded in FERC Account 403 IAX = Intangible Plant Amortization Expense recorded in FERC Account 404 OT = Other Tax Expense recorded in FERC Account 408 PPR = Ratio of Production Plant to Total Plant excluding Intangible Plant = PP / PXI PXI = Electric Plant in Service defined as PXIW3L above plus Waterford 3 Capital Lease as recorded in FERC Account 101.1, excluding ARO, if any ITC = Investment Tax Credit Amortization recorded in FERC Account 411 TX = Composite Corporate After Tax Income Tax Rate = (1-T)

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-136 Exhibit PJC-1 2011 TX Rate Case Page 59 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 58 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181

30.13 Average Production Cost Each Company’s share of System Average Variable and Fixed Production Cost shall be determined based on its respective Annual Energy Ratio (Energy Ratio) and Load Responsibility Ratio (Demand Ratio), respectively. The formula for determining each Company’s share of System Average Production Cost is as follows: APC = Average Production Cost = AVPC + AFPC where: AVPC = Company’s Allocation of the System’s Variable Production Cost = SVPC * ER where: SVPC = Sum of the Companies’ Actual Variable Production Cost ER = Each Company’s Annual Energy (Net Area Requirements less Non-Requirements Sales for Resale defined as Total Disposition of Energy (FERC Form 1 Page 401a, Line 28) less Non- Requirements Sales for Resale (FERC Form 1 Page 401a, Line 24) less Net Transmission for Others (FERC Form 1 Page 401a, Line 18)) Divided by the Sum of all Companies Annual Energy (Energy Ratio) AFPC = Company’s Allocation of the System’s Fixed Production Cost = SFPC * DR where: SFPC = Sum of the Companies’ Actual Fixed Production Cost DR = The ratio for each Company of its 12 CP loads divided by the sum of all Companies’ 12 CP loads as defined in Section 2.16(a) (Demand Ratio)

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-137 Exhibit PJC-1 2011 TX Rate Case Page 60 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 59 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181

30.14 Billing Procedure for Section 30.09(d) The billing parameters will be in effect from June 1 to the succeeding December 31 based on the preceding year’s results. Any amounts payable pursuant to Section 30.09(d) shall be paid on a monthly basis based on dividing the amount payable by seven. All amounts paid shall be recorded by each Company in FERC Account 555 – Purchased Power and all amounts received shall be recorded by each Company in FERC Account 447 – Sales for Resale. This billing procedure shall be effective June 1, 2007.

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-138 Exhibit PJC-1 2011 TX Rate Case Page 61 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 60 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181

This Service Schedule MSS-3 shall be attached to and become a part of the Agreement dated the 23rd day of April , 1982 and shall be effective with said Agreement or at such later date as may be fixed by any requisite regulatory approval or acceptance for filing.

Attest ARKANSAS POWER & LIGHT COMPANY

Original signed by Original signed by R. J. Estrada Jerry Maulden Assistant Secretary President

Attest LOUISIANA POWER & LIGHT COMPANY

Original signed by Original signed by W. H. Talbot J. M. Wyatt Secretary President

Attest MISSISSIPPI POWER & LIGHT COMPANY Original signed by Original signed by R. J. Estrads D. C. Lutken Assistant Secretary President

Attest NEW ORLEANS PUBLIC SERVICE INC.

Original signed by Original signed by William C. Nelson James M. Cain Secretary President

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-139 Exhibit PJC-1 2011 TX Rate Case Page 62 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 61 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181 SERVICE SCHEDULE MSS-4 UNIT POWER PURCHASE 40.01 Purpose The purpose of this Service Schedule is to provide the basis for making a unit power purchase between Companies and/or the sale of power purchased by another Company, unless an alternative basis is agreed to by the parties subject to the approval of the Commission and the regulatory agencies of the purchasing and selling Companies under otherwise applicable law and which provides a lower monthly capacity charge than the charge determined pursuant to Section 40.06 or Section 40.09 of this Service Schedule MSS-4.

40.02 Designated Generating Unit (a) A Designated Generating Unit shall be any generating unit from which the unit power purchase is made under Section 40.01 that is mutually agreed upon by the purchaser and the seller. (b) Any Company that makes a Unit Power Purchase of a portion of capability shall be entitled to receive each hour, the same portion of the total energy generated by the Designated Generating Unit. Such energy shall be purchased at the cost of fuel consumed per kWh in accordance with Section 30.08(a) and will be treated in the same manner as any other energy available to the purchasing Company.

40.03 Capability Payment For the capability purchased in accordance with Section 40.02, the Company making the sale shall receive, from the Company making the purchase, a monthly payment determined in accordance with the method described in Section 40.06 hereinafter.

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-140 Exhibit PJC-1 2011 TX Rate Case Page 63 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 62 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181 The monthly capability payment to be received by a Company shall be determined by multiplying the kW of capability sold from its Designated Generating Unit by a charge per kW–month as defined below.

40.04 Investment in Designated Generating Unit (DGURB) For the purpose of calculating the Monthly Charge under Section 40.06, the investment in the Designated Generating Unit (based on the Federal Energy Regulatory Commission’s Uniform System of Accounts prescribed for the Public Utilities and Licensees) shall be:

DGURB = Designated Generating Unit Rate Base DGURB = DGUPTPLT + DGUCME - DGUDR + DGUFINV - DGUADIT + [(GPLT – GDR + IPLT – IAA) * (DGUL / LXAG)] + [(MS + PP) * (DGUPLT / PLT)] (a) The cost of the Designated Generating Unit included in FERC Plant Accounts 310 through 346; the cost for step-up transformers, circuit breakers, switching equipment, etc. included in FERC Plant Account 353 which are required to connect the Designated Generating Unit to the transmission system (DGUPTPLT), (b) Plus Coal Mining Equipment in FERC Plant Account 399 directly associated with the Designated Generating Unit (DGUCME), (c) Less the Accumulated Provision for Depreciation (consistent with the accounting relating to Statement of Financial Accounting Standards (SFAS) 143 approved by the retail regulator having jurisdiction over the Designated Generating Unit, unless the FERC determines otherwise) associated with items (a) and (b) above, as recorded in FERC Account 108, excluding Nuclear Decommissioning Trust Fund Balances, if applicable (DGUDR),

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-141 Exhibit PJC-1 2011 TX Rate Case Page 64 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 63 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181 (d) Plus Fuel Inventory for the Designated Generating Unit, if applicable, in FERC Accounts 151 and 152 (DGUFINV), (e) Less net Accumulated Deferred Income Taxes recorded in FERC Accounts 190, 281, 282 and 283 and Accumulated Deferred Investment Tax Credit – 3% portion only recorded in FERC Account 255 (DGUADIT) directly associated with the Designated Generating Unit if known; otherwise, an allocation of the plant-related balances in FERC Accounts 190, 281, 282 and 283, as reduced by amounts not generally and properly includable for FERC cost of service purposes, including, but not limited to, SFAS 109 ADIT amounts and ADIT amounts arising from retail ratemaking decisions, and Accumulated Deferred Investment Tax Credit – 3% portion only recorded in FERC Account 255 based on the proportion of gross Plant in Service for the Designated Generating Unit (DGUPLT), where DGUPLT is the sum of the investment pursuant to Section 40.04 (a) above plus the calculated General and Intangible plant pursuant to Sections 40.04 (f) and (h) below, to the Company’s total gross Plant in Service (PLT), where PLT is the sum of Production, Transmission, Distribution, General and Intangible Plant in Service, (f) Plus an allocation of General Plant recorded in FERC Plant Accounts 389 through 398 (GPLT) based on the proportion of labor for the Designated Generating Unit (DGUL) to the Company’s total Labor charged to O&M Expense excluding Administrative and General (“A&G”) Labor (LXAG), (g) Less an allocation of Accumulated Provision for Depreciation (consistent with the accounting relating to SFAS 143 approved by the retail regulator having jurisdiction over the Designated Generating Unit, unless the FERC determines otherwise) associated with item (f) above as recorded in FERC Account 108 (GDR) based on the proportion of labor for the Designated Generating Unit (DGUL) to the Company’s total Labor charged to O&M Expense excluding A&G Labor (LXAG), Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-142 Exhibit PJC-1 2011 TX Rate Case Page 65 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 64 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181 (h) Plus an allocation of Miscellaneous Intangible Plant recorded in FERC Plant Account 303 (IPLT) based on the proportion of labor for the Designated Generating Unit (DGUL) to the Company's total Labor charged to O&M Expense excluding A&G Labor (LXAG), (i) Less an allocation of Accumulated Provision for Amortization associated with item (h) above recorded in FERC Account 111 (IAA) based on the proportion of labor for the Designated Generating Unit (DGUL) to the Company's total Labor charged to O&M Expense excluding A&G Labor (LXAG), (j) Plus an allocation of Materials & Supplies and Stores Expense Undistributed recorded in FERC Accounts 154 and 163, respectively, (MS) based on the proportion of Plant in Service for the Designated Generating Unit (DGUPLT) to the Company’s total Plant in Service (PLT), and (k) Plus an allocation of Prepayments recorded in FERC Account 165 (PP) based on the proportion of Plant in Service for the Designated Generating Unit (DGUPLT) to the Company’s total Plant in Service (PLT).

The Investment in the Designated Generating Unit (Designated Generating Unit Rate Base) shall be based on the actual balances on the seller’s books as of the end of the month immediately preceding the service month.

If the Designated Generating Unit is one of a multi-unit station, its costs shall include an allocation of the amounts in the above plant accounts, which are allocable to all the generating units in the station, such allocation to be in the ratio of the capability of the Designated Generating Unit to the total capability of all generating units installed in the station for the service month.

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-143 Exhibit PJC-1 2011 TX Rate Case Page 66 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 65 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181

40.05 Expenses associated with Designated Generating Unit (OXP) For the purpose of calculating the Monthly Charge under Section 40.06, expenses associated with Designated Generating Unit shall be the following:

OXP = Operating Expense OXP = DGUPOM + [SEOM * (DGUSEPLT / SEPLT)] + DGUDE + DGUI + DGUPT + DGUAG + [(GDX + OT + INDX) * (DGUL / LXAG)] + [FT * (DGUPLT / PLT)] (a) The Designated Generating Unit Production Operation and Maintenance Expense (“O&M”) Expense, included in FERC Accounts 500 through 554 excluding fuel in Accounts 501, 518 and 547 (DGUPOM), (b) Plus an allocation of O&M associated with Designated Generating Unit step-up transformers and related transmission investment recorded in FERC Accounts 562 and 570 (SEOM) based on the proportion of the Designated Generating Unit Step-up Transformer Plant recorded in Plant Account 353 (DGUSEPLT) to the Company’s total Transformer Station Equipment Plant recorded in Plant Account 353 (SEPLT), (c) Plus any Depreciation Expense associated with the plant investment in Designated Generating Unit referred to in Section 40.04 items (a) and (b) (as recorded in Account 403) and Decommissioning Expense, as approved by Retail Regulators, directly assigned to the Designated Generating Unit, if applicable (DGUDE) unless the jurisdiction for determining the depreciation and/or decommissioning rate is vested in the FERC under otherwise applicable law, (d) Plus Property Insurance Expense recorded in FERC Account 924 directly assigned to the Designated Generating Unit (DGUI), (e) Plus Ad Valorem Taxes recorded in FERC Account 408 directly assigned to the Designated Generating Unit (DGUPT),

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-144 Exhibit PJC-1 2011 TX Rate Case Page 67 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 66 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181 (f) Plus A&G Expense (DGUAG) directly associated with a nuclear-fueled Designated Generating Unit recorded in FERC Accounts 920 through 935, excluding property insurance in Account 924; otherwise, an allocation of A&G Expense recorded in FERC Accounts 920 through 935 excluding property insurance in Account 924 based on the proportion of labor for the Designated Generating Unit (DGUL) to the Company’s total labor charged to O&M Expense excluding EOI and A&G labor, (g) Plus an allocation of General Plant Depreciation Expense recorded in FERC Account 403 (GDX) based on the proportion of labor for the Designated Generating Unit (DGUL) to the Company’s total Labor charged to O&M Expense excluding A&G Labor (LXAG), (h) Plus an allocation of Payroll Taxes recorded in FERC Account 408 (OT) based on the proportion of labor for the Designated Generating Unit (DGUL) to the Company’s total Labor charged to O&M Expense excluding A&G Labor (LXAG), (i) Plus an allocation of Miscellaneous Intangible Plant Amortization Expense recorded in FERC Account 404 (INDX) based on the proportion of labor for the Designated Generating Unit (DGUL) to the Company's total Labor charged to O&M Expense excluding A&G Labor (LXAG), and (j) Plus an allocation of Corporate Franchise Taxes recorded in FERC Account 408 (FT) based on the proportion of Plant in Service for the Designated Generating Unit (DGUPLT) to the Company’s total Plant in Service (PLT).

The expenses shall be based on transactions recorded on the seller's books for the service month.

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-145 Exhibit PJC-1 2011 TX Rate Case Page 68 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 67 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181 If the Designated Generating Unit is one of a multi-unit station, expenses relating to the common plant shall be allocated to the Designated Generating Units in the station based on the ratio of the capability of the Designated Generating Unit to the total capability of all generating units installed in the station for the service month.

40.06 Determination of Monthly Capacity Charge For the purpose of calculating the Monthly Capacity Charge (MC) per kW for billings under Capability Payment for each unit, the following formula shall be followed: MONTHLY CAPACITY CHARGE MC = Monthly Capacity Charge ($/kW-Month) MC = [DGURB * ((CM + F)/12) + OXP - ITC/(1-T)] / CP Where: DGURB = Designated Generating Unit Rate Base per Section 40.04 CM = The weighted average cost of capital consistent with the procedures used by each Operating Company to calculate its AFUDC rate, determined as follows: CM = (DR * i) + (PR * p) + (ER * c), where DR = Ratio of Debt Capital and Preferred Stock with tax deductible dividends (QUIPS) at the last day of the month immediately preceding the current service month PR = Ratio of Preferred Stock without tax deductible dividends at the last day of the month immediately preceding the current service month ER = Ratio of Common Stock at the last day of the month immediately preceding the current service month i = Average embedded cost of debt capital outstanding at the last day of the month immediately preceding the current service month p = Average embedded cost of preferred stock outstanding at the last day of the month immediately preceding the current service month c = Return on common equity at 11.0% F = Federal and State Income Tax as determined from the following: F = T /(1 - T)* (CM – DR * i) Where:

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-146 Exhibit PJC-1 2011 TX Rate Case Page 69 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 68 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181

T = f + s – fs when federal tax is not deductible in computing state tax, and T = (f + s – 2fs) / (1-fs) when federal tax is deductible in computing state tax, and f = Federal Income Tax Rate s = State Income Tax Rate OXP = Operating Expense per Section 40.05 ITC = ITC Amortization recorded in FERC Account 411 directly associated with the Designated Generating Unit if known; otherwise, an allocation of ITC Amortization recorded in FERC Account 411 based on a gross plant-related balance ratio CP = Capability for the Designated Generating Unit as defined in Section 2.14 of the Entergy System Agreement for the service month General Notes: (a) Labor ratios shall be determined based on the sum of the payroll expenses for the owner of the DGU, including those payroll expenses billed to it by EOI and ESI, for the service month. (b) Plant ratios shall be determined based on plant in service balances as of the end of the month immediately preceding the service month.

40.07 Adjustment for Tax Changes The Capability Payment as determined above shall be adjusted to reflect the imposition of any applicable new taxes not included in the above formula or for any increase or decrease in taxes included as of the date of this Agreement.

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-147 Exhibit PJC-1 2011 TX Rate Case Page 70 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 69 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181

40.08 Billings Procedure Bills for services rendered under Section 40.06 shall be issued within 45 days following the end of the service month and shall be payable within 10 days of receipt.

Five days after such bill is due, interest shall accrue on any balance due at the rate as determined in Section 35.19a(2)iii of the FERC Regulations. The billing provisions under Section 4.14 of the Entergy System Agreement shall not apply to billings under Section 40.06 of this Service Schedule MSS-4.

40.09 Designated Power Purchase (a) A Designated Power Purchase shall be any portion of a power purchase contract the sale and purchase of which is made pursuant to Section 40.01 hereof, which is mutually agreed upon by the purchaser and the seller.

Any resale of a power purchase from the Grand Gulf nuclear unit pursuant to Section 40.09 shall be subject to the approval of the Commission and the regulatory agency of the purchasing company. (b) Any Company that makes a Designated Power Purchase of a portion of the capability of the power purchase contract from which the sale and purchase is made shall be entitled to receive each hour, the same portion of the total energy purchased pursuant to the Designated Power Purchase subject to review by the FERC. (c) Sales to one Company of power purchased by another Company shall be priced at the delivered cost of said purchase incurred by the selling Company as recorded in FERC Accounts 555 and 565, excluding all timing effects on such costs due to retail ratemaking decisions on a monthly basis, and shall be billed pursuant to Section 4.14 of the Entergy System Agreement subject to review by the FERC.

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-148 Exhibit PJC-1 2011 TX Rate Case Page 71 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 70 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181 This Service Schedule MSS-4 shall be attached to and become a part of the Agreement dated the 23rd day of April , 1982 and shall be effective with said Agreement or at such later date as may be fixed by any requisite regulatory approval or acceptance for filing.

Attest ARKANSAS POWER & LIGHT COMPANY

Original signed by Original signed by R. J. Estrada Jerry Maulden Assistant Secretary President

Attest LOUISIANA POWER & LIGHT COMPANY

Original signed by Original signed by W. H. Talbot J. M. Wyatt Secretary President

Attest MISSISSIPPI POWER & LIGHT COMPANY

Original signed by Original signed by R. J. Estrada D. C. Lutken Assistant Secretary President

Attest NEW ORLEANS PUBLIC SERVICE INC.

Original signed by Original signed by William C. Nelson James M. Cain Secretary President

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-149 Exhibit PJC-1 2011 TX Rate Case Page 72 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 71 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181

SERVICE SCHEDULE MSS-5 DISTRIBUTION OF REVENUE FROM SALES MADE FOR THE JOINT ACCOUNT OF ALL THE COMPANIES 50.01 Purpose The purpose of this Schedule is to provide a basis for the distribution among the Companies of the net balance received from sales to others for the joint account of all the Companies.

50.02 Revenue Deductions From the gross revenue received for such sales there shall be deducted the cost of the sales determined by taking the sum of: (a) Any direct tax imposed on the sale of capacity or energy or revenue derived there from. (b) Any appropriate adjustment for losses in the system of the Company providing the connection. (c) The cost of energy determined under the provisions of Section 30.04 of Service Schedule MSS-3. (d) The Ownership Costs for the specific connecting facilities not equalized elsewhere. For this purpose, Ownership Costs shall be computed at the rate developed for the connecting Company's Annual Ownership Cost under Service Schedule MSS-2 on the facilities provided by the Company and approved by the Operating Committee.

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-150 Exhibit PJC-1 2011 TX Rate Case Page 73 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 72 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181

50.03 Distribution of Net Balance The net balance remaining after the deductions provided for in 50.02 shall be distributed among the Companies in proportion to the Responsibility Ratio of each based on Sections 2.16(b) and 2.17(b). Provided, however, that EGSL and ETI shall not share in the distribution of the net revenue balance from sales to others for the joint account of all the Companies received from contracts entered by EAI, ELL, EMI, ENOI or Services prior to the merger. The net balance remaining after the deductions provided for in 50.02 for pre-merger sales shall be distributed among EAI, ELL, EMI and ENOI in proportion to the Company Load Responsibility of each divided by the sum of their Company Load Responsibilities based on Sections 2.16(b) and 2.17(b). EGSL and ETI shall participate pursuant to MSS-5 in any future sales, but shall only participate in the incremental portion of any extensions or expansions of existing contracts.

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-151 Exhibit PJC-1 2011 TX Rate Case Page 74 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 73 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181

This Service Schedule MSS-5 shall be attached to and become a part of the Agreement dated the 23rd day of April , 1982 and shall be effective with said Agreement or at such later date as may be fixed by any requisite regulatory approval or acceptance for filing.

Attest ARKANSAS POWER & LIGHT COMPANY

Original signed by Original signed by R. J. Estrada Jerry Maulden Assistant Secretary President

Attest LOUISIANA POWER & LIGHT COMPANY

Original signed by Original signed by W. H. Talbot J. M. Wyatt Secretary President

Attest MISSISSIPPI POWER & LIGHT COMPANY

Original signed by Original signed by R. J. Estrada D. C. Lutken Assistant Secretary President

Attest NEW ORLEANS PUBLIC SERVICE INC.

Original signed by Original signed by William C. Nelson James M. Cain Secretary President

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-152 Exhibit PJC-1 2011 TX Rate Case Page 75 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 74 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181

SERVICE SCHEDULE MSS-6 DISTRIBUTION OF OPERATING EXPENSES OF SYSTEM OPERATIONS CENTER 60.01 Purpose The purpose of this Schedule is to provide a basis for the distribution among the Companies of the costs incurred by Services in providing and operating the System Operations Center.

60.02 Costs Costs for the purpose of this Schedule shall include such items as salaries, wages, rentals, the cost of materials and supplies, interest, taxes, depreciation, transportation, travel expenses, consulting and other professional services, and other costs incurred by Services in providing, maintaining, and operating the System Operations Center in accordance with budget approved by the Operating Committee.

60.03 Distribution of Costs All costs of the Center shall be paid by Services. All normal costs shall be billed by Services to the Companies in proportion to the Responsibility Ratio of each. However, if the System Operations Center makes a study or performs a service in which all Companies are not proportionately interested, any resulting cost shall be distributed to the interested parties in accordance with the standard procedures of Services as outlined in their application declaration as filed with the Securities and Exchange Commission.

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-153 Exhibit PJC-1 2011 TX Rate Case Page 76 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 75 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181

This Service Schedule MSS-6 shall be attached to and become a part of the Agreement dated the 23rd day of April , 1982 and shall be effective with said Agreement or at such later date as may be fixed by any requisite regulatory approval or acceptance for filing.

Attest ARKANSAS POWER & LIGHT COMPANY

Original signed by Original signed by R. J. Estrada Jerry Maulden Assistant Secretary President

Attest LOUISIANA POWER & LIGHT COMPANY

Original signed by Original signed by W. H. Talbot J. M. Wyatt Secretary President

Attest MISSISSIPPI POWER & LIGHT COMPANY

Original signed by Original signed by R. J. Estrada D. C. Lutken Assistant Secretary President

Attest NEW ORLEANS PUBLIC SERVICE INC.

Original signed by Original signed by William C. Nelson James M. Cain Secretary President

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-154 Exhibit PJC-1 2011 TX Rate Case Page 77 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 76 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181 SERVICE SCHEDULE MSS-7 MERGER FUEL PROTECTION PROCEDURE 70.01 Purpose This Service Schedule provides a procedure for protecting the participating Companies from incurring higher fuel and purchased power costs as a result of the merger with Gulf States. For a Company which incurs an increase in its fuel costs as a result of the merger, the increase in cost will be transferred back to the companies obtaining fuel savings in proportion to those savings, in accordance with the following provisions.

70.02 Participating Companies Companies covered by this Service Schedule shall include Gulf States and any other Company notifying the Operating Committee prior to the first calculation performed pursuant to 70.03 of its intent to participate and that its participation has the approval of the regulatory agency with jurisdiction over the Company's retail rates. Any Company directed to participate by its retail regulator shall do so.

70.03 Calculation Procedure of Fuel Cost Changes Each year after the effective date of the Entergy-Gulf States Merger (Merger), merger-related fuel cost changes (MRFC) will be Calculated for each Company in accordance with 70.05. The MRFC will be used to calculate a Cumulative Fuel Change Balance (CFCB) for each Company, as follows: Year ending CFCB = (Year beginning CFCB x (1 + i)) + MRFC) where: i = the average yield on ten-year U.S. Treasury Notes for the year just ended.

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-155 Exhibit PJC-1 2011 TX Rate Case Page 78 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 77 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181

At the end of each of the years prior to the final year, if the CFCB is negative for one or more Companies and positive for one or more Companies, then 50 percent of the Company's positive CFCB (i.e., higher fuel costs due to the merger) shall be transferred to the CFCB of the Company or Companies with a negative balance. At the end of the tenth year (or such shorter period of time as set forth in Section 70.04) of this procedure, the above procedure will apply except that the full amount (100%) of a positive CFCB will be transferred subject to the limitation that such transfer does not cause the CFCB to become positive for another Company. For the Companies receiving the transferred amount, the transfer shall be allocated in proportion to each Company's percentage of the total of the negative balances of the participating companies.

Any year after a positive amount is transferred from a Company's CFCB and that Company's CFCB subsequently becomes negative, then such previous transfers will be reversed to the extent the reversals do not cause the Company's CFCB to become positive.

70.04 Limitation of Term This procedure shall apply for the shorter of: (1) the ten years following the effective date of the merger, or (2) the period between the effective date of the merger and the date of implementation of retail access in a jurisdiction in which one of the Companies operate.

70.05 Fuel Cost Change Measurement Procedure Merger-related fuel cost changes (MRFC) for each Company are measured annually as the difference between estimated stand-alone fuel costs (SAFC) and estimated merger fuel costs (MFC), where:

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-156 Exhibit PJC-1 2011 TX Rate Case Page 79 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 78 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181

SAFC = The estimated annual cost of fuel and purchased energy incurred to serve the Company's net area dispatch, as determined by a simulation of the dispatch of generating units and system operations under stand-alone (non-combined) operation of the Gulf States and Entergy System (excluding Gulf States) using Entergy's most current delivery of the PROMOD III production cost model and the input assumptions set forth in 70.06.

MFC = The estimated annual cost of fuel and purchased energy incurred to serve a Company's net area requirements as determined by a simulation of the dispatch of generating units and system operations under merged operation (combined) of the system using Entergy's most current delivery of the PROMOD III production cost model and the input assumptions set forth in 70.06.

70.06 Input Assumptions for Production Cost Simulations Customer Loads Actual hourly net area load, without off-system sales transactions, will be used as hourly load inputs.

Resources The Gulf States and Entergy resources available to meet customer loads shall be those reflected in Entergy's most recent Business Plan applicable to that year.

Generating Unit Efficiency The heat rate data shall be the then current data used in Entergy's Bulk Power Management system (BPMS).

Generating Unit Availability Generating unit availability data (available MW's for each generating unit) shall be those reflected in the BPMS data for that time period.

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-157 Exhibit PJC-1 2011 TX Rate Case Page 80 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 79 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181

System Operating Constraints All generating unit constraints, fuel constraints, and transmission constraints as represented in Entergy's most current Business Plan applicable to that year will be reflected in the input assumptions. However, the transmission constraint known as Amite South shall be changed after the end of the fifth post merger year in the Entergy stand- alone analysis to that contained in the merger analysis for the remaining time period.

Fuel Costs Nuclear -- Actual monthly fuel cost as used in the Intra-System Billing (ISB) program will be used as the nuclear fuel cost input.

Coal -- Actual monthly fuel cost as used in the ISB program will be used as the coal fuel cost input except that the stand-alone fuel cost for North Antelope coal shall be multiplied by the ratio of the stand-alone cost of North Antelope coal to the merger cost of North Antelope coal for each Entergy coal unit as reflected in 70.08.

Gas/Oil -- Fuel cost for each gas/oil unit will be based on actual weighted average fuel cost for each unit as calculated from fuel cost inputs to the ISB program.

Off System Economy Purchases The simulations will reflect the off-system economy sources listed in 70.09. For the stand-alone simulations, these sources will be allocated to Gulf States and Entergy based on the most current year ending load responsibility ratios. The pricing of these transactions will be based on the actual monthly average on-peak and off-peak price of economy energy purchases, as determined by the ISB, plus a $2/MWH markup for each transaction for which Gulf States would require wheeling service from Entergy.

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-158 Exhibit PJC-1 2011 TX Rate Case Page 81 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 80 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181

In addition, the Gulf States stand-alone simulation will also reflect a 300 MW off- peak source to be priced at the actual average monthly off-peak price of economy energy purchases as determined by the ISB. The available capacity for each Entergy stand-alone off-system economy source, as determined above, will be increased (to reflect economy energy not taken in the Gulf States stand-alone simulation) by the following method: IMW = Monthly on-peak and off-peak increase for each Entergy stand- alone off-system economy source rounded at the nearest whole MW.

= AMW x (1-CF) where: AMW = The available capacity (MW) for the off-system economy source in the Gulf States stand-alone.

CF = Monthly on-peak or off-peak capacity factor at which energy is taken in the Gulf States stand-alone simulation for the off-system economy source.

Operating Reserves An operating reserve level of 6 percent of annual peak will be reflected in the input assumptions.

70.07 PROMOD Benchmark A benchmark of PROMOD based on the actual 1992 and 1997 operating data will be made to verify the reasonableness of the model.

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-159 Exhibit PJC-1 2011 TX Rate Case Page 82 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 81 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181

70.08 North Antelope Coal Prices The following ratios will be used to increase the actual North Antelope coal prices used in the stand-alone simulation case: Year Stand Alone Combined ($/MMBtu) ($/MMBtu) Ratio 1994 1.8261 1.7910 1.0196 1995 1.8997 1.8500 1.0269 1996 1.9423 1.9190 1.0122 1997 2.0918 2.0240 1.0335 1998 2.2096 2.1760 1.0155 1999 2.2556 2.2160 1.0179 2000 2.3466 2.2960 1.0221 2001 2.4274 2.3800 1.0199 2002 2.5114 2.4830 1.0114 2003 2.6041 2.5690 1.0137

70.09 Joint Dispatch Economy Purchase Capacities The following off-system economy resources will be used in the PROMOD simulations, with the figures below being capacity in MW:

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

2011 ETI Rate Case 9-160 Exhibit PJC-1 2011 TX Rate Case Page 83 of 83

Entergy Arkansas, Inc., Third Revised Rate Schedule FERC No. 94 Original Sheet No. 82 Entergy Gulf States Louisiana, L.L.C., Rate Schedule FERC No. 181 Entergy Louisiana, LLC, Third Revised Rate Schedule FERC No. 69 Entergy Mississippi, Inc., Third Revised Rate Schedule FERC No. 262 Entergy New Orleans, Inc., Third Revised Rate Schedule FERC No. 8 Entergy Texas, Inc., Rate Schedule FERC No. 181

Company Type of Purchase Month 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 AECI On Peak & Year 400 400 400 400 400 400 400 400 400 400 Off Peak Round Cajun On Peak & Jan. 200 200 200 200 200 200 200 200 200 200 Off Peak Cajun On Peak & Feb. 200 200 200 200 200 200 200 200 200 200 Off Peak Cajun On Peak & Mar. 200 200 200 200 200 200 200 200 200 200 Off Peak Cajun On Peak & Apr. 200 200 200 200 200 200 200 200 200 200 Off Peak Cajun On Peak & May 110 95 80 120 100 160 160 160 160 160 Off Peak Cajun On Peak & Jun. 110 95 80 120 100 160 160 160 160 160 Off Peak Cajun On Peak & Jul. 110 95 80 120 100 160 160 160 160 160 Off Peak Cajun On Peak & Aug. 110 95 80 120 100 160 160 160 160 160 Off Peak Cajun On Peak & Sep. 200 200 200 200 200 200 200 200 200 200 Off Peak Cajun On Peak & Oct. 200 200 200 200 200 200 200 200 200 200 Off Peak Cajun On Peak & Nov. 200 200 200 200 200 200 200 200 200 200 Off Peak Cajun On Peak & Dec. 200 200 200 200 200 200 200 200 200 200 Off Peak Empire On Peak & Year 50 50 50 50 50 50 50 50 50 50 Off Peak Round Oklahoma On Peak Year 300 300 300 300 300 300 300 300 300 300 Only Round Oklahoma On Peak & Year 250 150 60 0 0 0 0 0 0 0 Off Peak Round Southern On Peak & Year 75 75 75 75 50 50 50 50 50 50 Off Peak Round SWEPCO On Peak & Year 100 100 100 100 100 100 100 100 100 100 Off Peak Round SWEPCO On Peak Year 200 200 200 200 200 200 200 200 200 200 Only Round TVA On Peak & Year 1,00 1,00 1,00 750 500 500 500 500 500 500 Off Peak Round 0 0 0 Union EL On Peak & Year 400 400 400 400 400 400 400 400 400 400 Off Peak Round

Issued by: Kimberly Despeaux Effective: November 22, 2008 Associate General Counsel Issued on: November 21, 2008 Filed to comply with unpublished letter order of the Federal Energy Regulatory Commission, Docket No. ER08-460, issued April 22, 2008.

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2011 ETI Rate Case 9-162 Exhibit PJC-2 2011 TX Rate Case Page 1 of 70

Entergy Electric System Date range - 20100701 through 20100731 Attachment 1 Intra-System Billing-201007RA KWH Log Sheet Reconciliation - Entergy Arkansas, Inc. Page 1 Company Net Gen To Area UPP Exchange Inadvertent Firm Sales Sys Sales Unacct AECC LOSS IN 2,995,170 2,995,170 0 0 0 0 0 0 AECC PURCH LOSSES IN 131,000 131,000 0 0 0 0 0 0 AECC SALE LOSSES IN 121,000 121,000 0 0 0 0 0 0 AEP SERVICE CORP./MINDEN PAYBACK (521,404) (521,404) 0 0 0 0 0 0 CALDWELL IMBAL IN 269,838 269,838 0 0 0 0 0 0 CALDWELL IMBAL OT (493) (493) 0 0 0 0 0 0 COG Sale Losses N 189,395 189,395 0 0 0 0 0 0 ETEC SALE LOSS N 744,000 744,000 0 0 0 0 0 0 GIS Imbalance IN 258,860 258,860 0 0 0 0 0 0 GIS Imbalance OT (269,531) (269,531) 0 0 0 0 0 0 PP Sale Losses N 1,772,931 1,772,931 0 0 0 0 0 0 JAS loss IN 418 418 0 0 0 0 0 0 JBO LOSS IN 3,790,000 3,790,000 0 0 0 0 0 0 K RBYV LLE IMBAL IN 128,602 128,602 0 0 0 0 0 0 K RBYV LLE IMBAL OT (1,332) (1,332) 0 0 0 0 0 0 NEWTON IMBAL IN 206,611 206,611 0 0 0 0 0 0 NEWTON IMBAL OT (130) (130) 0 0 0 0 0 0 SPA AECC PP IMBAL IN 3,528,000 3,528,000 0 0 0 0 0 0 SPA AECC PP IMBAL OT (5,902,000) (5,902,000) 0 0 0 0 0 0 SWPA/B/DG EXCHANG (28,495,000) (28,495,000) 0 0 0 0 0 0 ARK.NU 1 86,421,339 0 86,421,339 0 0 0 0 0 ARK.NU 1/NUCLEAR 536,659,661 536,659,661 0 0 0 0 0 0 ARK.NU 2 102,307,792 0 102,307,792 0 0 0 0 0 ARK.NU 2/NUCLEAR 635,309,208 635,309,208 0 0 0 0 0 0 BLAKLY 1/Aux (71,000) (71,000) 0 0 0 0 0 0 BLAKLY 1/HYDRO 14,898,000 14,898,000 0 0 0 0 0 0 BLAKLY 2/Aux (3,000) (3,000) 0 0 0 0 0 0 BLAKLY 2/HYDRO 5,811,000 5,811,000 0 0 0 0 0 0 CARPTR 1/Aux (110,000) (110,000) 0 0 0 0 0 0 CARPTR 1/HYDRO 2,011,000 2,011,000 0 0 0 0 0 0 CARPTR 2/Aux (12,000) (12,000) 0 0 0 0 0 0 CARPTR 2/HYDRO 8,856,000 8,856,000 0 0 0 0 0 0 COUCH 1/Aux (57,000) (57,000) 0 0 0 0 0 0 COUCH 2/CEGT E 19,368,107 7,913,041 0 9,781,627 1,673,230 0 0 209 COUCH 2/CENTERPO NT I 168,893 129,859 0 17,362 21,672 0 0 0 DEGRAY 1/HYDRO 8,560,000 8,560,000 0 0 0 0 0 0 DEGRAY 2/Aux (113,000) (113,000) 0 0 0 0 0 0 G.GULF 1/NUCLEAR 201,820,133 201,820,133 0 0 0 0 0 0 GGULF RET 66,088,728 0 66,088,728 0 0 0 0 0 GGULF RP 32,499,259 0 32,499,259 0 0 0 0 0 NDEPN 1 24,696,343 0 24,696,343 0 0 0 0 0 L.CATH 3/Aux (219,000) (219,000) 0 0 0 0 0 0 L.CATH 4/Aux (729,000) (729,000) 0 0 0 0 0 0 L.CATH 4/CEGT E 22,337,765 14,391,650 0 7,839,611 105,794 0 710 0 L.CATH 4/CENTERPOINT I 3,592,235 2,174,843 0 1,399,984 17,408 0 0 0 LYNCH 3/Aux (26,000) (26,000) 0 0 0 0 0 0 LYNCH 3/CEGT E 10,201,913 7,109,876 0 2,936,490 154,920 0 0 627 LYNCH 3/CENTERPOINT I 2,144,087 1,475,204 0 659,947 8,936 0 0 0 LYNCH IC/#2 OIL 2,000 0 0 2,000 0 0 0 0 MABELV T/CEGT E 2,423,998 2,032,336 0 2,000 389,662 0 0 0 MABELV T/CENTERPO NT I 1,245,002 1,166,995 0 0 78,007 0 0 0 OUACHITA 1/SIGCO I 13,400,626 13,160,723 0 234,880 5,023 0 0 0 OUACHITA 1/SIGPL E 24,862,374 21,315,758 0 3,527,779 18,837 0 0 0 OUACHITA 2/SIGCO I 7,138,433 7,138,433 0 0 0 0 0 0 OUACHITA 2/SIGPL E 27,493,567 26,561,557 0 910,452 21,558 0 0 0 REMMEL 1/HYDRO 1,613,000 1,613,000 0 0 0 0 0 0 REMMEL 2/HYDRO 1,508,000 1,508,000 0 0 0 0 0 0 REMMEL 3/Aux (13,000) (13,000) 0 0 0 0 0 0 REMMEL 3/HYDRO 1,451,000 1,451,000 0 0 0 0 0 0 RITCHE 1/Aux (28,000) (28,000) 0 0 0 0 0 0 WH.BLF 1 45,314,539 0 45,314,539 0 0 0 0 0 WH.BLF 2 38,134,556 0 38,134,556 0 0 0 0 0 NDEPN 1/COAL 153,487,079 153,487,079 0 0 0 0 0 0 NDEPN 2/COAL 6,410 6,410 0 0 0 0 0 0 WH.BLF 1/COAL 281,394,779 255,052,371 0 25,833,205 509,203 0 0 0 WH.BLF 2/Aux (10,260) (10,260) 0 0 0 0 0 0 WH.BLF 2/COAL 236,808,729 234,500,243 0 2,103,620 204,866 0 0 0 AECC Excess BAILEY 1 50,110 19,387 0 30,723 0 0 0 0 AECC Excess INDEPN 2 14,445 0 0 14,445 0 0 0 0 AECC Excess MCCLEL 1 3,294,648 2,328,767 0 952,753 13,128 0 0 0 AECC Excess WH.BLF 1 1,487,454 562,317 0 914,776 10,361 0 0 0 AECC Excess WH.BLF 2 7,262,197 4,021,499 0 3,188,988 51,710 0 0 0 CONWAY Excess WH.BLF 1 49,300 49,300 0 0 0 0 0 0 CONWAY Excess WH.BLF 2 287,280 287,280 0 0 0 0 0 0 ETEC Excess INDEPN 2 166,582 166,582 0 0 0 0 0 0 Attachment Snapshot: 20100826181933 RunID: 17029 Billing Snapshot: 20100826175238 2011 ETI Rate Case 9-163 Exhibit PJC-2 2011 TX Rate Case Page 2 of 70

Entergy Electric System Date range - 20100701 through 20100731 Attachment 1 Intra-System Billing-201007RA KWH Log Sheet Reconciliation - Entergy Arkansas, Inc. Page 2 Company Net Gen To Area UPP Exchange Inadvertent Firm Sales Sys Sales Unacct JONESBORO Excess INDEPN 2 2,986,600 1,764,678 0 1,221,922 0 0 0 0 JONESBORO Excess WH BLF 1 4,868,500 3,114,865 0 1,744,400 9,235 0 0 0 JONESBORO Excess WH BLF 2 9,850,050 7,159,003 0 2,670,122 20,925 0 0 0 OSCEOLA Excess INDEPN 1 142,645 142,645 0 0 0 0 0 0 OSCEOLA Excess INDEPN 2 2,225,615 2,225,615 0 0 0 0 0 0 WEST MEMPHIS Excess WH.BLF 1 56,440 56,440 0 0 0 0 0 0 WEST MEMPHIS Excess WH.BLF 2 454,030 454,030 0 0 0 0 0 0 AECI/WSPP A 499,659 214,488 0 275,334 9,837 0 0 0 AECI/WSPP B 4,176,000 3,393,000 0 783,000 0 0 0 0 AECI/WSPP C SYSTEM FIRM 9,620,460 6,726,581 0 2,837,035 53,556 0 3,288 0 AEP SERVICE CORP /WSPP A 626,400 369,543 0 254,973 1,884 0 0 0 AEP SERVICE CORP /WSPP C 167,040 156,600 0 10,440 0 0 0 0 AMEREN ENERGY NC. (AE) ACTING 501,120 353,129 0 145,951 0 0 2,040 0 Ameren Energy Marketing Company/WSPP 10,440 10,440 0 0 0 0 0 0 BNP PARIBAS ENERGY TRADING 41,760 41,760 0 0 0 0 0 0 BNP PARIBAS ENERGY TRADING 803,671 770,263 0 33,408 0 0 0 0 CALP NE ENERGY SERVICES L.P./WSPP 2,789,568 2,537,516 0 236,639 0 0 15,413 0 CARGILL POWER MARKETS LLC/WSPP A 349,740 349,740 0 0 0 0 0 0 CITIGROUP ENERGY NC/WSPP A 50,112 39,672 0 10,440 0 0 0 0 CLECO/WSPP B 1,048,172 627,636 0 317,798 19,334 0 83,404 0 CONSTELLATION ENERGY 37,584 26,463 0 0 11,121 0 0 0 CONSTELLATION ENERGY 1,135,245 929,399 0 204,354 807 0 685 0 COTTONWOOD ENERGY CO/EXS50 41,619 34,000 0 7,619 0 0 0 0 COTTONWOOD ENERGY CO/EXS75 10,037 7,926 0 2,111 0 0 0 0 COTTONWOOD ENERGY CO/EXS90 438,669 386,586 0 51,457 626 0 0 0 COTTONWOOD ENERGY CO/EXSSS50 2,541 2,541 0 0 0 0 0 0 COTTONWOOD ENERGY CO/EXSSTSH 290,367 209,453 0 80,914 0 0 0 0 CROSS O L/QF 209,394 132,508 0 76,886 0 0 0 0 CYPRES/EXS50 3,999 3,999 0 0 0 0 0 0 CYPRES/EXS75 219 219 0 0 0 0 0 0 CYPRES/EXS90 26,430 26,430 0 0 0 0 0 0 DB ENERGY TRAD NG LLC/WSPP B 21,593,680 18,492,782 0 2,901,191 87,866 0 111,632 209 DUKE ENERGY HINDS/EXS50 23,661 23,661 0 0 0 0 0 0 DUKE ENERGY HINDS/EXS75 17,266 11,684 0 5,582 0 0 0 0 DUKE ENERGY HINDS/EXS90 180,827 168,938 0 11,889 0 0 0 0 DUKEENERGY HOTSPRING/EXS50 29,273 29,253 0 20 0 0 0 0 DUKEENERGY HOTSPRING/EXS75 17,619 16,912 0 700 7 0 0 0 DUKEENERGY HOTSPRING/EXS90 152,741 150,477 0 2,264 0 0 0 0 DUKEENERGY HOTSPRING/FREE 156 156 0 0 0 0 0 0 ENDURE ENERGY/WSPP A 283,965 282,765 0 0 0 0 1,200 0 ENDURE ENERGY/WSPP B 13,572 0 0 13,572 0 0 0 0 ETEC/WSPP B 244,298 244,298 0 0 0 0 0 0 EXELON GENERATION COMPANY 19,524,239 15,079,121 0 4,361,740 52,602 0 30,776 0 J ARON & COMPANY/WSPP B 4,984,056 4,353,549 0 599,915 18,710 0 11,882 0 J.P. MORGAN VENTURES ENERGY 13,990 13,990 0 0 0 0 0 0 J.P. MORGAN VENTURES ENERGY 1,019,989 900,488 0 0 3,268 0 116,233 0 JBO/WSPP A 2,019,305 1,537,630 0 217,449 0 0 264,226 0 JBO/WSPP B 2,168,386 1,840,823 0 275,382 0 0 52,181 0 KANSAS CITY POWER & LIGHT 300,881 300,881 0 0 0 0 0 0 MAGNET COVE/EXS75 3,545 3,545 0 0 0 0 0 0 MAGNET COVE/EXS90 164,007 128,342 0 35,561 104 0 0 0 MAGNET COVE/EXSSTSH 901,963 556,965 0 344,998 0 0 0 0 MDEA CROSSROADS/EXS50 4,846 4,846 0 0 0 0 0 0 MDEA CROSSROADS/EXS75 977 977 0 0 0 0 0 0 MDEA CROSSROADS/EXS90 34,261 34,261 0 0 0 0 0 0 MERRILL LYNCH COMMODITIES 40,521,612 34,559,147 0 5,621,170 110,134 0 231,161 0 MORGAN STANLEY/WSPP A 51,366 29,859 0 21,507 0 0 0 0 NRG POWER MARKETING LLC./WSPP A 6,217,020 3,363,918 0 2,773,777 79,325 0 0 0 NRG POWER MARKETING LLC./WSPP B 38,603,785 33,443,893 0 4,613,037 159,901 0 386,954 0 NRG POWER MARKETING LLC./WSPP C 1,740,348 1,515,609 0 212,817 5,681 0 6,241 0 OCCIDENTAL POWER SERVICES/WSPP 1,189,742 859,931 0 241,196 23,113 0 65,502 0 PINE BLUFF ENERGY/QF 70,109,200 38,424,118 0 31,414,407 270,675 0 0 0 RAINBOW ENERGY MARKETING 2,907,333 2,746,765 0 154,939 5,629 0 0 0 SMEPA/WSPP B 626,400 601,514 0 0 19,675 0 5,211 0 SOUTHERN COMPANY SERVICES INC. 114,840 52,200 0 62,640 0 0 0 0 SOUTHERN COMPANY SERVICES INC. 2,213,280 1,811,139 0 0 120,558 0 281,583 0 SUEZ Energy Marketing NA Inc./WSPP A 1,808,208 1,630,717 0 177,491 0 0 0 0 SUEZ Energy Marketing NA Inc./WSPP B 11,804,928 10,673,972 0 1,049,490 18,284 0 63,182 0 TEA/WSPP A 233,021 204,833 0 28,188 0 0 0 0 TENASKA FRONTIER/EXS50 17,152 17,152 0 0 0 0 0 0 TENASKA FRONTIER/EXS75 13,458 9,788 0 3,670 0 0 0 0 TENASKA FRONTIER/EXS90 218,226 177,130 0 40,595 501 0 0 0 TENASKA/WSPP A 490,888 484,557 0 0 0 0 6,331 0 TENASKA/WSPP B 4,812,638 4,317,828 0 449,719 14,162 0 30,929 0 UNION POWER PARTNERS/WSPP A 39,672 36,096 0 3,576 0 0 0 0 Attachment Snapshot: 20100826181933 RunID: 17029 Billing Snapshot: 20100826175238

2011 ETI Rate Case 9-164 Exhibit PJC-2 2011 TX Rate Case Page 3 of 70

Entergy Electric System Date range - 20100701 through 20100731 Attachment 1 Intra-System Billing-201007RA KWH Log Sheet Reconciliation - Entergy Arkansas, Inc. Page 3 Company Net Gen To Area UPP Exchange Inadvertent Firm Sales Sys Sales Unacct UNION POWER PARTNERS/WSPP B 34,397,079 30,983,289 0 3,127,518 145,624 0 140,230 418 WESTAR ENERGY NC/WSPP A 1,447,817 1,005,766 0 420,854 21,197 0 0 0 WESTAR ENERGY NC/WSPP B 6,170,038 4,937,510 0 1,228,584 1,632 0 2,312 0 WESTAR ENERGY NC/WSPP C 167,040 156,600 0 10,440 0 0 0 0 WRIGHTSVILE POWER/EXS75 7,745 7,745 0 0 0 0 0 0 WRIGHTSVILE POWER/EXS90 169,805 167,905 0 1,900 0 0 0 0 YAZOO CITY/EXS90 1,101 1,101 0 0 0 0 0 0 Un-accounted In 4,036 4,036 0 0 0 0 0 0 Exchange 131,563,443 131,547,746 0 0 13,186 0 0 2,511 INADVERTENT N 3,196,726 3,196,726 0 0 0 0 0 0 Totals 3,068,221,822 2,534,515,289 395,462,556 131,743,223 4,583,474 0 1,913,306 3,974

Attachment Snapshot: 20100826181933 RunID: 17029 Billing Snapshot: 20100826175238

2011 ETI Rate Case 9-165 Exhibit PJC-2 2011 TX Rate Case Page 4 of 70

Entergy Electric System Date range - 20100701 through 20100731 Attachment 1 Intra-System Billing-201007RA KWH Log Sheet Reconciliation - Entergy Louisiana, LLC Page 4 Company Net Gen To Area UPP Exchange Inadvertent Firm Sales Sys Sales Unacct AEP SERVICE CORP /MINDEN PAYBACK (625,318) (625,318) 0 0 0 0 0 0 BURAS TEMP 131,908 0 0 45,238 0 0 86,670 0 CALDWELL IMBAL IN 325,038 325,038 0 0 0 0 0 0 CALDWELL IMBAL OT (592) (592) 0 0 0 0 0 0 COG Sale Losses N 228,116 228,116 0 0 0 0 0 0 EPI-ISES ELI IN 35,090,137 35,090,137 0 0 0 0 0 0 GIS Imbalance IN 311,804 311,804 0 0 0 0 0 0 GIS Imbalance OT (323,377) (323,377) 0 0 0 0 0 0 IPP Sale Losses N 2,135,618 2,135,618 0 0 0 0 0 0 JAS loss N 503 503 0 0 0 0 0 0 KIRBYVILLE IMBAL IN 154,924 154,924 0 0 0 0 0 0 KIRBYVILLE IMBAL OT (1,596) (1,596) 0 0 0 0 0 0 NEWTON IMBAL IN 248,837 248,837 0 0 0 0 0 0 NEWTON IMBAL OT (154) (154) 0 0 0 0 0 0 ACADIA POWER PARTNERS, LLC/WSPP 59,708,320 0 59,708,320 0 0 0 0 0 ARK.NU 1/NUCLEAR 24,991,859 24,991,859 0 0 0 0 0 0 ARK.NU 2/NUCLEAR 29,534,318 29,534,318 0 0 0 0 0 0 G.GULF 1/NUCLEAR 116,825,380 116,825,380 0 0 0 0 0 0 GGULF RET 19,691,908 19,691,908 0 0 0 0 0 0 GGULF RP 9,494,456 9,494,456 0 0 0 0 0 0 L.GPSY 1/BRDGLN E 5,159,508 5,159,508 0 0 0 0 0 0 L.GPSY 1/EVANG(LT) M 42,028,954 33,569,285 0 7,913,583 545,584 0 0 502 L.GPSY 1/EVG/CG I 2,715,643 2,669,294 0 46,349 0 0 0 0 L.GPSY 1/GSPL M 815,895 815,895 0 0 0 0 0 0 L.GPSY 2/Aux (575,000) (575,000) 0 0 0 0 0 0 L.GPSY 2/BRDGLN E 2,381,479 1,275,111 0 1,045,351 61,017 0 0 0 L.GPSY 2/CGT M 441,540 402,937 0 25,995 12,608 0 0 0 L.GPSY 2/EVANG(LT) M 45,103,438 19,275,826 0 25,320,605 507,007 0 0 0 L.GPSY 2/EVG/CG I 3,083,544 898,936 0 2,135,948 48,660 0 0 0 L.GPSY 2/GSPL M 2,511,999 2,128,198 0 346,715 37,086 0 0 0 L.GPSY 3/BRDGLN E 56,921,780 56,920,943 0 0 0 0 837 0 L.GPSY 3/CGT E 18,834,369 18,834,369 0 0 0 0 0 0 L.GPSY 3/CGT M 56,529,560 56,529,560 0 0 0 0 0 0 L.GPSY 3/EVANG(LT) M 21,210,502 18,405,512 0 2,662,097 142,642 0 0 251 L.GPSY 3/EVG/CG I 4,340,255 4,340,255 0 0 0 0 0 0 L.GPSY 3/GSPL E 7,924,740 7,924,740 0 0 0 0 0 0 L.GPSY 3/GSPL M 30,570,794 30,570,794 0 0 0 0 0 0 MURRAY 1/HYDRO 110,159,000 110,159,000 0 0 0 0 0 0 N NEMI 3/Aux (30,000) (30,000) 0 0 0 0 0 0 N NEMI 3/EVANG(LT) M 13,804,559 7,722,572 0 5,982,602 99,385 0 0 0 N NEMI 3/EVG/CG I 1,470,441 515,670 0 905,754 49,017 0 0 0 N NEMI 4/Aux (1,006,000) (1,006,000) 0 0 0 0 0 0 N NEMI 4/BRDGLN E 18,726,728 18,726,728 0 0 0 0 0 0 N NEMI 4/CGT E 1,635,542 1,635,542 0 0 0 0 0 0 N NEMI 4/CGT M 4,245,923 4,245,923 0 0 0 0 0 0 N NEMI 4/EVANG(LT) M 62,673,146 59,118,809 0 3,228,244 323,984 0 603 1,506 N NEMI 4/EVANG(SP) E 3,730,147 3,730,147 0 0 0 0 0 0 N NEMI 4/EVG/CG I 7,083,201 7,081,977 0 1,224 0 0 0 0 N NEMI 4/GSPL E 446,596 446,596 0 0 0 0 0 0 N NEMI 4/GSPL M 803,482 803,482 0 0 0 0 0 0 N NEMI 4/LGS E 2,134,235 2,134,235 0 0 0 0 0 0 N NEMI 5/Aux (141,000) (141,000) 0 0 0 0 0 0 N NEMI 5/BRDGLN E 90,282,967 90,234,151 0 0 0 0 48,816 0 N NEMI 5/CGT E 26,968,843 26,968,843 0 0 0 0 0 0 N NEMI 5/CGT M 84,111,485 84,111,485 0 0 0 0 0 0 N NEMI 5/EVANG(LT) M 99,312,226 97,761,791 0 1,193,561 356,623 0 0 251 N NEMI 5/EVANG(SP) E 336,710 336,710 0 0 0 0 0 0 N NEMI 5/EVG/CG I 8,282,375 8,282,375 0 0 0 0 0 0 N NEMI 5/GSPL E 3,393,948 3,393,948 0 0 0 0 0 0 N NEMI 5/GSPL M 8,258,057 8,258,057 0 0 0 0 0 0 N NEMI 5/LGS E 5,155,389 5,155,389 0 0 0 0 0 0 PERVIL 1 194,914,500 0 194,914,500 0 0 0 0 0 PERVIL 1/Aux (18,000) (18,000) 0 0 0 0 0 0 PERVIL 1/TENN E 52,512,761 52,512,761 0 0 0 0 0 0 PERVIL 1/TENN I 5,888,462 5,888,462 0 0 0 0 0 0 PERVIL 1/TEXAS GAS E 6,570,277 6,570,277 0 0 0 0 0 0 PERVIL 2/Aux (4,571,000) (4,571,000) 0 0 0 0 0 0 RVRBND 1/NUCLEAR 139,555,800 139,555,800 0 0 0 0 0 0 STERLN 6/Aux (213,000) (213,000) 0 0 0 0 0 0 TOLEDO 1/HYDRO 2,246,500 2,246,500 0 0 0 0 0 0 WATERF 1/Aux (62,000) (62,000) 0 0 0 0 0 0 WATERF 1/BRDGLN E 2,728,053 1,820,443 0 843,299 64,311 0 0 0 WATERF 1/CGT M 613,149 254,658 0 356,988 1,503 0 0 0 WATERF 1/EVANG(LT) M 68,159,274 18,545,667 0 47,727,893 1,884,710 0 0 1,004 WATERF 1/EVG/CG I 4,491,524 789,096 0 3,677,054 25,374 0 0 0 Attachment Snapshot: 20100826181933 RunID: 17029 Billing Snapshot: 20100826175238

2011 ETI Rate Case 9-166 Exhibit PJC-2 2011 TX Rate Case Page 5 of 70

Entergy Electric System Date range - 20100701 through 20100731 Attachment 1 Intra-System Billing-201007RA KWH Log Sheet Reconciliation - Entergy Louisiana, LLC Page 5 Company Net Gen To Area UPP Exchange Inadvertent Firm Sales Sys Sales Unacct WATERF 2/#6 OIL 352,500 50,000 0 302,500 0 0 0 0 WATERF 2/BRDGLN E 44,477,948 35,025,366 0 9,002,954 448,624 0 0 1,004 WATERF 2/CGT E 14,257,818 12,473,477 0 1,648,800 135,541 0 0 0 WATERF 2/CGT M 44,130,973 34,623,561 0 8,938,269 568,892 0 0 251 WATERF 2/EVANG(LT) M 11,514,423 8,153,222 0 3,286,637 74,564 0 0 0 WATERF 2/EVG/CG I 2,407,338 1,023,375 0 1,383,963 0 0 0 0 WATERF 3/NUCLEAR 866,024,000 866,024,000 0 0 0 0 0 0 WATERF 4/#2 OIL 46,000 0 0 46,000 0 0 0 0 INDEPN 1/COAL 7,145,175 7,145,175 0 0 0 0 0 0 WH.BLF 1/COAL 13,440,805 13,440,805 0 0 0 0 0 0 WH.BLF 2/COAL 10,706,289 10,706,289 0 0 0 0 0 0 AECC Excess BAILEY 1 60,190 60,190 0 0 0 0 0 0 AECC Excess INDEPN 2 17,399 17,399 0 0 0 0 0 0 AECC Excess MCCLEL 1 3,968,328 3,825,779 0 126,981 15,568 0 0 0 AECC Excess WH.BLF 1 1,791,648 1,791,648 0 0 0 0 0 0 AECC Excess WH.BLF 2 8,747,321 8,747,321 0 0 0 0 0 0 ACADIA POWER PARTNERS, LLC/WSPP 119,416,680 119,351,055 0 0 0 0 65,625 0 AECI/WSPP A 601,840 601,840 0 0 0 0 0 0 AECI/WSPP B 5,030,000 5,030,000 0 0 0 0 0 0 AECI/WSPP C SYSTEM FIRM 11,587,863 10,886,516 0 678,098 19,289 0 3,960 0 AEP SERVICE CORP /WSPP A 754,500 754,500 0 0 0 0 0 0 AEP SERVICE CORP /WSPP C 201,200 201,200 0 0 0 0 0 0 AMEREN ENERGY NC. (AE) ACTING 603,600 601,142 0 0 0 0 2,458 0 Ameren Energy Marketing Company/WSPP 12,575 12,575 0 0 0 0 0 0 BNP PARIBAS ENERGY TRADING 50,300 50,300 0 0 0 0 0 0 BNP PARIBAS ENERGY TRADING 968,024 968,024 0 0 0 0 0 0 BP-ALLIANCE/QF 12,189,947 12,189,947 0 0 0 0 0 0 CALP NE ENERGY SERVICES L.P./WSPP 3,360,048 3,341,476 0 0 0 0 18,572 0 CARGILL POWER MARKETS LLC/WSPP A 421,265 421,265 0 0 0 0 0 0 CII CARBON CALCINER/QF 7,833,120 7,833,120 0 0 0 0 0 0 CITIGROUP ENERGY NC/WSPP A 60,361 60,361 0 0 0 0 0 0 CLECO/WSPP B 1,262,618 1,027,846 0 132,197 2,103 0 100,472 0 CONSTELLATION ENERGY 45,271 45,271 0 0 0 0 0 0 CONSTELLATION ENERGY 1,367,406 1,366,580 0 0 0 0 826 0 COTTONWOOD ENERGY CO/EXS50 50,135 50,135 0 0 0 0 0 0 COTTONWOOD ENERGY CO/EXS75 12,102 12,102 0 0 0 0 0 0 COTTONWOOD ENERGY CO/EXS90 528,321 528,321 0 0 0 0 0 0 COTTONWOOD ENERGY CO/EXSSS50 3,060 3,060 0 0 0 0 0 0 COTTONWOOD ENERGY CO/EXSSTSH 349,743 349,743 0 0 0 0 0 0 CYPRES/EXS50 4,816 4,816 0 0 0 0 0 0 CYPRES/EXS75 264 264 0 0 0 0 0 0 CYPRES/EXS90 31,833 31,833 0 0 0 0 0 0 DB ENERGY TRAD NG LLC/WSPP B 26,009,688 25,875,218 0 0 0 0 134,470 0 DUKE ENERGY HINDS/EXS50 28,499 28,499 0 0 0 0 0 0 DUKE ENERGY HINDS/EXS75 20,807 20,807 0 0 0 0 0 0 DUKE ENERGY HINDS/EXS90 217,804 217,804 0 0 0 0 0 0 DUKEENERGY HOTSPRING/EXS50 35,260 35,260 0 0 0 0 0 0 DUKEENERGY HOTSPRING/EXS75 21,226 21,226 0 0 0 0 0 0 DUKEENERGY HOTSPRING/EXS90 183,983 183,983 0 0 0 0 0 0 DUKEENERGY HOTSPRING/FREE 189 189 0 0 0 0 0 0 ENDURE ENERGY/WSPP A 342,048 316,207 0 24,396 0 0 1,445 0 ENDURE ENERGY/WSPP B 16,348 16,348 0 0 0 0 0 0 ETEC/WSPP B 294,260 294,260 0 0 0 0 0 0 EXELON GENERATION COMPANY 23,517,077 23,479,999 0 0 0 0 37,078 0 GEORGIA GULF CORP/QF 7,269,980 7,269,980 0 0 0 0 0 0 J ARON & COMPANY/WSPP B 6,003,359 5,862,580 0 126,465 0 0 14,314 0 J.P. MORGAN VENTURES ENERGY 16,851 16,851 0 0 0 0 0 0 J.P. MORGAN VENTURES ENERGY 1,228,582 1,046,116 0 38,670 3,790 0 140,006 0 JBO/WSPP A 2,432,270 834,360 0 1,258,817 20,805 0 318,288 0 JBO/WSPP B 2,611,868 2,268,140 0 262,779 18,079 0 62,870 0 KANSAS CITY POWER & LIGHT 362,411 362,411 0 0 0 0 0 0 MAGNET COVE/EXS75 4,270 4,270 0 0 0 0 0 0 MAGNET COVE/EXS90 197,598 197,598 0 0 0 0 0 0 MAGNET COVE/EXSSTSH 1,086,406 1,086,406 0 0 0 0 0 0 MDEA CROSSROADS/EXS50 5,838 5,838 0 0 0 0 0 0 MDEA CROSSROADS/EXS75 1,178 1,178 0 0 0 0 0 0 MDEA CROSSROADS/EXS90 41,256 41,256 0 0 0 0 0 0 MERRILL LYNCH COMMODITIES 48,808,429 48,529,987 0 0 0 0 278,442 0 MORGAN STANLEY/WSPP A 61,868 61,868 0 0 0 0 0 0 NRG POWER MARKETING LLC./WSPP A 7,488,413 7,111,163 0 377,250 0 0 0 0 NRG POWER MARKETING LLC./WSPP B 46,498,600 45,526,626 0 500,863 5,000 0 466,111 0 NRG POWER MARKETING LLC./WSPP C 2,096,255 2,063,587 0 25,150 0 0 7,518 0 OCCIDENTAL CHEM CORP/QF 48,338,250 48,338,250 0 0 0 0 0 0 OCCIDENTAL POWER SERVICES/BASE 219,380,000 219,158,027 0 0 0 0 221,973 0 OCCIDENTAL POWER SERVICES/DAY- 50,188,000 50,182,559 0 0 0 0 5,441 0 Attachment Snapshot: 20100826181933 RunID: 17029 Billing Snapshot: 20100826175238

2011 ETI Rate Case 9-167 Exhibit PJC-2 2011 TX Rate Case Page 6 of 70

Entergy Electric System Date range - 20100701 through 20100731 Attachment 1 Intra-System Billing-201007RA KWH Log Sheet Reconciliation - Entergy Louisiana, LLC Page 6 Company Net Gen To Area UPP Exchange Inadvertent Firm Sales Sys Sales Unacct OCCIDENTAL POWER SERVICES/ NTRA- 9,090,000 9,049,131 0 0 0 0 40,869 0 OCCIDENTAL POWER SERVICES/WSPP 1,433,048 1,292,647 0 49,866 11,631 0 78,904 0 RAINBOW ENERGY MARKETING 3,501,908 3,501,908 0 0 0 0 0 0 SMEPA/WSPP B 754,504 0 0 748,227 0 0 6,277 0 SOUTHERN COMPANY SERVICES INC. 138,325 138,325 0 0 0 0 0 0 SOUTHERN COMPANY SERVICES INC. 2,665,900 0 0 2,326,731 0 0 339,169 0 SUEZ Energy Marketing NA Inc./WSPP A 2,178,009 2,178,009 0 0 0 0 0 0 SUEZ Energy Marketing NA Inc./WSPP B 14,219,068 14,142,961 0 0 0 0 76,107 0 TEA/WSPP A 280,677 280,677 0 0 0 0 0 0 TENASKA FRONTIER/EXS50 20,660 20,660 0 0 0 0 0 0 TENASKA FRONTIER/EXS75 16,210 16,210 0 0 0 0 0 0 TENASKA FRONTIER/EXS90 262,868 262,868 0 0 0 0 0 0 TENASKA/WSPP A 591,278 583,653 0 0 0 0 7,625 0 TENASKA/WSPP B 5,796,845 5,382,881 0 361,244 15,459 0 37,261 0 UNION CARBIDE CORP/QF 40,452,720 40,452,720 0 0 0 0 0 0 UNION POWER PARTNERS/WSPP A 47,786 47,786 0 0 0 0 0 0 UNION POWER PARTNERS/WSPP B 41,431,444 41,262,525 0 0 0 0 168,919 0 WESTAR ENERGY NC/WSPP A 1,743,909 1,743,909 0 0 0 0 0 0 WESTAR ENERGY NC/WSPP B 7,431,833 7,429,047 0 0 0 0 2,786 0 WESTAR ENERGY NC/WSPP C 201,200 201,200 0 0 0 0 0 0 WRIGHTSVILE POWER/EXS75 9,333 9,333 0 0 0 0 0 0 WRIGHTSVILE POWER/EXS90 204,509 204,509 0 0 0 0 0 0 YAZOO CITY/EXS90 1,324 1,324 0 0 0 0 0 0 Un-accounted In 4,843 4,843 0 0 0 0 0 0 Exchange 42,272,082 42,272,082 0 0 0 0 0 0 INADVERTENT N 3,850,516 3,850,516 0 0 0 0 0 0 Totals 3,491,820,106 3,093,813,592 254,622,820 135,105,357 5,498,856 0 2,774,712 4,769

Attachment Snapshot: 20100826181933 RunID: 17029 Billing Snapshot: 20100826175238

2011 ETI Rate Case 9-168 Exhibit PJC-2 2011 TX Rate Case Page 7 of 70

Entergy Electric System Date range - 20100701 through 20100731 Attachment 1 Intra-System Billing-201007RA KWH Log Sheet Reconciliation - Entergy Mississippi, Inc. Page 7 Company Net Gen To Area UPP Exchange Inadvertent Firm Sales Sys Sales Unacct AECCISES - MDEA 37,000 37,000 0 0 0 0 0 0 AECI - MDEA 1,380,000 1,380,000 0 0 0 0 0 0 AEP SERVICE CORP /MINDEN PAYBACK (348,600) (348,600) 0 0 0 0 0 0 CALDWELL IMBAL IN 180,158 180,158 0 0 0 0 0 0 CALDWELL IMBAL OT (330) (330) 0 0 0 0 0 0 COG Sale Losses N 126,412 126,412 0 0 0 0 0 0 DOWCHEM - MDEA 751,000 751,000 0 0 0 0 0 0 EPMCNELSON6 - MDEA 1,018,000 1,018,000 0 0 0 0 0 0 GIS Imbalance IN 172,809 172,809 0 0 0 0 0 0 GIS Imbalance OT (180,160) (180,160) 0 0 0 0 0 0 HYDRO2 - MDEA 18,000 18,000 0 0 0 0 0 0 IPP Sale Losses N 1,183,669 1,183,669 0 0 0 0 0 0 JAS loss N 279 279 0 0 0 0 0 0 JBOISES - MDEA 302,000 302,000 0 0 0 0 0 0 KIRBYVILLE IMBAL IN 85,867 85,867 0 0 0 0 0 0 KIRBYVILLE IMBAL OT (890) (890) 0 0 0 0 0 0 LAFA - MDEA 10,000 10,000 0 0 0 0 0 0 LAGN - MDEA 17,989,000 17,989,000 0 0 0 0 0 0 MAGNETCOVE - MDEA 1,322,000 1,322,000 0 0 0 0 0 0 MDEA LOAD OT (36,877,000) (36,877,000) 0 0 0 0 0 0 MEAM CANTON 1 IN 73,000 64,137 0 0 0 0 8,863 0 MEAM CANTON 2 IN 83,000 74,000 0 0 1,000 0 8,000 0 MEAM CANTON 3 IN 84,000 75,000 0 0 1,000 0 8,000 0 MEAM CANTON 4 IN 84,000 75,000 0 0 989 0 8,011 0 MEAM CANTON 5 IN 82,000 70,378 0 0 1,622 0 10,000 0 MEAM HENDERSON 10 IN 58,000 51,751 0 0 1,249 0 5,000 0 MEAM HENDERSON 11 IN 59,000 47,450 0 0 3,550 0 8,000 0 MEAM HENDERSON 2 IN 524,000 412,807 0 0 42,277 0 68,916 0 MEAM HENDERSON 4 IN 72,000 49,000 0 0 9,142 0 13,858 0 MEAM HENDERSON 5 IN 72,000 48,810 0 0 9,024 0 14,166 0 MEAM HENDERSON 6 IN 73,000 45,124 0 0 12,876 0 15,000 0 MEAM HENDERSON 7 IN 76,000 43,120 0 0 13,721 0 19,159 0 MEAM HENDERSON 8 IN 74,000 37,250 0 0 12,000 0 24,750 0 MEAM HENDERSON 9 IN 54,000 25,257 0 0 5,521 0 23,222 0 MEAM IMBALANCE IN 4,082,291 4,082,291 0 0 0 0 0 0 MEAM IMBALANCE OT (4,381) (4,381) 0 0 0 0 0 0 NEWTON IMBAL IN 137,943 137,943 0 0 0 0 0 0 NEWTON IMBAL OT (86) (86) 0 0 0 0 0 0 PLUM - MDEA 31,000 31,000 0 0 0 0 0 0 PPG - MDEA 28,000 28,000 0 0 0 0 0 0 SABCOGEN - MDEA 895,000 895,000 0 0 0 0 0 0 SWPP - MDEA 13,514,000 13,514,000 0 0 0 0 0 0 TVA - MDEA 723,000 723,000 0 0 0 0 0 0 ANDRUS 1/Aux (660,000) (660,000) 0 0 0 0 0 0 ANDRUS 1/TENN E 155,006,673 152,213,418 0 2,659,523 106,471 0 27,261 0 ANDRUS 1/TENN I 16,394,504 15,647,456 0 716,204 30,499 0 345 0 ANDRUS 1/TGT E 69,484,823 68,929,469 0 500,938 54,416 0 0 0 ARK.NU 1/NUCLEAR 11,975,579 11,975,579 0 0 0 0 0 0 ARK.NU 2/NUCLEAR 14,206,469 14,206,469 0 0 0 0 0 0 ATTALA 1/Aux (456,000) (456,000) 0 0 0 0 0 0 ATTALA 1/TETCO E 158,162,196 158,162,196 0 0 0 0 0 0 ATTALA 1/TETCO I 20,360,804 20,360,804 0 0 0 0 0 0 B.WLSN 1/COLUMBIA MAINLINE I 80,752 80,752 0 0 0 0 0 0 B.WLSN 1/COLUMBIA ML E 129,355,248 129,305,896 0 38,457 9,513 0 1,382 0 B.WLSN 2/COLUMBIA MAINLINE I 6,972,555 6,834,693 0 137,442 0 0 0 420 B.WLSN 2/COLUMBIA ML E 162,519,445 140,255,044 0 21,706,585 548,970 0 8,426 420 DELTA5 1/Aux (35,000) (35,000) 0 0 0 0 0 0 DELTA5 2/Aux (42,000) (42,000) 0 0 0 0 0 0 G.GULF 1/NUCLEAR 275,374,110 275,374,110 0 0 0 0 0 0 GGULF RET 8,775,642 8,775,642 0 0 0 0 0 0 GGULF RP 4,440,083 4,440,083 0 0 0 0 0 0 REX BR 1/Aux (76,000) (76,000) 0 0 0 0 0 0 REX BR 3/Aux (73,000) (73,000) 0 0 0 0 0 0 REX BR 4/GSPL E 20,874,591 13,534,553 0 5,393,054 1,946,844 0 0 140 REX BR 4/GSPL I 1,463,409 1,163,408 0 201,384 98,617 0 0 0 REX BR 5/#2 O L 5,000 2,580 0 0 2,420 0 0 0 REX BR 5/Aux (3,000) (3,000) 0 0 0 0 0 0 INDEPN 1/COAL 144,835,585 144,835,585 0 0 0 0 0 0 INDEPN 2/Aux (199,500) (199,500) 0 0 0 0 0 0 INDEPN 2/COAL 120,547,500 120,547,500 0 0 0 0 0 0 WH.BLF 1/COAL 6,292,389 6,292,389 0 0 0 0 0 0 WH.BLF 2/COAL 5,295,338 5,295,338 0 0 0 0 0 0 AECC Excess BAILEY 1 33,336 32,919 0 417 0 0 0 0 AECC Excess INDEPN 2 9,643 9,643 0 0 0 0 0 0 AECC Excess MCCLEL 1 2,199,527 2,084,823 0 114,704 0 0 0 0 Attachment Snapshot: 20100826181933 RunID: 17029 Billing Snapshot: 20100826175238

2011 ETI Rate Case 9-169 Exhibit PJC-2 2011 TX Rate Case Page 8 of 70

Entergy Electric System Date range - 20100701 through 20100731 Attachment 1 Intra-System Billing-201007RA KWH Log Sheet Reconciliation - Entergy Mississippi, Inc. Page 8 Company Net Gen To Area UPP Exchange Inadvertent Firm Sales Sys Sales Unacct AECC Excess WH.BLF 1 993,060 993,060 0 0 0 0 0 0 AECC Excess WH.BLF 2 4,848,407 4,848,407 0 0 0 0 0 0 AECI/WSPP A 333,584 333,584 0 0 0 0 0 0 AECI/WSPP B 2,788,000 2,788,000 0 0 0 0 0 0 AECI/WSPP C SYSTEM FIRM 6,422,855 6,420,661 0 0 0 0 2,194 0 AEP SERVICE CORP /WSPP A 418,200 418,200 0 0 0 0 0 0 AEP SERVICE CORP /WSPP C 111,520 111,520 0 0 0 0 0 0 AMEREN ENERGY NC. (AE) ACTING 334,560 333,199 0 0 0 0 1,361 0 Ameren Energy Marketing Company/WSPP 6,970 6,970 0 0 0 0 0 0 BNP PARIBAS ENERGY TRADING 27,880 27,880 0 0 0 0 0 0 BNP PARIBAS ENERGY TRADING 536,551 536,551 0 0 0 0 0 0 CALP NE ENERGY SERVICES L.P./WSPP 1,862,384 1,852,091 0 0 0 0 10,293 0 CARGILL POWER MARKETS LLC/WSPP A 233,494 233,494 0 0 0 0 0 0 CITIGROUP ENERGY NC/WSPP A 33,456 33,456 0 0 0 0 0 0 CLECO/WSPP B 699,790 543,971 0 97,617 2,518 0 55,684 0 CONSTELLATION ENERGY 25,092 25,092 0 0 0 0 0 0 CONSTELLATION ENERGY 757,918 757,460 0 0 0 0 458 0 COTTONWOOD ENERGY CO/EXS50 27,787 27,787 0 0 0 0 0 0 COTTONWOOD ENERGY CO/EXS75 6,703 6,703 0 0 0 0 0 0 COTTONWOOD ENERGY CO/EXS90 292,830 292,830 0 0 0 0 0 0 COTTONWOOD ENERGY CO/EXSSS50 1,696 1,696 0 0 0 0 0 0 COTTONWOOD ENERGY CO/EXSSTSH 193,858 193,858 0 0 0 0 0 0 CYPRES/EXS50 2,669 2,669 0 0 0 0 0 0 CYPRES/EXS75 146 146 0 0 0 0 0 0 CYPRES/EXS90 17,648 17,648 0 0 0 0 0 0 DB ENERGY TRAD NG LLC/WSPP B 14,416,465 14,341,940 0 0 0 0 74,525 0 DUKE ENERGY HINDS/EXS50 15,797 15,797 0 0 0 0 0 0 DUKE ENERGY HINDS/EXS75 11,523 11,523 0 0 0 0 0 0 DUKE ENERGY HINDS/EXS90 120,648 120,648 0 0 0 0 0 0 DUKEENERGY HOTSPRING/EXS50 19,538 19,538 0 0 0 0 0 0 DUKEENERGY HOTSPRING/EXS75 11,762 11,762 0 0 0 0 0 0 DUKEENERGY HOTSPRING/EXS90 101,969 101,969 0 0 0 0 0 0 DUKEENERGY HOTSPRING/FREE 105 105 0 0 0 0 0 0 ENDURE ENERGY/WSPP A 189,589 188,788 0 0 0 0 801 0 ENDURE ENERGY/WSPP B 9,061 9,061 0 0 0 0 0 0 ETEC/WSPP B 163,098 163,098 0 0 0 0 0 0 EXELON GENERATION COMPANY 13,034,879 13,014,333 0 0 0 0 20,546 0 J ARON & COMPANY/WSPP B 3,327,478 3,203,622 0 83,328 32,597 0 7,931 0 J.P. MORGAN VENTURES ENERGY 9,340 9,340 0 0 0 0 0 0 J.P. MORGAN VENTURES ENERGY 680,969 603,370 0 0 0 0 77,599 0 JBO/WSPP A 1,348,137 1,148,057 0 23,631 43 0 176,406 0 JBO/WSPP B 1,447,671 1,322,239 0 90,177 0 0 34,835 420 KANSAS CITY POWER & LIGHT 200,875 200,875 0 0 0 0 0 0 MAGNET COVE/EXS75 2,366 2,366 0 0 0 0 0 0 MAGNET COVE/EXS90 109,555 109,555 0 0 0 0 0 0 MAGNET COVE/EXSSTSH 602,169 602,169 0 0 0 0 0 0 MDEA CROSSROADS/EXS50 3,235 3,235 0 0 0 0 0 0 MDEA CROSSROADS/EXS75 653 653 0 0 0 0 0 0 MDEA CROSSROADS/EXS90 22,867 22,867 0 0 0 0 0 0 MERRILL LYNCH COMMODITIES 27,053,226 26,898,900 0 0 0 0 154,326 0 MISS CHEM NITROGEN/QF 29,448 29,448 0 0 0 0 0 0 MORGAN STANLEY/WSPP A 34,292 34,292 0 0 0 0 0 0 NRG POWER MARKETING LLC./WSPP A 4,150,635 4,150,635 0 0 0 0 0 0 NRG POWER MARKETING LLC./WSPP B 25,772,818 25,421,212 0 57,038 36,234 0 258,334 0 NRG POWER MARKETING LLC./WSPP C 1,161,899 1,157,732 0 0 0 0 4,167 0 OCCIDENTAL POWER SERVICES/WSPP 794,302 695,710 0 54,861 0 0 43,731 0 RAINBOW ENERGY MARKETING 1,941,010 1,941,010 0 0 0 0 0 0 SMEPA/WSPP B 418,200 414,721 0 0 0 0 3,479 0 SOUTHERN COMPANY SERVICES INC. 76,670 76,670 0 0 0 0 0 0 SOUTHERN COMPANY SERVICES INC. 1,477,640 1,209,063 0 0 80,583 0 187,994 0 SUEZ Energy Marketing NA Inc./WSPP A 1,207,204 1,207,204 0 0 0 0 0 0 SUEZ Energy Marketing NA Inc./WSPP B 7,881,251 7,839,067 0 0 0 0 42,184 0 TEA/WSPP A 155,570 155,570 0 0 0 0 0 0 TENASKA FRONTIER/EXS50 11,451 11,451 0 0 0 0 0 0 TENASKA FRONTIER/EXS75 8,985 8,985 0 0 0 0 0 0 TENASKA FRONTIER/EXS90 145,651 145,651 0 0 0 0 0 0 TENASKA/WSPP A 327,729 317,683 0 5,820 0 0 4,226 0 TENASKA/WSPP B 3,213,034 3,046,016 0 146,370 0 0 20,648 0 UNION POWER PARTNERS/WSPP A 26,486 26,486 0 0 0 0 0 0 UNION POWER PARTNERS/WSPP B 22,964,343 22,870,721 0 0 0 0 93,622 0 WESTAR ENERGY NC/WSPP A 966,608 966,608 0 0 0 0 0 0 WESTAR ENERGY NC/WSPP B 4,119,252 4,117,709 0 0 0 0 1,543 0 WESTAR ENERGY NC/WSPP C 111,520 111,520 0 0 0 0 0 0 WRIGHTSVILE POWER/EXS75 5,171 5,171 0 0 0 0 0 0 WRIGHTSVILE POWER/EXS90 113,362 113,362 0 0 0 0 0 0 Attachment Snapshot: 20100826181933 RunID: 17029 Billing Snapshot: 20100826175238

2011 ETI Rate Case 9-170 Exhibit PJC-2 2011 TX Rate Case Page 9 of 70

Entergy Electric System Date range - 20100701 through 20100731 Attachment 1 Intra-System Billing-201007RA KWH Log Sheet Reconciliation - Entergy Mississippi, Inc. Page 9 Company Net Gen To Area UPP Exchange Inadvertent Firm Sales Sys Sales Unacct YAZOO CITY/EXS90 734 734 0 0 0 0 0 0 Un-accounted In 2,701 2,701 0 0 0 0 0 0 Exchange 165,417,337 165,416,077 0 0 0 0 0 1,260 INADVERTENT N 2,134,214 2,134,214 0 0 0 0 0 0 Totals 1,669,714,232 1,633,071,080 0 32,027,550 3,063,696 0 1,549,246 2,660

Attachment Snapshot: 20100826181933 RunID: 17029 Billing Snapshot: 20100826175238

2011 ETI Rate Case 9-171 Exhibit PJC-2 2011 TX Rate Case Page 10 of 70

Entergy Electric System Date range - 20100701 through 20100731 Attachment 1 Intra-System Billing-201007RA KWH Log Sheet Reconciliation - Entergy New Orleans, Inc. Page 10 Company Net Gen To Area UPP Exchange Inadvertent Firm Sales Sys Sales Unacct AEP SERVICE CORP /MINDEN PAYBACK (111,056) (111,056) 0 0 0 0 0 0 CALDWELL IMBAL IN 58,420 58,420 0 0 0 0 0 0 CALDWELL IMBAL OT (104) (104) 0 0 0 0 0 0 COG Sale Losses N 40,983 40,983 0 0 0 0 0 0 EPI-ISES ENOI IN 34,395,193 34,395,193 0 0 0 0 0 0 GIS Imbalance IN 56,025 56,025 0 0 0 0 0 0 GIS Imbalance OT (57,568) (57,568) 0 0 0 0 0 0 IPP Sale Losses N 383,783 383,783 0 0 0 0 0 0 JAS loss N 90 90 0 0 0 0 0 0 KIRBYVILLE IMBAL IN 27,836 27,836 0 0 0 0 0 0 KIRBYVILLE IMBAL OT (285) (285) 0 0 0 0 0 0 NEWTON IMBAL IN 44,723 44,723 0 0 0 0 0 0 NEWTON IMBAL OT (28) (28) 0 0 0 0 0 0 ARK.NU 1/NUCLEAR 16,947,775 16,947,775 0 0 0 0 0 0 ARK.NU 2/NUCLEAR 19,989,454 19,989,454 0 0 0 0 0 0 G.GULF 1/NUCLEAR 141,859,390 141,859,390 0 0 0 0 0 0 GGULF RET 13,799,542 13,799,542 0 0 0 0 0 0 GGULF RP 6,514,363 6,514,363 0 0 0 0 0 0 MICHOD 1/Aux (208,000) (208,000) 0 0 0 0 0 0 MICHOD 2/BRDGLN E 17,595,495 17,411,762 0 62,252 116,111 0 5,370 0 MICHOD 2/GSPL E 56,709,373 56,651,579 0 0 45,575 0 12,219 0 MICHOD 2/NOPSI I 4,140,132 4,140,132 0 0 0 0 0 0 MICHOD 3/Aux (1,663,000) (1,663,000) 0 0 0 0 0 0 MICHOD 3/BRDGLN E 22,612,059 11,393,866 0 11,056,337 161,677 0 0 179 MICHOD 3/GSPL E 51,216,272 39,608,973 0 11,458,320 148,934 0 0 45 MICHOD 3/NOPSI I 10,702,389 5,463,663 0 5,187,011 51,715 0 0 0 MICHOD 3/SIGPL E 2,789,280 2,447,344 0 337,959 3,977 0 0 0 RVRBND 1/NUCLEAR 69,777,900 69,777,900 0 0 0 0 0 0 INDEPN 1/COAL 4,846,579 4,846,579 0 0 0 0 0 0 WH.BLF 1/COAL 8,494,462 8,494,462 0 0 0 0 0 0 WH.BLF 2/COAL 7,753,353 7,753,353 0 0 0 0 0 0 AECC Excess BAILEY 1 10,790 8,280 0 980 1,530 0 0 0 AECC Excess INDEPN 2 3,127 3,127 0 0 0 0 0 0 AECC Excess MCCLEL 1 713,178 383,473 0 315,602 14,103 0 0 0 AECC Excess WH.BLF 1 322,001 322,001 0 0 0 0 0 0 AECC Excess WH.BLF 2 1,572,080 1,572,080 0 0 0 0 0 0 AECI/WSPP A 108,163 108,163 0 0 0 0 0 0 AECI/WSPP B 904,000 904,000 0 0 0 0 0 0 AECI/WSPP C SYSTEM FIRM 2,082,590 1,473,723 0 608,021 134 0 712 0 AEP SERVICE CORP /WSPP A 135,600 135,600 0 0 0 0 0 0 AEP SERVICE CORP /WSPP C 36,160 36,160 0 0 0 0 0 0 AMEREN ENERGY NC. (AE) ACTING 108,480 88,921 0 18,080 1,038 0 441 0 Ameren Energy Marketing Company/WSPP 2,260 2,260 0 0 0 0 0 0 BNP PARIBAS ENERGY TRADING 9,040 9,040 0 0 0 0 0 0 BNP PARIBAS ENERGY TRADING 173,975 135,621 0 38,354 0 0 0 0 CALP NE ENERGY SERVICES L.P./WSPP 603,872 600,536 0 0 0 0 3,336 0 CARGILL POWER MARKETS LLC/WSPP A 75,710 75,710 0 0 0 0 0 0 CITIGROUP ENERGY NC/WSPP A 10,848 10,848 0 0 0 0 0 0 CLECO/WSPP B 226,908 123,535 0 76,004 9,320 0 18,049 0 CONSTELLATION ENERGY 8,136 8,136 0 0 0 0 0 0 CONSTELLATION ENERGY 245,753 245,605 0 0 0 0 148 0 COTTONWOOD ENERGY CO/EXS50 9,005 9,005 0 0 0 0 0 0 COTTONWOOD ENERGY CO/EXS75 2,169 2,169 0 0 0 0 0 0 COTTONWOOD ENERGY CO/EXS90 94,934 94,934 0 0 0 0 0 0 COTTONWOOD ENERGY CO/EXSSS50 550 550 0 0 0 0 0 0 COTTONWOOD ENERGY CO/EXSSTSH 62,864 62,864 0 0 0 0 0 0 CYPRES/EXS50 866 866 0 0 0 0 0 0 CYPRES/EXS75 48 48 0 0 0 0 0 0 CYPRES/EXS90 5,724 5,724 0 0 0 0 0 0 DB ENERGY TRAD NG LLC/WSPP B 4,674,492 4,554,768 0 95,558 0 0 24,166 0 DUKE ENERGY HINDS/EXS50 5,123 5,123 0 0 0 0 0 0 DUKE ENERGY HINDS/EXS75 3,726 3,726 0 0 0 0 0 0 DUKE ENERGY HINDS/EXS90 39,071 39,071 0 0 0 0 0 0 DUKEENERGY HOTSPRING/EXS50 6,334 6,334 0 0 0 0 0 0 DUKEENERGY HOTSPRING/EXS75 3,804 3,804 0 0 0 0 0 0 DUKEENERGY HOTSPRING/EXS90 33,061 33,061 0 0 0 0 0 0 DUKEENERGY HOTSPRING/FREE 33 33 0 0 0 0 0 0 ENDURE ENERGY/WSPP A 61,475 52,943 0 8,272 0 0 260 0 ENDURE ENERGY/WSPP B 2,938 2,938 0 0 0 0 0 0 ETEC/WSPP B 52,882 52,882 0 0 0 0 0 0 EXELON GENERATION COMPANY 4,226,539 4,219,874 0 0 0 0 6,665 0 J ARON & COMPANY/WSPP B 1,078,924 859,802 0 213,035 3,516 0 2,571 0 J.P. MORGAN VENTURES ENERGY 3,028 3,028 0 0 0 0 0 0 J.P. MORGAN VENTURES ENERGY 220,801 150,854 0 34,369 10,418 0 25,160 0 JBO/WSPP A 437,129 72,048 0 268,090 39,665 0 57,191 135 Attachment Snapshot: 20100826181933 RunID: 17029 Billing Snapshot: 20100826175238

2011 ETI Rate Case 9-172 Exhibit PJC-2 2011 TX Rate Case Page 11 of 70

Entergy Electric System Date range - 20100701 through 20100731 Attachment 1 Intra-System Billing-201007RA KWH Log Sheet Reconciliation - Entergy New Orleans, Inc. Page 11 Company Net Gen To Area UPP Exchange Inadvertent Firm Sales Sys Sales Unacct JBO/WSPP B 469,404 240,761 0 217,346 0 0 11,297 0 KANSAS CITY POWER & LIGHT 65,133 65,133 0 0 0 0 0 0 MAGNET COVE/EXS75 767 767 0 0 0 0 0 0 MAGNET COVE/EXS90 35,498 35,498 0 0 0 0 0 0 MAGNET COVE/EXSSTSH 195,248 195,248 0 0 0 0 0 0 MDEA CROSSROADS/EXS50 1,052 1,052 0 0 0 0 0 0 MDEA CROSSROADS/EXS75 212 212 0 0 0 0 0 0 MDEA CROSSROADS/EXS90 7,416 7,416 0 0 0 0 0 0 MERRILL LYNCH COMMODITIES 8,771,914 8,721,872 0 0 0 0 50,042 0 MORGAN STANLEY/WSPP A 11,118 11,118 0 0 0 0 0 0 NRG POWER MARKETING LLC./WSPP A 1,345,830 1,278,030 0 67,800 0 0 0 0 NRG POWER MARKETING LLC./WSPP B 8,356,751 7,962,176 0 280,383 30,425 0 83,767 0 NRG POWER MARKETING LLC./WSPP C 376,742 304,422 0 70,969 0 0 1,351 0 OCCIDENTAL POWER SERVICES/WSPP 257,550 182,926 0 40,184 20,217 0 14,178 45 RAINBOW ENERGY MARKETING 629,363 629,363 0 0 0 0 0 0 SMEPA/WSPP B 135,600 0 0 134,472 0 0 1,128 0 SOUTHERN COMPANY SERVICES INC. 24,860 24,860 0 0 0 0 0 0 SOUTHERN COMPANY SERVICES INC. 479,120 0 0 418,166 0 0 60,954 0 SUEZ Energy Marketing NA Inc./WSPP A 391,432 391,432 0 0 0 0 0 0 SUEZ Energy Marketing NA Inc./WSPP B 2,555,470 2,541,792 0 0 0 0 13,678 0 TEA/WSPP A 50,443 50,443 0 0 0 0 0 0 TENASKA FRONTIER/EXS50 3,714 3,714 0 0 0 0 0 0 TENASKA FRONTIER/EXS75 2,912 2,912 0 0 0 0 0 0 TENASKA FRONTIER/EXS90 47,232 47,232 0 0 0 0 0 0 TENASKA/WSPP A 106,266 104,270 0 0 626 0 1,370 0 TENASKA/WSPP B 1,041,808 480,385 0 554,729 0 0 6,694 0 UNION POWER PARTNERS/WSPP A 8,588 8,588 0 0 0 0 0 0 UNION POWER PARTNERS/WSPP B 7,446,119 7,415,760 0 0 0 0 30,359 0 WESTAR ENERGY NC/WSPP A 313,419 313,419 0 0 0 0 0 0 WESTAR ENERGY NC/WSPP B 1,335,662 1,335,162 0 0 0 0 500 0 WESTAR ENERGY NC/WSPP C 36,160 10,120 0 25,251 789 0 0 0 WRIGHTSVILE POWER/EXS75 1,675 1,675 0 0 0 0 0 0 WRIGHTSVILE POWER/EXS90 36,734 36,734 0 0 0 0 0 0 YAZOO CITY/EXS90 237 237 0 0 0 0 0 0 Un-accounted In 865 865 0 0 0 0 0 0 Exchange 45,025,369 44,705,819 0 0 319,102 0 0 448 INADVERTENT N 692,014 692,014 0 0 0 0 0 0 Totals 587,352,718 554,353,844 0 31,587,544 978,872 0 431,606 852

Attachment Snapshot: 20100826181933 RunID: 17029 Billing Snapshot: 20100826175238

2011 ETI Rate Case 9-173 Exhibit PJC-2 2011 TX Rate Case Page 12 of 70

Entergy Electric System Date range - 20100701 through 20100731 Attachment 1 Intra-System Billing-201007RA KWH Log Sheet Reconciliation - Entergy Gulf States Louisiana, LLC Page 12 Company Net Gen To Area UPP Exchange Inadvertent Firm Sales Sys Sales Unacct AEP SERVICE CORP /MINDEN PAYBACK (471,276) (471,276) 0 0 0 0 0 0 CALDWELL IMBAL IN 247,500 247,500 0 0 0 0 0 0 CALDWELL IMBAL OT (446) (446) 0 0 0 0 0 0 CALP NE A BASE IN 137,098,200 137,098,200 0 0 0 0 0 0 CALP NE B BASE IN 98,223,400 98,142,376 0 71,559 9,465 0 0 0 CALP NE C BASE IN 5,787,100 5,787,100 0 0 0 0 0 0 CALP NE B RAMP IN 1,973,300 1,973,300 0 0 0 0 0 0 CALP NE C RAMP IN 34,100 34,100 0 0 0 0 0 0 CALP NE EXCESS N 422,000 422,000 0 0 0 0 0 0 CLEC - RICHARDLOSSES 279,000 279,000 0 0 0 0 0 0 CLECO/TOLEDO BEND (1,206,925) (1,206,925) 0 0 0 0 0 0 COG Sale Losses N 173,685 173,685 0 0 0 0 0 0 GIS Imbalance IN 237,396 237,396 0 0 0 0 0 0 GIS Imbalance OT (243,779) (243,779) 0 0 0 0 0 0 IPP Sale Losses N 1,625,895 1,625,895 0 0 0 0 0 0 JAS loss N 383 383 0 0 0 0 0 0 KIRBYVILLE IMBAL IN 117,953 117,953 0 0 0 0 0 0 KIRBYVILLE IMBAL OT (1,205) (1,205) 0 0 0 0 0 0 NEWTON IMBAL IN 189,491 189,491 0 0 0 0 0 0 NEWTON IMBAL OT (116) (116) 0 0 0 0 0 0 ARK.NU 1/NUCLEAR 15,851,160 15,851,160 0 0 0 0 0 0 ARK.NU 2/NUCLEAR 18,809,417 18,809,417 0 0 0 0 0 0 CALCAS EU 1 4,690,725 0 4,690,725 0 0 0 0 0 CALCAS EU 1/Aux (332,000) (332,000) 0 0 0 0 0 0 CALCAS EU 1/GSPL E 5,798,159 1,980,749 0 3,714,474 102,936 0 0 0 CALCAS EU 1/GSPL I 548,116 0 0 548,116 0 0 0 0 CALCAS EU 2 5,250,450 0 5,250,450 0 0 0 0 0 CALCAS EU 2/GSPL E 7,103,550 4,163,301 0 2,906,170 34,079 0 0 0 GGULF RET 11,616,357 11,616,357 0 0 0 0 0 0 GGULF RP 5,876,574 5,876,574 0 0 0 0 0 0 LEWIS CREEK 1/COPANO E 4,754,332 2,871,914 0 1,879,528 2,890 0 0 0 LEWIS CREEK 1/COPANO M 27,587,139 16,462,009 0 10,925,536 184,068 0 15,337 189 LEWIS CREEK 1/TETCO E 6,385,297 4,739,291 0 1,521,741 117,176 0 6,900 189 LEWIS CREEK 1/TETCO I 2,320,478 1,154,988 0 1,157,040 8,450 0 0 0 LEWIS CREEK 1/TETCO M 17,169,779 13,456,160 0 3,647,410 64,331 0 1,878 0 LEWIS CREEK 2/COPANO E 6,018,572 5,010,477 0 926,721 81,364 0 10 0 LEWIS CREEK 2/COPANO M 6,495,036 2,992,409 0 3,483,050 18,869 0 519 189 LEWIS CREEK 2/TEJAS E 1,084,656 942,834 0 141,822 0 0 0 0 LEWIS CREEK 2/TETCO E 27,574,206 26,009,942 0 1,536,278 15,490 0 12,307 189 LEWIS CREEK 2/TETCO I 8,137,353 6,515,658 0 1,582,353 37,936 0 1,239 167 LEWIS CREEK 2/TETCO M 16,415,552 10,969,861 0 5,315,248 116,297 0 13,767 379 NELSON 3 5,192,225 0 5,192,225 0 0 0 0 0 NELSON 3/Aux (443,000) (443,000) 0 0 0 0 0 0 NELSON 3/TARGA E 284,050 71,574 0 211,896 580 0 0 0 NELSON 3/TENN M 2,091,290 322,313 0 1,700,865 68,112 0 0 0 NELSON 3/TETCO E 346,150 13,227 0 310,513 22,410 0 0 0 NELSON 3/TETCO M 4,303,285 113,170 0 4,149,185 40,930 0 0 0 NELSON 4 62,280,775 0 62,280,775 0 0 0 0 0 NELSON 4/Aux (1,398,000) (1,398,000) 0 0 0 0 0 0 NELSON 4/FLORIDA E 8,300,163 1,243,147 0 7,000,169 56,847 0 0 0 NELSON 4/TARGA E 19,008,705 4,409,283 0 14,524,924 74,498 0 0 0 NELSON 4/TENN E 16,820,496 4,323,987 0 12,398,148 98,361 0 0 0 NELSON 4/TENN M 12,742,940 1,116,094 0 11,564,685 61,325 0 836 0 NELSON 4/TETCO E 850,947 154,177 0 673,803 22,967 0 0 0 NELSON 4/TETCO I 4,447,488 342,815 0 4,071,417 33,255 0 1 0 NELSON 4/TETCO M 22,091,486 1,025,802 0 20,958,943 86,765 0 19,976 0 NELSON 6/GSU COAL 151,437,989 151,437,989 0 0 0 0 0 0 OUACHITA 3/SIGCO I 7,773,099 7,773,099 0 0 0 0 0 0 OUACHITA 3/SIGPL E 33,557,901 33,557,901 0 0 0 0 0 0 PERVIL 1 82,838,753 0 82,838,753 0 0 0 0 0 PERVIL 1/TENN E 90,584,771 90,584,771 0 0 0 0 0 0 PERVIL 1/TENN I 10,157,373 10,157,373 0 0 0 0 0 0 PERVIL 1/TEXAS GAS E 11,333,603 11,333,603 0 0 0 0 0 0 RVRBND 1 416,923,129 0 416,923,129 0 0 0 0 0 RVRBND 1/Aux (636,000) (636,000) 0 0 0 0 0 0 RVRBND 1/NUCLEAR 280,855,871 280,855,871 0 0 0 0 0 0 SABINE 1/CENTANA#3 E 1,991,296 1,428,431 0 528,309 34,556 0 0 0 SABINE 1/CENTANA#3 M 14,139,569 2,927,977 0 11,158,610 52,407 0 575 0 SABINE 1/ENBRIDGE E 7,109,237 4,073,972 0 2,981,642 53,617 0 6 0 SABINE 1/ENBRIDGE M 19,334,191 5,734,266 0 13,526,870 59,310 0 13,745 0 SABINE 1/HPL/CH E 2,454,586 1,411,802 0 988,225 54,559 0 0 0 SABINE 1/STORAGE I 3,963,609 2,456,407 0 1,426,945 80,257 0 0 0 SABINE 1/TEJAS E 132,959 11,300 0 121,659 0 0 0 0 SABINE 1/TEJAS M 2,020,803 1,063,465 0 947,156 10,182 0 0 0 SABINE 2/CENTANA#3 E 1,067,826 975,918 0 91,908 0 0 0 0 Attachment Snapshot: 20100826181933 RunID: 17029 Billing Snapshot: 20100826175238

2011 ETI Rate Case 9-174 Exhibit PJC-2 2011 TX Rate Case Page 13 of 70

Entergy Electric System Date range - 20100701 through 20100731 Attachment 1 Intra-System Billing-201007RA KWH Log Sheet Reconciliation - Entergy Gulf States Louisiana, LLC Page 13 Company Net Gen To Area UPP Exchange Inadvertent Firm Sales Sys Sales Unacct SABINE 2/CENTANA#3 M 1,640,764 962,855 0 664,972 12,937 0 0 0 SABINE 2/ENBRIDGE E 18,075,411 17,296,375 0 692,152 71,934 0 14,950 0 SABINE 2/ENBRIDGE M 15,307,706 8,209,508 0 7,036,036 60,197 0 1,398 567 SABINE 2/STORAGE I 10,780,443 10,735,018 0 44,850 0 0 575 0 SABINE 2/TEJAS M 3,689,900 2,689,320 0 908,661 91,919 0 0 0 SABINE 3/CENTANA#3 E 2,359,458 1,271,924 0 1,060,597 26,937 0 0 0 SABINE 3/CENTANA#3 M 26,532,333 10,193,621 0 16,217,549 117,137 0 4,026 0 SABINE 3/ENBRIDGE E 11,275,875 8,080,644 0 3,103,193 91,859 0 179 0 SABINE 3/ENBRIDGE M 26,260,809 13,818,877 0 12,241,869 199,424 0 71 568 SABINE 3/HPL/CH E 1,994,197 1,664,112 0 326,498 3,587 0 0 0 SABINE 3/STORAGE I 61,879 51,555 0 10,324 0 0 0 0 SABINE 3/TEJAS E 2,651,427 1,706,812 0 925,496 18,930 0 0 189 SABINE 3/TEJAS M 8,961,522 1,724,865 0 7,186,222 49,860 0 575 0 SABINE 4/CENTANA#3 M 9,048,063 8,594,274 0 453,221 568 0 0 0 SABINE 4/ENBRIDGE E 28,033,463 25,240,374 0 2,601,263 191,251 0 575 0 SABINE 4/ENBRIDGE M 19,827,303 17,470,401 0 2,257,273 99,607 0 0 22 SABINE 4/HPL/CH E 1,071,225 923,196 0 123,231 24,798 0 0 0 SABINE 4/STORAGE I 13,195,044 12,757,477 0 354,533 83,034 0 0 0 SABINE 4/TEJAS M 4,992,852 4,447,031 0 540,521 5,300 0 0 0 SABINE 5/CENTANA#3 M 14,674,847 1,675,960 0 12,993,537 5,338 0 12 0 SABINE 5/ENBRIDGE E 4,577,833 961,570 0 3,605,523 10,551 0 0 189 SABINE 5/ENBRIDGE M 3,761,796 42,310 0 3,707,371 12,115 0 0 0 SABINE 5/HPL/CH E 2,185,515 119,242 0 2,059,458 6,815 0 0 0 SABINE 5/TEJAS E 1,859,403 210,670 0 1,643,812 4,921 0 0 0 SABINE 5/TEJAS M 43,874,331 4,833,677 0 38,907,022 133,443 0 0 189 TOLEDO 1/HYDRO 3,875,207 3,875,207 0 0 0 0 0 0 WILLOW GLEN 1 5,445,950 0 5,445,950 0 0 0 0 0 WILLOW GLEN 1/Aux (8,000) (8,000) 0 0 0 0 0 0 WILLOW GLEN 1/BL HOLDINGS E 7,368,050 282,945 0 7,061,062 24,043 0 0 0 WILLOW GLEN 2 10,391,250 0 10,391,250 0 0 0 0 0 WILLOW GLEN 2/Aux (313,000) (313,000) 0 0 0 0 0 0 WILLOW GLEN 2/BL HOLDINGS E 14,058,750 747,921 0 13,042,792 265,448 0 2,589 0 WILLOW GLEN 3/Aux (218,000) (218,000) 0 0 0 0 0 0 WILLOW GLEN 4 77,447,750 0 77,447,750 0 0 0 0 0 WILLOW GLEN 4/Aux (193,000) (193,000) 0 0 0 0 0 0 WILLOW GLEN 4/BL HOLDINGS E 104,782,250 35,620,086 0 68,607,715 551,523 0 2,358 568 WILLOW GLEN 5/Aux (203,000) (203,000) 0 0 0 0 0 0 INDEPN 1/COAL 4,526,010 4,526,010 0 0 0 0 0 0 WH.BLF 1/COAL 8,331,086 8,331,086 0 0 0 0 0 0 WH.BLF 2/COAL 7,011,078 7,011,078 0 0 0 0 0 0 AECC Excess BAILEY 1 46,025 20,538 0 24,335 1,152 0 0 0 AECC Excess INDEPN 2 13,248 13,248 0 0 0 0 0 0 AECC Excess MCCLEL 1 3,021,702 211,103 0 2,792,163 18,436 0 0 0 AECC Excess WH.BLF 1 1,364,211 1,364,211 0 0 0 0 0 0 AECC Excess WH.BLF 2 6,660,472 6,660,472 0 0 0 0 0 0 ACADIA POWER PARTNERS, LLC/WSPP 59,708,320 59,675,508 0 0 0 0 32,812 0 AECI/WSPP A 458,259 458,259 0 0 0 0 0 0 AECI/WSPP B 3,830,000 3,830,000 0 0 0 0 0 0 AECI/WSPP C SYSTEM FIRM 8,823,362 5,646,503 0 3,173,844 0 0 3,015 0 AEP SERVICE CORP /WSPP A 574,500 574,500 0 0 0 0 0 0 AEP SERVICE CORP /WSPP C 153,200 153,200 0 0 0 0 0 0 AGRILECTRIC/QF 5,310,500 5,297,791 0 12,709 0 0 0 0 AIR LIQUIDE AMERICA/QF 512,000 512,000 0 0 0 0 0 0 AMEREN ENERGY NC. (AE) ACTING 459,600 153,200 0 304,529 0 0 1,871 0 Ameren Energy Marketing Company/WSPP 9,575 9,575 0 0 0 0 0 0 BNP PARIBAS ENERGY TRADING 38,300 38,300 0 0 0 0 0 0 BNP PARIBAS ENERGY TRADING 737,083 675,803 0 61,280 0 0 0 0 CALP NE ENERGY SERVICES L.P./WSPP 2,558,432 2,343,869 0 193,011 7,415 0 14,137 0 CARGILL POWER MARKETS LLC/WSPP A 320,760 320,760 0 0 0 0 0 0 CITIGROUP ENERGY NC/WSPP A 45,959 45,959 0 0 0 0 0 0 CLECO/WSPP B 961,242 49,715 0 830,943 4,096 0 76,488 0 CONOCOPH LLIPS COMPANY /INTRA- 1,969,375 287,500 0 1,681,875 0 0 0 0 CONSTELLATION ENERGY 34,469 34,469 0 0 0 0 0 0 CONSTELLATION ENERGY 1,041,185 1,040,557 0 0 0 0 628 0 COTTONWOOD ENERGY CO/EXS50 38,172 38,172 0 0 0 0 0 0 COTTONWOOD ENERGY CO/EXS75 9,218 9,218 0 0 0 0 0 0 COTTONWOOD ENERGY CO/EXS90 402,325 402,325 0 0 0 0 0 0 COTTONWOOD ENERGY CO/EXSSS50 2,330 2,330 0 0 0 0 0 0 COTTONWOOD ENERGY CO/EXSSTSH 266,318 266,318 0 0 0 0 0 0 CYPRES/EXS50 3,667 3,667 0 0 0 0 0 0 CYPRES/EXS75 201 201 0 0 0 0 0 0 CYPRES/EXS90 24,238 24,238 0 0 0 0 0 0 DB ENERGY TRAD NG LLC/WSPP B 19,804,486 17,993,200 0 1,654,147 54,752 0 102,387 0 DOW CHEMICAL/QF 227,204,450 227,080,662 0 123,788 0 0 0 0 DOW P PELINE COMPANY/INTRA-DAY 2,127,500 0 0 2,116,638 0 0 10,862 0 Attachment Snapshot: 20100826181933 RunID: 17029 Billing Snapshot: 20100826175238

2011 ETI Rate Case 9-175 Exhibit PJC-2 2011 TX Rate Case Page 14 of 70

Entergy Electric System Date range - 20100701 through 20100731 Attachment 1 Intra-System Billing-201007RA KWH Log Sheet Reconciliation - Entergy Gulf States Louisiana, LLC Page 14 Company Net Gen To Area UPP Exchange Inadvertent Firm Sales Sys Sales Unacct DUKE ENERGY HINDS/EXS50 21,701 21,701 0 0 0 0 0 0 DUKE ENERGY HINDS/EXS75 15,831 15,831 0 0 0 0 0 0 DUKE ENERGY HINDS/EXS90 165,827 165,827 0 0 0 0 0 0 DUKEENERGY HOTSPRING/EXS50 26,842 26,842 0 0 0 0 0 0 DUKEENERGY HOTSPRING/EXS75 16,148 16,148 0 0 0 0 0 0 DUKEENERGY HOTSPRING/EXS90 140,121 140,121 0 0 0 0 0 0 DUKEENERGY HOTSPRING/FREE 144 144 0 0 0 0 0 0 ENDURE ENERGY/WSPP A 260,432 224,289 0 35,043 0 0 1,100 0 ENDURE ENERGY/WSPP B 12,447 12,447 0 0 0 0 0 0 ETEC/WSPP B 224,050 224,050 0 0 0 0 0 0 EXELON GENERATION COMPANY 17,906,524 17,818,311 0 53,551 6,436 0 28,226 0 EXXON ENCO/QF 21,120,565 21,120,565 0 0 0 0 0 0 EXXON ESSO/QF 7,447,850 7,447,850 0 0 0 0 0 0 EXXON EXXON/QF 5,300,520 5,300,520 0 0 0 0 0 0 FORMOSA PLASTICS/QF 1,778,370 1,778,370 0 0 0 0 0 0 GAPACIFIC/QF 165,150 165,150 0 0 0 0 0 0 J ARON & COMPANY/WSPP B 4,571,051 2,465,103 0 2,095,052 0 0 10,896 0 J.P. MORGAN VENTURES ENERGY 12,830 12,830 0 0 0 0 0 0 J.P. MORGAN VENTURES ENERGY 935,473 0 0 828,870 0 0 106,603 0 JBO/WSPP A 1,851,983 0 0 1,609,650 0 0 242,333 0 JBO/WSPP B 1,988,687 803,309 0 1,137,518 0 0 47,860 0 KANSAS CITY POWER & LIGHT 275,952 275,952 0 0 0 0 0 0 MAGNET COVE/EXS75 3,251 3,251 0 0 0 0 0 0 MAGNET COVE/EXS90 150,472 150,472 0 0 0 0 0 0 MAGNET COVE/EXSSTSH 827,228 827,228 0 0 0 0 0 0 MDEA CROSSROADS/EXS50 4,443 4,443 0 0 0 0 0 0 MDEA CROSSROADS/EXS75 896 896 0 0 0 0 0 0 MDEA CROSSROADS/EXS90 31,427 31,427 0 0 0 0 0 0 MERRILL LYNCH COMMODITIES 37,164,138 36,370,473 0 513,751 67,902 0 212,012 0 MORGAN STANLEY/WSPP A 47,110 47,110 0 0 0 0 0 0 NRG CAJUN 3/CAJUN 3 95,955,425 95,955,425 0 0 0 0 0 0 NRG POWER MARKETING LLC./WSPP A 5,701,912 5,414,662 0 287,250 0 0 0 0 NRG POWER MARKETING LLC./WSPP B 35,405,012 31,125,729 0 3,866,468 57,925 0 354,890 0 NRG POWER MARKETING LLC./WSPP C 1,596,150 1,014,374 0 576,051 0 0 5,725 0 OCCIDENTAL POWER SERVICES/WSPP 1,091,166 162,610 0 860,110 8,372 0 60,074 0 PPG INDUSTR ES/QF 169,586,800 169,586,800 0 0 0 0 0 0 RAINBOW ENERGY MARKETING 2,666,424 2,649,436 0 16,988 0 0 0 0 SHELL WOODSTOCK/QF 13,180,862 13,165,150 0 0 15,712 0 0 0 SMEPA/WSPP B 574,496 0 0 569,717 0 0 4,779 0 SOUTHERN COMPANY SERVICES INC. 105,325 105,325 0 0 0 0 0 0 SOUTHERN COMPANY SERVICES INC. 2,029,900 0 0 1,771,646 0 0 258,254 0 SUEZ Energy Marketing NA Inc./WSPP A 1,658,371 1,658,371 0 0 0 0 0 0 SUEZ Energy Marketing NA Inc./WSPP B 10,826,823 10,663,125 0 87,489 18,262 0 57,947 0 TEA/WSPP A 213,711 213,711 0 0 0 0 0 0 TENASKA FRONTIER/EXS50 15,731 15,731 0 0 0 0 0 0 TENASKA FRONTIER/EXS75 12,343 12,343 0 0 0 0 0 0 TENASKA FRONTIER/EXS90 200,195 200,195 0 0 0 0 0 0 TENASKA/WSPP A 450,215 190,542 0 253,868 0 0 5,805 0 TENASKA/WSPP B 4,413,862 1,602,890 0 2,782,607 0 0 28,365 0 UNION POWER PARTNERS/WSPP A 36,384 36,384 0 0 0 0 0 0 UNION POWER PARTNERS/WSPP B 31,547,047 30,407,933 0 993,273 17,226 0 128,615 0 Un-accounted In 3,652 3,652 0 0 0 0 0 0 WESTAR ENERGY NC/WSPP A 1,327,853 1,327,853 0 0 0 0 0 0 WESTAR ENERGY NC/WSPP B 5,658,817 5,558,739 0 97,958 0 0 2,120 0 WESTAR ENERGY NC/WSPP C 153,200 0 0 153,200 0 0 0 0 WRIGHTSVILE POWER/EXS75 7,107 7,107 0 0 0 0 0 0 WRIGHTSVILE POWER/EXS90 155,716 155,716 0 0 0 0 0 0 YAZOO CITY/EXS90 1,011 1,011 0 0 0 0 0 0 Exchange 8,681,301 8,681,301 0 0 0 0 0 0 INADVERTENT N 2,931,814 2,931,814 0 0 0 0 0 0 Totals 3,103,786,681 2,038,635,428 670,461,007 388,628,993 4,145,451 0 1,912,208 3,594

Attachment Snapshot: 20100826181933 RunID: 17029 Billing Snapshot: 20100826175238

2011 ETI Rate Case 9-176 Exhibit PJC-2 2011 TX Rate Case Page 15 of 70

Entergy Electric System Date range - 20100701 through 20100731 Attachment 1 Intra-System Billing-201007RA KWH Log Sheet Reconciliation - Entergy Texas, Inc Page 15 Company Net Gen To Area UPP Exchange Inadvertent Firm Sales Sys Sales Unacct AEP SERVICE CORP /MINDEN PAYBACK (412,346) (412,346) 0 0 0 0 0 0 CALDWELL IMBAL IN 211,422 211,422 0 0 0 0 0 0 CALDWELL IMBAL OT (390) (390) 0 0 0 0 0 0 CLECO/TOLEDO BEND (892,075) (892,075) 0 0 0 0 0 0 COG Sale Losses N 148,409 148,409 0 0 0 0 0 0 CYPRESS - ETEC 1,057,000 1,057,000 0 0 0 0 0 0 EPMCNELSON6 - CLEC (774,000) (774,000) 0 0 0 0 0 0 EPMCNELSON6 - CNWY (10,000) (10,000) 0 0 0 0 0 0 EPMCNELSON6 - DERS (10,000) (10,000) 0 0 0 0 0 0 EPMCNELSON6 - MDEA (1,018,000) (1,018,000) 0 0 0 0 0 0 EPMCNELSON6 - SOCO (78,000) (78,000) 0 0 0 0 0 0 EPMCNELSON6 - SWPP (3,294,000) (3,294,000) 0 0 0 0 0 0 ETEC EXCESS-CONTRAOT (4,937) (4,937) 0 0 0 0 0 0 ETEC EXCESS-HRSNHRDN 4,937 4,937 0 0 0 0 0 0 ETI SALE TO ETEC IN 87,385,599 87,385,599 0 0 0 0 0 0 EXELON FRONT ER 10YR 93,424,000 93,424,000 0 0 0 0 0 0 GIS Imbalance IN 202,815 202,815 0 0 0 0 0 0 GIS Imbalance OT (213,386) (213,386) 0 0 0 0 0 0 HARDIN 9,029,000 9,029,000 0 0 0 0 0 0 INTERNAL LOAD IN 21,576,000 21,576,000 0 0 0 0 0 0 IPP Sale Losses N 1,389,104 1,389,104 0 0 0 0 0 0 JAS loss N 327 327 0 0 0 0 0 0 KIRBYVILLE IMBAL IN 100,758 100,758 0 0 0 0 0 0 KIRBYVILLE IMBAL OT (1,053) (1,053) 0 0 0 0 0 0 NEWTON IMBAL IN 161,878 161,878 0 0 0 0 0 0 NEWTON IMBAL OT (102) (102) 0 0 0 0 0 0 RSCOGEN - SRMPA 8,470,000 8,470,000 0 0 0 0 0 0 SAN JACINTO 1 5,722,000 5,722,000 0 0 0 0 0 0 SAN JACINTO 2 5,612,000 5,612,000 0 0 0 0 0 0 SR ACT LOAD OT (208,678,469) (208,678,469) 0 0 0 0 0 0 SR ACT LOAD IN ETI 27,893,256 27,893,256 0 0 0 0 0 0 SRMA LOAD OT (37,747,524) (37,747,524) 0 0 0 0 0 0 SWPP - ETEC 20,505,000 20,505,000 0 0 0 0 0 0 ARK.NU 1/NUCLEAR 16,654,966 16,654,966 0 0 0 0 0 0 ARK.NU 2/NUCLEAR 19,768,134 19,768,134 0 0 0 0 0 0 CALCAS EU 1/GSPL E 4,285,611 4,285,611 0 0 0 0 0 0 CALCAS EU 1/GSPL I 405,114 405,114 0 0 0 0 0 0 CALCAS EU 2/GSPL E 5,250,450 5,250,450 0 0 0 0 0 0 GGULF RET 12,205,279 12,205,279 0 0 0 0 0 0 GGULF RP 6,173,783 6,173,783 0 0 0 0 0 0 LEWIS CREEK 1 58,217,025 0 58,217,025 0 0 0 0 0 LEWIS CREEK 1/COPANO E 3,513,838 3,513,838 0 0 0 0 0 0 LEWIS CREEK 1/COPANO M 20,390,449 20,379,112 0 0 0 0 11,337 0 LEWIS CREEK 1/TETCO E 4,719,555 4,714,455 0 0 0 0 5,100 0 LEWIS CREEK 1/TETCO I 1,715,190 1,715,190 0 0 0 0 0 0 LEWIS CREEK 1/TETCO M 12,690,943 12,689,556 0 0 0 0 1,387 0 LEWIS CREEK 2 65,725,375 0 65,725,375 0 0 0 0 0 LEWIS CREEK 2/Aux (9,000) (9,000) 0 0 0 0 0 0 LEWIS CREEK 2/COPANO E 4,448,495 4,448,487 0 0 0 0 8 0 LEWIS CREEK 2/COPANO M 4,800,621 4,800,236 0 0 0 0 385 0 LEWIS CREEK 2/TEJAS E 801,683 801,683 0 0 0 0 0 0 LEWIS CREEK 2/TETCO E 20,380,744 20,371,648 0 0 0 0 9,096 0 LEWIS CREEK 2/TETCO I 6,014,580 6,013,664 0 0 0 0 916 0 LEWIS CREEK 2/TETCO M 12,133,502 12,123,325 0 0 0 0 10,177 0 NELSON 3/TARGA E 209,950 207,485 0 0 2,465 0 0 0 NELSON 3/TENN M 1,545,767 1,401,589 0 0 144,178 0 0 0 NELSON 3/TETCO E 255,850 101,536 0 0 154,314 0 0 0 NELSON 3/TETCO M 3,180,658 2,478,395 0 0 702,263 0 0 0 NELSON 4/FLORIDA E 6,135,214 6,087,711 0 47,337 0 0 0 166 NELSON 4/TARGA E 14,050,111 13,926,196 0 121,380 2,535 0 0 0 NELSON 4/TENN E 12,432,537 12,414,755 0 17,782 0 0 0 0 NELSON 4/TENN M 9,418,739 9,253,513 0 57,443 107,165 0 618 0 NELSON 4/TETCO E 628,945 626,428 0 0 2,517 0 0 0 NELSON 4/TETCO I 3,287,176 3,287,175 0 0 0 0 1 0 NELSON 4/TETCO M 16,328,053 15,846,269 0 177,010 290,009 0 14,765 0 NELSON 6/GSU COAL 224,805,011 224,805,011 0 0 0 0 0 0 PERVIL 1/TENN E 66,954,359 66,954,359 0 0 0 0 0 0 PERVIL 1/TENN I 7,507,634 7,507,634 0 0 0 0 0 0 PERVIL 1/TEXAS GAS E 8,376,760 8,376,760 0 0 0 0 0 0 RVRBND 1/NUCLEAR 207,589,429 207,589,429 0 0 0 0 0 0 SABINE 1 51,146,250 0 51,146,250 0 0 0 0 0 SABINE 1/Aux (183,000) (183,000) 0 0 0 0 0 0 SABINE 1/CENTANA#3 E 1,471,820 1,471,820 0 0 0 0 0 0 SABINE 1/CENTANA#3 M 10,450,916 10,449,828 0 0 0 0 425 663 SABINE 1/ENBRIDGE E 5,254,580 5,254,575 0 0 0 0 5 0 Attachment Snapshot: 20100826181933 RunID: 17029 Billing Snapshot: 20100826175238

2011 ETI Rate Case 9-177 Exhibit PJC-2 2011 TX Rate Case Page 16 of 70

Entergy Electric System Date range - 20100701 through 20100731 Attachment 1 Intra-System Billing-201007RA KWH Log Sheet Reconciliation - Entergy Texas, Inc Page 16 Company Net Gen To Area UPP Exchange Inadvertent Firm Sales Sys Sales Unacct SABINE 1/ENBRIDGE M 14,290,597 14,280,438 0 0 0 0 10,159 0 SABINE 1/HPL/CH E 1,814,305 1,814,305 0 0 0 0 0 0 SABINE 1/STORAGE I 2,929,631 2,929,631 0 0 0 0 0 0 SABINE 1/TEJAS E 98,285 98,285 0 0 0 0 0 0 SABINE 1/TEJAS M 1,493,616 1,493,616 0 0 0 0 0 0 SABINE 2 50,562,050 0 50,562,050 0 0 0 0 0 SABINE 2/CENTANA#3 E 789,282 789,282 0 0 0 0 0 0 SABINE 2/CENTANA#3 M 1,212,690 1,212,690 0 0 0 0 0 0 SABINE 2/ENBRIDGE E 13,360,029 13,348,979 0 0 0 0 11,050 0 SABINE 2/ENBRIDGE M 11,314,406 11,313,373 0 0 0 0 1,033 0 SABINE 2/STORAGE I 7,968,187 7,967,762 0 0 0 0 425 0 SABINE 2/TEJAS M 2,727,356 2,727,356 0 0 0 0 0 0 SABINE 3 80,097,500 0 80,097,500 0 0 0 0 0 SABINE 3/CENTANA#3 E 1,743,891 1,743,891 0 0 0 0 0 0 SABINE 3/CENTANA#3 M 19,610,652 19,607,345 0 0 0 0 2,976 331 SABINE 3/ENBRIDGE E 8,334,248 8,334,115 0 0 0 0 133 0 SABINE 3/ENBRIDGE M 19,410,359 19,410,307 0 0 0 0 52 0 SABINE 3/HPL/CH E 1,473,991 1,473,991 0 0 0 0 0 0 SABINE 3/STORAGE I 45,749 45,749 0 0 0 0 0 0 SABINE 3/TEJAS E 1,959,750 1,959,750 0 0 0 0 0 0 SABINE 3/TEJAS M 6,623,860 6,623,435 0 0 0 0 425 0 SABINE 4 76,167,950 0 76,167,950 0 0 0 0 0 SABINE 4/Aux (510,000) (510,000) 0 0 0 0 0 0 SABINE 4/CENTANA#3 M 6,687,645 6,687,645 0 0 0 0 0 0 SABINE 4/ENBRIDGE E 20,720,155 20,719,730 0 0 0 0 425 0 SABINE 4/ENBRIDGE M 14,655,058 14,655,058 0 0 0 0 0 0 SABINE 4/HPL/CH E 791,784 791,784 0 0 0 0 0 0 SABINE 4/STORAGE I 9,753,002 9,753,002 0 0 0 0 0 0 SABINE 4/TEJAS M 3,690,406 3,690,406 0 0 0 0 0 0 SABINE 5 70,933,725 0 70,933,725 0 0 0 0 0 SABINE 5/CENTANA#3 M 10,846,322 10,846,314 0 0 0 0 8 0 SABINE 5/ENBRIDGE E 3,383,577 3,383,577 0 0 0 0 0 0 SABINE 5/ENBRIDGE M 2,780,434 2,780,434 0 0 0 0 0 0 SABINE 5/HPL/CH E 1,615,404 1,615,404 0 0 0 0 0 0 SABINE 5/TEJAS E 1,374,341 1,374,341 0 0 0 0 0 0 SABINE 5/TEJAS M 32,429,197 32,423,416 0 0 5,781 0 0 0 SAMRAY 1_2/Aux (134,000) (134,000) 0 0 0 0 0 0 SAMRAY 1_2/HYDRO 8,333,000 8,333,000 0 0 0 0 0 0 TOLEDO 1/HYDRO 2,864,293 2,864,293 0 0 0 0 0 0 TOWN B 1/HYDRO 3,105,000 3,105,000 0 0 0 0 0 0 WILLOW GLEN 1/BL HOLDINGS E 5,445,950 5,291,095 0 0 154,855 0 0 0 WILLOW GLEN 2/BL HOLDINGS E 10,391,250 8,907,191 0 569,266 912,881 0 1,912 0 WILLOW GLEN 4/BL HOLDINGS E 77,447,750 77,445,013 0 0 0 0 1,742 995 INDEPN 1/COAL 4,757,472 4,757,472 0 0 0 0 0 0 WH.BLF 1/COAL 8,755,797 8,755,797 0 0 0 0 0 0 WH.BLF 2/COAL 7,368,498 7,368,498 0 0 0 0 0 0 AECC Excess BAILEY 1 39,312 39,312 0 0 0 0 0 0 AECC Excess INDEPN 2 11,318 11,318 0 0 0 0 0 0 AECC Excess MCCLEL 1 2,581,467 2,581,467 0 0 0 0 0 0 AECC Excess WH.BLF 1 1,165,458 1,165,458 0 0 0 0 0 0 AECC Excess WH.BLF 2 5,690,108 5,690,108 0 0 0 0 0 0 AECI/WSPP A 391,495 391,495 0 0 0 0 0 0 AECI/WSPP B 3,272,000 3,272,000 0 0 0 0 0 0 AECI/WSPP C SYSTEM FIRM 7,537,870 7,445,246 0 43,518 46,531 0 2,575 0 AEP SERVICE CORP /WSPP A 490,800 490,800 0 0 0 0 0 0 AEP SERVICE CORP /WSPP C 130,880 130,880 0 0 0 0 0 0 AIR LIQUIDE MAGNOLIA/QF 202,615 202,615 0 0 0 0 0 0 AMEREN ENERGY NC. (AE) ACTING 392,640 391,043 0 0 0 0 1,597 0 Ameren Energy Marketing Company/WSPP 8,180 8,180 0 0 0 0 0 0 BASF CORPORATION/QF 4,486,070 4,486,070 0 0 0 0 0 0 BNP PARIBAS ENERGY TRADING 32,720 32,720 0 0 0 0 0 0 BNP PARIBAS ENERGY TRADING 629,696 629,696 0 0 0 0 0 0 CALP NE ENERGY SERVICES L.P./WSPP 2,185,696 2,173,624 0 0 0 0 12,072 0 CARGILL POWER MARKETS LLC/WSPP A 274,031 274,031 0 0 0 0 0 0 CARROLLSTPARK/QF 91,582,450 91,582,450 0 0 0 0 0 0 CITIGROUP ENERGY NC/WSPP A 39,264 39,264 0 0 0 0 0 0 CLECO/WSPP B 821,270 742,128 0 0 13,803 0 65,339 0 CONOCOPH LLIPS COMPANY /INTRA- 1,575,625 1,575,625 0 0 0 0 0 0 CONSTELLATION ENERGY 29,448 29,448 0 0 0 0 0 0 CONSTELLATION ENERGY 889,493 888,956 0 0 0 0 537 0 COTTONWOOD ENERGY CO/EXS50 32,612 32,612 0 0 0 0 0 0 COTTONWOOD ENERGY CO/EXS75 7,868 7,868 0 0 0 0 0 0 COTTONWOOD ENERGY CO/EXS90 343,686 343,686 0 0 0 0 0 0 COTTONWOOD ENERGY CO/EXSSS50 1,990 1,990 0 0 0 0 0 0 COTTONWOOD ENERGY CO/EXSSTSH 227,513 227,513 0 0 0 0 0 0 Attachment Snapshot: 20100826181933 RunID: 17029 Billing Snapshot: 20100826175238

2011 ETI Rate Case 9-178 Exhibit PJC-2 2011 TX Rate Case Page 17 of 70

Entergy Electric System Date range - 20100701 through 20100731 Attachment 1 Intra-System Billing-201007RA KWH Log Sheet Reconciliation - Entergy Texas, Inc Page 17 Company Net Gen To Area UPP Exchange Inadvertent Firm Sales Sys Sales Unacct CYPRES/EXS50 3,133 3,133 0 0 0 0 0 0 CYPRES/EXS75 172 172 0 0 0 0 0 0 CYPRES/EXS90 20,708 20,708 0 0 0 0 0 0 DB ENERGY TRAD NG LLC/WSPP B 16,919,189 16,831,732 0 0 0 0 87,457 0 DOW P PELINE COMPANY/INTRA-DAY 1,572,500 1,281,171 0 274,685 8,616 0 8,028 0 DUKE ENERGY HINDS/EXS50 18,538 18,538 0 0 0 0 0 0 DUKE ENERGY HINDS/EXS75 13,524 13,524 0 0 0 0 0 0 DUKE ENERGY HINDS/EXS90 141,631 141,631 0 0 0 0 0 0 DUKEENERGY HOTSPRING/EXS50 22,927 22,927 0 0 0 0 0 0 DUKEENERGY HOTSPRING/EXS75 13,806 13,806 0 0 0 0 0 0 DUKEENERGY HOTSPRING/EXS90 119,726 119,726 0 0 0 0 0 0 DUKEENERGY HOTSPRING/FREE 123 123 0 0 0 0 0 0 ENDURE ENERGY/WSPP A 222,491 221,552 0 0 0 0 939 0 ENDURE ENERGY/WSPP B 10,634 10,634 0 0 0 0 0 0 ENG. CARBONS NC/QF 2,020,069 2,020,069 0 0 0 0 0 0 ETEC/WSPP B 191,412 191,412 0 0 0 0 0 0 EXELON GENERATION COMPANY 15,297,742 15,273,636 0 0 0 0 24,106 0 GOODYEAR TIRE/QF 577,318 577,318 0 0 0 0 0 0 HUNTSMAN P.N./QF 74,401 74,401 0 0 0 0 0 0 J ARON & COMPANY/WSPP B 3,905,132 3,895,829 0 0 0 0 9,303 0 J.P. MORGAN VENTURES ENERGY 10,961 10,961 0 0 0 0 0 0 J.P. MORGAN VENTURES ENERGY 799,186 708,121 0 0 0 0 91,065 0 JBO/WSPP A 1,582,176 1,025,309 0 75,631 274,237 0 206,999 0 JBO/WSPP B 1,698,984 1,502,028 0 111,406 44,672 0 40,878 0 KANSAS CITY POWER & LIGHT 235,748 235,748 0 0 0 0 0 0 MAGNET COVE/EXS75 2,777 2,777 0 0 0 0 0 0 MAGNET COVE/EXS90 128,521 128,521 0 0 0 0 0 0 MAGNET COVE/EXSSTSH 706,713 706,713 0 0 0 0 0 0 MDEA CROSSROADS/EXS50 3,797 3,797 0 0 0 0 0 0 MDEA CROSSROADS/EXS75 768 768 0 0 0 0 0 0 MDEA CROSSROADS/EXS90 26,848 26,848 0 0 0 0 0 0 MERRILL LYNCH COMMODITIES 31,749,681 31,568,580 0 0 0 0 181,101 0 MORGAN STANLEY/WSPP A 40,246 40,246 0 0 0 0 0 0 NRG CAJUN 3/CAJUN 3 70,923,575 70,923,575 0 0 0 0 0 0 NRG POWER MARKETING LLC./WSPP A 4,871,190 4,638,871 0 225,360 6,959 0 0 0 NRG POWER MARKETING LLC./WSPP B 30,247,034 29,856,229 0 0 87,663 0 303,142 0 NRG POWER MARKETING LLC./WSPP C 1,363,606 1,353,747 0 0 4,971 0 4,888 0 OCCIDENTAL POWER SERVICES/WSPP 932,192 828,673 0 32,720 19,494 0 51,305 0 PREMCR/QF 376,760 376,760 0 0 0 0 0 0 RAINBOW ENERGY MARKETING 2,277,962 2,277,962 0 0 0 0 0 0 SABINE COGEN L P./QF 35,724,878 35,724,878 0 0 0 0 0 0 SMEPA/WSPP B 490,800 310,404 0 167,697 8,616 0 4,083 0 SOUTHERN COMPANY SERVICES INC. 89,980 89,980 0 0 0 0 0 0 SOUTHERN COMPANY SERVICES INC. 1,734,160 1,111,805 0 322,527 79,204 0 220,624 0 SRW COGENERATION/QF 49,808,910 49,808,910 0 0 0 0 0 0 SUEZ Energy Marketing NA Inc./WSPP A 1,416,776 1,416,776 0 0 0 0 0 0 SUEZ Energy Marketing NA Inc./WSPP B 9,249,460 9,199,959 0 0 0 0 49,501 0 TEA/WSPP A 182,578 182,578 0 0 0 0 0 0 TENASKA FRONTIER/EXS50 13,439 13,439 0 0 0 0 0 0 TENASKA FRONTIER/EXS75 10,544 10,544 0 0 0 0 0 0 TENASKA FRONTIER/EXS90 170,975 170,975 0 0 0 0 0 0 TENASKA/WSPP A 384,624 364,212 0 15,456 0 0 4,956 0 TENASKA/WSPP B 3,770,813 3,682,588 0 0 63,999 0 24,226 0 UNION POWER PARTNERS/WSPP A 31,084 31,084 0 0 0 0 0 0 UNION POWER PARTNERS/WSPP B 26,950,968 26,841,101 0 0 0 0 109,867 0 Un-accounted In 3,203 3,203 0 0 0 0 0 0 WESTAR ENERGY NC/WSPP A 1,134,394 1,134,394 0 0 0 0 0 0 WESTAR ENERGY NC/WSPP B 4,834,398 4,832,588 0 0 0 0 1,810 0 WESTAR ENERGY NC/WSPP C 130,880 130,880 0 0 0 0 0 0 WRIGHTSVILE POWER/EXS75 6,069 6,069 0 0 0 0 0 0 WRIGHTSVILE POWER/EXS90 133,010 133,010 0 0 0 0 0 0 YAZOO CITY/EXS90 863 863 0 0 0 0 0 0 Exchange 328,392,353 327,900,434 0 0 490,923 0 0 996 INADVERTENT N 2,504,716 2,504,716 0 0 0 0 0 0 Totals 2,373,774,114 1,913,442,261 452,849,875 2,259,218 3,628,651 0 1,590,958 3,151

Attachment Snapshot: 20100826181933 RunID: 17029 Billing Snapshot: 20100826175238

2011 ETI Rate Case 9-179 Exhibit PJC-2 2011 TX Rate Case Page 18 of 70

Entergy Electric System Date range - 20100701 through 20100731 Attachment 1 Intra-System Billing-201007RA KWH Energy Summary Page 18 Company Net Gen To Area UPP Exchange Inadvertent Firm Sales System Sales Unaccounted AR 3,068,221,822 2,534,515,289 395,462,556 131,743,223 4,583,474 0 1,913,306 3,974 LA 3,491,820,106 3,093,813,592 254,622,820 135,105,357 5,498,856 0 2,774,712 4,769 MS 1,669,714,232 1,633,071,080 0 32,027,550 3,063,696 0 1,549,246 2,660 NO 587,352,718 554,353,844 0 31,587,544 978,872 0 431,606 852 EGSL 3,103,786,681 2,038,635,428 670,461,007 388,628,993 4,145,451 0 1,912,208 3,594 ETI 2,373,774,114 1,913,442,261 452,849,875 2,259,218 3,628,651 0 1,590,958 3,151 Totals 14,294,669,673 11,767,831,494 1,773,396,258 721,351,885 21,899,000 0 10,172,036 19,000

Attachment Snapshot: 20100826181933 RunID: 17029 Billing Snapshot: 20100826175238

2011 ETI Rate Case 9-180 Exhibit PJC-2 2011 TX Rate Case Page 19 of 70

Entergy Electric System Date range - 20100701 through 20100731 Attachment 1 Intra-System Billing-201007RA Joint Account Purchases - KWH Page 19 Description System AR LA MS NO EGSL ETI AECI/WSPP A 2,393,000 499,659 601,840 333,584 108,163 458,259 391,495 AECI/WSPP B 20,000,000 4,176,000 5,030,000 2,788,000 904,000 3,830,000 3,272,000 AECI/WSPP C SYSTEM FIRM 46,075,000 9,620,460 11,587,863 6,422,855 2,082,590 8,823,362 7,537,870 AEP SERVICE CORP /WSPP A 3,000,000 626,400 754,500 418,200 135,600 574,500 490,800 AEP SERVICE CORP /WSPP C 800,000 167,040 201,200 111,520 36,160 153,200 130,880 AMEREN ENERGY NC. (AE) ACTING /WSPP C 2,400,000 501,120 603,600 334,560 108,480 459,600 392,640 AMEREN ENERGY MARKETING COMPANY/WSPP A 50,000 10,440 12,575 6,970 2,260 9,575 8,180 BNP PARIBAS ENERGY TRADING GP/WSPP A 200,000 41,760 50,300 27,880 9,040 38,300 32,720 BNP PARIBAS ENERGY TRADING GP/WSPP B 3,849,000 803,671 968,024 536,551 173,975 737,083 629,696 CALP NE ENERGY SERVICES L.P./WSPP B 13,360,000 2,789,568 3,360,048 1,862,384 603,872 2,558,432 2,185,696 CARGILL POWER MARKETS LLC/WSPP A 1,675,000 349,740 421,265 233,494 75,710 320,760 274,031 CITIGROUP ENERGY NC/WSPP A 240,000 50,112 60,361 33,456 10,848 45,959 39,264 CLECO/WSPP B 5,020,000 1,048,172 1,262,618 699,790 226,908 961,242 821,270 CONSTELLATION ENERGY COMMODITIES GROUP 180,000 37,584 45,271 25,092 8,136 34,469 29,448 CONSTELLATION ENERGY COMMODITIES GROUP 5,437,000 1,135,245 1,367,406 757,918 245,753 1,041,185 889,493 COTTONWOOD ENERGY CO/EXS50 199,330 41,619 50,135 27,787 9,005 38,172 32,612 COTTONWOOD ENERGY CO/EXS75 48,097 10,037 12,102 6,703 2,169 9,218 7,868 COTTONWOOD ENERGY CO/EXS90 2,100,765 438,669 528,321 292,830 94,934 402,325 343,686 COTTONWOOD ENERGY CO/EXSSS50 12,167 2,541 3,060 1,696 550 2,330 1,990 COTTONWOOD ENERGY CO/EXSSTSH 1,390,663 290,367 349,743 193,858 62,864 266,318 227,513 CYPRES/EXS50 19,150 3,999 4,816 2,669 866 3,667 3,133 CYPRES/EXS75 1,050 219 264 146 48 201 172 CYPRES/EXS90 126,581 26,430 31,833 17,648 5,724 24,238 20,708 DB ENERGY TRAD NG LLC/WSPP B 103,418,000 21,593,680 26,009,688 14,416,465 4,674,492 19,804,486 16,919,189 DUKE ENERGY HINDS/EXS50 113,319 23,661 28,499 15,797 5,123 21,701 18,538 DUKE ENERGY HINDS/EXS75 82,677 17,266 20,807 11,523 3,726 15,831 13,524 DUKE ENERGY HINDS/EXS90 865,808 180,827 217,804 120,648 39,071 165,827 141,631 DUKEENERGY HOTSPRING/EXS50 140,174 29,273 35,260 19,538 6,334 26,842 22,927 DUKEENERGY HOTSPRING/EXS75 84,365 17,619 21,226 11,762 3,804 16,148 13,806 DUKEENERGY HOTSPRING/EXS90 731,601 152,741 183,983 101,969 33,061 140,121 119,726 DUKEENERGY HOTSPRING/FREE 750 156 189 105 33 144 123 ENDURE ENERGY/WSPP A 1,360,000 283,965 342,048 189,589 61,475 260,432 222,491 ENDURE ENERGY/WSPP B 65,000 13,572 16,348 9,061 2,938 12,447 10,634 ETEC/WSPP B 1,170,000 244,298 294,260 163,098 52,882 224,050 191,412 EXELON GENERATION COMPANY LLC/DA LY CALL 93,507,000 19,524,239 23,517,077 13,034,879 4,226,539 17,906,524 15,297,742 J ARON & COMPANY/WSPP B 23,870,000 4,984,056 6,003,359 3,327,478 1,078,924 4,571,051 3,905,132 J.P. MORGAN VENTURES ENERGY 67,000 13,990 16,851 9,340 3,028 12,830 10,961 J.P. MORGAN VENTURES ENERGY 4,885,000 1,019,989 1,228,582 680,969 220,801 935,473 799,186 JBO/WSPP A 9,671,000 2,019,305 2,432,270 1,348,137 437,129 1,851,983 1,582,176 JBO/WSPP B 10,385,000 2,168,386 2,611,868 1,447,671 469,404 1,988,687 1,698,984 KANSAS CITY POWER & LIGHT COMPANY/WSPP A 1,441,000 300,881 362,411 200,875 65,133 275,952 235,748 MAGNET COVE/EXS75 16,976 3,545 4,270 2,366 767 3,251 2,777 MAGNET COVE/EXS90 785,651 164,007 197,598 109,555 35,498 150,472 128,521 MAGNET COVE/EXSSTSH 4,319,727 901,963 1,086,406 602,169 195,248 827,228 706,713 MDEA CROSSROADS/EXS50 23,211 4,846 5,838 3,235 1,052 4,443 3,797 MDEA CROSSROADS/EXS75 4,684 977 1,178 653 212 896 768 MDEA CROSSROADS/EXS90 164,075 34,261 41,256 22,867 7,416 31,427 26,848 MERRILL LYNCH COMMODITIES INC/WSPP B 194,069,000 40,521,612 48,808,429 27,053,226 8,771,914 37,164,138 31,749,681 MORGAN STANLEY/WSPP A 246,000 51,366 61,868 34,292 11,118 47,110 40,246 NRG POWER MARKETING LLC./WSPP A 29,775,000 6,217,020 7,488,413 4,150,635 1,345,830 5,701,912 4,871,190 NRG POWER MARKETING LLC./WSPP B 184,884,000 38,603,785 46,498,600 25,772,818 8,356,751 35,405,012 30,247,034 NRG POWER MARKETING LLC./WSPP C 8,335,000 1,740,348 2,096,255 1,161,899 376,742 1,596,150 1,363,606 OCCIDENTAL POWER SERVICES/WSPP B 5,698,000 1,189,742 1,433,048 794,302 257,550 1,091,166 932,192 RAINBOW ENERGY MARKETING CORP/WSPP A 13,924,000 2,907,333 3,501,908 1,941,010 629,363 2,666,424 2,277,962 SMEPA/WSPP B 3,000,000 626,400 754,504 418,200 135,600 574,496 490,800 SOUTHERN COMPANY SERVICES INC. AS AGENT 550,000 114,840 138,325 76,670 24,860 105,325 89,980 SOUTHERN COMPANY SERVICES INC. AS AGENT 10,600,000 2,213,280 2,665,900 1,477,640 479,120 2,029,900 1,734,160 SUEZ ENERGY MARKETING NA NC /WSPP A 8,660,000 1,808,208 2,178,009 1,207,204 391,432 1,658,371 1,416,776 SUEZ ENERGY MARKETING NA NC /WSPP B 56,537,000 11,804,928 14,219,068 7,881,251 2,555,470 10,826,823 9,249,460 TEA/WSPP A 1,116,000 233,021 280,677 155,570 50,443 213,711 182,578 TENASKA FRONTIER/EXS50 82,147 17,152 20,660 11,451 3,714 15,731 13,439 TENASKA FRONTIER/EXS75 64,452 13,458 16,210 8,985 2,912 12,343 10,544 TENASKA FRONTIER/EXS90 1,045,147 218,226 262,868 145,651 47,232 200,195 170,975 TENASKA/WSPP A 2,351,000 490,888 591,278 327,729 106,266 450,215 384,624 TENASKA/WSPP B 23,049,000 4,812,638 5,796,845 3,213,034 1,041,808 4,413,862 3,770,813 UNION POWER PARTNERS/WSPP A 190,000 39,672 47,786 26,486 8,588 36,384 31,084 UNION POWER PARTNERS/WSPP B 164,737,000 34,397,079 41,431,444 22,964,343 7,446,119 31,547,047 26,950,968 WESTAR ENERGY NC/WSPP A 6,934,000 1,447,817 1,743,909 966,608 313,419 1,327,853 1,134,394 WESTAR ENERGY NC/WSPP B 29,550,000 6,170,038 7,431,833 4,119,252 1,335,662 5,658,817 4,834,398 WESTAR ENERGY NC/WSPP C 800,000 167,040 201,200 111,520 36,160 153,200 130,880 WRIGHTSVILE POWER/EXS75 37,100 7,745 9,333 5,171 1,675 7,107 6,069 WRIGHTSVILE POWER/EXS90 813,136 169,805 204,509 113,362 36,734 155,716 133,010 YAZOO CITY/EXS90 5,270 1,101 1,324 734 237 1,011 863 Totals 1,112,801,073 232,352,897 279,870,424 155,124,383 50,298,464 213,100,660 182,054,245 Attachment Snapshot: 20100826181933 RunID: 17029 Billing Snapshot: 20100826175238

2011 ETI Rate Case 9-181 Exhibit PJC-2 2011 TX Rate Case Page 20 of 70

Entergy Electric System Date range - 20100701 through 20100731 Attachment 1 Intra-System Billing-201007RA Individual Company Purchases - KWH Page 20 Description System AR LA MS NO EGSL ETI ACADIA POWER PARTNERS, LLC/WSPP B 179,125,000 0 179,125,000 0 0 0 0 BURAS TEMP 131,908 0 131,908 0 0 0 0 CALP NE A BASE IN 137,098,200 0 0 0 0 137,098,200 0 CALP NE B BASE IN 98,223,400 0 0 0 0 98,223,400 0 CALP NE C BASE IN 5,787,100 0 0 0 0 5,787,100 0 CALP NE B RAMP IN 1,973,300 0 0 0 0 1,973,300 0 CALP NE C RAMP IN 34,100 0 0 0 0 34,100 0 CALP NE EXCESS N 422,000 0 0 0 0 422,000 0 CONOCOPH LLIPS COMPANY /INTRA-DAY CALL 3,425,000 0 0 0 0 1,969,375 1,455,625 CONOCOPH LLIPS COMPANY /INTRA-DAY CALL 120,000 0 0 0 0 0 120,000 DOW P PELINE COMPANY/INTRA-DAY CALL OPTION 3,700,000 0 0 0 0 2,127,500 1,572,500 EPI-ISES ELI IN 35,090,137 0 35,090,137 0 0 0 0 EPI-ISES ENOI IN 34,395,193 0 0 0 34,395,193 0 0 ETEC EXCESS-HRSNHRDN 4,937 0 0 0 0 0 4,937 EXELON FRONT ER 10YR 93,424,000 0 0 0 0 0 93,424,000 HARDIN 9,029,000 0 0 0 0 0 9,029,000 MEAM CANTON 1 IN 73,000 0 0 73,000 0 0 0 MEAM CANTON 2 IN 83,000 0 0 83,000 0 0 0 MEAM CANTON 3 IN 84,000 0 0 84,000 0 0 0 MEAM CANTON 4 IN 84,000 0 0 84,000 0 0 0 MEAM CANTON 5 IN 82,000 0 0 82,000 0 0 0 MEAM HENDERSON 10 IN 58,000 0 0 58,000 0 0 0 MEAM HENDERSON 11 IN 59,000 0 0 59,000 0 0 0 MEAM HENDERSON 2 IN 524,000 0 0 524,000 0 0 0 MEAM HENDERSON 4 IN 72,000 0 0 72,000 0 0 0 MEAM HENDERSON 5 IN 72,000 0 0 72,000 0 0 0 MEAM HENDERSON 6 IN 73,000 0 0 73,000 0 0 0 MEAM HENDERSON 7 IN 76,000 0 0 76,000 0 0 0 MEAM HENDERSON 8 IN 74,000 0 0 74,000 0 0 0 MEAM HENDERSON 9 IN 54,000 0 0 54,000 0 0 0 OCCIDENTAL POWER SERVICES/BASE CAPACITY 219,380,000 0 219,380,000 0 0 0 0 OCCIDENTAL POWER SERVICES/DAY-AHEAD CALL 50,188,000 0 50,188,000 0 0 0 0 OCCIDENTAL POWER SERVICES/ NTRA-DAY CALL 9,090,000 0 9,090,000 0 0 0 0 SAN JACINTO 1 5,722,000 0 0 0 0 0 5,722,000 SAN JACINTO 2 5,612,000 0 0 0 0 0 5,612,000 Totals 893,443,275 0 493,005,045 1,468,000 34,395,193 247,634,975 116,940,062

Attachment Snapshot: 20100826181933 RunID: 17029 Billing Snapshot: 20100826175238

2011 ETI Rate Case 9-182 Exhibit PJC-2 2011 TX Rate Case Page 21 of 70

Entergy Electric System Date range - 20100701 through 20100731 Attachment 2 Intra-System Billing-201007RA Energy Sold to Exchange - Entergy Arkansas, Inc. Page 21 Source KWH Mills per KWH Cost AECC Excess BAILEY 1 30,723 59.282297 1,821.33 AECC Excess INDEPN 2 14,445 21.739702 314.03 AECC Excess MCCLEL 1 952,753 61.531173 58,624.01 AECC Excess WH.BLF 1 914,776 21.867474 20,003.84 AECC Excess WH.BLF 2 3,188,988 22.097709 70,469.33 AECI/WSPP A 275,334 26.304343 7,242.48 AECI/WSPP B 783,000 38.000000 29,754.00 AECI/WSPP C SYSTEM FIRM 2,837,035 34.875139 98,941.99 AEP SERVICE CORP /WSPP A 254,973 29.310241 7,473.32 AEP SERVICE CORP /WSPP C 10,440 49.000000 511.56 AMEREN ENERGY INC. (AE) ACTING /WSPP C 145,951 30.098663 4,392.93 BNP PARIBAS ENERGY TRADING GP/WSPP B 33,408 52.000120 1,737.22 CALP NE ENERGY SERVICES L.P./WSPP B 236,639 53.867663 12,747.19 CITIGROUP ENERGY INC/WSPP A 10,440 29.000000 302.76 CLECO/WSPP B 317,798 63.178623 20,078.04 CONSTELLATION ENERGY COMMODITIES 204,354 39.196982 8,010.06 COTTONWOOD ENERGY CO/EXS50 7,619 22.040950 167.93 COTTONWOOD ENERGY CO/EXS75 2,111 30.127901 63.60 COTTONWOOD ENERGY CO/EXS90 51,457 35.798434 1,842.08 COTTONWOOD ENERGY CO/EXSSTSH 80,914 37.536026 3,037.19 COUCH 2/CEGT E 9,781,627 75.576540 739,261.52 COUCH 2/CENTERPOINT I 17,362 70.389356 1,222.10 CROSS O L/QF 76,886 37.393414 2,875.03 DB ENERGY TRAD NG LLC/WSPP B 2,901,191 51.582105 149,649.54 DUKE ENERGY HINDS/EXS75 5,582 29.681118 165.68 DUKE ENERGY HINDS/EXS90 11,889 37.935066 451.01 DUKEENERGY HOTSPRING/EXS50 20 22.000000 0.44 DUKEENERGY HOTSPRING/EXS75 700 29.671429 20.77 DUKEENERGY HOTSPRING/EXS90 2,264 39.553887 89.55 ENDURE ENERGY/WSPP B 13,572 26.000589 352.88 EXELON GENERATION COMPANY LLC/DA LY 4,361,740 39.438912 172,022.28 J ARON & COMPANY/WSPP B 599,915 50.452247 30,267.06 JBO/WSPP A 217,449 71.165607 15,474.89 JBO/WSPP B 275,382 48.699370 13,410.93 JONESBORO Excess INDEPN 2 1,221,922 24.163605 29,526.04 JONESBORO Excess WH BLF 1 1,744,400 24.848733 43,346.13 JONESBORO Excess WH BLF 2 2,670,122 25.411835 67,852.70 L.CATH 4/CEGT E 7,839,611 58.044036 455,042.66 L.CATH 4/CENTERPOINT I 1,399,984 57.172289 80,040.29 LYNCH 3/CEGT E 2,936,490 74.911340 219,976.40 LYNCH 3/CENTERPOINT I 659,947 70.499298 46,525.80 LYNCH IC/#2 OIL 2,000 159.310000 318.62 MABELV T/CEGT E 2,000 77.685000 155.37 MAGNET COVE/EXS90 35,561 34.416636 1,223.89 MAGNET COVE/EXSSTSH 344,998 35.709888 12,319.84 MERRILL LYNCH COMMODITIES INC/WSPP B 5,621,170 44.051592 247,621.49 MORGAN STANLEY/WSPP A 21,507 22.999954 494.66 NRG POWER MARKETING LLC./WSPP A 2,773,777 23.000003 63,796.88 NRG POWER MARKETING LLC./WSPP B 4,613,037 53.167872 245,265.36 NRG POWER MARKETING LLC./WSPP C 212,817 40.363881 8,590.12 OCCIDENTAL POWER SERVICES/WSPP B 241,196 63.464402 15,307.36 OUACHITA 1/SIGCO I 234,880 41.043256 9,640.24 OUACHITA 1/SIGPL E 3,527,779 38.975406 137,496.62 OUACHITA 2/SIGPL E 910,452 37.911828 34,516.90 PINE BLUFF ENERGY/QF 31,414,407 37.351724 1,173,382.27 RAINBOW ENERGY MARKETING CORP/WSPP A 154,939 39.856524 6,175.33 SOUTHERN COMPANY SERVICES INC. AS 62,640 38.000000 2,380.32 SUEZ Energy Marketing NA Inc./WSPP A 177,491 37.581568 6,670.39 SUEZ Energy Marketing NA Inc./WSPP B 1,049,490 44.543045 46,747.48 TEA/WSPP A 28,188 23.110898 651.45 TENASKA FRONTIER/EXS75 3,670 31.572207 115.87 TENASKA FRONTIER/EXS90 40,595 34.643183 1,406.34 TENASKA/WSPP B 449,719 62.669200 28,183.53 UNION POWER PARTNERS/WSPP A 3,576 35.000000 125.16 UNION POWER PARTNERS/WSPP B 3,127,518 48.726594 152,393.30 WESTAR ENERGY INC/WSPP A 420,854 29.662876 12,483.74 WESTAR ENERGY INC/WSPP B 1,228,584 36.666341 45,047.68 WESTAR ENERGY INC/WSPP C 10,440 62.000000 647.28 WH.BLF 1/COAL 25,833,205 21.377925 552,260.31 WH.BLF 2/COAL 2,103,620 21.350173 44,912.65 WRIGHTSVILE POWER/EXS90 1,900 35.321053 67.11 Totals 131,743,223 39.967947 5,265,506.15

Attachment Snapshot: 20100826181933 RunID: 17029 Billing Snapshot: 20100826175238

2011 ETI Rate Case 9-183 Exhibit PJC-2 2011 TX Rate Case Page 22 of 70

Entergy Electric System Date range - 20100701 through 20100731 Attachment 2 Intra-System Billing-201007RA Energy Sold to Exchange - Entergy Louisiana, LLC Page 22 Source KWH Mills per KWH Cost AECC Excess MCCLEL 1 126,981 61.531095 7,813.28 AECI/WSPP C SYSTEM FIRM 678,098 66.741784 45,257.47 BURAS TEMP 45,238 260.515054 11,785.18 CLECO/WSPP B 132,197 71.855337 9,499.06 ENDURE ENERGY/WSPP A 24,396 68.000082 1,658.93 J ARON & COMPANY/WSPP B 126,465 69.758668 8,822.03 J.P. MORGAN VENTURES ENERGY 38,670 68.000000 2,629.56 JBO/WSPP A 1,258,817 71.820749 90,409.18 JBO/WSPP B 262,779 73.000049 19,182.88 L.GPSY 1/EVANG(LT) M 7,913,583 65.067524 514,917.25 L.GPSY 1/EVG/CG I 46,349 62.358627 2,890.26 L.GPSY 2/BRDGLN E 1,045,351 72.682793 75,979.03 L.GPSY 2/CGT M 25,995 69.795730 1,814.34 L.GPSY 2/EVANG(LT) M 25,320,605 76.863691 1,946,235.15 L.GPSY 2/EVG/CG I 2,135,948 77.639226 165,833.35 L.GPSY 2/GSPL M 346,715 71.005754 24,618.76 L.GPSY 3/EVANG(LT) M 2,662,097 61.674045 164,182.29 N NEMI 3/EVANG(LT) M 5,982,602 78.343928 468,700.54 N NEMI 3/EVG/CG I 905,754 79.255449 71,785.94 N NEMI 4/EVANG(LT) M 3,228,244 63.765917 205,851.94 N NEMI 4/EVG/CG I 1,224 61.078431 74.76 N NEMI 5/EVANG(LT) M 1,193,561 60.638794 72,376.10 NRG POWER MARKETING LLC./WSPP A 377,250 84.000000 31,689.00 NRG POWER MARKETING LLC./WSPP B 500,863 78.088499 39,111.64 NRG POWER MARKETING LLC./WSPP C 25,150 65.000000 1,634.75 OCCIDENTAL POWER SERVICES/WSPP B 49,866 65.000000 3,241.29 SMEPA/WSPP B 748,227 89.186383 66,731.66 SOUTHERN COMPANY SERVICES INC. AS 2,326,731 127.999992 297,821.55 TENASKA/WSPP B 361,244 66.072654 23,868.35 WATERF 1/BRDGLN E 843,299 73.709028 62,158.75 WATERF 1/CGT M 356,988 72.433695 25,857.96 WATERF 1/EVANG(LT) M 47,727,893 79.757661 3,806,665.12 WATERF 1/EVG/CG I 3,677,054 79.147478 291,029.55 WATERF 2/#6 OIL 302,500 121.708562 36,816.84 WATERF 2/BRDGLN E 9,002,954 66.117939 595,256.76 WATERF 2/CGT E 1,648,800 64.400734 106,183.93 WATERF 2/CGT M 8,938,269 65.179773 582,594.34 WATERF 2/EVANG(LT) M 3,286,637 71.768790 235,877.96 WATERF 2/EVG/CG I 1,383,963 69.682672 96,438.24 WATERF 4/#2 OIL 46,000 236.132391 10,862.09 Totals 135,105,357 75.690241 10,226,157.06

Attachment Snapshot: 20100826181933 RunID: 17029 Billing Snapshot: 20100826175238

2011 ETI Rate Case 9-184 Exhibit PJC-2 2011 TX Rate Case Page 23 of 70

Entergy Electric System Date range - 20100701 through 20100731 Attachment 2 Intra-System Billing-201007RA Energy Sold to Exchange - Entergy Mississippi, Inc. Page 23 Source KWH Mills per KWH Cost AECC Excess BAILEY 1 417 59.280576 24.72 AECC Excess MCCLEL 1 114,704 61.529851 7,057.72 ANDRUS 1/TENN E 2,659,523 59.401915 157,980.76 ANDRUS 1/TENN I 716,204 63.247231 45,297.92 ANDRUS 1/TGT E 500,938 59.031856 29,571.30 B.WLSN 1/COLUMBIA ML E 38,457 55.997348 2,153.49 B.WLSN 2/COLUMBIA MAINLINE I 137,442 62.881579 8,642.57 B.WLSN 2/COLUMBIA ML E 21,706,585 60.407527 1,311,241.12 CLECO/WSPP B 97,617 62.407368 6,092.02 J ARON & COMPANY/WSPP B 83,328 59.500048 4,958.02 JBO/WSPP A 23,631 70.000000 1,654.17 JBO/WSPP B 90,177 72.999989 6,582.92 NRG POWER MARKETING LLC./WSPP B 57,038 62.625267 3,572.02 OCCIDENTAL POWER SERVICES/WSPP B 54,861 64.510490 3,539.11 REX BR 4/GSPL E 5,393,054 80.026983 431,589.84 REX BR 4/GSPL I 201,384 84.433470 17,003.55 TENASKA/WSPP A 5,820 63.049828 366.95 TENASKA/WSPP B 146,370 62.000000 9,074.94 Totals 32,027,550 63.895088 2,046,403.14

Attachment Snapshot: 20100826181933 RunID: 17029 Billing Snapshot: 20100826175238

2011 ETI Rate Case 9-185 Exhibit PJC-2 2011 TX Rate Case Page 24 of 70

Entergy Electric System Date range - 20100701 through 20100731 Attachment 2 Intra-System Billing-201007RA Energy Sold to Exchange - Entergy New Orleans, Inc. Page 24 Source KWH Mills per KWH Cost AECC Excess BAILEY 1 980 59.336735 58.15 AECC Excess MCCLEL 1 315,602 61.530789 19,419.24 AECI/WSPP C SYSTEM FIRM 608,021 64.528742 39,234.83 AMEREN ENERGY INC. (AE) ACTING /WSPP C 18,080 61.000000 1,102.88 BNP PARIBAS ENERGY TRADING GP/WSPP B 38,354 60.000000 2,301.24 CLECO/WSPP B 76,004 65.476159 4,976.45 DB ENERGY TRAD NG LLC/WSPP B 95,558 60.088742 5,741.96 ENDURE ENERGY/WSPP A 8,272 68.000484 562.50 J ARON & COMPANY/WSPP B 213,035 63.098599 13,442.21 J.P. MORGAN VENTURES ENERGY 34,369 67.999942 2,337.09 JBO/WSPP A 268,090 72.038718 19,312.86 JBO/WSPP B 217,346 72.039283 15,657.45 MICHOD 2/BRDGLN E 62,252 56.774722 3,534.34 MICHOD 3/BRDGLN E 11,056,337 60.606405 670,084.84 MICHOD 3/GSPL E 11,458,320 59.604617 682,968.77 MICHOD 3/NOPSI I 5,187,011 61.884854 320,997.42 MICHOD 3/SIGPL E 337,959 59.764912 20,198.09 NRG POWER MARKETING LLC./WSPP A 67,800 84.000000 5,695.20 NRG POWER MARKETING LLC./WSPP B 280,383 65.790544 18,446.55 NRG POWER MARKETING LLC./WSPP C 70,969 65.000070 4,612.99 OCCIDENTAL POWER SERVICES/WSPP B 40,184 66.828588 2,685.44 SMEPA/WSPP B 134,472 89.186745 11,993.12 SOUTHERN COMPANY SERVICES INC. AS 418,166 127.999981 53,525.24 TENASKA/WSPP B 554,729 64.464883 35,760.54 WESTAR ENERGY INC/WSPP C 25,251 61.999921 1,565.56 Totals 31,587,544 61.929948 1,956,214.96

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2011 ETI Rate Case 9-186 Exhibit PJC-2 2011 TX Rate Case Page 25 of 70

Entergy Electric System Date range - 20100701 through 20100731 Attachment 2 Intra-System Billing-201007RA Energy Sold to Exchange - Entergy Gulf States Louisiana, LLC Page 25 Source KWH Mills per KWH Cost AECC Excess BAILEY 1 24,335 59.272242 1,442.39 AECC Excess MCCLEL 1 2,792,163 61.531042 171,804.70 AECI/WSPP C SYSTEM FIRM 3,173,844 63.794610 202,474.14 AGRILECTRIC/QF 12,709 44.799748 569.36 AMEREN ENERGY INC. (AE) ACTING /WSPP C 304,529 61.000003 18,576.27 BNP PARIBAS ENERGY TRADING GP/WSPP B 61,280 60.000000 3,676.80 CALCAS EU 1/GSPL E 3,714,474 59.468127 220,892.81 CALCAS EU 1/GSPL I 548,116 61.952069 33,956.92 CALCAS EU 2/GSPL E 2,906,170 59.035428 171,566.99 CALP NE B BASE IN 71,559 38.740759 2,772.25 CALP NE ENERGY SERVICES L.P./WSPP B 193,011 54.830346 10,582.86 CLECO/WSPP B 830,943 63.194395 52,510.94 CONOCOPH LLIPS COMPANY /INTRA-DAY CALL 1,681,875 60.305136 101,425.70 DB ENERGY TRAD NG LLC/WSPP B 1,654,147 57.964353 95,881.56 DOW CHEMICAL/QF 123,788 44.948056 5,564.03 DOW P PELINE COMPANY/INTRA-DAY CALL 2,116,638 62.456778 132,198.39 ENDURE ENERGY/WSPP A 35,043 67.999600 2,382.91 EXELON GENERATION COMPANY LLC/DA LY 53,551 42.891449 2,296.88 J ARON & COMPANY/WSPP B 2,095,052 62.638798 131,231.54 J.P. MORGAN VENTURES ENERGY 828,870 68.000024 56,363.18 JBO/WSPP A 1,609,650 71.438574 114,991.10 JBO/WSPP B 1,137,518 70.893981 80,643.18 LEWIS CREEK 1/COPANO E 1,879,528 56.584988 106,353.07 LEWIS CREEK 1/COPANO M 10,925,536 57.084223 623,675.73 LEWIS CREEK 1/TETCO E 1,521,741 55.948581 85,139.25 LEWIS CREEK 1/TETCO I 1,157,040 56.793741 65,712.63 LEWIS CREEK 1/TETCO M 3,647,410 56.295626 205,333.23 LEWIS CREEK 2/COPANO E 926,721 55.342859 51,287.39 LEWIS CREEK 2/COPANO M 3,483,050 56.566756 197,024.84 LEWIS CREEK 2/TEJAS E 141,822 54.865254 7,781.10 LEWIS CREEK 2/TETCO E 1,536,278 55.145833 84,719.33 LEWIS CREEK 2/TETCO I 1,582,353 54.986530 87,008.10 LEWIS CREEK 2/TETCO M 5,315,248 55.780833 296,488.96 MERRILL LYNCH COMMODITIES INC/WSPP B 513,751 52.752150 27,101.47 NELSON 3/TARGA E 211,896 73.711255 15,619.12 NELSON 3/TENN M 1,700,865 72.146243 122,711.02 NELSON 3/TETCO E 310,513 74.583769 23,159.23 NELSON 3/TETCO M 4,149,185 72.377696 300,308.45 NELSON 4/FLORIDA E 7,000,169 61.712570 431,998.42 NELSON 4/TARGA E 14,524,924 61.566255 894,245.17 NELSON 4/TENN E 12,398,148 61.183407 758,560.93 NELSON 4/TENN M 11,564,685 62.458012 722,307.24 NELSON 4/TETCO E 673,803 62.029837 41,795.89 NELSON 4/TETCO I 4,071,417 60.797956 247,533.83 NELSON 4/TETCO M 20,958,943 62.744334 1,315,054.91 NRG POWER MARKETING LLC./WSPP A 287,250 84.000000 24,129.00 NRG POWER MARKETING LLC./WSPP B 3,866,468 63.031477 243,709.19 NRG POWER MARKETING LLC./WSPP C 576,051 61.175903 35,240.44 OCCIDENTAL POWER SERVICES/WSPP B 860,110 64.057109 55,096.16 RAINBOW ENERGY MARKETING CORP/WSPP A 16,988 45.500353 772.96 SABINE 1/CENTANA#3 E 528,309 58.315891 30,808.81 SABINE 1/CENTANA#3 M 11,158,610 60.270426 672,534.18 SABINE 1/ENBRIDGE E 2,981,642 59.069701 176,124.70 SABINE 1/ENBRIDGE M 13,526,870 59.643680 806,792.30 SABINE 1/HPL/CH E 988,225 59.296527 58,598.31 SABINE 1/STORAGE I 1,426,945 55.129616 78,666.93 SABINE 1/TEJAS E 121,659 59.397414 7,226.23 SABINE 1/TEJAS M 947,156 60.289340 57,103.41 SABINE 2/CENTANA#3 E 91,908 56.319798 5,176.24 SABINE 2/CENTANA#3 M 664,972 56.811565 37,778.10 SABINE 2/ENBRIDGE E 692,152 55.256562 38,245.94 SABINE 2/ENBRIDGE M 7,036,036 56.249057 395,770.39 SABINE 2/STORAGE I 44,850 51.999108 2,332.16 SABINE 2/TEJAS M 908,661 56.809272 51,620.37 SABINE 3/CENTANA#3 E 1,060,597 59.090201 62,670.89 SABINE 3/CENTANA#3 M 16,217,549 58.704064 952,036.04 SABINE 3/ENBRIDGE E 3,103,193 58.061200 180,175.11 SABINE 3/ENBRIDGE M 12,241,869 58.110576 711,382.06 SABINE 3/HPL/CH E 326,498 58.477785 19,092.88 SABINE 3/STORAGE I 10,324 53.748547 554.90 SABINE 3/TEJAS E 925,496 59.023659 54,626.16 SABINE 3/TEJAS M 7,186,222 58.774696 422,368.01 SABINE 4/CENTANA#3 M 453,221 54.745257 24,811.70 SABINE 4/ENBRIDGE E 2,601,263 53.583790 139,385.53 SABINE 4/ENBRIDGE M 2,257,273 54.260118 122,479.90 Attachment Snapshot: 20100826181933 RunID: 17029 Billing Snapshot: 20100826175238

2011 ETI Rate Case 9-187 Exhibit PJC-2 2011 TX Rate Case Page 26 of 70

Entergy Electric System Date range - 20100701 through 20100731 Attachment 2 Intra-System Billing-201007RA Energy Sold to Exchange - Entergy Gulf States Louisiana, LLC Page 26 Source KWH Mills per KWH Cost SABINE 4/HPL/CH E 123,231 53.774943 6,626.74 SABINE 4/STORAGE I 354,533 52.808342 18,722.30 SABINE 4/TEJAS M 540,521 54.799166 29,620.10 SABINE 5/CENTANA#3 M 12,993,537 60.726777 789,055.62 SABINE 5/ENBRIDGE E 3,605,523 60.124634 216,780.75 SABINE 5/ENBRIDGE M 3,707,371 60.131940 222,931.41 SABINE 5/HPL/CH E 2,059,458 61.208420 126,056.17 SABINE 5/TEJAS E 1,643,812 61.391668 100,916.36 SABINE 5/TEJAS M 38,907,022 60.796120 2,365,395.96 SMEPA/WSPP B 569,717 89.186491 50,811.06 SOUTHERN COMPANY SERVICES INC. AS 1,771,646 128.000001 226,770.69 SUEZ Energy Marketing NA Inc./WSPP B 87,489 53.713153 4,699.31 TENASKA/WSPP A 253,868 62.640624 15,902.45 TENASKA/WSPP B 2,782,607 64.098886 178,362.01 UNION POWER PARTNERS/WSPP B 993,273 55.584890 55,210.97 WESTAR ENERGY INC/WSPP B 97,958 56.092203 5,494.68 WESTAR ENERGY INC/WSPP C 153,200 62.000000 9,498.40 WILLOW GLEN 1/BL HOLDINGS E 7,061,062 62.406062 440,653.07 WILLOW GLEN 2/BL HOLDINGS E 13,042,792 71.414827 931,448.74 WILLOW GLEN 4/BL HOLDINGS E 68,607,715 59.777690 4,101,210.69 Totals 388,628,993 60.953251 23,688,200.69

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2011 ETI Rate Case 9-188 Exhibit PJC-2 2011 TX Rate Case Page 27 of 70

Entergy Electric System Date range - 20100701 through 20100731 Attachment 2 Intra-System Billing-201007RA Energy Sold to Exchange - Entergy Texas, Inc Page 27 Source KWH Mills per KWH Cost AECI/WSPP C SYSTEM FIRM 43,518 62.999908 2,741.63 DOW P PELINE COMPANY/INTRA-DAY CALL 274,685 63.636784 17,480.07 JBO/WSPP A 75,631 70.000000 5,294.17 JBO/WSPP B 111,406 73.000018 8,132.64 NELSON 4/FLORIDA E 47,337 62.611065 2,963.82 NELSON 4/TARGA E 121,380 62.737354 7,615.06 NELSON 4/TENN E 17,782 62.358002 1,108.85 NELSON 4/TENN M 57,443 62.438939 3,586.68 NELSON 4/TETCO M 177,010 62.728942 11,103.65 NRG POWER MARKETING LLC./WSPP A 225,360 84.000000 18,930.24 OCCIDENTAL POWER SERVICES/WSPP B 32,720 66.000000 2,159.52 SMEPA/WSPP B 167,697 98.509812 16,519.80 SOUTHERN COMPANY SERVICES INC. AS 322,527 128.000012 41,283.46 TENASKA/WSPP A 15,456 63.049948 974.50 WILLOW GLEN 2/BL HOLDINGS E 569,266 72.351045 41,186.99 Totals 2,259,218 80.152106 181,081.08

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2011 ETI Rate Case 9-189 Exhibit PJC-2 2011 TX Rate Case Page 28 of 70

Entergy Electric System Date range - 20100701 through 20100731 Attachment 2 Intra-System Billing-201007RA Energy Sold to Exchange Page 28 Company KWH Mills per KWH Cost Entergy Arkansas, Inc. 131,743,223 39.967947 5,265,506.15 Entergy Louisiana, LLC 135,105,357 75.690241 10,226,157.06 Entergy Mississippi, Inc. 32,027,550 63.895088 2,046,403.14 Entergy New Orleans, Inc. 31,587,544 61.929948 1,956,214.96 Entergy Gulf States Louisiana, LLC 388,628,993 60.953251 23,688,200.69 Entergy Texas, Inc 2,259,218 80.152106 181,081.08 Totals 721,351,885 60.114299 43,363,563.08

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2011 ETI Rate Case 9-190 Exhibit PJC-2 2011 TX Rate Case Page 29 of 70

Entergy Electric System Date range - 20100701 through 20100731 Attachment 2 Intra-System Billing-201007RA Energy Purchased from Exchange Page 29 Company KWH Mills per KWH Cost Entergy Arkansas, Inc. 131,563,443 64.953756 8,545,539.76 Entergy Louisiana, LLC 42,272,082 50.486528 2,134,170.65 Entergy Mississippi, Inc. 165,417,337 64.005776 10,587,664.98 Entergy New Orleans, Inc. 45,025,369 58.268323 2,623,552.75 Entergy Gulf States Louisiana, LLC 8,681,301 37.886068 328,900.36 Entergy Texas, Inc 328,392,353 58.295312 19,143,734.58 Totals 721,351,885 60.114299 43,363,563.08

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2011 ETI Rate Case 9-191 Exhibit PJC-2 2011 TX Rate Case Page 30 of 70

Entergy Electric System Date range - 20100701 through 20100731 Attachment 2 Intra-System Billing-201007RA Unit Power Purchases - KWH Page 30 Generating Unit AR LA MS NO EGSL ETI ACADIA POWER PARTNERS, 0 0 0 0 59,708,320 0 ARK.NU 1 - UPP from AR 0 24,991,859 11,975,579 16,947,775 15,851,160 16,654,966 ARK.NU 2 - UPP from AR 0 29,534,318 14,206,469 19,989,454 18,809,417 19,768,134 CALCAS EU 1 - UPP from EGSL 0 0 0 0 0 4,690,725 CALCAS EU 2 - UPP from EGSL 0 0 0 0 0 5,250,450 GGULF RET - UPP from AR 0 19,691,908 8,775,642 13,799,542 11,616,357 12,205,279 GGULF RP - UPP from AR 0 9,494,456 4,440,083 6,514,363 5,876,574 6,173,783 INDEPN 1 - UPP from AR 0 7,145,175 3,421,107 4,846,579 4,526,010 4,757,472 LEWIS CREEK 1 - UPP from ETI 0 0 0 0 58,217,025 0 LEWIS CREEK 2 - UPP from ETI 0 0 0 0 65,725,375 0 NELSON 3 - UPP from EGSL 0 0 0 0 0 5,192,225 NELSON 4 - UPP from EGSL 0 0 0 0 0 62,280,775 PERV L 1 - UPP from EGSL 0 0 0 0 0 82,838,753 PERV L 1 - UPP from LA 0 0 0 0 194,914,500 0 RVRBND 1 - UPP from EGSL 0 139,555,800 0 69,777,900 0 207,589,429 SABINE 1 - UPP from ETI 0 0 0 0 51,146,250 0 SABINE 2 - UPP from ETI 0 0 0 0 50,562,050 0 SABINE 3 - UPP from ETI 0 0 0 0 80,097,500 0 SABINE 4 - UPP from ETI 0 0 0 0 76,167,950 0 SABINE 5 - UPP from ETI 0 0 0 0 70,933,725 0 WH.BLF 1 - UPP from AR 0 13,440,805 6,292,389 8,494,462 8,331,086 8,755,797 WH.BLF 2 - UPP from AR 0 10,706,289 5,295,338 7,753,353 7,011,078 7,368,498 WILLOW GLEN 1 - UPP from 0 0 0 0 0 5,445,950 WILLOW GLEN 2 - UPP from 0 0 0 0 0 10,391,250 WILLOW GLEN 4 - UPP from 0 0 0 0 0 77,447,750 Totals 0 254,560,610 54,406,607 148,123,428 779,494,377 536,811,236

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2011 ETI Rate Case 9-192 Exhibit PJC-2 2011 TX Rate Case Page 31 of 70

Entergy Electric System Date range - 20100701 through 20100731 Attachment 2 Intra-System Billing-201007RA AECC Excess Energy Page 31 Company KWH Mills per KWH Cost Entergy Arkansas, Inc. 12,108,854 32.952174 399,013.07 Entergy Louisiana, LLC 14,584,886 32.951794 480,598.16 Entergy Mississippi, Inc. 8,083,973 32.951544 266,379.39 Entergy New Orleans, Inc. 2,621,176 32.951442 86,371.53 Entergy Gulf States Louisiana, LLC 11,105,658 32.952414 365,958.24 Entergy Texas, Inc 9,487,663 32.952434 312,641.59 Totals 57,992,210 32.952046 1,910,961.98

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2011 ETI Rate Case 9-193 Exhibit PJC-2 2011 TX Rate Case Page 32 of 70

Entergy Electric System Date range - 20100701 through 20100731 Attachment 3 Intra-System Billing-201007RA Joint Account Deliveries Page 32 Company / Type KWH Mills per KWH Charge AECC/1-NON F RM 60,000 53.000000 3,180.00 AECI/WSPP A 750,000 41.773333 31,330.00 AEP SERVICE CORP./SPP ASSIST 135,000 65.750074 8,876.26 AEP SERVICE CORP./WSPP A 850,000 30.352941 25,800.00 BNP PAR BAS ENERGY TRADING GP/WSPP A 150,000 68.000000 10,200.00 BOARD OF PUBLIC UTILITIES/SPP ASSIST 15,000 66.000000 990.00 CITIGROUP ENERGY NC/WSPP A 208,000 57.442308 11,948.00 CLECO/SPP ASSIST 260,000 68.860923 17,903.84 CONSTELLATION ENERGY COMM/SPP ASSIST 5,000 77.000000 385.00 CONSTELLATION ENERGY COMMOD/SPP ASSIST (W 15,000 64.162000 962.43 CONSTELLATION ENERGY COMMODIT /SPP ASSIST 71,000 75.745070 5,377.90 CONSTELLATION ENERGY COMMODIT E/SWPP ASSIST 15,000 61.259333 918.89 CONSTELLATION ENERGY COMMODIT ES GR/WSPP C 300,000 59.270000 17,781.00 CONSTELLATION ENERGY COMMODIT ES GROUP /1- 24,000 51.625000 1,239.00 CONSTELLATION ENERGY COMMODIT ES/SPP ASSIST 8,000 72.875000 583.00 COTTONWOOD ENERGY CO/DEF110 642,523 74.096678 47,608.82 CYPRES/DEF110 528,066 80.697167 42,613.43 DUKE ENERGY H NDS/DEF110 190,414 62.675066 11,934.21 DUKEENERGY HOTSPR NG/DEF110 214,680 71.472098 15,343.63 GRDA/SPP ASSIST 79,000 58.944937 4,656.65 KANSAS CITY POWER & LIGHT COMPANY/SPP ASSIST 488,000 70.980246 34,638.36 KANSAS CITY POWER & LIGHT COMPANY/WSPP A 100,000 63.000000 6,300.00 MAGNET COVE/DEF110 648,504 67.715326 43,913.66 MDEA CROSSROADS/DEF110 63,959 78.770306 5,038.07 MISSOURI PUBLIC SERVICE/SPP ASSIST 489,000 69.808732 34,136.47 NPPD/SPP ASSIST 177,000 55.965480 9,905.89 NRG POWER MARKETING LLC./1-NON FIRM 275,000 42.000000 11,550.00 NRG POWER MARKETING LLC./SPP ASSIST 149,000 74.895973 11,159.50 NRG POWER MARKETING LLC./WSPP C DAMAGES 1,200,000 65.258125 78,309.75 OCCIDENTAL CHEM CORP/DEF110 17,810 69.602471 1,239.62 OG&E/SPP ASSIST 306,000 77.899608 23,837.28 PPG INDUSTRIES/DEF110 28,405 80.299947 2,280.92 RS COGEN LLC/DEF110 108 81.388889 8.79 SPS/SPP ASSIST 58,000 55.541379 3,221.40 SRW COGENERATION/DEF110 54,784 79.191917 4,338.45 SUNFLOWER/SPP ASSIST 6,000 69.300000 415.80 SUNFLOWER/SWPP ASSIST 124,000 58.196129 7,216.32 SWPA/SPP ASSIST 85,000 65.334000 5,553.39 TENASKA FRONTIER/DEF110 328,937 68.567780 22,554.48 TENASKA/WSPP A 50,000 36.000000 1,800.00 WESTAR ENERGY NC/SPP ASSIST 93,000 69.512903 6,464.70 WESTAR ENERGY NC/WSPP A 150,000 35.000000 5,250.00 WESTAR ENERGY NC/WSPP C DAMAGES 412,000 70.000000 28,840.00 WESTERN FARMERS/SPP ASSIST 15,000 68.200000 1,023.00 WRIGHTSVILE POWER/DEF110 315,742 78.991582 24,940.96 YAZOO CITY/DEF110 16,104 91.066816 1,466.54 Totals 10,172,036 62.429528 635,035.41

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2011 ETI Rate Case 9-194 Exhibit PJC-2 2011 TX Rate Case Page 33 of 70

Entergy Electric System Date range - 20100701 through 20100731 Attachment 3 Intra-System Billing-201007RA Joint Account Delivery Sources - Entergy Arkansas, Inc. Page 33 Source KWH Mills per KWH Charge AECI/WSPP C SYSTEM FIRM 3,288 62.858881 206.68 AMEREN ENERGY NC. (AE) ACTING /WSPP C 2,040 61.000000 124.44 CALPINE ENERGY SERVICES L.P./WSPP B 15,413 54.792059 844.51 CLECO/WSPP B 83,404 63.829672 5,323.65 CONSTELLATION ENERGY COMMODIT ES 685 45.328467 31.05 DB ENERGY TRADING LLC/WSPP B 111,632 54.443529 6,077.64 ENDURE ENERGY/WSPP A 1,200 52.000000 62.40 EXELON GENERATION COMPANY LLC/DAILY 30,776 40.569925 1,248.58 J ARON & COMPANY/WSPP B 11,882 56.502272 671.36 J.P. MORGAN VENTURES ENERGY 116,233 68.000052 7,903.85 JBO/WSPP A 264,226 70.911228 18,736.59 JBO/WSPP B 52,181 70.734367 3,690.99 L.CATH 4/CEGT E 710 45.464789 32.28 MERR LL LYNCH COMMODITIES INC/WSPP B 231,161 50.663737 11,711.48 NRG POWER MARKETING LLC./WSPP B 386,954 60.796374 23,525.40 NRG POWER MARKETING LLC./WSPP C 6,241 65.000801 405.67 OCCIDENTAL POWER SERVICES/WSPP B 65,502 66.050808 4,326.46 SMEPA/WSPP B 5,211 98.508923 513.33 SOUTHERN COMPANY SERVICES INC. AS 281,583 128 000021 36,042.63 SUEZ Energy Marketing NA Inc./WSPP B 63,182 51.789275 3,272.15 TENASKA/WSPP A 6,331 60.830832 385.12 TENASKA/WSPP B 30,929 63.290439 1,957.51 UNION POWER PARTNERS/WSPP B 140,230 52.566783 7,371.44 WESTAR ENERGY NC/WSPP B 2,312 49.247405 113.86 Totals 1,913,306 70.338498 134,579.07

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2011 ETI Rate Case 9-195 Exhibit PJC-2 2011 TX Rate Case Page 34 of 70

Entergy Electric System Date range - 20100701 through 20100731 Attachment 3 Intra-System Billing-201007RA Joint Account Delivery Sources - Entergy Louisiana, LLC Page 34 Source KWH Mills per KWH Charge ACADIA POWER PARTNERS, LLC/WSPP B 65,625 39.956419 2,622.14 AECI/WSPP C SYSTEM FIRM 3,960 62.858586 248.92 AMEREN ENERGY NC. (AE) ACTING /WSPP C 2,458 61.000814 149.94 BURAS TEMP 86,670 260 515403 22,578.87 CALPINE ENERGY SERVICES L.P./WSPP B 18,572 54.790545 1,017.57 CLECO/WSPP B 100,472 63.829326 6,413.06 CONSTELLATION ENERGY COMMODIT ES 826 45.326877 37.44 DB ENERGY TRADING LLC/WSPP B 134,470 54.443816 7,321.06 ENDURE ENERGY/WSPP A 1,445 52.000000 75.14 EXELON GENERATION COMPANY LLC/DAILY 37,078 40.569610 1,504.24 J ARON & COMPANY/WSPP B 14,314 56.502725 808.78 J.P. MORGAN VENTURES ENERGY 140,006 67.999871 9,520.39 JBO/WSPP A 318,288 70.911376 22,570.24 JBO/WSPP B 62,870 70.734054 4,447.05 L.GPSY 3/BRDGLN E 837 47.849462 40.05 MERR LL LYNCH COMMODITIES INC/WSPP B 278,442 50.664124 14,107.02 NINEMI 4/EVANG(LT) M 603 47.877280 28.87 NINEMI 5/BRDGLN E 48,816 46.392371 2,264.69 NRG POWER MARKETING LLC./WSPP B 466,111 60.796184 28,337.77 NRG POWER MARKETING LLC./WSPP C 7,518 65.001330 488.68 OCCIDENTAL POWER SERVICES/BASE 221,973 35.759034 7,937.54 OCCIDENTAL POWER SERVICES/DAY-AHEAD 5,441 41.705569 226.92 OCCIDENTAL POWER SERVICES/INTRA-DAY 40,869 52.705474 2,154.02 OCCIDENTAL POWER SERVICES/WSPP B 78,904 66.050771 5,211.67 SMEPA/WSPP B 6,277 98.510435 618.35 SOUTHERN COMPANY SERVICES INC. AS 339,169 128 000024 43,413.64 SUEZ Energy Marketing NA Inc./WSPP B 76,107 51.789717 3,941.56 TENASKA/WSPP A 7,625 60.828852 463.82 TENASKA/WSPP B 37,261 63.290572 2,358.27 UNION POWER PARTNERS/WSPP B 168,919 52.566733 8,879.52 WESTAR ENERGY NC/WSPP B 2,786 49.249821 137.21 Totals 2,774,712 72.052321 199,924.44

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2011 ETI Rate Case 9-196 Exhibit PJC-2 2011 TX Rate Case Page 35 of 70

Entergy Electric System Date range - 20100701 through 20100731 Attachment 3 Intra-System Billing-201007RA Joint Account Delivery Sources - Entergy Mississippi, Inc. Page 35 Source KWH Mills per KWH Charge AECI/WSPP C SYSTEM FIRM 2,194 62.857794 137.91 AMEREN ENERGY NC. (AE) ACTING /WSPP C 1,361 61.006613 83.03 ANDRUS 1/TENN E 27,261 43.250064 1,179.04 ANDRUS 1/TENN I 345 46.550725 16.06 B.WLSN 1/COLUMBIA ML E 1,382 46.714906 64.56 B.WLSN 2/COLUMBIA ML E 8,426 46.840731 394.68 CALPINE ENERGY SERVICES L.P./WSPP B 10,293 54.793549 563.99 CLECO/WSPP B 55,684 63.829825 3,554.30 CONSTELLATION ENERGY COMMODIT ES 458 45.327511 20.76 DB ENERGY TRADING LLC/WSPP B 74,525 54.443744 4,057.42 ENDURE ENERGY/WSPP A 801 51.997503 41.65 EXELON GENERATION COMPANY LLC/DAILY 20,546 40.570427 833.56 J ARON & COMPANY/WSPP B 7,931 56.498550 448.09 J.P. MORGAN VENTURES ENERGY 77,599 67.999974 5,276.73 JBO/WSPP A 176,406 70.911307 12,509.18 JBO/WSPP B 34,835 70.733458 2,464.00 MEAM CANTON 1 N 8,863 120 910527 1,071.63 MEAM CANTON 2 N 8,000 120 910000 967.28 MEAM CANTON 3 N 8,000 120 910000 967.28 MEAM CANTON 4 N 8,011 120 909999 968.61 MEAM CANTON 5 N 10,000 120 910000 1,209.10 MEAM HENDERSON 10 IN 5,000 120 910000 604.55 MEAM HENDERSON 11 IN 8,000 120 910000 967.28 MEAM HENDERSON 2 IN 68,916 120 907627 8,332.47 MEAM HENDERSON 4 IN 13,858 120 909944 1,675.57 MEAM HENDERSON 5 IN 14,166 120 909925 1,712.81 MEAM HENDERSON 6 IN 15,000 120 910000 1,813.65 MEAM HENDERSON 7 IN 19,159 120 910277 2,316.52 MEAM HENDERSON 8 IN 24,750 120 909899 2,992.52 MEAM HENDERSON 9 IN 23,222 120 910344 2,807.78 MERR LL LYNCH COMMODITIES INC/WSPP B 154,326 50.663660 7,818.72 NRG POWER MARKETING LLC./WSPP B 258,334 60.796604 15,705.83 NRG POWER MARKETING LLC./WSPP C 4,167 65.003600 270.87 OCCIDENTAL POWER SERVICES/WSPP B 43,731 66.052228 2,888.53 SMEPA/WSPP B 3,479 98.511066 342.72 SOUTHERN COMPANY SERVICES INC. AS 187,994 128 000043 24,063.24 SUEZ Energy Marketing NA Inc./WSPP B 42,184 51.789304 2,184.68 TENASKA/WSPP A 4,226 60.828206 257.06 TENASKA/WSPP B 20,648 63.290391 1,306.82 UNION POWER PARTNERS/WSPP B 93,622 52.566811 4,921.41 WESTAR ENERGY NC/WSPP B 1,543 49.254699 76.00 Totals 1,549,246 77.384670 119,887.89

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2011 ETI Rate Case 9-197 Exhibit PJC-2 2011 TX Rate Case Page 36 of 70

Entergy Electric System Date range - 20100701 through 20100731 Attachment 3 Intra-System Billing-201007RA Joint Account Delivery Sources - Entergy New Orleans, Inc. Page 36 Source KWH Mills per KWH Charge AECI/WSPP C SYSTEM FIRM 712 62.837079 44.74 AMEREN ENERGY NC. (AE) ACTING /WSPP C 441 61.020408 26.91 CALPINE ENERGY SERVICES L.P./WSPP B 3,336 54.805156 182.83 CLECO/WSPP B 18,049 63.829575 1,152.06 CONSTELLATION ENERGY COMMODIT ES 148 45.337838 6.71 DB ENERGY TRADING LLC/WSPP B 24,166 54.441364 1,315.63 ENDURE ENERGY/WSPP A 260 52.000000 13.52 EXELON GENERATION COMPANY LLC/DAILY 6,665 40.565641 270.37 J ARON & COMPANY/WSPP B 2,571 56.503306 145.27 J.P. MORGAN VENTURES ENERGY 25,160 68.000000 1,710.88 JBO/WSPP A 57,191 70.911157 4,055.48 JBO/WSPP B 11,297 70.733823 799.08 MERR LL LYNCH COMMODITIES INC/WSPP B 50,042 50.664842 2,535.37 MICHOD 2/BRDGLN E 5,370 40.242086 216.10 MICHOD 2/GSPL E 12,219 44.370243 542.16 NRG POWER MARKETING LLC./WSPP B 83,767 60.795898 5,092.69 NRG POWER MARKETING LLC./WSPP C 1,351 65.011103 87.83 OCCIDENTAL POWER SERVICES/WSPP B 14,178 66.055156 936.53 SMEPA/WSPP B 1,128 98.510638 111.12 SOUTHERN COMPANY SERVICES INC. AS 60,954 128 000295 7,802.13 SUEZ Energy Marketing NA Inc./WSPP B 13,678 51.788273 708.36 TENASKA/WSPP A 1,370 60.832117 83.34 TENASKA/WSPP B 6,694 63.288019 423.65 UNION POWER PARTNERS/WSPP B 30,359 52.566949 1,595.88 WESTAR ENERGY NC/WSPP B 500 49.260000 24.63 Totals 431,606 69.237383 29,883.27

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2011 ETI Rate Case 9-198 Exhibit PJC-2 2011 TX Rate Case Page 37 of 70

Entergy Electric System Date range - 20100701 through 20100731 Attachment 3 Intra-System Billing-201007RA Joint Account Delivery Sources - Entergy Gulf States Louisiana, LLC Page 37 Source KWH Mills per KWH Charge ACADIA POWER PARTNERS, LLC/WSPP B 32,812 39.956114 1,311.04 AECI/WSPP C SYSTEM FIRM 3,015 62.855721 189.51 AMEREN ENERGY NC. (AE) ACTING /WSPP C 1,871 60.999466 114.13 CALPINE ENERGY SERVICES L.P./WSPP B 14,137 54.792389 774.60 CLECO/WSPP B 76,488 63.829620 4,882.20 CONSTELLATION ENERGY COMMODIT ES 628 45.318471 28.46 DB ENERGY TRADING LLC/WSPP B 102,387 54.443728 5,574.33 DOW PIPELINE COMPANY/INTRA-DAY CALL 10,862 63.936660 694.48 ENDURE ENERGY/WSPP A 1,100 52.000000 57.20 EXELON GENERATION COMPANY LLC/DAILY 28,226 40.569333 1,145.11 J ARON & COMPANY/WSPP B 10,896 56.502386 615.65 J.P. MORGAN VENTURES ENERGY 106,603 67.999869 7,248.99 JBO/WSPP A 242,333 70.911391 17,184.17 JBO/WSPP B 47,860 70.733180 3,385.29 LEWIS CREEK 1/COPANO M 15,337 44.627372 684.45 LEWIS CREEK 1/TETCO E 6,900 43.344928 299.08 LEWIS CREEK 1/TETCO M 1,878 42.923323 80.61 LEWIS CREEK 2/COPANO E 10 43.000000 0.43 LEWIS CREEK 2/COPANO M 519 43.757225 22.71 LEWIS CREEK 2/TETCO E 12,307 45.314049 557.68 LEWIS CREEK 2/TETCO I 1,239 42.695722 52.90 LEWIS CREEK 2/TETCO M 13,767 43.846154 603.63 MERR LL LYNCH COMMODITIES INC/WSPP B 212,012 50.663972 10,741.37 NELSON 4/TENN M 836 43.277512 36.18 NELSON 4/TETCO I 1 40.000000 0.04 NELSON 4/TETCO M 19,976 44.455346 888.04 NRG POWER MARKETING LLC./WSPP B 354,890 60.796219 21,575.97 NRG POWER MARKETING LLC./WSPP C 5,725 65.002620 372.14 OCCIDENTAL POWER SERVICES/WSPP B 60,074 66.051370 3,967.97 SAB NE 1/CENTANA#3 M 575 44.921739 25.83 SAB NE 1/ENBRIDGE E 6 46.666667 0.28 SAB NE 1/ENBRIDGE M 13,745 45.014187 618.72 SAB NE 2/ENBRIDGE E 14,950 44.728428 668.69 SAB NE 2/ENBRIDGE M 1,398 46.108727 64.46 SAB NE 2/STORAGE I 575 46.852174 26.94 SAB NE 3/CENTANA#3 M 4,026 46.395926 186.79 SAB NE 3/ENBRIDGE E 179 46.145251 8.26 SAB NE 3/ENBRIDGE M 71 47.464789 3.37 SAB NE 3/TEJAS M 575 46.121739 26.52 SAB NE 4/ENBRIDGE E 575 44.886957 25.81 SAB NE 5/CENTANA#3 M 12 48.333333 0.58 SMEPA/WSPP B 4,779 98.510149 470.78 SOUTHERN COMPANY SERVICES INC. AS 258,254 127.999992 33,056.51 SUEZ Energy Marketing NA Inc./WSPP B 57,947 51.789739 3,001.06 TENASKA/WSPP A 5,805 60.830319 353.12 TENASKA/WSPP B 28,365 63.289970 1,795.22 UNION POWER PARTNERS/WSPP B 128,615 52.566886 6,760.89 WESTAR ENERGY NC/WSPP B 2,120 49.245283 104.40 WILLOW GLEN 2/BL HOLDINGS E 2,589 44.998069 116.50 WILLOW GLEN 4/BL HOLDINGS E 2,358 45.979644 108.42 Totals 1,912,208 68.251733 130,511.51

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2011 ETI Rate Case 9-199 Exhibit PJC-2 2011 TX Rate Case Page 38 of 70

Entergy Electric System Date range - 20100701 through 20100731 Attachment 3 Intra-System Billing-201007RA Joint Account Delivery Sources - Entergy Texas, Inc Page 38 Source KWH Mills per KWH Charge AECI/WSPP C SYSTEM FIRM 2,575 62.854369 161.85 AMEREN ENERGY NC. (AE) ACTING /WSPP C 1,597 60.989355 97.40 CALPINE ENERGY SERVICES L.P./WSPP B 12,072 54.773857 661.23 CLECO/WSPP B 65,339 63.829413 4,170.55 CONSTELLATION ENERGY COMMODIT ES 537 45.307263 24.33 DB ENERGY TRADING LLC/WSPP B 87,457 54.444241 4,761.53 DOW PIPELINE COMPANY/INTRA-DAY CALL 8,028 63.937469 513.29 ENDURE ENERGY/WSPP A 939 52.002130 48.83 EXELON GENERATION COMPANY LLC/DAILY 24,106 40.568738 977.95 J ARON & COMPANY/WSPP B 9,303 56.492529 525.55 J.P. MORGAN VENTURES ENERGY 91,065 68.000000 6,192.42 JBO/WSPP A 206,999 70.911116 14,678.53 JBO/WSPP B 40,878 70.731689 2,891.37 LEWIS CREEK 1/COPANO M 11,337 44.627326 505.94 LEWIS CREEK 1/TETCO E 5,100 43.345098 221.06 LEWIS CREEK 1/TETCO M 1,387 42.927181 59.54 LEWIS CREEK 2/COPANO E 8 42.500000 0.34 LEWIS CREEK 2/COPANO M 385 43.740260 16.84 LEWIS CREEK 2/TETCO E 9,096 45.313325 412.17 LEWIS CREEK 2/TETCO I 916 42.696507 39.11 LEWIS CREEK 2/TETCO M 10,177 43.846910 446.23 MERR LL LYNCH COMMODITIES INC/WSPP B 181,101 50.663884 9,175.28 NELSON 4/TENN M 618 43.284790 26.75 NELSON 4/TETCO I 1 40.000000 0.04 NELSON 4/TETCO M 14,765 44.453099 656.35 NRG POWER MARKETING LLC./WSPP B 303,142 60.796096 18,429.85 NRG POWER MARKETING LLC./WSPP C 4,888 64.989771 317.67 OCCIDENTAL POWER SERVICES/WSPP B 51,305 66.044440 3,388.41 SAB NE 1/CENTANA#3 M 425 44.941176 19.10 SAB NE 1/ENBRIDGE E 5 48.000000 0.24 SAB NE 1/ENBRIDGE M 10,159 45.018210 457.34 SAB NE 2/ENBRIDGE E 11,050 44.729412 494.26 SAB NE 2/ENBRIDGE M 1,033 46.098742 47.62 SAB NE 2/STORAGE I 425 46.847059 19.91 SAB NE 3/CENTANA#3 M 2,976 46.387769 138.05 SAB NE 3/ENBRIDGE E 133 46.090226 6.13 SAB NE 3/ENBRIDGE M 52 47.307692 2.46 SAB NE 3/TEJAS M 425 46.117647 19.60 SAB NE 4/ENBRIDGE E 425 44.894118 19.08 SAB NE 5/CENTANA#3 M 8 47.500000 0.38 SMEPA/WSPP B 4,083 98.508450 402.21 SOUTHERN COMPANY SERVICES INC. AS 220,624 127.999855 28,239.84 SUEZ Energy Marketing NA Inc./WSPP B 49,501 51.789459 2,563.63 TENASKA/WSPP A 4,956 60.831316 301.48 TENASKA/WSPP B 24,226 63.290267 1,533.27 UNION POWER PARTNERS/WSPP B 109,867 52.567377 5,775.42 WESTAR ENERGY NC/WSPP B 1,810 49.248619 89.14 WILLOW GLEN 2/BL HOLDINGS E 1,912 45.000000 86.04 WILLOW GLEN 4/BL HOLDINGS E 1,742 45.975890 80.09 Totals 1,590,958 68.949463 109,695.70

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2011 ETI Rate Case 9-200 Exhibit PJC-2 2011 TX Rate Case Page 39 of 70

Entergy Electric System Date range - 20100701 through 20100731 Attachment 3 Intra-System Billing-201007RA Joint Account Delivery Sources - Summary Page 39 Source KWH Mills per KWH Charge Entergy Arkansas, Inc. 1,913,306 70.338498 134,579.07 Entergy Louisiana, LLC 2,774,712 72.052321 199,924.44 Entergy Mississippi, Inc. 1,549,246 77.384670 119,887.89 Entergy New Orleans, Inc. 431,606 69.237383 29,883.27 Entergy Gulf States Louisiana, LLC 1,912,208 68.251733 130,511.51 Entergy Texas, Inc 1,590,958 68.949463 109,695.70 Totals 10,172,036 71.222898 724,481.88

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2011 ETI Rate Case 9-201 Exhibit PJC-2 2011 TX Rate Case Page 40 of 70

Entergy Electric System Date range - 20100701 through 20100731 Attachment 3 Intra-System Billing-201007RA Joint Account Deliveries Page 40 KWH Cost Total Energy Supplied for Other Joint Account Sales 10,172,036 724,481.88 Cost to System for Other Joint Account Sales 724,481.88 Total Billing to Other Joint Account Sales 635,035.41 Net Balance From Other Joint Account Sales (89,446.47) Total Net Balance (89,446.47) Total Net Balance - Demand 0.00 Total Net Balance - Energy (89,446.47)

Apportioning of Adjusted Net Balance from Joint Account Sales Company Resp. Ratio Net Balance Entergy Arkansas, Inc. 0 2093 X (89,446.47) = (18,721.14) Entergy Louisiana, LLC 0 2511 X (89,446.47) = (22,460.01) Entergy Mississippi, Inc. 0.1399 X (89,446.47) = (12,513.56) Entergy New Orleans, Inc. 0 0447 X (89,446.47) = (3,998.26) Entergy Gulf States Louisiana, LLC 0.1893 X (89,446.47) = (16,932.22) Entergy Texas, Inc 0.1657 X (89,446.47) = (14,821.28) 1.0000 (89,446.47)

Apportioning of Adjusted Net Balance - Demand and Energy Company Demand Energy Total Entergy Arkansas, Inc. 0 00 (18,721.14) (18,721.14) Entergy Louisiana, LLC 0 00 (22,460.01) (22,460.01) Entergy Mississippi, Inc. 0 00 (12,513.56) (12,513.56) Entergy New Orleans, Inc. 0 00 (3,998.26) (3,998.26) Entergy Gulf States Louisiana, LLC 0 00 (16,932.22) (16,932.22) Entergy Texas, Inc 0 00 (14,821.28) (14,821.28) System 0.00 (89,446.47) (89,446.47)

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2011 ETI Rate Case 9-202 Exhibit PJC-2 2011 TX Rate Case Page 41 of 70

Entergy Electric System Date range - 20100701 through 20100731 Attachment 4 Intra-System Billing-201007RA Coincident Peaks Page 41

Full Load (including interruptible customers) Year Month Day Hour System AR LA MS NO EGSL ETI 2009 7 2 16 20,266,591 4,076,854 5,207,236 2,960,570 960,099 3,864,047 3,197,785 2009 8 4 16 20,101,486 4,324,348 4,993,585 2,920,053 905,162 3,857,302 3,101,036 2009 9 8 16 17,789,153 3,869,828 4,425,469 2,654,403 762,423 3,416,026 2,661,004 2009 10 8 17 17,406,013 3,253,525 4,712,375 2,334,228 855,958 3,496,830 2,753,097 2009 11 17 19 13,100,671 3,023,242 3,553,282 1,773,843 558,074 2,316,730 1,875,500 2009 12 4 19 15,501,240 3,136,408 4,106,356 1,991,288 704,068 3,021,804 2,541,316 2010 1 8 8 18,693,431 3,945,217 4,824,812 2,386,441 857,848 3,136,742 3,542,371 2010 2 25 8 16,411,849 3,546,185 4,165,035 2,070,332 726,106 2,961,626 2,942,565 2010 3 3 7 15,338,210 3,137,824 4,034,685 1,929,748 712,963 2,858,148 2,664,842 2010 4 29 17 14,125,067 3,062,959 3,802,850 1,743,982 598,277 2,756,644 2,160,355 2010 5 24 15 18,755,924 3,909,082 5,001,840 2,640,718 858,007 3,356,689 2,989,588 2010 6 21 16 21,056,833 4,673,598 5,191,088 3,163,850 877,645 3,602,175 3,548,477 Total 0 43,959,070 54,018,613 28,569,456 9,376,630 38,644,763 33,977,936 12-Month Average 3,663,255 4,501,551 2,380,788 781,385 3,220,396 2,831,494 Responsibility Ratio 0.2108 0.2590 0.1370 0 0450 0.1853 0.1629

Load Excluding Interruptible Customers Year Month Day Hour System AR LA MS NO EGSL ETI 2009 7 2 16 19,757,681 3,948,568 4,918,012 2,960,570 929,369 3,856,647 3,144,515 2009 8 4 16 19,684,363 4,238,659 4,759,049 2,920,053 883,034 3,834,101 3,049,467 2009 9 8 16 17,330,307 3,750,282 4,155,695 2,647,732 743,406 3,384,270 2,648,922 2009 10 8 17 17,055,723 3,223,627 4,459,097 2,329,371 841,486 3,469,237 2,732,905 2009 11 30 20 12,842,330 2,926,002 3,295,668 1,772,797 508,186 2,385,320 1,954,357 2009 12 4 19 15,184,415 3,136,164 3,881,283 1,967,199 683,654 2,998,563 2,517,552 2010 1 8 19 18,315,622 3,641,573 4,666,900 2,466,992 879,520 3,150,301 3,510,336 2010 2 25 7 16,157,950 3,426,523 4,006,582 2,070,845 703,193 2,989,430 2,961,377 2010 3 3 7 15,002,144 3,135,491 3,788,194 1,929,748 684,009 2,858,148 2,606,554 2010 4 29 17 13,729,642 2,925,536 3,610,881 1,743,982 577,503 2,729,585 2,142,155 2010 5 24 16 18,381,604 3,776,637 4,758,960 2,614,298 825,064 3,382,890 3,023,755 2010 6 21 16 20,563,419 4,569,484 4,921,567 3,124,114 860,795 3,570,306 3,517,153 Total 0 42,698,546 51,221,888 28,547,701 9,119,219 38,608,798 33,809,048 12-Month Average 3,558,212 4,268,490 2,378,975 759,934 3,217,399 2,817,420 Responsibility Ratio 0.2093 0.2511 0.1399 0 0447 0.1893 0.1657

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2011 ETI Rate Case 9-203 Exhibit PJC-2 2011 TX Rate Case Page 42 of 70

Entergy Electric System Date range - 20100701 through 20100731 Attachment 5 Intra-System Billing-201007RA Service Schedule MSS - 1 / Reserve Equalization Page 42

Source System AR LA MS NO EGSL ETI Owned Capability (A) ANDRUS 712 000 0.000 0.000 712 000 0.000 0.000 0.000 ANO 1,835 000 1,580.486 73.533 35.308 49.812 46.742 49.119 ATTALA 455 000 0.000 0.000 455 000 0.000 0.000 0.000 BAXTER WILSON 1,176 000 0.000 0.000 1,176 000 0.000 0.000 0.000 BIG CAJUN 247 000 0.000 0.000 0 000 0.000 142.025 104.975 BURAS 12 000 0.000 12.000 0 000 0.000 0 000 0.000 CALCASIEU 310 000 0.000 0.000 0 000 0.000 178.250 131.750 CARPENTER & REMMEL 74 000 74.000 0.000 0 000 0.000 0.000 0.000 COUCH 123 000 123.000 0.000 0 000 0.000 0 000 0.000 DELTA 177 000 0.000 0.000 177 000 0.000 0.000 0.000 INDEPENDENCE 682 840 226.815 10.563 424 561 7.163 6 699 7.039 LAKE CATHERINE 712 000 712.000 0.000 0 000 0.000 0 000 0.000 LEWIS CREEK 460 000 0.000 0.000 0 000 0.000 264.500 195.500 LITTLE GYPSY 1,170 000 0.000 1,170.000 0 000 0.000 0.000 0.000 LYNCH 115 000 115.000 0.000 0 000 0.000 0 000 0.000 MABELVALE 56 000 56.000 0.000 0 000 0.000 0.000 0.000 MICHOUD 748 000 0.000 0.000 0 000 748.000 0.000 0.000 MOSES 134 000 134.000 0.000 0 000 0.000 0 000 0.000 NELSON 988 000 0.000 0.000 0 000 0.000 568.100 419.900 NINEMILE PT. 1,599 000 0.000 1,599.000 0 000 0.000 0.000 0.000 OUACHITA 771 000 513.000 0.000 0 000 0.000 258 000 0.000 PERRYVILLE 691 000 0.000 172.750 0 000 0.000 297 995 220.255 REX BROWN 289 000 0.000 0.000 289 000 0.000 0.000 0.000 RITCHIE 16 000 16.000 0.000 0 000 0.000 0.000 0.000 RIVERBEND 681 800 0.000 0.000 0 000 0.000 392.035 289.765 SAB NE 1,814 000 0.000 0.000 0 000 0.000 1,043.050 770.950 STERLINGTON 174 000 0.000 174.000 0 000 0.000 0 000 0.000 WATERFORD 2,021 000 0.000 2,021.000 0 000 0.000 0.000 0.000 WHITE BLUFF 945 631 814.471 37.845 18.213 25.645 24.114 25.343 WILLOW GLEN 817 000 0.000 0.000 0 000 0.000 469.775 347.225 Subtotal Owned Capability (A) 20,006.271 4,364.772 5,270.691 3,287.082 830.620 3,691.285 2,561.821

Capacity Purch. w/o (B) ACADIAPOWERPARTNERS 580 000 0.000 386.667 0 000 0.000 193 333 0.000 BLAKELY-ADD. 11 000 11.000 0.000 0 000 0.000 0.000 0.000 CALPINE CARVILLE 485 000 0.000 0.000 0 000 0.000 485.000 0.000 CONOCOPHIL PS-100 100 000 0.000 0.000 0 000 0.000 57.500 42.500 CONOCOPHIL PS-SRW 100 000 0.000 0.000 0 000 0.000 0.000 100.000 DEGRAY-ADD. 10 000 10.000 0.000 0 000 0.000 0.000 0.000 DOW PIPELINE 100 000 0.000 0.000 0 000 0.000 57.500 42.500 EPI ISES2 121 000 0.000 61.105 0 000 59.895 0 000 0.000 ETEC HARD N 146 000 0.000 0.000 0 000 0.000 0.000 146.000 ETEC HARRISON 50 000 0.000 0.000 0 000 0.000 0.000 50.000 ETEC SAM RAYBURN 34 667 0.000 0.000 0 000 0.000 0.000 34.667 ETEC SAN JACINTO 146 000 0.000 0.000 0 000 0.000 0.000 146.000 ETEC W LLIS 1 244 0.000 0.000 0 000 0.000 0.000 1.244 EXELON FRONTIER 10YR 150 000 0.000 0.000 0 000 0.000 0.000 150.000 GRAND GULF #1 992 878 272.302 157.626 371 550 191.400 0 000 0.000 GRAND GULF #1(RET/RP) 133 023 0.000 39.380 17.831 27.408 23.603 24.801 MEAM 84 000 0.000 0.000 84.000 0.000 0.000 0.000 MURRAY HYDRO 100 910 0.000 100.910 0 000 0.000 0 000 0.000 OCCIDENTAL-OXYTAFT 480 000 0.000 480.000 0 000 0.000 0 000 0.000 RIVERBEND 30 292 200 0.000 194.800 0 000 97.400 0 000 0.000 TOLEDO BEND 69 000 0.000 23.000 0 000 0.000 26.450 19.550 Subtotal Capacity Purch. w/o (B) 4,186.922 293.302 1,443.488 473.381 376.103 843.386 757.262

Contract Capacity (D) EXELON-150 150 000 31.320 37.725 20.910 6.780 28.725 24.540 Subtotal Contract Capacity (D) 150.000 31.320 37.725 20.910 6.780 28.725 24.540

Totals 24,343.193 4,689.394 6,751.904 3,781.373 1,213.503 4,563.396 3,343.623

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2011 ETI Rate Case 9-204 Exhibit PJC-2 2011 TX Rate Case Page 43 of 70

Entergy Electric System Date range - 20100701 through 20100731 Attachment 5 Intra-System Billing-201007RA Service Schedule MSS - 1 / Reserve Equalization Page 43

AR LA MS NO EGSL ETI A. Total Investment (Reserve Basis) (9 225500) 32.030600 41.588200 (17.393100) (10 568500) 64.834900 B. Cost of Capital Debt Ratio 0.476500 0.502800 0.527000 0.455600 0.491300 0.483500 x Bond Cost 0 061600 0.067100 0.063400 0.060700 0.060900 0 075100 + Preferred Ratio 0 039300 0.019900 0.031800 0.047700 0.003200 x Preferred Cost 0 059900 0.075500 0.056900 0.048200 0.087100 + Common Ratio 0.484200 0.477400 0.441200 0.496700 0.505500 0 516500 x Common Cost 0.110000 0.110000 0.110000 0.110000 0.110000 0.110000 Total Cost of Capital 0 084968 0.087754 0.083753 0.084591 0.085804 0 093126 E. Summary ($/KW) 1. Cost of Money (0.783872) 2.810813 3.483137 (1.471300) (0 906820) 6 037815 2. Depreciation 4 392930 5.463640 3.185940 7.406280 4.376400 5 651380 3. Income Tax (0 331149) 1.082090 1.296845 (0.619351) (0 369380) 1 983494 4. Insurance 0.473440 1.712090 1.516810 2.206730 0.485550 0 375450 5. Property Tax 0.764290 1.219660 4.398050 2.406210 2.067020 1 890110 6. Franchise Tax 0 031400 0.194550 0.426430 0.197930 7. Operations & Maintenance + Overhead 21.271470 22.889030 24.841370 34.298770 14.459670 24.806290 Annual Cost per KW 25.818509 35.177323 38.916702 44.653769 20.112440 40.942469 Monthly Cost per KW 2.151542 2.931444 3.243059 3.721147 1.676037 3.411872 Monthly Cost $/MW 2,152 2,931 3,243 3,721 1,676 3,412 System Capability (SC) 24,343.193 Company Capability (CC) 4,689.394 6,751.904 3,781 373 1,213.503 4,563 396 3,343.623 Required Capability (SC x CLR/SLR) 5,095.062 6,112.120 3,406.493 1,088.162 4,607 046 4,034.310 Equalization Reserve (ER = CC - SC x CLR/SLR) (405.668) 639.784 374 880 125.341 (43.650) (690.687) Allocation Factor 0.3558 0.0383 0 6059 Receipts 1,875,205.93 1,215,735.84 466,393.86 Payments 1,265,700.02 136,245.95 2,155,389.66

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2011 ETI Rate Case 9-205 Exhibit PJC-2 2011 TX Rate Case Page 44 of 70

Entergy Electric System Date range - 20100701 through 20100731 Attachment 5 Intra-System Billing-201007RA Service Schedule MSS - 2 / Transmission Equalization Page 44

AR LA MS NO EGSL ETI Total Investment 414,292,644.47 516,998,737.69 270,282,974.70 26,290,825 51 332,286,730.47 246,384,445.14 Deferred Taxes 37,430,361.00 58,063,215.00 30,006,678.00 3,089,864.00 25,629,920 00 19,783,447 00 Depreciation Reserve 162,587,708.00 186,714,652.00 98,019,787.00 14,138,861 00 167,174,252.00 61,398,531 00 Net Transmission Investment 214,274,575.47 272,220,870.69 142,256,509.70 9,062,100.51 139,482,558.47 165,202,467.14 Cost of Capital Debt Ratio (DR) 0.476500 0.502800 0.527000 0.455600 0.491300 0.483500 Bond Cost (i) 0.061600 0.067100 0.063400 0.060700 0.060900 0 075100 Preferred Ratio (PR) 0.039300 0.019900 0.031800 0.047700 0.003200 Preferred Cost (p) 0.059900 0.075500 0.056900 0.048200 0.087100 Common Ratio (ER) 0.484200 0.477400 0.441200 0.496700 0.505500 0 516500 Common Cost (c) 0.110000 0.110000 0.110000 0.110000 0.110000 0.110000 Total Cost of Capital (CM) 0.084968 0.087754 0.083753 0.084591 0.085804 0 093126 Tax Rate (F) 0.035895 0.033783 0.031183 0.035609 0.034951 0 030593 Operating Expenses Depreciation Factor (D) 0.0153010 0 0271140 0.0229240 0.0277360 0.0202970 0.0197710 Insurance Expense (I) 0.0038030 0 0011480 0.0038520 0.0021750 0.0018310 Property Tax (PT) 0.0043820 0 0082710 0.0166890 0.0121940 0.0067670 0.0074320 Franchise Tax (FT) 0.0001530 0.0010110 0.0020450 0.0008500 Operations & Maintenance (OM) 0.0351800 0 0374620 0.0356540 0.0424620 0.0448010 0.0263850 Total Operating Expenses 0.0588190 0 0739950 0.0801300 0.0844370 0.0740400 0.0562690 Net Investment Ratio (K) 0.517206 0.526541 0.526324 0.344687 0.419766 0 670507 Annual Ownership Cost 0.234587 0.262067 0.267180 0.365167 0.297138 0 207639 Net Transmission Investment * AOC 50,266,030.00 71,340,107.00 38,008,094.00 3,309,180.00 41,445,568 00 34,302,475 00 System Average Annual Ownership Cost 238,671,454.00 / 942,499,081.98 = 0.2532326 System Average Monthly Ownership Cost 0.2532326 / 12 0.0211027 Responsibility Ratio 0.2108 0.2590 0.1370 0.0450 0.1853 0.1629 Transmission Responsibility 198,678,806.48 244,107,262.23 129,122,374.23 42,412,458 69 174,645,079.89 153,533,100.45 Investment Difference 15,595,768.99 28,113,608.46 13,134,135.47 (33,350,358.18) (35,162,521.42) 11,669,366 69 Payments 703,783.04 742,024.61 Receipts 329,113.04 593,273.42 277,165.89 246,255.30

Attachment Snapshot: 20100826181933 RunID: 17029 Billing Snapshot: 20100826175238

2011 ETI Rate Case 9-206 Exhibit PJC-2 2011 TX Rate Case Page 45 of 70

Entergy Electric System Date range - 20100701 through 20100731 Attachment 6-AR Intra-System Billing-201007RA Company Summary - Entergy Arkansas, Inc. Page 45

Sales(KWH) Purchases(KWH) Revenue($) Expense($) Purchases and Sales - Associated Companies Exchange Energy 131,743,223 131,563,443 5,265,506.15 8,545,539.76 Tele. AECC Excess Energy 45,883,356 0 1,511,948.91 0.00 ARK.NU 1 Desig. Energy 86,421,339 0 0.00 0.00 ARK.NU 2 Desig. Energy 102,307,792 0 0.00 0.00 GGULF RET Desig. Energy 66,088,728 0 0.00 0.00 GGULF RP Desig. Energy 32,499,259 0 0.00 0.00 INDEPN 1 Desig. Energy 24,696,343 0 0.00 0.00 WH.BLF 1 Desig. Energy 45,314,539 0 0.00 0.00 WH.BLF 2 Desig. Energy 38,134,556 0 0.00 0.00 Equalized Res. Charge 0 0 0.00 1,265,700.02 Trans. Equal. Charge 0 0 0.00 (329,113.04) Fiber Optic Equalization 0 0 0.00 45,958.19 Bandwidth Pymt/Receipt-Opinion Nos. 480 & 480-A 0 0 0.00 3,905,000.00 Subtotal Purchases and Sales - Associated Companies 573,089,135 131,563,443 6,777,455.06 13,433,084.93

Non-Associated Companies - Joint Account Sales Sales(KWH) Purchases(KWH) Revenue($) Expense($) Net Balance for Sales 0 0 (18,721.14) 0.00 Energy Supp. for Sales 1,913,306 0 134,579.07 0.00 AIR LIQUIDE AMERICA - ANN FEE 0 0 2,093.00 0.00 BASF CORPORATION - ANN FEE 0 0 2,093.00 0.00 CENTRAL LA ELEC CO ENG CHG ADJ - REVENUE 0 0 (0.01) 0.00 COTTONWOOD ENERGY CO - GEN REG 0 0 4,911.95 0.00 CYPRES - GEN REG 0 0 8,479.13 0.00 DOW CHEMICAL - ANN FEE 0 0 2,093.00 0.00 DUKE ENERGY HINDS - GEN REG 0 0 3,671.18 0.00 DUKEENERGY HOTSPRING - GEN REG 0 0 8,791.81 0.00 FORMOSA PLASTICS - ANN FEE 0 0 2,093.00 0.00 GRAND RIVER DAM AUTHORITY ENG CHG ADJ - REVENUE 0 0 (0.05) 0.00 HUNTSMAN P.N. - ANN FEE 0 0 2,093.00 0.00 KANSAS CITY POWER & LIGHT COMP ENG CHG ADJ - REVENUE 0 0 0.03 0.00 MAGNET COVE - GEN REG 0 0 1,740.09 0.00 MDEA CROSSROADS - GEN REG 0 0 744.10 0.00 MISSOURI PUBLIC SERVICE ENG CHG ADJ - REVENUE 0 0 0.04 0.00 NEBRASKA PUBLIC POWER DISTRICT ENG CHG ADJ - REVENUE 0 0 (0.05) 0.00 OCCIDENTAL CHEM CORP - GEN REG 0 0 1,164.71 0.00 PINE BLUFF ENERGY - GEN REG 0 0 0.51 0.00 PPG INDUSTR ES - ANN FEE 0 0 2,093.00 0.00 SRW COGENERATION - GEN REG 0 0 682.53 0.00 TENASKA FRONTIER - GEN REG 0 0 3,280.86 0.00 UNION CARBIDE CORP - ANN FEE 0 0 2,093.00 0.00 WRIGHTSVILE POWER - GEN REG 0 0 4,452.16 0.00 YAZOO CITY - GEN REG 0 0 2.49 0.00 Subtotal Non-Associated Companies - Joint Account Sales 1,913,306 0 168,430.41 0.00

Non-Associated Companies - Joint Account Purchases Sales(KWH) Purchases(KWH) Revenue($) Expense($) AECI RE Energy 0 14,296,119 0.00 610,073.17 AEP SERVICE CORP. RE Energy 0 793,440 0.00 27,039.59 AMEREN ENERGY NC. (AE) ACTING RE Energy 0 501,120 0.00 24,554.89 Ameren Energy Marketing Company RE Energy 0 10,440 0.00 334.08 BNP PARIBAS ENERGY TRADING GP RE Energy 0 845,431 0.00 45,316.99 CALP NE ENERGY SERVICES L.P. RE Energy 0 2,789,568 0.00 146,243.56 CARGILL POWER MARKETS LLC RE Energy 0 349,740 0.00 9,888.24 CITIGROUP ENERGY NC RE Energy 0 50,112 0.00 1,681.88 CLECO RE Energy 0 1,048,172 0.00 66,267.70 CONSTELLATION ENERGY COMMODITIES GROUP INC RE Energy 0 1,172,829 0.00 48,758.64 COTTONWOOD ENERGY CO RE Energy 0 783,233 0.00 30,180.30 CYPRES RE Energy 0 30,648 0.00 1,267.50 DB ENERGY TRAD NG LLC RE Energy 0 21,593,680 0.00 1,102,783.95 DUKE ENERGY HINDS RE Energy 0 221,754 0.00 8,431.92 DUKEENERGY HOTSPRING RE Energy 0 199,789 0.00 7,436.91 ENDURE ENERGY RE Energy 0 297,537 0.00 13,904.44 ETEC RE Energy 0 244,298 0.00 10,993.46 EXELON GENERATION COMPANY LLC RE Energy 0 19,524,239 0.00 809,340.37 Attachment Snapshot: 20100826181933 RunID: 17029 Billing Snapshot: 20100826175238

2011 ETI Rate Case 9-207 Exhibit PJC-2 2011 TX Rate Case Page 46 of 70

Entergy Electric System Date range - 20100701 through 20100731 Attachment 6-AR Intra-System Billing-201007RA Company Summary - Entergy Arkansas, Inc. Page 46 Sales(KWH) Purchases(KWH) Revenue($) Expense($) J ARON & COMPANY RE Energy 0 4,984,056 0.00 256,121.06 J.P. MORGAN VENTURES ENERGY CORPORATION RE Energy 0 1,033,979 0.00 69,555.14 JBO RE Energy 0 4,187,691 0.00 275,806.37 KANSAS CITY POWER & LIGHT COMPANY RE Energy 0 300,881 0.00 8,339.06 MAGNET COVE RE Energy 0 1,069,515 0.00 39,180.42 MDEA CROSSROADS RE Energy 0 40,084 0.00 1,700.80 MERRILL LYNCH COMMODITIES INC RE Energy 0 40,521,612 0.00 1,994,933.07 MORGAN STANLEY RE Energy 0 51,366 0.00 1,223.18 NRG POWER MARKETING LLC. RE Energy 0 46,561,153 0.00 2,253,552.56 OCCIDENTAL POWER SERVICES RE Energy 0 1,189,742 0.00 75,381.01 RAINBOW ENERGY MARKETING CORP RE Energy 0 2,907,333 0.00 93,375.97 SMEPA RE Energy 0 626,400 0.00 55,914.95 SOUTHERN COMPANY SERVICES INC. AS AGENT FO RE Energy 0 2,328,120 0.00 287,663.83 SUEZ Energy Marketing NA Inc. RE Energy 0 13,613,136 0.00 646,652.75 TEA RE Energy 0 233,021 0.00 6,829.44 TENASKA FRONTIER RE Energy 0 248,836 0.00 9,376.03 TENASKA RE Energy 0 5,303,526 0.00 318,688.60 UNION POWER PARTNERS RE Energy 0 34,436,751 0.00 1,728,653.96 WESTAR ENERGY NC RE Energy 0 7,784,895 0.00 270,527.41 WRIGHTSVILE POWER RE Energy 0 177,550 0.00 7,503.15 YAZOO CITY RE Energy 0 1,101 0.00 48.70 ENG ADJ - EXPENSE 0 0 0.00 (0.01) EXELON 150 1YR- CAP CHG 0 0 0.00 343,658.70 EXELON GENERATION COMPANY LLC ENG CHG ADJ - EXPENSE 0 0 0.00 (0.01) JAP - DB ENERGY ENG CHG 0 0 0.00 (0.07) JAP - EXELON ENG CHG 0 0 0.00 (0.15) JAP - MLCI ENG CHG 0 0 0.00 (0.20) JAP - NRG ENG CHG 0 0 0.00 (0.21) JAP - SUEZ ENG CHG 0 0 0.00 (0.04) JAP - UNION ENG CHG 0 0 0.00 (0.16) MERRILL LYNCH COMMODITIES ENG CHG ADJ - EXPENSE 0 0 0.00 0.20 SWPP RESER - CAP CHG 0 0 0.00 626.40 SWPP TARIFF CHG 0 0 0.00 152.23 UNION POWER PARTNERS LP ENG CHG ADJ - EXPENSE 0 0 0.00 (0.10) Subtotal Non-Associated Companies - Joint Account Purchases 0 232,352,897 0.00 11,709,961.63

Totals 575,002,441 363,916,340 6,945,885.47 25,143,046.56 ESI Receivable from Entergy Arkansas, Inc. 18,197,161.09

Attachment Snapshot: 20100826181933 RunID: 17029 Billing Snapshot: 20100826175238

2011 ETI Rate Case 9-208 Exhibit PJC-2 2011 TX Rate Case Page 47 of 70

Entergy Electric System Date range - 20100701 through 20100731 Attachment 6-LA Intra-System Billing-201007RA Company Summary - Entergy Louisiana, LLC Page 47

Sales(KWH) Purchases(KWH) Revenue($) Expense($) Purchases and Sales - Associated Companies Exchange Energy 135,105,357 42,272,082 10,226,157.06 2,134,170.65 Tele. AECC Excess Energy 0 14,584,886 0.00 480,598.16 ARK.NU 1 - UPP from AR Desig. Energy 0 24,991,859 0.00 0.00 ARK.NU 2 - UPP from AR Desig. Energy 0 29,534,318 0.00 0.00 GGULF RET - UPP from AR Desig. Energy 0 19,691,908 0.00 0.00 GGULF RP - UPP from AR Desig. Energy 0 9,494,456 0.00 0.00 INDEPN 1 - UPP from AR Desig. Energy 0 7,145,175 0.00 0.00 RVRBND 1 - UPP from EGSL Desig. Energy 0 139,555,800 0.00 0.00 WH.BLF 1 - UPP from AR Desig. Energy 0 13,440,805 0.00 0.00 WH.BLF 2 - UPP from AR Desig. Energy 0 10,706,289 0.00 0.00 ACADIA POWER PARTNERS, LLC/WSPP B Desig. Energy 59,708,320 0 0.00 0.00 PERVIL 1 Desig. Energy 194,914,500 0 0.00 0.00 Equalized Res. Charge 0 0 1,875,205.93 0.00 Trans. Equal. Charge 0 0 0.00 (593,273.42) Fiber Optic Equalization 0 0 0.00 13,548.63 Bandwidth Pymt/Receipt-Opinion Nos. 480 & 480-A 0 0 1,843,000.00 0.00 Subtotal Purchases and Sales - Associated Companies 389,728,177 311,417,578 13,944,362.99 2,035,044.02

Non-Associated Companies - Joint Account Sales Sales(KWH) Purchases(KWH) Revenue($) Expense($) Net Balance for Sales 0 0 (22,460.01) 0.00 Energy Supp. for Sales 2,774,712 0 199,924.44 0.00 AIR LIQUIDE AMERICA - ANN FEE 0 0 2,511.00 0.00 BASF CORPORATION - ANN FEE 0 0 2,511.00 0.00 CENTRAL LA ELEC CO ENG CHG ADJ - REVENUE 0 0 (0.01) 0.00 COTTONWOOD ENERGY CO - GEN REG 0 0 5,892.94 0.00 CYPRES - GEN REG 0 0 10,172.52 0.00 DOW CHEMICAL - ANN FEE 0 0 2,511.00 0.00 DUKE ENERGY HINDS - GEN REG 0 0 4,404.37 0.00 DUKEENERGY HOTSPRING - GEN REG 0 0 10,547.65 0.00 FORMOSA PLASTICS - ANN FEE 0 0 2,511.00 0.00 GRAND RIVER DAM AUTHORITY ENG CHG ADJ - REVENUE 0 0 (0.06) 0.00 HUNTSMAN P.N. - ANN FEE 0 0 2,511.00 0.00 KANSAS CITY POWER & LIGHT COMP ENG CHG ADJ - REVENUE 0 0 0.04 0.00 MAGNET COVE - GEN REG 0 0 2,087.62 0.00 MDEA CROSSROADS - GEN REG 0 0 892.70 0.00 MISSOURI PUBLIC SERVICE ENG CHG ADJ - REVENUE 0 0 0.05 0.00 NEBRASKA PUBLIC POWER DISTRICT ENG CHG ADJ - REVENUE 0 0 (0.06) 0.00 OCCIDENTAL CHEM CORP - GEN REG 0 0 1,397.32 0.00 PINE BLUFF ENERGY - GEN REG 0 0 0.62 0.00 PPG INDUSTR ES - ANN FEE 0 0 2,511.00 0.00 SOUTHWEST POWER ADMN ENG CHG ADJ - REVENUE 0 0 (0.01) 0.00 SRW COGENERATION - GEN REG 0 0 818.84 0.00 TENASKA FRONTIER - GEN REG 0 0 3,936.09 0.00 UNION CARBIDE CORP - ANN FEE 0 0 2,511.00 0.00 WRIGHTSVILE POWER - GEN REG 0 0 5,341.31 0.00 YAZOO CITY - GEN REG 0 0 2.99 0.00 Subtotal Non-Associated Companies - Joint Account Sales 2,774,712 0 240,536.35 0.00

Non-Associated Companies - Joint Account Purchases Sales(KWH) Purchases(KWH) Revenue($) Expense($) ACADIA POWER PARTNERS, LLC RE Energy 0 179,125,000 0.00 6,106,961.20 AECI RE Energy 0 17,219,703 0.00 734,834.42 AEP SERVICE CORP. RE Energy 0 955,700 0.00 32,569.33 AMEREN ENERGY NC. (AE) ACTING RE Energy 0 603,600 0.00 29,576.40 Ameren Energy Marketing Company RE Energy 0 12,575 0.00 402.40 BNP PARIBAS ENERGY TRADING GP RE Energy 0 1,018,324 0.00 54,584.38 BURAS TEMP RE Energy 0 131,908 0.00 34,364.05 CALP NE ENERGY SERVICES L.P. RE Energy 0 3,360,048 0.00 176,151.06 CARGILL POWER MARKETS LLC RE Energy 0 421,265 0.00 11,910.49 CITIGROUP ENERGY NC RE Energy 0 60,361 0.00 2,025.87 CLECO RE Energy 0 1,262,618 0.00 79,826.20 CONSTELLATION ENERGY COMMODITIES GROUP INC RE Energy 0 1,412,677 0.00 58,730.23 COTTONWOOD ENERGY CO RE Energy 0 943,361 0.00 36,350.30 CYPRES RE Energy 0 36,913 0.00 1,526.56 Attachment Snapshot: 20100826181933 RunID: 17029 Billing Snapshot: 20100826175238

2011 ETI Rate Case 9-209 Exhibit PJC-2 2011 TX Rate Case Page 48 of 70

Entergy Electric System Date range - 20100701 through 20100731 Attachment 6-LA Intra-System Billing-201007RA Company Summary - Entergy Louisiana, LLC Page 48 Sales(KWH) Purchases(KWH) Revenue($) Expense($) DB ENERGY TRAD NG LLC RE Energy 0 26,009,688 0.00 1,328,308.08 DUKE ENERGY HINDS RE Energy 0 267,110 0.00 10,156.10 DUKEENERGY HOTSPRING RE Energy 0 240,658 0.00 8,957.84 ENDURE ENERGY RE Energy 0 358,396 0.00 16,748.60 ETEC RE Energy 0 294,260 0.00 13,241.70 EXELON GENERATION COMPANY LLC RE Energy 0 23,517,077 0.00 974,855.35 J ARON & COMPANY RE Energy 0 6,003,359 0.00 308,501.05 J.P. MORGAN VENTURES ENERGY CORPORATION RE Energy 0 1,245,433 0.00 83,779.48 JBO RE Energy 0 5,044,138 0.00 332,212.21 KANSAS CITY POWER & LIGHT COMPANY RE Energy 0 362,411 0.00 10,044.40 MAGNET COVE RE Energy 0 1,288,274 0.00 47,194.28 MDEA CROSSROADS RE Energy 0 48,272 0.00 2,048.17 MERRILL LYNCH COMMODITIES INC RE Energy 0 48,808,429 0.00 2,402,903.87 MORGAN STANLEY RE Energy 0 61,868 0.00 1,473.28 NRG POWER MARKETING LLC. RE Energy 0 56,083,268 0.00 2,714,420.29 OCCIDENTAL POWER SERVICES RE Energy 0 280,091,048 0.00 10,465,221.67 RAINBOW ENERGY MARKETING CORP RE Energy 0 3,501,908 0.00 112,472.37 SMEPA RE Energy 0 754,504 0.00 67,350.01 SOUTHERN COMPANY SERVICES INC. AS AGENT FO RE Energy 0 2,804,225 0.00 346,491.54 SUEZ Energy Marketing NA Inc. RE Energy 0 16,397,077 0.00 778,895.88 TEA RE Energy 0 280,677 0.00 8,226.15 TENASKA FRONTIER RE Energy 0 299,738 0.00 11,293.95 TENASKA RE Energy 0 6,388,123 0.00 383,862.17 UNION POWER PARTNERS RE Energy 0 41,479,230 0.00 2,082,171.87 WESTAR ENERGY NC RE Energy 0 9,376,942 0.00 325,851.13 WRIGHTSVILE POWER RE Energy 0 213,842 0.00 9,036.81 YAZOO CITY RE Energy 0 1,324 0.00 58.57 ACADIA POWER PARTNERS ENG CHG ADJ - EXPENSE 0 0 0.00 14.83 ACADIA PPA - 580 MW - CAP CHG 0 0 0.00 714,364.24 ACADIA PPA - 580 MW -START CHG 0 0 0.00 930,785.87 ACADIA PPA - 580 MW -VOM CHG 0 0 0.00 199,376.00 EXELON 150 1YR- CAP CHG 0 0 0.00 413,937.56 EXELON GENERATION COMPANY LLC ENG CHG ADJ - EXPENSE 0 0 0.00 (0.01) JAP - ACADIA ENG CHG 0 0 0.00 (0.62) JAP - DB ENERGY ENG CHG 0 0 0.00 (0.08) JAP - EXELON ENG CHG 0 0 0.00 (0.18) JAP - MLCI ENG CHG 0 0 0.00 (0.25) JAP - NRG ENG CHG 0 0 0.00 (0.26) JAP - OXY ENG CHG 0 0 0.00 (4.79) JAP - SUEZ ENG CHG 0 0 0.00 (0.05) JAP - UNION ENG CHG 0 0 0.00 (0.20) MERRILL LYNCH COMMODITIES ENG CHG ADJ - EXPENSE 0 0 0.00 0.24 OCCIDENTAL POWER SERVICES NC. - STARTUP CHG - 0 0 0 0.00 231,750.00 OCCIDENTAL POWER SERVICES NC. ENG CHG ADJ - EXPENSE 0 0 0.00 (0.29) OCCIDENTIAL - 480MW - CAP CHG 0 0 0.00 3,399,552.43 SWPP RESER - CAP CHG 0 0 0.00 754.50 SWPP TARIFF CHG 0 0 0.00 183.36 UNION POWER PARTNERS LP ENG CHG ADJ - EXPENSE 0 0 0.00 (0.11) Subtotal Non-Associated Companies - Joint Account Purchases 0 737,785,332 0.00 36,096,301.90

Transmission Service Sales(KWH) Purchases(KWH) Revenue($) Expense($) CLECO TRAN SERV CHG 0 0 0.00 104,767.78 Subtotal Transmission Service 0 0 0.00 104,767.78

Totals 392,502,889 1,049,202,910 14,184,899.34 38,236,113.70 ESI Receivable from Entergy Louisiana, LLC 24,051,214.36

Attachment Snapshot: 20100826181933 RunID: 17029 Billing Snapshot: 20100826175238

2011 ETI Rate Case 9-210 Exhibit PJC-2 2011 TX Rate Case Page 49 of 70

Entergy Electric System Date range - 20100701 through 20100731 Attachment 6-MS Intra-System Billing-201007RA Company Summary - Entergy Mississippi, Inc. Page 49

Sales(KWH) Purchases(KWH) Revenue($) Expense($) Purchases and Sales - Associated Companies Exchange Energy 32,027,550 165,417,337 2,046,403.14 10,587,664.98 Tele. AECC Excess Energy 0 8,083,973 0.00 266,379.39 ARK.NU 1 - UPP from AR Desig. Energy 0 11,975,579 0.00 0.00 ARK.NU 2 - UPP from AR Desig. Energy 0 14,206,469 0.00 0.00 GGULF RET - UPP from AR Desig. Energy 0 8,775,642 0.00 0.00 GGULF RP - UPP from AR Desig. Energy 0 4,440,083 0.00 0.00 INDEPN 1 - UPP from AR Desig. Energy 0 3,421,107 0.00 0.00 WH.BLF 1 - UPP from AR Desig. Energy 0 6,292,389 0.00 0.00 WH.BLF 2 - UPP from AR Desig. Energy 0 5,295,338 0.00 0.00 Equalized Res. Charge 0 0 1,215,735.84 0.00 Trans. Equal. Charge 0 0 0.00 (277,165.89) Fiber Optic Equalization 0 0 0.00 (77,957.98) Bandwidth Pymt/Receipt-Opinion Nos. 480 & 480-A 0 0 2,062,000.00 0.00 Subtotal Purchases and Sales - Associated Companies 32,027,550 227,907,917 5,324,138.98 10,498,920.50

Non-Associated Companies - Joint Account Sales Sales(KWH) Purchases(KWH) Revenue($) Expense($) Net Balance for Sales 0 0 (12,513.56) 0.00 Energy Supp. for Sales 1,549,246 0 119,887.89 0.00 AIR LIQUIDE AMERICA - ANN FEE 0 0 1,399.00 0.00 BASF CORPORATION - ANN FEE 0 0 1,399.00 0.00 COTTONWOOD ENERGY CO - GEN REG 0 0 3,283.24 0.00 CYPRES - GEN REG 0 0 5,667.60 0.00 DOW CHEMICAL - ANN FEE 0 0 1,399.00 0.00 DUKE ENERGY HINDS - GEN REG 0 0 2,453.89 0.00 DUKEENERGY HOTSPRING - GEN REG 0 0 5,876.61 0.00 FORMOSA PLASTICS - ANN FEE 0 0 1,399.00 0.00 GRAND RIVER DAM AUTHORITY ENG CHG ADJ - REVENUE 0 0 (0.04) 0.00 HUNTSMAN P.N. - ANN FEE 0 0 1,399.00 0.00 KANSAS CITY POWER & LIGHT COMP ENG CHG ADJ - REVENUE 0 0 0.02 0.00 MAGNET COVE - GEN REG 0 0 1,163.11 0.00 MDEA CROSSROADS - GEN REG 0 0 497.37 0.00 MISSOURI PUBLIC SERVICE ENG CHG ADJ - REVENUE 0 0 0.03 0.00 NEBRASKA PUBLIC POWER DISTRICT ENG CHG ADJ - REVENUE 0 0 (0.04) 0.00 OCCIDENTAL CHEM CORP - GEN REG 0 0 778.51 0.00 PINE BLUFF ENERGY - GEN REG 0 0 0.34 0.00 PPG INDUSTR ES - ANN FEE 0 0 1,399.00 0.00 SRW COGENERATION - GEN REG 0 0 456.21 0.00 TENASKA FRONTIER - GEN REG 0 0 2,192.99 0.00 UNION CARBIDE CORP - ANN FEE 0 0 1,399.00 0.00 WRIGHTSVILE POWER - GEN REG 0 0 2,975.90 0.00 YAZOO CITY - GEN REG 0 0 1.67 0.00 Subtotal Non-Associated Companies - Joint Account Sales 1,549,246 0 142,514.74 0.00

Non-Associated Companies - Joint Account Purchases Sales(KWH) Purchases(KWH) Revenue($) Expense($) AECI RE Energy 0 9,544,439 0.00 407,299.61 AEP SERVICE CORP. RE Energy 0 529,720 0.00 18,052.30 AMEREN ENERGY NC. (AE) ACTING RE Energy 0 334,560 0.00 16,393.44 Ameren Energy Marketing Company RE Energy 0 6,970 0.00 223.04 BNP PARIBAS ENERGY TRADING GP RE Energy 0 564,431 0.00 30,254.63 CALP NE ENERGY SERVICES L.P. RE Energy 0 1,862,384 0.00 97,635.84 CARGILL POWER MARKETS LLC RE Energy 0 233,494 0.00 6,601.61 CITIGROUP ENERGY NC RE Energy 0 33,456 0.00 1,122.87 CLECO RE Energy 0 699,790 0.00 44,242.50 CONSTELLATION ENERGY COMMODITIES GROUP INC RE Energy 0 783,010 0.00 32,552.49 COTTONWOOD ENERGY CO RE Energy 0 522,874 0.00 20,147.91 CYPRES RE Energy 0 20,463 0.00 846.28 DB ENERGY TRAD NG LLC RE Energy 0 14,416,465 0.00 736,245.05 DUKE ENERGY HINDS RE Energy 0 147,968 0.00 5,625.85 DUKEENERGY HOTSPRING RE Energy 0 133,374 0.00 4,964.61 ENDURE ENERGY RE Energy 0 198,650 0.00 9,283.31 ETEC RE Energy 0 163,098 0.00 7,339.39 EXELON GENERATION COMPANY LLC RE Energy 0 13,034,879 0.00 540,336.52 J ARON & COMPANY RE Energy 0 3,327,478 0.00 170,992.64 Attachment Snapshot: 20100826181933 RunID: 17029 Billing Snapshot: 20100826175238

2011 ETI Rate Case 9-211 Exhibit PJC-2 2011 TX Rate Case Page 50 of 70

Entergy Electric System Date range - 20100701 through 20100731 Attachment 6-MS Intra-System Billing-201007RA Company Summary - Entergy Mississippi, Inc. Page 50 Sales(KWH) Purchases(KWH) Revenue($) Expense($) J.P. MORGAN VENTURES ENERGY CORPORATION RE Energy 0 690,309 0.00 46,436.66 JBO RE Energy 0 2,795,808 0.00 184,135.12 KANSAS CITY POWER & LIGHT COMPANY RE Energy 0 200,875 0.00 5,567.35 MAGNET COVE RE Energy 0 714,090 0.00 26,159.84 MDEA CROSSROADS RE Energy 0 26,755 0.00 1,135.26 MEAM CANTON 1 IN RE Energy 0 73,000 0.00 8,826.43 MEAM CANTON 2 IN RE Energy 0 83,000 0.00 10,035.53 MEAM CANTON 3 IN RE Energy 0 84,000 0.00 10,156.44 MEAM CANTON 4 IN RE Energy 0 84,000 0.00 10,156.44 MEAM CANTON 5 IN RE Energy 0 82,000 0.00 9,914.62 MEAM HENDERSON 10 IN RE Energy 0 58,000 0.00 7,012.78 MEAM HENDERSON 11 IN RE Energy 0 59,000 0.00 7,133.69 MEAM HENDERSON 2 IN RE Energy 0 524,000 0.00 63,355.61 MEAM HENDERSON 4 IN RE Energy 0 72,000 0.00 8,705.52 MEAM HENDERSON 5 IN RE Energy 0 72,000 0.00 8,705.52 MEAM HENDERSON 6 IN RE Energy 0 73,000 0.00 8,826.43 MEAM HENDERSON 7 IN RE Energy 0 76,000 0.00 9,189.16 MEAM HENDERSON 8 IN RE Energy 0 74,000 0.00 8,947.34 MEAM HENDERSON 9 IN RE Energy 0 54,000 0.00 6,529.14 MERRILL LYNCH COMMODITIES INC RE Energy 0 27,053,226 0.00 1,331,865.81 MORGAN STANLEY RE Energy 0 34,292 0.00 816.61 NRG POWER MARKETING LLC. RE Energy 0 31,085,352 0.00 1,504,525.39 OCCIDENTAL POWER SERVICES RE Energy 0 794,302 0.00 50,326.31 RAINBOW ENERGY MARKETING CORP RE Energy 0 1,941,010 0.00 62,340.08 SMEPA RE Energy 0 418,200 0.00 37,330.24 SOUTHERN COMPANY SERVICES INC. AS AGENT FO RE Energy 0 1,554,310 0.00 192,051.39 SUEZ Energy Marketing NA Inc. RE Energy 0 9,088,455 0.00 431,720.89 TEA RE Energy 0 155,570 0.00 4,559.48 TENASKA FRONTIER RE Energy 0 166,087 0.00 6,258.00 TENASKA RE Energy 0 3,540,763 0.00 212,764.09 UNION POWER PARTNERS RE Energy 0 22,990,829 0.00 1,154,092.08 WESTAR ENERGY NC RE Energy 0 5,197,380 0.00 180,610.47 WRIGHTSVILE POWER RE Energy 0 118,533 0.00 5,009.24 YAZOO CITY RE Energy 0 734 0.00 32.46 EXELON 150 1YR- CAP CHG 0 0 0.00 229,434.98 JAP - DB ENERGY ENG CHG 0 0 0.00 (0.04) JAP - EXELON ENG CHG 0 0 0.00 (0.10) JAP - MEAM ENG CHG 0 0 0.00 (2.03) JAP - MLCI ENG CHG 0 0 0.00 (0.14) JAP - NRG ENG CHG 0 0 0.00 (0.14) JAP - SUEZ ENG CHG 0 0 0.00 (0.02) JAP - UNION ENG CHG 0 0 0.00 (0.11) MERRILL LYNCH COMMODITIES ENG CHG ADJ - EXPENSE 0 0 0.00 0.13 SWPP RESER - CAP CHG 0 0 0.00 418.20 SWPP TARIFF CHG 0 0 0.00 101.63 UNION POWER PARTNERS LP ENG CHG ADJ - EXPENSE 0 0 0.00 (0.06) Subtotal Non-Associated Companies - Joint Account Purchases 0 156,592,383 0.00 7,995,343.61

Totals 33,576,796 384,500,300 5,466,653.72 18,494,264.11 ESI Receivable from Entergy Mississippi, Inc. 13,027,610.39

Attachment Snapshot: 20100826181933 RunID: 17029 Billing Snapshot: 20100826175238

2011 ETI Rate Case 9-212 Exhibit PJC-2 2011 TX Rate Case Page 51 of 70

Entergy Electric System Date range - 20100701 through 20100731 Attachment 6-NO Intra-System Billing-201007RA Company Summary - Entergy New Orleans, Inc. Page 51

Sales(KWH) Purchases(KWH) Revenue($) Expense($) Purchases and Sales - Associated Companies Exchange Energy 31,587,544 45,025,369 1,956,214.96 2,623,552.75 Tele. AECC Excess Energy 0 2,621,176 0.00 86,371.53 ARK.NU 1 - UPP from AR Desig. Energy 0 16,947,775 0.00 0.00 ARK.NU 2 - UPP from AR Desig. Energy 0 19,989,454 0.00 0.00 GGULF RET - UPP from AR Desig. Energy 0 13,799,542 0.00 0.00 GGULF RP - UPP from AR Desig. Energy 0 6,514,363 0.00 0.00 INDEPN 1 - UPP from AR Desig. Energy 0 4,846,579 0.00 0.00 RVRBND 1 - UPP from EGSL Desig. Energy 0 69,777,900 0.00 0.00 WH.BLF 1 - UPP from AR Desig. Energy 0 8,494,462 0.00 0.00 WH.BLF 2 - UPP from AR Desig. Energy 0 7,753,353 0.00 0.00 Equalized Res. Charge 0 0 466,393.86 0.00 Trans. Equal. Charge 0 0 0.00 703,783.04 Fiber Optic Equalization 0 0 0.00 18,451.16 Subtotal Purchases and Sales - Associated Companies 31,587,544 195,769,973 2,422,608.82 3,432,158.48

Non-Associated Companies - Joint Account Sales Sales(KWH) Purchases(KWH) Revenue($) Expense($) Net Balance for Sales 0 0 (3,998.26) 0.00 Energy Supp. for Sales 431,606 0 29,883.27 0.00 AIR LIQUIDE AMERICA - ANN FEE 0 0 447.00 0.00 BASF CORPORATION - ANN FEE 0 0 447.00 0.00 COTTONWOOD ENERGY CO - GEN REG 0 0 1,049.04 0.00 CYPRES - GEN REG 0 0 1,810.88 0.00 DOW CHEMICAL - ANN FEE 0 0 447.00 0.00 DUKE ENERGY HINDS - GEN REG 0 0 784.05 0.00 DUKEENERGY HOTSPRING - GEN REG 0 0 1,877.66 0.00 FORMOSA PLASTICS - ANN FEE 0 0 447.00 0.00 GRAND RIVER DAM AUTHORITY ENG CHG ADJ - REVENUE 0 0 (0.01) 0.00 HUNTSMAN P.N. - ANN FEE 0 0 447.00 0.00 KANSAS CITY POWER & LIGHT COMP ENG CHG ADJ - REVENUE 0 0 0.01 0.00 MAGNET COVE - GEN REG 0 0 371.63 0.00 MDEA CROSSROADS - GEN REG 0 0 158.92 0.00 MISSOURI PUBLIC SERVICE ENG CHG ADJ - REVENUE 0 0 0.01 0.00 NEBRASKA PUBLIC POWER DISTRICT ENG CHG ADJ - REVENUE 0 0 (0.01) 0.00 OCCIDENTAL CHEM CORP - GEN REG 0 0 248.75 0.00 PINE BLUFF ENERGY - GEN REG 0 0 0.11 0.00 PPG INDUSTR ES - ANN FEE 0 0 447.00 0.00 SRW COGENERATION - GEN REG 0 0 145.76 0.00 TENASKA FRONTIER - GEN REG 0 0 700.69 0.00 UNION CARBIDE CORP - ANN FEE 0 0 447.00 0.00 WRIGHTSVILE POWER - GEN REG 0 0 950.84 0.00 YAZOO CITY - GEN REG 0 0 0.53 0.00 Subtotal Non-Associated Companies - Joint Account Sales 431,606 0 37,112.87 0.00

Non-Associated Companies - Joint Account Purchases Sales(KWH) Purchases(KWH) Revenue($) Expense($) AECI RE Energy 0 3,094,753 0.00 132,065.67 AEP SERVICE CORP. RE Energy 0 171,760 0.00 5,853.40 AMEREN ENERGY NC. (AE) ACTING RE Energy 0 108,480 0.00 5,315.53 Ameren Energy Marketing Company RE Energy 0 2,260 0.00 72.32 BNP PARIBAS ENERGY TRADING GP RE Energy 0 183,015 0.00 9,809.91 CALP NE ENERGY SERVICES L.P. RE Energy 0 603,872 0.00 31,658.15 CARGILL POWER MARKETS LLC RE Energy 0 75,710 0.00 2,140.56 CITIGROUP ENERGY NC RE Energy 0 10,848 0.00 364.09 CLECO RE Energy 0 226,908 0.00 14,346.26 CONSTELLATION ENERGY COMMODITIES GROUP INC RE Energy 0 253,889 0.00 10,555.07 COTTONWOOD ENERGY CO RE Energy 0 169,522 0.00 6,532.24 CYPRES RE Energy 0 6,638 0.00 274.46 DB ENERGY TRAD NG LLC RE Energy 0 4,674,492 0.00 238,724.80 DUKE ENERGY HINDS RE Energy 0 47,920 0.00 1,821.89 DUKEENERGY HOTSPRING RE Energy 0 43,232 0.00 1,609.44 ENDURE ENERGY RE Energy 0 64,413 0.00 3,010.19 ETEC RE Energy 0 52,882 0.00 2,379.67 EXELON GENERATION COMPANY LLC RE Energy 0 4,226,539 0.00 175,202.96 J ARON & COMPANY RE Energy 0 1,078,924 0.00 55,443.44 Attachment Snapshot: 20100826181933 RunID: 17029 Billing Snapshot: 20100826175238

2011 ETI Rate Case 9-213 Exhibit PJC-2 2011 TX Rate Case Page 52 of 70

Entergy Electric System Date range - 20100701 through 20100731 Attachment 6-NO Intra-System Billing-201007RA Company Summary - Entergy New Orleans, Inc. Page 52 Sales(KWH) Purchases(KWH) Revenue($) Expense($) J.P. MORGAN VENTURES ENERGY CORPORATION RE Energy 0 223,829 0.00 15,056.82 JBO RE Energy 0 906,533 0.00 59,705.32 KANSAS CITY POWER & LIGHT COMPANY RE Energy 0 65,133 0.00 1,805.19 MAGNET COVE RE Energy 0 231,513 0.00 8,481.26 MDEA CROSSROADS RE Energy 0 8,680 0.00 368.22 MERRILL LYNCH COMMODITIES INC RE Energy 0 8,771,914 0.00 431,852.92 MORGAN STANLEY RE Energy 0 11,118 0.00 264.74 NRG POWER MARKETING LLC. RE Energy 0 10,079,323 0.00 487,837.23 OCCIDENTAL POWER SERVICES RE Energy 0 257,550 0.00 16,318.15 RAINBOW ENERGY MARKETING CORP RE Energy 0 629,363 0.00 20,213.51 SMEPA RE Energy 0 135,600 0.00 12,104.24 SOUTHERN COMPANY SERVICES INC. AS AGENT FO RE Energy 0 503,980 0.00 62,272.05 SUEZ Energy Marketing NA Inc. RE Energy 0 2,946,902 0.00 139,984.20 TEA RE Energy 0 50,443 0.00 1,478.40 TENASKA FRONTIER RE Energy 0 53,858 0.00 2,029.38 TENASKA RE Energy 0 1,148,074 0.00 68,987.77 UNION POWER PARTNERS RE Energy 0 7,454,707 0.00 374,211.01 WESTAR ENERGY NC RE Energy 0 1,685,241 0.00 58,562.31 WRIGHTSVILE POWER RE Energy 0 38,409 0.00 1,623.20 YAZOO CITY RE Energy 0 237 0.00 10.49 EXELON 150 1YR- CAP CHG 0 0 0.00 74,393.55 JAP - DB ENERGY ENG CHG 0 0 0.00 (0.01) JAP - EXELON ENG CHG 0 0 0.00 (0.03) JAP - MLCI ENG CHG 0 0 0.00 (0.04) JAP - NRG ENG CHG 0 0 0.00 (0.05) JAP - SUEZ ENG CHG 0 0 0.00 (0.01) JAP - UNION ENG CHG 0 0 0.00 (0.04) MERRILL LYNCH COMMODITIES ENG CHG ADJ - EXPENSE 0 0 0.00 0.04 SWPP RESER - CAP CHG 0 0 0.00 135.60 SWPP TARIFF CHG 0 0 0.00 32.95 UNION POWER PARTNERS LP ENG CHG ADJ - EXPENSE 0 0 0.00 (0.02) Subtotal Non-Associated Companies - Joint Account Purchases 0 50,298,464 0.00 2,534,908.40

Totals 32,019,150 246,068,437 2,459,721.69 5,967,066.88 ESI Receivable from Entergy New Orleans, Inc. 3,507,345.19

Attachment Snapshot: 20100826181933 RunID: 17029 Billing Snapshot: 20100826175238

2011 ETI Rate Case 9-214 Exhibit PJC-2 2011 TX Rate Case Page 53 of 70

Entergy Electric System Date range - 20100701 through 20100731 Attachment 6-EGSL Intra-System Billing-201007RA Company Summary - Entergy Gulf States Louisiana, LLC Page 53

Sales(KWH) Purchases(KWH) Revenue($) Expense($) Purchases and Sales - Associated Companies Exchange Energy 388,628,993 8,681,301 23,688,200.69 328,900.36 Tele. AECC Excess Energy 0 11,105,658 0.00 365,958.24 ACADIA POWER PARTNERS, LLC/WSPP B - UPP from LA Desig. Energy 0 59,708,320 0.00 0.00 ARK.NU 1 - UPP from AR Desig. Energy 0 15,851,160 0.00 0.00 ARK.NU 2 - UPP from AR Desig. Energy 0 18,809,417 0.00 0.00 GGULF RET - UPP from AR Desig. Energy 0 11,616,357 0.00 0.00 GGULF RP - UPP from AR Desig. Energy 0 5,876,574 0.00 0.00 INDEPN 1 - UPP from AR Desig. Energy 0 4,526,010 0.00 0.00 LEWIS CREEK 1 - UPP from ETI Desig. Energy 0 58,217,025 0.00 0.00 LEWIS CREEK 2 - UPP from ETI Desig. Energy 0 65,725,375 0.00 0.00 PERVIL 1 - UPP from LA Desig. Energy 0 194,914,500 0.00 0.00 SABINE 1 - UPP from ETI Desig. Energy 0 51,146,250 0.00 0.00 SABINE 2 - UPP from ETI Desig. Energy 0 50,562,050 0.00 0.00 SABINE 3 - UPP from ETI Desig. Energy 0 80,097,500 0.00 0.00 SABINE 4 - UPP from ETI Desig. Energy 0 76,167,950 0.00 0.00 SABINE 5 - UPP from ETI Desig. Energy 0 70,933,725 0.00 0.00 WH.BLF 1 - UPP from AR Desig. Energy 0 8,331,086 0.00 0.00 WH.BLF 2 - UPP from AR Desig. Energy 0 7,011,078 0.00 0.00 CALCAS EU 1 Desig. Energy 4,690,725 0 0.00 0.00 CALCAS EU 2 Desig. Energy 5,250,450 0 0.00 0.00 NELSON 3 Desig. Energy 5,192,225 0 0.00 0.00 NELSON 4 Desig. Energy 62,280,775 0 0.00 0.00 PERVIL 1 Desig. Energy 82,838,753 0 0.00 0.00 RVRBND 1 Desig. Energy 416,923,129 0 0.00 0.00 WILLOW GLEN 1 Desig. Energy 5,445,950 0 0.00 0.00 WILLOW GLEN 2 Desig. Energy 10,391,250 0 0.00 0.00 WILLOW GLEN 4 Desig. Energy 77,447,750 0 0.00 0.00 Equalized Res. Charge 0 0 0.00 136,245.95 Trans. Equal. Charge 0 0 0.00 742,024.61 Subtotal Purchases and Sales - Associated Companies 1,059,090,000 799,281,336 23,688,200.69 1,573,129.16

Non-Associated Companies - Joint Account Sales Sales(KWH) Purchases(KWH) Revenue($) Expense($) Net Balance for Sales 0 0 (16,932.22) 0.00 Energy Supp. for Sales 1,912,208 0 130,511.51 0.00 AIR LIQUIDE AMERICA - ANN FEE 0 0 1,893.00 0.00 BASF CORPORATION - ANN FEE 0 0 1,893.00 0.00 CENTRAL LA ELEC CO ENG CHG ADJ - REVENUE 0 0 (0.01) 0.00 COTTONWOOD ENERGY CO - GEN REG 0 0 4,442.59 0.00 CYPRES - GEN REG 0 0 7,668.89 0.00 DOW CHEMICAL - ANN FEE 0 0 1,893.00 0.00 DUKE ENERGY HINDS - GEN REG 0 0 3,320.38 0.00 DUKEENERGY HOTSPRING - GEN REG 0 0 7,951.70 0.00 FORMOSA PLASTICS - ANN FEE 0 0 1,893.00 0.00 GRAND RIVER DAM AUTHORITY ENG CHG ADJ - REVENUE 0 0 (0.05) 0.00 HUNTSMAN P.N. - ANN FEE 0 0 1,893.00 0.00 KANSAS CITY POWER & LIGHT COMP ENG CHG ADJ - REVENUE 0 0 0.03 0.00 MAGNET COVE - GEN REG 0 0 1,573.82 0.00 MDEA CROSSROADS - GEN REG 0 0 672.99 0.00 MISSOURI PUBLIC SERVICE ENG CHG ADJ - REVENUE 0 0 0.04 0.00 NEBRASKA PUBLIC POWER DISTRICT ENG CHG ADJ - REVENUE 0 0 (0.05) 0.00 OCCIDENTAL CHEM CORP - GEN REG 0 0 1,053.41 0.00 PINE BLUFF ENERGY - GEN REG 0 0 0.47 0.00 PPG INDUSTR ES - ANN FEE 0 0 1,893.00 0.00 SRW COGENERATION - GEN REG 0 0 617.31 0.00 TENASKA FRONTIER - GEN REG 0 0 2,967.35 0.00 UNION CARBIDE CORP - ANN FEE 0 0 1,893.00 0.00 WRIGHTSVILE POWER - GEN REG 0 0 4,026.72 0.00 YAZOO CITY - GEN REG 0 0 2.25 0.00 Subtotal Non-Associated Companies - Joint Account Sales 1,912,208 0 161,128.13 0.00

Non-Associated Companies - Joint Account Purchases Sales(KWH) Purchases(KWH) Revenue($) Expense($) ACADIA POWER PARTNERS, LLC RE Energy 0 0 0.00 (0.01) AECI RE Energy 0 13,111,621 0.00 559,525.81 Attachment Snapshot: 20100826181933 RunID: 17029 Billing Snapshot: 20100826175238

2011 ETI Rate Case 9-215 Exhibit PJC-2 2011 TX Rate Case Page 54 of 70

Entergy Electric System Date range - 20100701 through 20100731 Attachment 6-EGSL Intra-System Billing-201007RA Company Summary - Entergy Gulf States Louisiana, LLC Page 54 Sales(KWH) Purchases(KWH) Revenue($) Expense($) AEP SERVICE CORP. RE Energy 0 727,700 0.00 24,799.18 AMEREN ENERGY NC. (AE) ACTING RE Energy 0 459,600 0.00 22,520.40 Ameren Energy Marketing Company RE Energy 0 9,575 0.00 306.40 BNP PARIBAS ENERGY TRADING GP RE Energy 0 775,383 0.00 41,562.12 CALP NE A BASE IN RE Energy 0 137,098,200 0.00 4,886,179.84 CALP NE B BASE IN RE Energy 0 98,223,400 0.00 3,779,830.92 CALP NE C BASE IN RE Energy 0 5,787,100 0.00 275,641.39 CALP NE B RAMP IN RE Energy 0 1,973,300 0.00 75,957.00 CALP NE C RAMP IN RE Energy 0 34,100 0.00 1,317.79 CALP NE ENERGY SERVICES L.P. RE Energy 0 2,558,432 0.00 134,126.16 CALP NE EXCESS N RE Energy 0 422,000 0.00 14,994.68 CARGILL POWER MARKETS LLC RE Energy 0 320,760 0.00 9,068.87 CITIGROUP ENERGY NC RE Energy 0 45,959 0.00 1,542.49 CLECO RE Energy 0 961,242 0.00 60,771.75 CONOCOPH LLIPS COMPANY RE Energy 0 1,969,375 0.00 117,903.00 CONSTELLATION ENERGY COMMODITIES GROUP INC RE Energy 0 1,075,654 0.00 44,718.46 COTTONWOOD ENERGY CO RE Energy 0 718,363 0.00 27,680.48 CYPRES RE Energy 0 28,106 0.00 1,162.40 DB ENERGY TRAD NG LLC RE Energy 0 19,804,486 0.00 1,011,410.14 DOW P PELINE COMPANY RE Energy 0 2,127,500 0.00 132,892.87 DUKE ENERGY HINDS RE Energy 0 203,359 0.00 7,732.15 DUKEENERGY HOTSPRING RE Energy 0 183,255 0.00 6,821.62 ENDURE ENERGY RE Energy 0 272,879 0.00 12,752.13 ETEC RE Energy 0 224,050 0.00 10,082.27 EXELON GENERATION COMPANY LLC RE Energy 0 17,906,524 0.00 742,280.74 J ARON & COMPANY RE Energy 0 4,571,051 0.00 234,897.47 J.P. MORGAN VENTURES ENERGY CORPORATION RE Energy 0 948,303 0.00 63,791.79 JBO RE Energy 0 3,840,670 0.00 252,951.97 KANSAS CITY POWER & LIGHT COMPANY RE Energy 0 275,952 0.00 7,648.14 MAGNET COVE RE Energy 0 980,951 0.00 35,935.90 MDEA CROSSROADS RE Energy 0 36,766 0.00 1,560.00 MERRILL LYNCH COMMODITIES INC RE Energy 0 37,164,138 0.00 1,829,640.85 MORGAN STANLEY RE Energy 0 47,110 0.00 1,121.82 NRG POWER MARKETING LLC. RE Energy 0 42,703,074 0.00 2,066,821.42 OCCIDENTAL POWER SERVICES RE Energy 0 1,091,166 0.00 69,135.39 RAINBOW ENERGY MARKETING CORP RE Energy 0 2,666,424 0.00 85,638.22 SMEPA RE Energy 0 574,496 0.00 51,281.84 SOUTHERN COMPANY SERVICES INC. AS AGENT FO RE Energy 0 2,135,225 0.00 263,829.55 SUEZ Energy Marketing NA Inc. RE Energy 0 12,485,194 0.00 593,072.66 TEA RE Energy 0 213,711 0.00 6,263.48 TENASKA FRONTIER RE Energy 0 228,269 0.00 8,601.20 TENASKA RE Energy 0 4,864,077 0.00 292,282.06 UNION POWER PARTNERS RE Energy 0 31,583,431 0.00 1,585,423.12 WESTAR ENERGY NC RE Energy 0 7,139,870 0.00 248,112.40 WRIGHTSVILE POWER RE Energy 0 162,823 0.00 6,880.95 YAZOO CITY RE Energy 0 1,011 0.00 44.72 CALP NE-CARVILLE - STARTUP CHG - 0 0 0 0.00 196,850.41 CARVILLE - 485 MW - CAP CHG 0 0 0.00 2,430,000.00 CONOCO PHIL PS - 100 MW - CAP CHG 0 0 0.00 94,875.00 DOW - 100 MW - CAP CHG 0 0 0.00 86,250.00 DOW P PELINE COMPANY ENG CHG ADJ - EXPENSE 0 0 0.00 0.29 EXELON 150 1YR- CAP CHG 0 0 0.00 315,185.06 JAP - ACADIA ADJ ENG CHG 0 0 0.00 0.01 JAP - CONOCO ENG CHG 0 0 0.00 (0.05) JAP - DB ENERGY ENG CHG 0 0 0.00 (0.06) JAP - EXELON ENG CHG 0 0 0.00 (0.14) JAP - MLCI ENG CHG 0 0 0.00 (0.19) JAP - NRG ENG CHG 0 0 0.00 (0.20) JAP - SUEZ ENG CHG 0 0 0.00 (0.03) JAP - UNION ENG CHG 0 0 0.00 (0.15) MERRILL LYNCH COMMODITIES ENG CHG ADJ - EXPENSE 0 0 0.00 0.18 SWPP RESER - CAP CHG 0 0 0.00 574.50 SWPP TARIFF CHG 0 0 0.00 139.61 UNION POWER PARTNERS LP ENG CHG ADJ - EXPENSE 0 0 0.00 (0.09) Subtotal Non-Associated Companies - Joint Account Purchases 0 460,735,635 0.00 22,832,390.15

Totals 1,061,002,208 1,260,016,971 23,849,328.82 24,405,519.31 ESI Receivable from Entergy Gulf States Louisiana, LLC 556,190.49

Attachment Snapshot: 20100826181933 RunID: 17029 Billing Snapshot: 20100826175238

2011 ETI Rate Case 9-216 Exhibit PJC-2 2011 TX Rate Case Page 55 of 70

Entergy Electric System Date range - 20100701 through 20100731 Attachment 6-ETI Intra-System Billing-201007RA Company Summary - Entergy Texas, Inc Page 55

Sales(KWH) Purchases(KWH) Revenue($) Expense($) Purchases and Sales - Associated Companies Exchange Energy 2,259,218 328,392,353 181,081.08 19,143,734.58 Tele. AECC Excess Energy 0 9,487,663 0.00 312,641.59 ARK.NU 1 - UPP from AR Desig. Energy 0 16,654,966 0.00 0.00 ARK.NU 2 - UPP from AR Desig. Energy 0 19,768,134 0.00 0.00 CALCAS EU 1 - UPP from EGSL Desig. Energy 0 4,690,725 0.00 0.00 CALCAS EU 2 - UPP from EGSL Desig. Energy 0 5,250,450 0.00 0.00 GGULF RET - UPP from AR Desig. Energy 0 12,205,279 0.00 0.00 GGULF RP - UPP from AR Desig. Energy 0 6,173,783 0.00 0.00 INDEPN 1 - UPP from AR Desig. Energy 0 4,757,472 0.00 0.00 NELSON 3 - UPP from EGSL Desig. Energy 0 5,192,225 0.00 0.00 NELSON 4 - UPP from EGSL Desig. Energy 0 62,280,775 0.00 0.00 PERVIL 1 - UPP from EGSL Desig. Energy 0 82,838,753 0.00 0.00 RVRBND 1 - UPP from EGSL Desig. Energy 0 207,589,429 0.00 0.00 WH.BLF 1 - UPP from AR Desig. Energy 0 8,755,797 0.00 0.00 WH.BLF 2 - UPP from AR Desig. Energy 0 7,368,498 0.00 0.00 WILLOW GLEN 1 - UPP from EGSL Desig. Energy 0 5,445,950 0.00 0.00 WILLOW GLEN 2 - UPP from EGSL Desig. Energy 0 10,391,250 0.00 0.00 WILLOW GLEN 4 - UPP from EGSL Desig. Energy 0 77,447,750 0.00 0.00 LEWIS CREEK 1 Desig. Energy 58,217,025 0 0.00 0.00 LEWIS CREEK 2 Desig. Energy 65,725,375 0 0.00 0.00 SABINE 1 Desig. Energy 51,146,250 0 0.00 0.00 SABINE 2 Desig. Energy 50,562,050 0 0.00 0.00 SABINE 3 Desig. Energy 80,097,500 0 0.00 0.00 SABINE 4 Desig. Energy 76,167,950 0 0.00 0.00 SABINE 5 Desig. Energy 70,933,725 0 0.00 0.00 Equalized Res. Charge 0 0 0.00 2,155,389.66 Trans. Equal. Charge 0 0 0.00 (246,255.30) Subtotal Purchases and Sales - Associated Companies 455,109,093 874,691,252 181,081.08 21,365,510.53

Non-Associated Companies - Joint Account Sales Sales(KWH) Purchases(KWH) Revenue($) Expense($) Net Balance for Sales 0 0 (14,821.28) 0.00 Energy Supp. for Sales 1,590,958 0 109,695.70 0.00 AIR LIQUIDE AMERICA - ANN FEE 0 0 1,657.00 0.00 BASF CORPORATION - ANN FEE 0 0 1,657.00 0.00 CENTRAL LA ELEC CO ENG CHG ADJ - REVENUE 0 0 (0.01) 0.00 COTTONWOOD ENERGY CO - GEN REG 0 0 3,888.73 0.00 CYPRES - GEN REG 0 0 6,712.81 0.00 DOW CHEMICAL - ANN FEE 0 0 1,657.00 0.00 DUKE ENERGY HINDS - GEN REG 0 0 2,906.42 0.00 DUKEENERGY HOTSPRING - GEN REG 0 0 6,960.36 0.00 FORMOSA PLASTICS - ANN FEE 0 0 1,657.00 0.00 GRAND RIVER DAM AUTHORITY ENG CHG ADJ - REVENUE 0 0 (0.04) 0.00 HUNTSMAN P.N. - ANN FEE 0 0 1,657.00 0.00 KANSAS CITY POWER & LIGHT COMP ENG CHG ADJ - REVENUE 0 0 0.03 0.00 MAGNET COVE - GEN REG 0 0 1,377.61 0.00 MDEA CROSSROADS - GEN REG 0 0 589.09 0.00 MISSOURI PUBLIC SERVICE ENG CHG ADJ - REVENUE 0 0 0.03 0.00 NEBRASKA PUBLIC POWER DISTRICT ENG CHG ADJ - REVENUE 0 0 (0.04) 0.00 OCCIDENTAL CHEM CORP - GEN REG 0 0 922.08 0.00 PINE BLUFF ENERGY - GEN REG 0 0 0.41 0.00 PPG INDUSTR ES - ANN FEE 0 0 1,657.00 0.00 SRW COGENERATION - GEN REG 0 0 540.35 0.00 TENASKA FRONTIER - GEN REG 0 0 2,597.42 0.00 UNION CARBIDE CORP - ANN FEE 0 0 1,657.00 0.00 WRIGHTSVILE POWER - GEN REG 0 0 3,524.71 0.00 YAZOO CITY - GEN REG 0 0 1.97 0.00 Subtotal Non-Associated Companies - Joint Account Sales 1,590,958 0 136,495.35 0.00

Non-Associated Companies - Joint Account Purchases Sales(KWH) Purchases(KWH) Revenue($) Expense($) AECI RE Energy 0 11,201,365 0.00 478,007.57 AEP SERVICE CORP. RE Energy 0 621,680 0.00 21,186.20 AMEREN ENERGY NC. (AE) ACTING RE Energy 0 392,640 0.00 19,239.34 Ameren Energy Marketing Company RE Energy 0 8,180 0.00 261.76 Attachment Snapshot: 20100826181933 RunID: 17029 Billing Snapshot: 20100826175238

2011 ETI Rate Case 9-217 Exhibit PJC-2 2011 TX Rate Case Page 56 of 70

Entergy Electric System Date range - 20100701 through 20100731 Attachment 6-ETI Intra-System Billing-201007RA Company Summary - Entergy Texas, Inc Page 56 Sales(KWH) Purchases(KWH) Revenue($) Expense($) BNP PARIBAS ENERGY TRADING GP RE Energy 0 662,416 0.00 35,506.97 CALP NE ENERGY SERVICES L.P. RE Energy 0 2,185,696 0.00 114,585.23 CARGILL POWER MARKETS LLC RE Energy 0 274,031 0.00 7,747.73 CITIGROUP ENERGY NC RE Energy 0 39,264 0.00 1,317.80 CLECO RE Energy 0 821,270 0.00 51,922.59 CONOCOPH LLIPS COMPANY RE Energy 0 1,575,625 0.00 94,510.83 CONSTELLATION ENERGY COMMODITIES GROUP INC RE Energy 0 918,941 0.00 38,203.61 COTTONWOOD ENERGY CO RE Energy 0 613,669 0.00 23,646.38 CYPRES RE Energy 0 24,013 0.00 993.07 DB ENERGY TRAD NG LLC RE Energy 0 16,919,189 0.00 864,058.62 DOW P PELINE COMPANY RE Energy 0 1,572,500 0.00 98,225.13 DUKE ENERGY HINDS RE Energy 0 173,693 0.00 6,603.99 DUKEENERGY HOTSPRING RE Energy 0 156,582 0.00 5,828.80 ENDURE ENERGY RE Energy 0 233,125 0.00 10,894.33 ETEC EXCESS-HRSNHRDN RE Energy 0 4,937 0.00 176.69 ETEC RE Energy 0 191,412 0.00 8,613.51 EXELON FRONT ER 10YR RE Energy 0 93,424,000 0.00 3,266,581.59 EXELON GENERATION COMPANY LLC RE Energy 0 15,297,742 0.00 634,138.34 HARDIN RE Energy 0 9,029,000 0.00 488,396.52 J ARON & COMPANY RE Energy 0 3,905,132 0.00 200,676.84 J.P. MORGAN VENTURES ENERGY CORPORATION RE Energy 0 810,147 0.00 54,498.11 JBO RE Energy 0 3,281,160 0.00 216,101.01 KANSAS CITY POWER & LIGHT COMPANY RE Energy 0 235,748 0.00 6,533.86 MAGNET COVE RE Energy 0 838,011 0.00 30,699.64 MDEA CROSSROADS RE Energy 0 31,413 0.00 1,332.85 MERRILL LYNCH COMMODITIES INC RE Energy 0 31,749,681 0.00 1,563,079.13 MORGAN STANLEY RE Energy 0 40,246 0.00 958.37 NRG POWER MARKETING LLC. RE Energy 0 36,481,830 0.00 1,765,715.06 OCCIDENTAL POWER SERVICES RE Energy 0 932,192 0.00 59,062.49 RAINBOW ENERGY MARKETING CORP RE Energy 0 2,277,962 0.00 73,162.10 SAN JACINTO 1 RE Energy 0 5,722,000 0.00 353,399.75 SAN JACINTO 2 RE Energy 0 5,612,000 0.00 346,601.58 SMEPA RE Energy 0 490,800 0.00 43,810.72 SOUTHERN COMPANY SERVICES INC. AS AGENT FO RE Energy 0 1,824,140 0.00 225,391.64 SUEZ Energy Marketing NA Inc. RE Energy 0 10,666,236 0.00 506,668.80 TEA RE Energy 0 182,578 0.00 5,351.05 TENASKA FRONTIER RE Energy 0 194,958 0.00 7,346.06 TENASKA RE Energy 0 4,155,437 0.00 249,700.11 UNION POWER PARTNERS RE Energy 0 26,982,052 0.00 1,354,443.71 WESTAR ENERGY NC RE Energy 0 6,099,672 0.00 211,965.28 WRIGHTSVILE POWER RE Energy 0 139,079 0.00 5,877.43 YAZOO CITY RE Energy 0 863 0.00 38.17 CONOCO PHIL PS - 100 MW - CAP CHG 0 0 0.00 70,125.00 DOW - 100 MW - CAP CHG 0 0 0.00 63,750.00 DOW P PELINE COMPANY ENG CHG ADJ - EXPENSE 0 0 0.00 0.21 ETEC - STARTUP CHG - 0 0 0 0.00 46,121.40 ETEC - STARTUP CHG - 1 0 0 0.00 39,203.19 ETEC SAN JAC- 146 MW - CAP CHG 0 0 0.00 985,500.00 EXELON 150 10YR- CAP CHG 0 0 0.00 1,527,900.00 EXELON 150 1YR- CAP CHG 0 0 0.00 269,265.15 EXELON GENERATION COMPANY LLC - STARTUP CHG - 0 0 0 0.00 70,880.00 JAP - CONOCO ENG CHG 0 0 0.00 (0.03) JAP - DB ENERGY ENG CHG 0 0 0.00 (0.05) JAP - EXELON ENG CHG 0 0 0.00 (0.12) JAP - HARDIN ENG CHG 0 0 0.00 0.01 JAP - MLCI ENG CHG 0 0 0.00 (0.16) JAP - NRG ENG CHG 0 0 0.00 (0.17) JAP - SAN JAC ENG CHG 0 0 0.00 0.05 JAP - SUEZ ENG CHG 0 0 0.00 (0.03) JAP - UNION ENG CHG 0 0 0.00 (0.13) MERRILL LYNCH COMMODITIES ENG CHG ADJ - EXPENSE 0 0 0.00 0.16 SWPP RESER - CAP CHG 0 0 0.00 490.80 SWPP TARIFF CHG 0 0 0.00 119.27 UNION POWER PARTNERS LP ENG CHG ADJ - EXPENSE 0 0 0.00 (0.07) Subtotal Non-Associated Companies - Joint Account Purchases 0 298,994,307 0.00 16,626,414.84

Totals 456,700,051 1,173,685,559 317,576.43 37,991,925.37 ESI Receivable from Entergy Texas, Inc 37,674,348.94

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2011 ETI Rate Case 9-218 Exhibit PJC-2 2011 TX Rate Case Page 57 of 70

Entergy Electric System Date range - 20100701 through 20100731 Attachment 6-System Intra-System Billing-201007RA System Summary Page 57

Net Receivable from Entergy Arkansas, Inc. 18,197,161.09 Net Receivable from Entergy Louisiana, LLC 24,051,214.36 Net Receivable from Entergy Mississippi, Inc. 13,027,610.39 Net Receivable from Entergy New Orleans, Inc. 3,507,345.19 Net Receivable from Entergy Gulf States Louisiana, LLC 556,190.49 Net Receivable from Entergy Texas, Inc 37,674,348.94 Net Receivable from System Companies 97,013,870.46

Net Payable to Outside Companies (97,013,870.46)

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Entergy Electric System Date range - 20100701 through 20100731 Attachment 11 Intra-System Billing-201007RA Joint Account / Individual Company Purchases Page 58

Description KWH Mills per KWH Charge ACADIA POWER PARTNERS, LLC/WSPP B LA 179,125,000 34 0933 6,106,961.20 Total 179,125,000 34.0933 6,106,961.20 AECI/WSPP A AR 499,659 28 6147 14,297.61 LA 601,840 28 6147 17,221.49 MS 333,584 28 6147 9,545.41 NO 108,163 28 6147 3,095 05 EGSL 458,259 28 6147 13,112.93 ETI 391,495 28 6147 11,202.51 Total 2,393,000 28.6147 68,475.00 AECI/WSPP B AR 4,176,000 38 0000 158,688 00 LA 5,030,000 38 0000 191,140 00 MS 2,788,000 38 0000 105,944 00 NO 904,000 38 0000 34,352.00 EGSL 3,830,000 38 0000 145,540 00 ETI 3,272,000 38 0000 124,336 00 Total 20,000,000 38.0000 760,000.00 AECI/WSPP C SYSTEM FIRM AR 9,620,460 45.4331 437,087 56 LA 11,587,863 45.4331 526,472 93 MS 6,422,855 45.4331 291,810 20 NO 2,082,590 45.4331 94,618.62 EGSL 8,823,362 45.4331 400,872 88 ETI 7,537,870 45.4331 342,469 06 Total 46,075,000 45.4331 2,093,331.25 AEP SERVICE CORP./WSPP A AR 626,400 30.1000 18,854.63 LA 754,500 30.1000 22,710.45 MS 418,200 30.1000 12,587.82 NO 135,600 30.1000 4,081 56 EGSL 574,500 30.1000 17,292.46 ETI 490,800 30.1000 14,773.08 Total 3,000,000 30.1000 90,300.00 AEP SERVICE CORP./WSPP C AR 167,040 49 0000 8,184 96 LA 201,200 49 0000 9,858 88 MS 111,520 49 0000 5,464.48 NO 36,160 49 0000 1,771 84 EGSL 153,200 49 0000 7,506.72 ETI 130,880 49 0000 6,413.12 Total 800,000 49.0000 39,200.00 AMEREN ENERGY INC. (AE) ACTING /WSPP C SYSTEM FIRM AR 501,120 49 0000 24,554.89 LA 603,600 49 0000 29,576.40 MS 334,560 49 0000 16,393.44 NO 108,480 49 0000 5,315 53 EGSL 459,600 49 0000 22,520.40 ETI 392,640 49 0000 19,239.34 Total 2,400,000 49.0000 117,600.00 AMEREN ENERGY MARKETING COMPANY/WSPP A AR 10,440 32 0000 334 08 LA 12,575 32 0000 402.40 MS 6,970 32 0000 223 04 NO 2,260 32 0000 72.32 EGSL 9,575 32 0000 306.40 ETI 8,180 32 0000 261.76 Total 50,000 32.0000 1,600.00 BNP PAR BAS ENERGY TRAD NG GP/WSPP A AR 41,760 35 5000 1,482.48 LA 50,300 35 5000 1,785 65 MS 27,880 35 5000 989.74 NO 9,040 35 5000 320 92 EGSL 38,300 35 5000 1,359 65 Attachment Snapshot: 20100826181933 RunID: 17029 Billing Snapshot: 20100826175238

2011 ETI Rate Case 9-220 Exhibit PJC-2 2011 TX Rate Case Page 59 of 70

Entergy Electric System Date range - 20100701 through 20100731 Attachment 11 Intra-System Billing-201007RA Joint Account / Individual Company Purchases Page 59 Description KWH Mills per KWH Charge ETI 32,720 35 5000 1,161 56 Total 200,000 35.5000 7,100.00 BNP PAR BAS ENERGY TRAD NG GP/WSPP B AR 803,671 54 5427 43,834.51 LA 968,024 54 5427 52,798.73 MS 536,551 54 5427 29,264.89 NO 173,975 54 5427 9,488 99 EGSL 737,083 54 5427 40,202.47 ETI 629,696 54 5427 34,345.41 Total 3,849,000 54.5427 209,935.00 BURAS TEMP LA 131,908 260 5153 34,364.05 Total 131,908 260.5153 34,364.05 CALPINE A BASE N EGSL 137,098,200 35 6400 4,886,179.84 Total 137,098,200 35.6400 4,886,179.84 CALPINE B BASE N EGSL 98,223,400 38.4820 3,779,830.92 Total 98,223,400 38.4820 3,779,830.92 CALPINE C BASE IN EGSL 5,787,100 47 6303 275,641 39 Total 5,787,100 47.6303 275,641.39 CALPINE B RAMP IN EGSL 1,973,300 38.4924 75,957.00 Total 1,973,300 38.4924 75,957.00 CALPINE C RAMP IN EGSL 34,100 38 6449 1,317.79 Total 34,100 38.6449 1,317.79 CALPINE ENERGY SERVICES L P /WSPP B AR 2,789,568 52.4251 146,243 56 LA 3,360,048 52.4251 176,151 06 MS 1,862,384 52.4251 97,635.84 NO 603,872 52.4251 31,658.15 EGSL 2,558,432 52.4251 134,126.16 ETI 2,185,696 52.4251 114,585 23 Total 13,360,000 52.4251 700,400.00 CALPINE EXCESS IN EGSL 422,000 35 5324 14,994.68 Total 422,000 35.5324 14,994.68 CARGILL POWER MARKETS LLC/WSPP A AR 349,740 28 2731 9,888 24 LA 421,265 28 2731 11,910.49 MS 233,494 28 2731 6,601 61 NO 75,710 28 2731 2,140 56 EGSL 320,760 28 2731 9,068 87 ETI 274,031 28 2731 7,747.73 Total 1,675,000 28.2731 47,357.50 CITIGROUP ENERGY INC/WSPP A AR 50,112 33 5625 1,681 88 LA 60,361 33 5625 2,025 87 MS 33,456 33 5625 1,122 87 NO 10,848 33 5625 364 09 EGSL 45,959 33 5625 1,542.49 ETI 39,264 33 5625 1,317 80 Total 240,000 33.5625 8,055.00 CLECO/WSPP B AR 1,048,172 63 2225 66,267.70 LA 1,262,618 63 2225 79,826.20 MS 699,790 63 2225 44,242.50 NO 226,908 63 2225 14,346.26 EGSL 961,242 63 2225 60,771.75 ETI 821,270 63 2225 51,922.59 Total 5,020,000 63.2225 317,377.00 Attachment Snapshot: 20100826181933 RunID: 17029 Billing Snapshot: 20100826175238

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Entergy Electric System Date range - 20100701 through 20100731 Attachment 11 Intra-System Billing-201007RA Joint Account / Individual Company Purchases Page 60 Description KWH Mills per KWH Charge

CONOCOPHILLIPS COMPANY / NTRA-DAY CALL OPTION EGSL 1,969,375 59 9193 117,903 00 ETI 1,575,625 59 9193 94,510.83 Total 3,545,000 59.9193 212,413.83 CONSTELLATION ENERGY COMMODITIES GROUP INC/WSPP A AR 37,584 30.7500 1,155.70 LA 45,271 30.7500 1,392 08 MS 25,092 30.7500 771 58 NO 8,136 30.7500 250.19 EGSL 34,469 30.7500 1,059 92 ETI 29,448 30.7500 905 53 Total 180,000 30.7500 5,535.00 CONSTELLATION ENERGY COMMODITIES GROUP INC/WSPP C AR 1,135,245 41 9319 47,602.94 LA 1,367,406 41 9319 57,338.15 MS 757,918 41 9319 31,780.91 NO 245,753 41 9319 10,304.88 EGSL 1,041,185 41 9319 43,658.54 ETI 889,493 41 9319 37,298.08 Total 5,437,000 41.9319 227,983.50 COTTONWOOD ENERGY CO/EXS50 AR 41,619 20 8668 868.44 LA 50,135 20 8668 1,046.16 MS 27,787 20 8668 579 81 NO 9,005 20 8668 187 93 EGSL 38,172 20 8668 796 52 ETI 32,612 20 8668 680 51 Total 199,330 20.8668 4,159.37 COTTONWOOD ENERGY CO/EXS75 AR 10,037 30.4381 305.49 LA 12,102 30.4381 368 39 MS 6,703 30.4381 204 00 NO 2,169 30.4381 65.99 EGSL 9,218 30.4381 280 59 ETI 7,868 30.4381 239 52 Total 48,097 30.4381 1,463.98 COTTONWOOD ENERGY CO/EXS90 AR 438,669 40 3917 17,718.60 LA 528,321 40 3917 21,339.80 MS 292,830 40 3917 11,828.07 NO 94,934 40 3917 3,834 55 EGSL 402,325 40 3917 16,250.50 ETI 343,686 40 3917 13,882.01 Total 2,100,765 40.3917 84,853.53 COTTONWOOD ENERGY CO/EXSSS50 AR 2,541 18 5781 47.21 LA 3,060 18 5781 56.85 MS 1,696 18 5781 31.51 NO 550 18 5781 10.22 EGSL 2,330 18 5781 43.28 ETI 1,990 18 5781 36.97 Total 12,167 18.5781 226.04 COTTONWOOD ENERGY CO/EXSSTSH AR 290,367 38.7115 11,240.56 LA 349,743 38.7115 13,539.10 MS 193,858 38.7115 7,504 52 NO 62,864 38.7115 2,433 55 EGSL 266,318 38.7115 10,309.59 ETI 227,513 38.7115 8,807 37 Total 1,390,663 38.7115 53,834.69 CYPRES/EXS50 AR 3,999 25 0501 100.18 LA 4,816 25 0501 120 64 MS 2,669 25 0501 66.86 NO 866 25 0501 21.69 EGSL 3,667 25 0501 91.86 Attachment Snapshot: 20100826181933 RunID: 17029 Billing Snapshot: 20100826175238

2011 ETI Rate Case 9-222 Exhibit PJC-2 2011 TX Rate Case Page 61 of 70

Entergy Electric System Date range - 20100701 through 20100731 Attachment 11 Intra-System Billing-201007RA Joint Account / Individual Company Purchases Page 61 Description KWH Mills per KWH Charge ETI 3,133 25 0501 78.48 Total 19,150 25.0501 479.71 CYPRES/EXS75 AR 219 37 5714 8 23 LA 264 37 5714 9 92 MS 146 37 5714 5.48 NO 48 37 5714 1 80 EGSL 201 37 5714 7 56 ETI 172 37 5714 6.46 Total 1,050 37.5714 39.45 CYPRES/EXS90 AR 26,430 43 8542 1,159 09 LA 31,833 43 8542 1,396 00 MS 17,648 43 8542 773 94 NO 5,724 43 8542 250 97 EGSL 24,238 43 8542 1,062 98 ETI 20,708 43 8542 908.13 Total 126,581 43.8542 5,551.11 DB ENERGY TRADING LLC/WSPP B AR 21,593,680 51 0697 1,102,783.95 LA 26,009,688 51 0697 1,328,308.08 MS 14,416,465 51 0697 736,245 05 NO 4,674,492 51 0697 238,724 80 EGSL 19,804,486 51 0697 1,011,410.14 ETI 16,919,189 51 0697 864,058 62 Total 103,418,000 51.0697 5,281,530.64 DOW PIPELINE COMPANY/INTRA-DAY CALL OPTION EGSL 2,127,500 62.4643 132,892 87 ETI 1,572,500 62.4643 98,225.13 Total 3,700,000 62.4643 231,118.00 DUKE ENERGY HINDS/EXS50 AR 23,661 20 8211 492 65 LA 28,499 20 8211 593 37 MS 15,797 20 8211 328 92 NO 5,123 20 8211 106 67 EGSL 21,701 20 8211 451 87 ETI 18,538 20 8211 385 95 Total 113,319 20.8211 2,359.43 DUKE ENERGY HINDS/EXS75 AR 17,266 31 3792 541 80 LA 20,807 31 3792 652 91 MS 11,523 31 3792 361 59 NO 3,726 31 3792 116 93 EGSL 15,831 31 3792 496.77 ETI 13,524 31 3792 424 34 Total 82,677 31.3792 2,594.34 DUKE ENERGY HINDS/EXS90 AR 180,827 40 9076 7,397.47 LA 217,804 40 9076 8,909 82 MS 120,648 40 9076 4,935 34 NO 39,071 40 9076 1,598 29 EGSL 165,827 40 9076 6,783 51 ETI 141,631 40 9076 5,793.70 Total 865,808 40.9076 35,418.13 DUKEENERGY HOTSPRING/EXS50 AR 29,273 19 2460 563.40 LA 35,260 19 2460 678 64 MS 19,538 19 2460 376 00 NO 6,334 19 2460 121 89 EGSL 26,842 19 2460 516 59 ETI 22,927 19 2460 441 27 Total 140,174 19.2460 2,697.79 DUKEENERGY HOTSPRING/EXS75 AR 17,619 29 9495 527 68 LA 21,226 29 9495 635.70 MS 11,762 29 9495 352 26 Attachment Snapshot: 20100826181933 RunID: 17029 Billing Snapshot: 20100826175238

2011 ETI Rate Case 9-223 Exhibit PJC-2 2011 TX Rate Case Page 62 of 70

Entergy Electric System Date range - 20100701 through 20100731 Attachment 11 Intra-System Billing-201007RA Joint Account / Individual Company Purchases Page 62 Description KWH Mills per KWH Charge NO 3,804 29 9495 113 89 EGSL 16,148 29 9495 483 64 ETI 13,806 29 9495 413 52 Total 84,365 29.9495 2,526.69 DUKEENERGY HOTSPRING/EXS90 AR 152,741 41 5455 6,345 83 LA 183,983 41 5455 7,643 50 MS 101,969 41 5455 4,236 35 NO 33,061 41 5455 1,373 66 EGSL 140,121 41 5455 5,821 39 ETI 119,726 41 5455 4,974 01 Total 731,601 41.5455 30,394.74 DUKEENERGY HOTSPRING/FREE AR 156 0 0000 0 00 LA 189 0 0000 0 00 MS 105 0 0000 0 00 NO 33 0 0000 0 00 EGSL 144 0 0000 0 00 ETI 123 0 0000 0 00 Total 750 0.0000 0.00 ENDURE ENERGY/WSPP A AR 283,965 47.7228 13,551.56 LA 342,048 47.7228 16,323.56 MS 189,589 47.7228 9,047.72 NO 61,475 47.7228 2,933 80 EGSL 260,432 47.7228 12,428.51 ETI 222,491 47.7228 10,617.85 Total 1,360,000 47.7228 64,903.00 ENDURE ENERGY/WSPP B AR 13,572 26 0000 352 88 LA 16,348 26 0000 425 04 MS 9,061 26 0000 235 59 NO 2,938 26 0000 76.39 EGSL 12,447 26 0000 323 62 ETI 10,634 26 0000 276.48 Total 65,000 26.0000 1,690.00 EPI-ISES ELI IN LA 35,090,137 18.7385 657,536.48 Total 35,090,137 18.7385 657,536.48 EPI-ISES ENOI IN NO 34,395,193 18.7385 644,515 01 Total 34,395,193 18.7385 644,515.01 ETEC EXCESS-HRSNHRDN ETI 4,937 35.7889 176 69 Total 4,937 35.7889 176.69 ETEC/WSPP B AR 244,298 45 0000 10,993.46 LA 294,260 45 0000 13,241.70 MS 163,098 45 0000 7,339 39 NO 52,882 45 0000 2,379 67 EGSL 224,050 45 0000 10,082.27 ETI 191,412 45 0000 8,613 51 Total 1,170,000 45.0000 52,650.00 EXELON FRONTIER 10YR ETI 93,424,000 34 9651 3,266,581.59 Total 93,424,000 34.9651 3,266,581.59 EXELON GENERATION COMPANY LLC/DAILY CALL OPTION AR 19,524,239 41.4531 809,340 37 LA 23,517,077 41.4531 974,855 35 MS 13,034,879 41.4531 540,336 52 NO 4,226,539 41.4531 175,202 96 EGSL 17,906,524 41.4531 742,280.74 ETI 15,297,742 41.4531 634,138 34 Total 93,507,000 41.4531 3,876,154.28

Attachment Snapshot: 20100826181933 RunID: 17029 Billing Snapshot: 20100826175238

2011 ETI Rate Case 9-224 Exhibit PJC-2 2011 TX Rate Case Page 63 of 70

Entergy Electric System Date range - 20100701 through 20100731 Attachment 11 Intra-System Billing-201007RA Joint Account / Individual Company Purchases Page 63 Description KWH Mills per KWH Charge HARD N ETI 9,029,000 54 0920 488,396 52 Total 9,029,000 54.0920 488,396.52 J ARON & COMPANY/WSPP B AR 4,984,056 51 3880 256,121 06 LA 6,003,359 51 3880 308,501 05 MS 3,327,478 51 3880 170,992 64 NO 1,078,924 51 3880 55,443.44 EGSL 4,571,051 51 3880 234,897.47 ETI 3,905,132 51 3880 200,676 84 Total 23,870,000 51.3880 1,226,632.50 J.P. MORGAN VENTURES ENERGY CORPORATION/WSPP A AR 13,990 14 0000 195 86 LA 16,851 14 0000 235 91 MS 9,340 14 0000 130.76 NO 3,028 14 0000 42.39 EGSL 12,830 14 0000 179 62 ETI 10,961 14 0000 153.46 Total 67,000 14.0000 938.00 J.P. MORGAN VENTURES ENERGY CORPORATION/WSPP B AR 1,019,989 68 0000 69,359.28 LA 1,228,582 68 0000 83,543.57 MS 680,969 68 0000 46,305.90 NO 220,801 68 0000 15,014.43 EGSL 935,473 68 0000 63,612.17 ETI 799,186 68 0000 54,344.65 Total 4,885,000 68.0000 332,180.00 JBO/WSPP A AR 2,019,305 71 3696 144,116 87 LA 2,432,270 71 3696 173,590 05 MS 1,348,137 71 3696 96,215.96 NO 437,129 71 3696 31,197.70 EGSL 1,851,983 71 3696 132,175 27 ETI 1,582,176 71 3696 112,919.15 Total 9,671,000 71.3696 690,215.00 JBO/WSPP B AR 2,168,386 60.7315 131,689 50 LA 2,611,868 60.7315 158,622.16 MS 1,447,671 60.7315 87,919.16 NO 469,404 60.7315 28,507.62 EGSL 1,988,687 60.7315 120,776.70 ETI 1,698,984 60.7315 103,181 86 Total 10,385,000 60.7315 630,697.00 KANSAS CITY POWER & LIGHT COMPANY/WSPP A AR 300,881 27.7155 8,339 06 LA 362,411 27.7155 10,044.40 MS 200,875 27.7155 5,567 35 NO 65,133 27.7155 1,805.19 EGSL 275,952 27.7155 7,648.14 ETI 235,748 27.7155 6,533 86 Total 1,441,000 27.7155 39,938.00 MAGNET COVE/EXS75 AR 3,545 35 2498 124 96 LA 4,270 35 2498 150 52 MS 2,366 35 2498 83.40 NO 767 35 2498 27.04 EGSL 3,251 35 2498 114 59 ETI 2,777 35 2498 97.89 Total 16,976 35.2498 598.40 MAGNET COVE/EXS90 AR 164,007 38 6344 6,336 37 LA 197,598 38 6344 7,634 03 MS 109,555 38 6344 4,232 55 NO 35,498 38 6344 1,371 51 EGSL 150,472 38 6344 5,813 28 ETI 128,521 38 6344 4,965.45 Total 785,651 38.6344 30,353.19 Attachment Snapshot: 20100826181933 RunID: 17029 Billing Snapshot: 20100826175238

2011 ETI Rate Case 9-225 Exhibit PJC-2 2011 TX Rate Case Page 64 of 70

Entergy Electric System Date range - 20100701 through 20100731 Attachment 11 Intra-System Billing-201007RA Joint Account / Individual Company Purchases Page 64 Description KWH Mills per KWH Charge

MAGNET COVE/EXSSTSH AR 901,963 36 2754 32,719.09 LA 1,086,406 36 2754 39,409.73 MS 602,169 36 2754 21,843.89 NO 195,248 36 2754 7,082.71 EGSL 827,228 36 2754 30,008.03 ETI 706,713 36 2754 25,636.30 Total 4,319,727 36.2754 156,699.75 MDEA CROSSROADS/EXS50 AR 4,846 24 3350 117 93 LA 5,838 24 3350 142 08 MS 3,235 24 3350 78.73 NO 1,052 24 3350 25.58 EGSL 4,443 24 3350 108.12 ETI 3,797 24 3350 92.40 Total 23,211 24.3350 564.84 MDEA CROSSROADS/EXS75 AR 977 36.1678 35.34 LA 1,178 36.1678 42.61 MS 653 36.1678 23.63 NO 212 36.1678 7 66 EGSL 896 36.1678 32.40 ETI 768 36.1678 27.77 Total 4,684 36.1678 169.41 MDEA CROSSROADS/EXS90 AR 34,261 45.1687 1,547 53 LA 41,256 45.1687 1,863.48 MS 22,867 45.1687 1,032 90 NO 7,416 45.1687 334 98 EGSL 31,427 45.1687 1,419.48 ETI 26,848 45.1687 1,212 68 Total 164,075 45.1687 7,411.05 MEAM CANTON 1 IN MS 73,000 120 9100 8,826.43 Total 73,000 120.9100 8,826.43 MEAM CANTON 2 IN MS 83,000 120 9100 10,035.53 Total 83,000 120.9100 10,035.53 MEAM CANTON 3 IN MS 84,000 120 9100 10,156.44 Total 84,000 120.9100 10,156.44 MEAM CANTON 4 IN MS 84,000 120 9100 10,156.44 Total 84,000 120.9100 10,156.44 MEAM CANTON 5 IN MS 82,000 120 9100 9,914 62 Total 82,000 120.9100 9,914.62 MEAM HENDERSON 10 N MS 58,000 120 9100 7,012.78 Total 58,000 120.9100 7,012.78 MEAM HENDERSON 11 N MS 59,000 120 9100 7,133 69 Total 59,000 120.9100 7,133.69 MEAM HENDERSON 2 IN MS 524,000 120 9077 63,355.61 Total 524,000 120.9077 63,355.61 MEAM HENDERSON 4 IN MS 72,000 120 9100 8,705 52 Total 72,000 120.9100 8,705.52 MEAM HENDERSON 5 IN MS 72,000 120 9100 8,705 52 Attachment Snapshot: 20100826181933 RunID: 17029 Billing Snapshot: 20100826175238

2011 ETI Rate Case 9-226 Exhibit PJC-2 2011 TX Rate Case Page 65 of 70

Entergy Electric System Date range - 20100701 through 20100731 Attachment 11 Intra-System Billing-201007RA Joint Account / Individual Company Purchases Page 65 Description KWH Mills per KWH Charge Total 72,000 120.9100 8,705.52 MEAM HENDERSON 6 IN MS 73,000 120 9100 8,826.43 Total 73,000 120.9100 8,826.43 MEAM HENDERSON 7 IN MS 76,000 120 9100 9,189.16 Total 76,000 120.9100 9,189.16 MEAM HENDERSON 8 IN MS 74,000 120 9100 8,947 34 Total 74,000 120.9100 8,947.34 MEAM HENDERSON 9 IN MS 54,000 120 9100 6,529.14 Total 54,000 120.9100 6,529.14 MERRILL LYNCH COMMODIT ES NC/WSPP B AR 40,521,612 49 2313 1,994,933.07 LA 48,808,429 49 2313 2,402,903.87 MS 27,053,226 49 2313 1,331,865.81 NO 8,771,914 49 2313 431,852 92 EGSL 37,164,138 49 2313 1,829,640.85 ETI 31,749,681 49 2313 1,563,079.13 Total 194,069,000 49.2313 9,554,275.65 MORGAN STANLEY/WSPP A AR 51,366 23 8130 1,223.18 LA 61,868 23 8130 1,473 28 MS 34,292 23 8130 816 61 NO 11,118 23 8130 264.74 EGSL 47,110 23 8130 1,121 82 ETI 40,246 23 8130 958 37 Total 246,000 23.8130 5,858.00 NRG CAJUN 3/CAJUN 3 EGSL 95,955,425 19 5172 1,872,781.39 ETI 70,923,575 19 5172 1,384,231.31 Total 166,879,000 19.5172 3,257,012.70 NRG POWER MARKET NG LLC /WSPP A AR 6,217,020 26 2779 163,370 39 LA 7,488,413 26 2779 196,780.76 MS 4,150,635 26 2779 109,070 04 NO 1,345,830 26 2779 35,365.61 EGSL 5,701,912 26 2779 149,833.47 ETI 4,871,190 26 2779 128,004.73 Total 29,775,000 26.2779 782,425.00 NRG POWER MARKET NG LLC /WSPP B AR 38,603,785 52 0823 2,010,574.87 LA 46,498,600 52 0823 2,421,752.09 MS 25,772,818 52 0823 1,342,307.42 NO 8,356,751 52 0823 435,238.73 EGSL 35,405,012 52 0823 1,843,976.61 ETI 30,247,034 52 0823 1,575,336.23 Total 184,884,000 52.0823 9,629,185.95 NRG POWER MARKET NG LLC /WSPP C AR 1,740,348 45.7422 79,607.30 LA 2,096,255 45.7422 95,887.44 MS 1,161,899 45.7422 53,147.93 NO 376,742 45.7422 17,232.89 EGSL 1,596,150 45.7422 73,011.34 ETI 1,363,606 45.7422 62,374.10 Total 8,335,000 45.7422 381,261.00 OCC DENTAL POWER SERVICES/BASE CAPACITY LA 219,380,000 35.7590 7,844,813.12 Total 219,380,000 35.7590 7,844,813.12 OCC DENTAL POWER SERVICES/DAY-AHEAD CALL OPTION LA 50,188,000 41 0872 2,062,086.80 Total 50,188,000 41.0872 2,062,086.80 Attachment Snapshot: 20100826181933 RunID: 17029 Billing Snapshot: 20100826175238

2011 ETI Rate Case 9-227 Exhibit PJC-2 2011 TX Rate Case Page 66 of 70

Entergy Electric System Date range - 20100701 through 20100731 Attachment 11 Intra-System Billing-201007RA Joint Account / Individual Company Purchases Page 66 Description KWH Mills per KWH Charge

OCC DENTAL POWER SERVICES/INTRA-DAY CALL OPTION LA 9,090,000 51.4329 467,525.10 Total 9,090,000 51.4329 467,525.10 OCC DENTAL POWER SERVICES/WSPP B AR 1,189,742 63 3591 75,381.01 LA 1,433,048 63 3591 90,796.65 MS 794,302 63 3591 50,326.31 NO 257,550 63 3591 16,318.15 EGSL 1,091,166 63 3591 69,135.39 ETI 932,192 63 3591 59,062.49 Total 5,698,000 63.3591 361,020.00 RAINBOW ENERGY MARKETING CORP/WSPP A AR 2,907,333 32.1174 93,375.97 LA 3,501,908 32.1174 112,472 37 MS 1,941,010 32.1174 62,340.08 NO 629,363 32.1174 20,213.51 EGSL 2,666,424 32.1174 85,638.22 ETI 2,277,962 32.1174 73,162.10 Total 13,924,000 32.1174 447,202.25 SAN JAC NTO 1 ETI 5,722,000 61.7616 353,399.75 Total 5,722,000 61.7616 353,399.75 SAN JAC NTO 2 ETI 5,612,000 61.7608 346,601 58 Total 5,612,000 61.7608 346,601.58 SMEPA/WSPP B AR 626,400 89 2640 55,914.95 LA 754,504 89 2640 67,350.01 MS 418,200 89 2640 37,330.24 NO 135,600 89 2640 12,104.24 EGSL 574,496 89 2640 51,281.84 ETI 490,800 89 2640 43,810.72 Total 3,000,000 89.2640 267,792.00 SOUTHERN COMPANY SERVICES NC. AS AGENT FO/WSPP A AR 114,840 38 0000 4,363 92 LA 138,325 38 0000 5,256 35 MS 76,670 38 0000 2,913.46 NO 24,860 38 0000 944 68 EGSL 105,325 38 0000 4,002 35 ETI 89,980 38 0000 3,419 24 Total 550,000 38.0000 20,900.00 SOUTHERN COMPANY SERVICES NC. AS AGENT FO/WSPP B AR 2,213,280 128 0000 283,299 91 LA 2,665,900 128 0000 341,235.19 MS 1,477,640 128 0000 189,137 93 NO 479,120 128 0000 61,327.37 EGSL 2,029,900 128 0000 259,827 20 ETI 1,734,160 128 0000 221,972.40 Total 10,600,000 128.0000 1,356,800.00 SUEZ ENERGY MARKETING NA INC./WSPP A AR 1,808,208 39 6552 71,705.05 LA 2,178,009 39 6552 86,369.35 MS 1,207,204 39 6552 47,871.99 NO 391,432 39 6552 15,522.47 EGSL 1,658,371 39 6552 65,762.74 ETI 1,416,776 39 6552 56,182.58 Total 8,660,000 39.6552 343,414.18 SUEZ ENERGY MARKETING NA INC./WSPP B AR 11,804,928 48.7041 574,947.70 LA 14,219,068 48.7041 692,526 53 MS 7,881,251 48.7041 383,848 90 NO 2,555,470 48.7041 124,461.73 EGSL 10,826,823 48.7041 527,309 92 ETI 9,249,460 48.7041 450,486 22 Total 56,537,000 48.7041 2,753,581.00 Attachment Snapshot: 20100826181933 RunID: 17029 Billing Snapshot: 20100826175238

2011 ETI Rate Case 9-228 Exhibit PJC-2 2011 TX Rate Case Page 67 of 70

Entergy Electric System Date range - 20100701 through 20100731 Attachment 11 Intra-System Billing-201007RA Joint Account / Individual Company Purchases Page 67 Description KWH Mills per KWH Charge

TEA/WSPP A AR 233,021 29 3082 6,829.44 LA 280,677 29 3082 8,226.15 MS 155,570 29 3082 4,559.48 NO 50,443 29 3082 1,478.40 EGSL 213,711 29 3082 6,263.48 ETI 182,578 29 3082 5,351 05 Total 1,116,000 29.3082 32,708.00 TENASKA FRONTIER/EXS50 AR 17,152 21 3697 366 54 LA 20,660 21 3697 441.49 MS 11,451 21 3697 244.70 NO 3,714 21 3697 79.37 EGSL 15,731 21 3697 336.17 ETI 13,439 21 3697 287.19 Total 82,147 21.3697 1,755.46 TENASKA FRONTIER/EXS75 AR 13,458 32 0598 431.45 LA 16,210 32 0598 519 69 MS 8,985 32 0598 288 06 NO 2,912 32 0598 93.37 EGSL 12,343 32 0598 395.71 ETI 10,544 32 0598 338 04 Total 64,452 32.0598 2,066.32 TENASKA FRONTIER/EXS90 AR 218,226 39 3082 8,578 04 LA 262,868 39 3082 10,332.77 MS 145,651 39 3082 5,725 24 NO 47,232 39 3082 1,856 64 EGSL 200,195 39 3082 7,869 32 ETI 170,975 39 3082 6,720 83 Total 1,045,147 39.3082 41,082.84 TENASKA/WSPP A AR 490,888 59 9025 29,405.41 LA 591,278 59 9025 35,419.00 MS 327,729 59 9025 19,631.77 NO 106,266 59 9025 6,365 63 EGSL 450,215 59 9025 26,969.02 ETI 384,624 59 9025 23,039.97 Total 2,351,000 59.9025 140,830.80 TENASKA/WSPP B AR 4,812,638 60.1091 289,283.19 LA 5,796,845 60.1091 348,443.17 MS 3,213,034 60.1091 193,132 32 NO 1,041,808 60.1091 62,622.14 EGSL 4,413,862 60.1091 265,313 04 ETI 3,770,813 60.1091 226,660.14 Total 23,049,000 60.1091 1,385,454.00 UNION POWER PARTNERS/WSPP A AR 39,672 33.1579 1,315.44 LA 47,786 33.1579 1,584.49 MS 26,486 33.1579 878 22 NO 8,588 33.1579 284.76 EGSL 36,384 33.1579 1,206.41 ETI 31,084 33.1579 1,030 68 Total 190,000 33.1579 6,300.00 UNION POWER PARTNERS/WSPP B AR 34,397,079 50 2176 1,727,338.52 LA 41,431,444 50 2176 2,080,587.38 MS 22,964,343 50 2176 1,153,213.86 NO 7,446,119 50 2176 373,926 25 EGSL 31,547,047 50 2176 1,584,216.71 ETI 26,950,968 50 2176 1,353,413.03 Total 164,737,000 50.2176 8,272,695.75 WESTAR ENERGY INC/WSPP A AR 1,447,817 32.4570 46,991.85 Attachment Snapshot: 20100826181933 RunID: 17029 Billing Snapshot: 20100826175238

2011 ETI Rate Case 9-229 Exhibit PJC-2 2011 TX Rate Case Page 68 of 70

Entergy Electric System Date range - 20100701 through 20100731 Attachment 11 Intra-System Billing-201007RA Joint Account / Individual Company Purchases Page 68 Description KWH Mills per KWH Charge LA 1,743,909 32.4570 56,602.16 MS 966,608 32.4570 31,373.20 NO 313,419 32.4570 10,172.73 EGSL 1,327,853 32.4570 43,098.05 ETI 1,134,394 32.4570 36,819.01 Total 6,934,000 32.4570 225,057.00 WESTAR ENERGY INC/WSPP B AR 6,170,038 34 5507 213,179 08 LA 7,431,833 34 5507 256,774 57 MS 4,119,252 34 5507 142,323 03 NO 1,335,662 34 5507 46,147.66 EGSL 5,658,817 34 5507 195,515 95 ETI 4,834,398 34 5507 167,031.71 Total 29,550,000 34.5507 1,020,972.00 WESTAR ENERGY INC/WSPP C AR 167,040 62 0000 10,356.48 LA 201,200 62 0000 12,474.40 MS 111,520 62 0000 6,914 24 NO 36,160 62 0000 2,241 92 EGSL 153,200 62 0000 9,498.40 ETI 130,880 62 0000 8,114 56 Total 800,000 62.0000 49,600.00 WRIGHTSVILE POWER/EXS75 AR 7,745 36 3604 281 61 LA 9,333 36 3604 339 34 MS 5,171 36 3604 188 00 NO 1,675 36 3604 60.91 EGSL 7,107 36 3604 258.42 ETI 6,069 36 3604 220 69 Total 37,100 36.3604 1,348.97 WRIGHTSVILE POWER/EXS90 AR 169,805 42 5289 7,221 54 LA 204,509 42 5289 8,697.47 MS 113,362 42 5289 4,821 24 NO 36,734 42 5289 1,562 29 EGSL 155,716 42 5289 6,622 53 ETI 133,010 42 5289 5,656.74 Total 813,136 42.5289 34,581.81 YAZOO CITY/EXS90 AR 1,101 44 2334 48.70 LA 1,324 44 2334 58.57 MS 734 44 2334 32.46 NO 237 44 2334 10.49 EGSL 1,011 44 2334 44.72 ETI 863 44 2334 38.17 Total 5,270 44.2334 233.11

Attachment Snapshot: 20100826181933 RunID: 17029 Billing Snapshot: 20100826175238

2011 ETI Rate Case 9-230 Exhibit PJC-2 2011 TX Rate Case Page 69 of 70

Entergy Electric System Date range - 20100701 through 20100731 Attachment 11 Intra-System Billing-201007RA Purchase Capacity and Reserve Sharing Charges - Dollars Page 69

Description System AR LA MS NO EGSL ETI ACADIA PPA - 580 MW - CAP CHG 714,364 0 714,364 0 0 0 0 CARVILLE - 485 MW - CAP CHG 2,430,000 0 0 0 0 2,430,000 0 CONOCO PHILIPS - 100 MW - CAP 165,000 0 0 0 0 94,875 70,125 DOW - 100 MW - CAP CHG 150,000 0 0 0 0 86,250 63,750 ETEC SAN JAC- 146 MW - CAP CHG 985,500 0 0 0 0 0 985,500 EXELON 150 10YR- CAP CHG 1,527,900 0 0 0 0 0 1,527,900 EXELON 150 1YR- CAP CHG 1,645,875 343,659 413,938 229,435 74,394 315,185 269,265 OCC DENTIAL - 480MW - CAP CHG 3,399,552 0 3,399,552 0 0 0 0 SWPP RESER - CAP CHG 3,000 626 754 418 136 574 491 Totals 11,021,192 344,285 4,528,609 229,853 74,529 2,926,885 2,917,031

Attachment Snapshot: 20100826181933 RunID: 17029 Billing Snapshot: 20100826175238

2011 ETI Rate Case 9-231 Exhibit PJC-2 2011 TX Rate Case Page 70 of 70

Entergy Electric System Date range - 20100701 through 20100731 Attachment 12 Intra-System Billing-201007RA Fiber Optic Equalization Report Page 70

AR LA MS NO Inter-Company Circuits(ICC)-Number 5.50 8.34 4.00 4.16 Inter-Company Circuits(ICC)-Percent 25 0000 37.9091 18.1818 18.9091 System Operations Circuits(SOC)-Number 62.50 46.34 26.50 14.66 System Operations Circuits(SOC)-Percent 41 6667 30.8933 17.6667 9.7733 Tele-Processing Circuits(TPC)-Number 64.00 58.24 26.00 23.76 Tele-Processing Circuits(TPC)-Percent 37 2093 33.8605 15.1163 13.8140 Total Circuits-Number 132.00 112.92 56.50 42.58 Total Circuits-Percent 38 3721 32.8256 16.4244 12.3779 Total Allocations 0 358248 0.343196 0.154639 0.143917

ICC SOC TPC Total Percent 6 3953 43.6047 50.0000 Equalization Percent 11 3402 0.0000 88.6598 AR LA MS NO Cost of Capital Debt Ratio (DR) 0.476500 0.502800 0.527000 0.455600 Bond Cost (i) 0 061600 0.067100 0.063400 0 060700 Preferred Ratio (PR) 0 039300 0.019900 0.031800 0 047700 Preferred Cost (p) 0 059900 0.075500 0.056900 0 048200 Common Ratio (ER) 0.484200 0.477400 0.441200 0.496700 Common Cost (c) 0.110000 0.110000 0.110000 0.110000 Total Cost of Capital (CM) 0 084968 0.087754 0.083753 0 084591 Tax Rate (F) 0 035895 0.033783 0.031183 0 035609 Operating Expenses Depreciation Factor (D) 0.0285710 0.0285710 0.0285710 0.0285710 Insurance Expense (I) 0.0040898 0.0012272 0.0040751 Property Tax (PT) 0.0045996 0.0090891 0.0168837 0.0124608 Franchise Tax (FT) 0.0001604 0.0010224 0.0021793 Operations & Maintenance (OM) 0.1539117 0.1111532 0.0465445 0.0486027 Total Operating Expenses 0.1913325 0.1500405 0.0970967 0.0918138 Net Fiber Investment 4,893,907.00 5,459,070.00 6,916,494.00 1,399,554.00 less SOC Investment 3,391,907.86 2,514,891.44 1,438,170.49 795,602 56 Credited Investment 1,501,999.14 2,944,178.56 5,478,323.51 603,951.44 Annual Ownership Cost 0 312196 0.271578 0.212033 0 212014 Net Annual Ownership Cost 468,917.37 799,572.65 1,161,583.73 128,046 04 System Average Annual Ownership cost 2,558,119.79 / 18,669,025.00 = 0.2429721 System Average Monthly Ownership cost 0.2429721 / 12 = 0.0202477 Company Responsibilities 3,771,797.11 3,613,322.84 1,628,109.39 1,515,223.32 Investment Difference 2,269,797.97 669,144.28 (3,850,214.12) 911,271 88 Payments 45,958.19 13,548.63 18,451.16 Receipts 77,957.98

Attachment Snapshot: 20100826181933 RunID: 17029 Billing Snapshot: 20100826175238

2011 ETI Rate Case 9-232 2011 ETI Rate Case

Families and Functions I I Operations Corporate Support I H Distribution I Accounting Entries

H Customer Service I Corporate

H Generation I Finance y Transmission I Human Resources & Administration Information Technology Supply Chain

N 9-233

..... .....

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2011 ETI Rate Case 9-234 2011 ETI Rate Case

Corporate Support Functions & Classes ($ Total ETI Adjusted) I I I I I I Accounting Human Resources Information Finance Corporate Supply Chain Entries & Administration Technology

Federal PRG Treasury Operations Depreciation Human Resources Information Technology Supply Chain Affairs ,_ SMcNea/ I- I- S Tumminello I- KGardner I- J Brown J Hunter WFerguson $811,510 $1,777,986 $9,365,982 $6,620,998 $1,424,411 $521,454

Financial Services Utility & Executive Other Expenses Administration DDoucet .... Management JDomino ... S Tumminello ... TP/auche .... $3,529,673 $1,756,009 $644,557 $1,939,228

Internal & External Service Company Tax Services P Galbraith ... Communications C Herrington Recipient Offsets S Tumminello $2,033,445 $332,317 $0

Legal Services ncome Tax Expense R Sloan RRoberts $6,691,561 $510,800

Regulatory Services PMay $3,965,085 9-235

N -"' -"' 2011 ETI Rate Case

Operations Functions & Classes ($ Total ETI Adjusted) Domestic Regulated Utility Operations Group

I I I Customer Distribution Transmission Generation Service

Distribution Customer Service Transmission Energy and Fuel Operations S Corkran $836,799 Operations A Roman $6,403,681 - Operations M Mcculla $9,106,198 - Management PCicio $3,742,314 -

Environmental Fossil Plant T&D Support S Corkran $750,435 Services A Roman $451, 103 - Operations WGarrison $5,265,241 -

Nelson 6 Retail Operations A Roman $1,533,679 - Co-Owner WGarrison - $8,984,309 9-236 2011 ETI Rate Case

SPO Leadership Team and Areas of Responsibility

Drew Marsh VPSPO

Judy Campbell, Executive Secretary I I I John Hurstell Patrick Cicio Stuart Barrett Tony Walz VP Director Director Director Strategic Initiatives Regulatory Affairs & Asset Operations Planning Analysis Energy Settlements

Lee Kellough Dakin DuBroc Michelle Thiry Director Manager Director Power Delivery & Project & Performance Energy Management Technical Services Management 9-237 This page has been intentionally left blank.

2011 ETI Rate Case 9-238 2011 ETI Rate Case

Exhibit PJC-6 Entergy Texas, Inc. 2011 TX Rate Case Dollars Closed to Plant in Service Including Affliate Component Page 1 of 1 July 1, 2009 - June 30, 2011

(A) (B) (C) (D) (E) (F) (G) (H) (I) (J) (K) (L) (M) (N) (O) Non-Affiliate Non-Capital Charges Excluding Capital Affiliate Capital Suspense Suspense Dollars In Service Cap Susp and Suspense Capital Charges excluding Affiliate Total Affiliate Closed to Project Code Project Code Description Asset Class Date Asset Location Description State Business Unit Reimbursements Reimbursements Charges Suspense Affiliate Charges Charges Plant C1PPWS0889 SPO IT 2008 General Plant 30-Oct-09 CBLE - Capital Billed to LEs Multi-State ETI 7,529.57 0.00 162.51 121.36 41.15 97,923.69 98,045.05 105,615.77 C1PPWS0909 SPO Corporate PC Refresh General Plant 31-Dec-09 CBLE - Capital Billed to LEs Multi-State ETI 1,393.83 0.00 8.30 6.20 2.10 8,304.03 8,310.23 9,706.16 C1PPWS0664E SPO 2007 Server Refresh General Plant 30-Jun-08 CBLE - Capital Billed to LEs Multi-State ETI 812.32 0.00 96.76 72.26 24.50 4,305.73 4,377.99 5,214.81 C1PPWS0774E SPO Gas Telemetry Migration General Plant 31-Dec-08 CBLE - Capital Billed to LEs Multi-State ETI 299.48 0.00 6.63 4.95 1.68 1,327.26 1,332.21 1,633.37 General Plant Total 10,035.20 0.00 274.20 204.77 69.43 111,860.71 112,065.48 122,170.11 C1PPWS0907 Operations Planning Model Develpmnt Intangible 30-Oct-09 CBLE - Capital Billed to LEs Multi-State ETI 24,129.39 0.00 75.99 56.75 19.24 3,764.55 3,821.30 27,969.93 C1PPWS0883 SPO ECI Project Support 2008 Intangible 30-Oct-09 CBLE - Capital Billed to LEs Multi-State ETI 17,161.91 0.00 18.58 13.88 4.70 2,553.88 2,567.76 19,734.37 C1PPWS0911 SPO Add NOxCost to Dispatch Process Intangible 30-Oct-09 CBLE - Capital Billed to LEs Multi-State ETI 12,888.60 0.00 47.00 35.10 11.90 2,121.47 2,156.57 15,057.07 C1PPWS0884 SPO Weekly Procurement Process 2008 Intangible 30-Oct-09 CBLE - Capital Billed to LEs Multi-State ETI 9,701.76 0.00 0.00 0.00 0.00 1,488.10 1,488.10 11,189.86 C1PPWS0913 SPO Automated Confirmation Engine Intangible 30-Oct-09 CBLE - Capital Billed to LEs Multi-State ETI 8,970.67 0.00 64.94 48.50 16.44 1,444.10 1,492.60 10,479.71 C1PPWS0912 SPO Deal Eval Redevelopment Intangible 30-Oct-09 CBLE - Capital Billed to LEs Multi-State ETI 7,413.87 0.00 7.01 5.23 1.78 1,174.95 1,180.18 8,595.83 C1PPWS0910 SPO Document Retention Alignment Intangible 30-Oct-09 CBLE - Capital Billed to LEs Multi-State ETI 3,591.52 0.00 27.21 20.32 6.89 590.35 610.67 4,209.08 Intangible Total 83,857.72 0.00 240.73 179.77 60.96 13,137.40 13,317.17 97,235.85 Grand Total 93,892.92 0.00 514.93 384.54 130.39 124,998.11 125,382.65 219,405.96 9-239

2011 TX Rate Case Exhibit PJC-6 Page 1 of 1 Page 1 of 1 This page has been intentionally left blank.

2011 ETI Rate Case 9-240 ENTERGY TEXAS, INC. EXHIBIT PJC-A 2011 ETI Rate Case

Affiliate Billings - by Witness, Class, and Department 2011 TX Rate Case For the Twelve Months Ended June 30, 2011 Page 1 of 1 Amounts in Dollars (A) (B) (C) (D) (E) (F) (G) (H) Total Billings Billing Service Company ETI Per Pro Forma Total ETI Class Entity Dept Support Recipient Total All Other BU's Books Exclusions Amount Adjusted ENERGY AND FUEL MANAGEMENT ESI CP204 1,545,092 45,658 1,590,750 1,373,069 217,681 - 1,282 218,963 ENERGY AND FUEL MANAGEMENT ESI CP218 670,285 52,421 722,706 608,009 114,697 - (1,424) 113,273 ENERGY AND FUEL MANAGEMENT ESI CP227 1,056,752 88,917 1,145,669 967,710 177,959 - 3,154 181,114 ENERGY AND FUEL MANAGEMENT ESI CP235 1,076,761 52,798 1,129,559 1,037,552 92,007 (392) 2,445 94,059 ENERGY AND FUEL MANAGEMENT ESI CP236 89 - 89 75 14 - - 14 ENERGY AND FUEL MANAGEMENT ESI CP237 971 - 971 812 159 (30) 30 159 ENERGY AND FUEL MANAGEMENT ESI CP23K 868,238 71,263 939,501 707,570 231,931 (382) 3,043 234,592 ENERGY AND FUEL MANAGEMENT ESI CPSLG 1,062,402 67,150 1,129,552 951,196 178,356 - 1,328 179,684 ENERGY AND FUEL MANAGEMENT ESI CPSLQ 808,223 69,511 877,734 866,107 11,627 (923) (1,263) 9,442 ENERGY AND FUEL MANAGEMENT ESI SE08B 1,238,559 91,322 1,329,881 1,125,393 204,488 (812) (2,507) 201,168 ENERGY AND FUEL MANAGEMENT ESI SESEE 567,647 51,472 619,119 521,181 97,938 (51) 1,392 99,280 ENERGY AND FUEL MANAGEMENT ESI SESKA 1,084,977 1,551 1,086,528 916,884 169,644 - (106) 169,538 ENERGY AND FUEL MANAGEMENT ESI SESKB 1,525,041 137,574 1,662,615 1,403,471 259,144 - 4,105 263,250 ENERGY AND FUEL MANAGEMENT ESI SESKC 491 - 491 491 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKD 1,338,433 107,239 1,445,672 1,283,449 162,223 (581) 3,539 165,181 ENERGY AND FUEL MANAGEMENT ESI SESKE 1,250,562 78,031 1,328,594 1,120,970 207,624 (2,563) 2,163 207,224 ENERGY AND FUEL MANAGEMENT ESI SESKF 1,336,569 118,596 1,455,165 1,220,425 234,741 (570) (5,187) 228,983 ENERGY AND FUEL MANAGEMENT ESI SESKG 659 - 659 550 109 - - 109 ENERGY AND FUEL MANAGEMENT ESI SESKH 1,765,397 152,163 1,917,560 1,594,341 323,219 (212) 1,476 324,483 ENERGY AND FUEL MANAGEMENT ESI SESKJ 2,966,567 246,827 3,213,393 2,706,497 506,896 - 9,480 516,376 ENERGY AND FUEL MANAGEMENT ESI SESKQ 854,394 71,339 925,732 772,863 152,869 (99) (23,673) 129,098 ENERGY AND FUEL MANAGEMENT ESI SESKU 999,442 92,955 1,092,397 941,814 150,582 - 2,851 153,434 ENERGY AND FUEL MANAGEMENT ESI SESLA 830,292 75,667 905,959 763,656 142,303 (398) 2,726 144,631 ENERGY AND FUEL MANAGEMENT ESI SESLB 373,117 32,386 405,504 345,786 59,718 (9) 712 60,421 ENERGY AND FUEL MANAGEMENT ESI SESLC 508 - 508 427 81 - - 81 ENERGY AND FUEL MANAGEMENT ESI SESLE 1,076 - 1,076 914 162 - - 162 ENERGY AND FUEL MANAGEMENT ESI SESLT 299,128 27,344 326,472 279,563 46,909 (7) 692 47,594 ENERGY AND FUEL MANAGEMENT Total ESI 23,521,673 1,732,183 25,253,856 21,510,774 3,743,083 (7,029) 6,260 3,742,314 Total ENERGY AND FUEL MANAGEMENT 23,521,673 1,732,183 25,253,856 21,510,774 3,743,083 (7,029) 6,260 3,742,314 Total for Witness Cicio, Patrick 23,521,673 1,732,183 25,253,856 21,510,774 3,743,083 (7,029) 6,260 3,742,314 9-241

Amounts may not add or tie to other schedules due to rounding. EXHIBIT PJC-A Cicio, Patrick Page 1 of 1 This page has been intentionally left blank.

2011 ETI Rate Case 9-242 ENTERGY TEXAS, INC. EXHIBIT PJC-B 2011 ETI Rate Case

Affiliate Billings - by Witness, Class and Project 2011 TX Rate Case For the Twelve Months Ended June 30, 2011 Page 1 of 4 Amounts in Dollars (A) (B) (C) (D) (E) (F) (G) (H) Total Billings Billing Activity / ESI Billing Service Company ETI Per Pro Forma Total ETI Class Entity Project Code Activity / Project Description Method Support Recipient Total All Other BU's Books Exclusions Amount Adjusted ENERGY AND FUEL MANAGEMENT ESI C1PCN70859 RIVER BEND EXTENDED POWER UPRA DIRCTEOI - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI C1PPRNE010 New Nuclear -Regulatory Filing NWDVRBGG (9,843) (774) (10,617) (10,617) - - - - ENERGY AND FUEL MANAGEMENT ESI C1PPRTOSOF RTO Implement Software ALLCOS LOADOPCO 13,959 1,480 15,439 12,876 2,563 (2,563) - - ENERGY AND FUEL MANAGEMENT ESI C1PPSP0008 SPO ELL&ENOI Purchase Option I OWNISES2 (174,936) (7,788) (182,724) (182,724) - - - - ENERGY AND FUEL MANAGEMENT ESI C6PCN32144 GRAND GULF EXTENDED POWER UPRA DIRCTSER 15,927 1,458 17,385 17,385 - - - - ENERGY AND FUEL MANAGEMENT ESI C6PCN70858 RIVER BEND EXTENDED POWER UPRA 3,104 283 3,386 3,386 - - - - ENERGY AND FUEL MANAGEMENT ESI C6PPGN0020 New Nuclear Reg Filing EGSL On DIRECTLG 6,813 537 7,350 7,350 - - - - ENERGY AND FUEL MANAGEMENT ESI C6PPLN0020 New Nuclear Reg Filing ELL Ong DIRCTELI 8,823 695 9,518 9,518 - - - - ENERGY AND FUEL MANAGEMENT ESI C6PPMN0020 New Nuclear Reg Filing EMI Ong DIRCTEMI - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI C6PPN66876 Cladding Failure Root Cause & DIRCTWF3 5,748 545 6,293 6,293 - - - - ENERGY AND FUEL MANAGEMENT ESI C6PPRN0002 New Nuclear - Entergy DIRCTR1 - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI C6PPRN0010 New Nuclear - Regulatory Filin DIRCTR1 - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI C6PPSP0012 SPO Project Gator Transact/Tra DIRCTELI 143,114 4,441 147,555 147,555 - - - - ENERGY AND FUEL MANAGEMENT ESI C6PPSP0029 SPO Evange ine DIRCTELI 41,666 2,947 44,613 44,613 - - - - ENERGY AND FUEL MANAGEMENT ESI C6PPSP0030 SPO Ouachita Fuel Meter Common DIRCTEAI 539 45 584 584 - - - - ENERGY AND FUEL MANAGEMENT ESI C6PPSP0038 SPO Project Lamar Transaction DIRCTEAI 381,462 11,378 392,839 392,839 - - - - ENERGY AND FUEL MANAGEMENT ESI C6PPSP0045 SPO Real Time Calcasieu RTU DIRECTLG 25,835 156 25,991 25,991 - - - - ENERGY AND FUEL MANAGEMENT ESI C6PPSP0046 SPO Project Burnet Transaction DIRCTEMI 414,076 11,232 425,307 425,307 - - - - ENERGY AND FUEL MANAGEMENT ESI C6PPWGP516 SBC CIP Compliance DIRECTTX 120 - 120 - 120 (120) - - ENERGY AND FUEL MANAGEMENT ESI C6PPWS0534 System Planning Pet Coke Repow DIRCTELI 374 11 384 384 - - - - ENERGY AND FUEL MANAGEMENT ESI C6PPWS0628 SPO W-WOTAB CT Development Spe DIRECTTX - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI C6PPWS0783 Ninemile 6 Development DIRCTELI 34,977 3,274 38,251 38,251 - - - - ENERGY AND FUEL MANAGEMENT ESI C6PPWS0984 SPO EGSL Purchase of Ouach ta DIRECTLG - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI E1PPEFF003 EAI ENERGY EFFCNCY NON-INCREME DIRCTEAI 11,515 1,145 12,660 12,660 - - - - ENERGY AND FUEL MANAGEMENT ESI F3PCCPM001 CORPORATE PERFORMANCE MANAGEME ASSTSALL - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI F3PCCSPEAI SYSTEM PLANNING - EAI DIRCTEAI 33,801 3,163 36,965 36,965 - - - - ENERGY AND FUEL MANAGEMENT ESI F3PCCSPEEI SYSTEM PLANNING - NONREG - EEI ASSTNREG 548 48 596 596 - - - - ENERGY AND FUEL MANAGEMENT ESI F3PCCSPELI SYSTEM PLANNING - ELI DIRCTELI 30,852 2,782 33,634 33,634 - - - - ENERGY AND FUEL MANAGEMENT ESI F3PCCSPEMI SYSTEM PLANNING - EMI DIRCTEMI 3,103 276 3,379 3,379 - - - - ENERGY AND FUEL MANAGEMENT ESI F3PCCSPENO SYSTEM PLANNING - ENOI DIRCTENO 34,626 3,063 37,689 37,689 - - - - ENERGY AND FUEL MANAGEMENT ESI F3PCCSPGSL SYSTEM PLANNING - EGSI-LA DIRECTLG 15,257 1,350 16,607 16,607 - - - - ENERGY AND FUEL MANAGEMENT ESI F3PCCSPGST SYSTEM PLANNING - EGSI-TX DIRECTTX 22,828 2,070 24,898 - 24,898 - 515 25,413 ENERGY AND FUEL MANAGEMENT ESI F3PCCSPSYS SYSTEM PLANNING AND STRATEGIC ASSTSALL 290,004 525 290,529 261,342 29,187 - 13 29,199 ENERGY AND FUEL MANAGEMENT ESI F3PCCSPUTI SYSTEM PLANNING & STRATEGIC AD LOADOPCO 2,778,700 170,067 2,948,767 2,487,717 461,050 - 5,541 466,591 ENERGY AND FUEL MANAGEMENT ESI F3PCE14420 REGULATORY AFFAIRS - EAI DIRCTEAI 19,919 1,638 21,556 21,556 - - - - ENERGY AND FUEL MANAGEMENT ESI F3PCE14423 REGULATORY AFFAIRS - EMI DIRCTEMI 8,233 760 8,993 8,993 - - - - ENERGY AND FUEL MANAGEMENT ESI F3PCF07300 CORP PLANNING & ANALYSIS- REGU CUSTEGOP 16,968 1,166 18,135 15,634 2,500 - 37 2,537 ENERGY AND FUEL MANAGEMENT ESI F3PCF21600 CORP RPTG ANALYSIS & POLICY AL GENLEDAL - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI F3PCFBLETR BELOW THE LINE EXPENSES -ETR DIRCTETR - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI F3PCFBLFOS BELOW THE LINE - FOSSIL OPERAT CAPAOPCO 7,368 - 7,368 6,571 797 (797) - - ENERGY AND FUEL MANAGEMENT ESI F3PCFF1003 BOARD SUPPORT ASSTSALL 5,434 377 5,812 5,233 578 - 8 587 ENERGY AND FUEL MANAGEMENT ESI F3PCFVARAS ADMIN SUPRT - VARIBUS CORPORAT DIRECTLG 41,139 3,778 44,917 44,917 - - - - ENERGY AND FUEL MANAGEMENT ESI F3PCSYSAGR SYSTEM AGREEMENT-2001 CUSEOPCO 381,179 30,815 411,994 351,119 60,875 - 1,599 62,474 ENERGY AND FUEL MANAGEMENT ESI F3PCSYSRAS SYSTEM REGULATORY AFFAIRS-STAT CUSTEGOP 2,691 265 2,956 2,546 410 - 13 423 ENERGY AND FUEL MANAGEMENT ESI F3PCW15822 RESOURCE PLANNING COORDINATOR LOADOPCO 122,890 11,496 134,385 113,301 21,085 - 694 21,779 ENERGY AND FUEL MANAGEMENT ESI F3PCW15830 SYSTEM GENERATION PLANNING LOADOPCO 1,726,349 155,656 1,882,005 1,586,195 295,809 - 5,726 301,535 ENERGY AND FUEL MANAGEMENT ESI F3PCW15840 PLANNING MODELING & ANALYSIS G LOADOPCO 295,253 26,854 322,107 271,607 50,501 - 960 51,461 ENERGY AND FUEL MANAGEMENT ESI F3PCW18100 OPNS-GAS SUPPLY CAPXCOPC 1,150,758 104,642 1,255,400 1,083,837 171,563 - 3,266 174,829 ENERGY AND FUEL MANAGEMENT ESI F3PCW18200 OPNS-OIL SUPPLY OWNISFI 137,062 12,761 149,823 149,823 - - - - ENERGY AND FUEL MANAGEMENT ESI F3PCW18300 OPNS-COAL SUPPLY COALARGS 770,795 66,064 836,859 836,859 - - - - ENERGY AND FUEL MANAGEMENT ESI F3PCW19501 WHOLESALE PURCHASING & SALES LOADOPCO 1,620,269 116,517 1,736,786 1,462,875 273,911 - 5,282 279,193 9-243

ENERGY AND FUEL MANAGEMENT ESI F3PCW19502 WHOLESALE TRXN - EAI CUSTOMERS DIRCTEAI 56 - 56 56 - - - - ENERGY AND FUEL MANAGEMENT ESI F3PCW19510 ENERGY MANAGEMENT OPERATIONS LOADOPCO 2,469,933 219,678 2,689,611 2,264,551 425,060 - 7,958 433,019 ENERGY AND FUEL MANAGEMENT ESI F3PCW19511 ENERGY MANAGEMENT OPERATIONS P LOADOPCO 1,548,975 133,113 1,682,089 1,416,167 265,922 - 4,977 270,899 ENERGY AND FUEL MANAGEMENT ESI F3PCW19512 ENERGY MGMT - FUEL & ENERGY AN LOADOPCO 1,015,950 90,454 1,106,404 931,546 174,858 - 3,336 178,195 ENERGY AND FUEL MANAGEMENT ESI F3PCW29607 POWER SYSTEM ACCOUNTING LOADWEPI 420,638 38,815 459,453 387,423 72,031 - 1,389 73,419 ENERGY AND FUEL MANAGEMENT ESI F3PCW51400 SFI FUEL OIL O&M DIRCTSFI 251 27 278 278 - - - - ENERGY AND FUEL MANAGEMENT ESI F3PCW54035 VICE PRESIDENT OF ENERGY MANAG LOADOPCO 1,073,545 310 1,073,855 905,703 168,152 - 8 168,160 ENERGY AND FUEL MANAGEMENT ESI F3PCWE0012 1998 FUELS MANAGEMENT TELEMETR CAPAOPCO 140,071 - 140,071 124,928 15,143 - - 15,143 ENERGY AND FUEL MANAGEMENT ESI F3PCWE0034 DIRECTOR - PLANT SUPPORT CAPAOPCO - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI F3PCWE0046 PLANT SUPPORT SERVICES - BIG C ASSTTXLG 29,487 2,456 31,943 18,773 13,169 - 265 13,435 ENERGY AND FUEL MANAGEMENT ESI F3PCWE0058 AWARDS & RECOGNITIONS PROGRAM LOADOPCO 11,430 1,572 13,003 11,042 1,961 - 43 2,004 Amounts may not add or tie to other schedules due to rounding. EXHIBIT PJC-B Cicio, Patrick Page 1 of 4 ENTERGY TEXAS, INC. EXHIBIT PJC-B 2011 ETI Rate Case

Affiliate Billings - by Witness, Class and Project 2011 TX Rate Case For the Twelve Months Ended June 30, 2011 Page 2 of 4 Amounts in Dollars (A) (B) (C) (D) (E) (F) (G) (H) Total Billings Billing Activity / ESI Billing Service Company ETI Per Pro Forma Total ETI Class Entity Project Code Activity / Project Description Method Support Recipient Total All Other BU's Books Exclusions Amount Adjusted ENERGY AND FUEL MANAGEMENT ESI F3PCWE0064 LONG TERM ENERGY LOADOPCO 327,588 28,335 355,923 299,950 55,973 - 1,019 56,992 ENERGY AND FUEL MANAGEMENT ESI F3PCWE0092 EMS OPERATIONS & MAINTENANCE S LOADOPCO 89,299 - 89,299 74,476 14,823 - 279 15,102 ENERGY AND FUEL MANAGEMENT ESI F3PCWE0133 EMO INFORMATION TECHNOLOGY SUP LOADOPCO 7,521 - 7,521 6,273 1,248 - - 1,248 ENERGY AND FUEL MANAGEMENT ESI F3PCWE0135 NEL. 6 JOINT OWNERSHIP PART. A DIRECTLG 4,929 463 5,392 5,392 - - - - ENERGY AND FUEL MANAGEMENT ESI F3PCWE0138 POWER CONTRACTS LOADOPCO 508 - 508 427 81 - - 81 ENERGY AND FUEL MANAGEMENT ESI F3PCWE0140 EMO REGULATORY AFFAIRS LOADOPCO 447,019 40,575 487,594 411,164 76,430 - 1,862 78,292 ENERGY AND FUEL MANAGEMENT ESI F3PCWE0151 FOSSIL DIVERSITY INITIATIVE - CAPAOPCO 68 5 73 65 8 - 0 8 ENERGY AND FUEL MANAGEMENT ESI F3PCZU1571 EGSI TX FUEL RELATED MATTERS DIRECTTX 67 - 67 - 67 - - 67 ENERGY AND FUEL MANAGEMENT ESI F3PCZU1582 EGSI LA 3RD EARNINGS REVIEW DIRECTLG (43) - (43) (43) - - - - ENERGY AND FUEL MANAGEMENT ESI F3PPADSENT Analytic/Decision Support-Ente ASSTSALL 614 - 614 555 58 - - 58 ENERGY AND FUEL MANAGEMENT ESI F3PPADTFL9 ELL Fuel Audit 2005-2009 DIRCTELI 1,541 141 1,682 1,682 - - - - ENERGY AND FUEL MANAGEMENT ESI F3PPAMPDEV Advanced Mgmt Dev Program EMPLOYAL 22,486 - 22,486 21,430 1,056 - - 1,056 ENERGY AND FUEL MANAGEMENT ESI F3PPAPSCLG APSC Complaint - FERC Investig CUSEOPCO - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI F3PPDOWPPA Dow 3 Year PPA (2011-2014) DIRECTLG 1,622 151 1,773 1,773 - - - - ENERGY AND FUEL MANAGEMENT ESI F3PPDSMALL DSM/Energy Efficiency -All Jur CUSTEGOP 3,059 258 3,318 2,858 460 - (460) - ENERGY AND FUEL MANAGEMENT ESI F3PPE14432 EAI SPP RTO Study DIRCTEAI 3,545 366 3,910 3,910 - - - - ENERGY AND FUEL MANAGEMENT ESI F3PPE14434 EAI POST SYS AGMT INCREMENTAL DIRCTEAI 17,270 1,376 18,646 18,646 - - - - ENERGY AND FUEL MANAGEMENT ESI F3PPE14435 EAI POST SYS AGMT NON-INCREMEN DIRCTEAI 2,616 270 2,886 2,886 - - - - ENERGY AND FUEL MANAGEMENT ESI F3PPE14436 EAI MISO RTO STUDY DIRCTEAI 1,103 93 1,196 1,196 - - - - ENERGY AND FUEL MANAGEMENT ESI F3PPEAI011 EAI 2011 Rate Filing DIRCTEAI 1,337 141 1,479 1,479 - - - - ENERGY AND FUEL MANAGEMENT ESI F3PPEAIMIS MISO Transition EAI Path 1 cos DIRCTEAI 39,150 3,057 42,207 42,207 - - - - ENERGY AND FUEL MANAGEMENT ESI F3PPEAIPAT Maintain EAI Paths 2 and 3 RTO DIRCTEAI 7,481 565 8,046 8,046 - - - - ENERGY AND FUEL MANAGEMENT ESI F3PPEGSLMI MISO Transition EGSL costs DIRECTLG 235 - 235 235 - - - - ENERGY AND FUEL MANAGEMENT ESI F3PPELLMIS MISO Transition ELL costs DIRCTELI 235 - 235 235 - - - - ENERGY AND FUEL MANAGEMENT ESI F3PPEMI381 EMI-2010 PMR Docket 2008-UN-38 DIRCTEMI 1,048 109 1,157 1,157 - - - - ENERGY AND FUEL MANAGEMENT ESI F3PPEMI884 EMI-2010 ECR Docket 2008-UN-88 DIRCTEMI 1,365 139 1,504 1,504 - - - - ENERGY AND FUEL MANAGEMENT ESI F3PPEMIMIS MISO Transition EMI costs DIRCTEMI 1,299 84 1,382 1,382 - - - - ENERGY AND FUEL MANAGEMENT ESI F3PPENOIMI MISO Transition ENOI costs DIRCTENO 47 4 50 50 - - - - ENERGY AND FUEL MANAGEMENT ESI F3PPETIMIS MISO Transition ETI costs DIRECTTX 358 27 385 - 385 - (385) - ENERGY AND FUEL MANAGEMENT ESI F3PPINVDOJ DOJ Anti Trust Investigation CUSEOPCO 18,258 1,510 19,768 16,851 2,917 - 77 2,994 ENERGY AND FUEL MANAGEMENT ESI F3PPISP717 Integration Planning Studies 7 LOADOPCO 40,136 3,855 43,991 36,925 7,066 - 149 7,215 ENERGY AND FUEL MANAGEMENT ESI F3PPMSEE10 MS Docket2010-AD-02 Ergy Effic DIRCTEMI - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI F3PPMSFA10 2010 EMI Fuel Aud t DIRCTEMI 27,307 2,651 29,959 29,959 - - - - ENERGY AND FUEL MANAGEMENT ESI F3PPPGA010 PGA Audit 2010 DIRECTLG 3,163 301 3,463 3,463 - - - - ENERGY AND FUEL MANAGEMENT ESI F3PPR56620 WHOLESALE - EGSI LA DIRECTLG - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI F3PPSPE001 SPO NISCO JOPOA MANAGEMENT EXP DIRECTLG 2,404 229 2,633 2,633 - - - - ENERGY AND FUEL MANAGEMENT ESI F3PPSPE002 SPO 2009 Renewable RFI Expense LOADOPCO 10,073 983 11,056 9,405 1,651 - 34 1,685 ENERGY AND FUEL MANAGEMENT ESI F3PPSPE003 SPO Summer 2009 RFP Expense LOADOPCO 146,425 14,002 160,427 136,260 24,168 - 358 24,526 ENERGY AND FUEL MANAGEMENT ESI F3PPSPE004 SPO Summer09RFP IM&PropslSubmt LOADOPCO 269,064 - 269,064 227,046 42,018 - - 42,018 ENERGY AND FUEL MANAGEMENT ESI F3PPSPE006 SPO ISES Mining Asset Evaluati DIRCTEAI - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI F3PPSPE007 SPO July 2009 Flexible Baseloa LOADOPCO - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI F3PPSPE008 SPO July 09 Flex Baseld RFP IM LOADOPCO - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI F3PPSPE010 SPO Diversity Initiative LOADOPCO 4,168 253 4,422 3,725 697 - (4) 693 ENERGY AND FUEL MANAGEMENT ESI F3PPSPE011 SPO NISCO Contract DIRECTLG 28,482 2,396 30,879 30,879 - - - - ENERGY AND FUEL MANAGEMENT ESI F3PPSPE013 SPO PROMOD License for LPSC CUSELGLA 70,620 - 70,620 70,620 - - - - ENERGY AND FUEL MANAGEMENT ESI F3PPSPE015 SPO Compliance and Business Su LOADOPCO 860,093 78,087 938,180 789,566 148,614 - 2,649 151,263 ENERGY AND FUEL MANAGEMENT ESI F3PPSPE016 Addendum-WE0418 Summer 08 IM LOADOPCO - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI F3PPSPE017 SPO 2010 Renewable RFP LOADOPCO 80,022 3,874 83,896 71,371 12,525 - 141 12,666 ENERGY AND FUEL MANAGEMENT ESI F3PPSPE018 SPO VP of Strategic Initiative LOADOPCO 371,895 34,263 406,158 343,181 62,977 - 1,120 64,097 ENERGY AND FUEL MANAGEMENT ESI F3PPSPE019 SPO IT Infrastructure Maint. LOADOPCO 100,713 - 100,713 83,996 16,718 - - 16,718 ENERGY AND FUEL MANAGEMENT ESI F3PPSPE020 SPO SOFTWARE SUPPORT/LICENSING LOADOPCO 24,665 - 24,665 20,571 4,094 - - 4,094 9-244

ENERGY AND FUEL MANAGEMENT ESI F3PPSPE022 SPO Communications Infrastruct LOADOPCO 52,135 - 52,135 43,481 8,654 - - 8,654 ENERGY AND FUEL MANAGEMENT ESI F3PPSPE024 SPO Power De ivery & Tech Serv LOADOPCO 348,447 30,104 378,551 318,892 59,659 - 1,130 60,789 ENERGY AND FUEL MANAGEMENT ESI F3PPSPE025 SPO 2010 Renewable RFP - LA on CUSELGLA 7,915 26,865 34,780 34,780 - - - - ENERGY AND FUEL MANAGEMENT ESI F3PPSPE027 SPO ESI Project Houston PPA DIRCTESI - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI F3PPSPE028 SPO CIP Expense LOADOPCO 85,786 - 85,786 71,547 14,240 - - 14,240 ENERGY AND FUEL MANAGEMENT ESI F3PPSPE038 SPO Pwr Del & Tech Svcs - EMI DIRCTEMI - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI F3PPSPE042 SPO Expense ISES Purchase Opti OWNISES2 245,805 11,722 257,526 257,526 - - - - ENERGY AND FUEL MANAGEMENT ESI F3PPSPE045 PMO Support Initiative - EAI DIRCTEAI 2,817 234 3,051 3,051 - - - - ENERGY AND FUEL MANAGEMENT ESI F3PPSPE047 SPO Telecommunications LOADOPCO 6,086 - 6,086 5,075 1,010 - - 1,010 ENERGY AND FUEL MANAGEMENT ESI F3PPSPE048 SPO Cottonwood Expense LOADOPCO 486 37 522 435 87 - 2 89 ENERGY AND FUEL MANAGEMENT ESI F3PPSPE049 SPO 2011 EAI RFP DIRCTEAI 4,968 318 5,286 5,286 - - - - Amounts may not add or tie to other schedules due to rounding. EXHIBIT PJC-B Cicio, Patrick Page 2 of 4 ENTERGY TEXAS, INC. EXHIBIT PJC-B 2011 ETI Rate Case

Affiliate Billings - by Witness, Class and Project 2011 TX Rate Case For the Twelve Months Ended June 30, 2011 Page 3 of 4 Amounts in Dollars (A) (B) (C) (D) (E) (F) (G) (H) Total Billings Billing Activity / ESI Billing Service Company ETI Per Pro Forma Total ETI Class Entity Project Code Activity / Project Description Method Support Recipient Total All Other BU's Books Exclusions Amount Adjusted ENERGY AND FUEL MANAGEMENT ESI F3PPSPSENI Strategic Planning SVCS-ENI DIRCTENU 497 39 536 536 - - - - ENERGY AND FUEL MANAGEMENT ESI F3PPSPSENT Strategic Planning SVCS-Enterg ASSTSALL 16,152 1,416 17,568 15,832 1,736 - 37 1,774 ENERGY AND FUEL MANAGEMENT ESI F3PPSPSREG Strategic Planning SVCS-Utilit ASSTSREG 5,833 459 6,292 5,352 939 - 20 960 ENERGY AND FUEL MANAGEMENT ESI F3PPTCGS11 TX Docket Competitive Generati DIRECTTX 2,870 267 3,137 - 3,137 - 66 3,203 ENERGY AND FUEL MANAGEMENT ESI F3PPTDERSC Entergy Regional State Committ LOADOPCO 271,962 19,669 291,631 244,380 47,250 - 1,014 48,265 ENERGY AND FUEL MANAGEMENT ESI F3PPTDERSD MISO Transition ALL OPCO LOADOPCO 122,670 8,589 131,259 109,471 21,788 - (21,788) - ENERGY AND FUEL MANAGEMENT ESI F3PPTDHY11 Transmission Compliance FERC A TRSBLNOP 144 15 159 140 19 - 1 19 ENERGY AND FUEL MANAGEMENT ESI F3PPUD0802 ENO Integrated Resource Plan DIRCTENO 6,267 462 6,729 6,729 - - - - ENERGY AND FUEL MANAGEMENT ESI F3PPUTLDER Util ty Derivatives Compliance LOADOPCO 2,881 261 3,142 2,620 521 - 11 533 ENERGY AND FUEL MANAGEMENT ESI F3PPWE0292 System Planning Asset Manageme LOADOPCO 319,863 27,284 347,147 291,842 55,305 - 952 56,258 ENERGY AND FUEL MANAGEMENT ESI F3PPWE0315 Dir. Southeast Region-TXT_ ELI CAPASTHN 18,259 1,717 19,976 19,976 - - - - ENERGY AND FUEL MANAGEMENT ESI F3PPWE0402 SPO Regulatory Compliance LOADOPCO 545,842 47,326 593,168 499,258 93,910 - 1,882 95,792 ENERGY AND FUEL MANAGEMENT ESI F3PPWE0403 SPO Performance Mngmnt/Special LOADOPCO 437,200 36,298 473,498 398,296 75,202 - 1,619 76,821 ENERGY AND FUEL MANAGEMENT ESI F3PPWE0420 SPO EGSL-SupplyProcuremt/Asset DIRECTLG 4,225 356 4,581 4,581 - - - - ENERGY AND FUEL MANAGEMENT ESI F3PPWE0432 SPOManagement of Sys IRP Activ LOADOPCO 1,286 107 1,393 1,177 216 - 7 223 ENERGY AND FUEL MANAGEMENT ESI F3PPWE0437 SPO Expense KGen Hinds DIRCTEMI - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI F3PPWE0438 SPO Expense KGen Hot Springs DIRCTEAI - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI F3PPWE0478 Parkwood II Safety Team CAPAOPCO 8,234 - 8,234 7,343 890 - (147) 743 ENERGY AND FUEL MANAGEMENT ESI F3PPWE0516 EPA Section 114 Request for In DIRCTEAI 3,836 365 4,201 4,201 - - - - ENERGY AND FUEL MANAGEMENT ESI F3PPWET300 SPO 2008 Western Region RFP-Te DIRECTTX 473 39 512 - 512 - 11 523 ENERGY AND FUEL MANAGEMENT ESI F3PPWET301 SPO ETI-SupplyProcuremt/AssetM DIRECTTX - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI F3PPWET302 SPO 2008 Winter Western Region DIRECTTX 4,218 388 4,607 - 4,607 - 91 4,698 ENERGY AND FUEL MANAGEMENT ESI F3PPWET303 SPO2008WinterWestnRegionRFP-IM DIRECTTX 4,200 - 4,200 - 4,200 - - 4,200 ENERGY AND FUEL MANAGEMENT ESI F3PPWET304 SPO Frontier 10 Year PPA DIRECTTX 88 7 95 - 95 - 2 97 ENERGY AND FUEL MANAGEMENT ESI F3PPWET305 SPO WWOTAB Expense DIRECTTX - - - - - - (0) (0) ENERGY AND FUEL MANAGEMENT ESI F3PPWET306 SPO 2011 Western Region RFP DIRECTTX 87,224 5,621 92,845 - 92,845 - 1,563 94,408 ENERGY AND FUEL MANAGEMENT ESI F3PPWET307 SPO2011WestnRegionRFP-IM&PropS DIRECTTX 19,469 - 19,469 - 19,469 - - 19,469 ENERGY AND FUEL MANAGEMENT ESI F3PPWET308 SPO Calpine PPA/Project Housto DIRECTTX 86,588 8,357 94,945 - 94,945 - 1,996 96,941 ENERGY AND FUEL MANAGEMENT ESI F5PC25116F ELI FUEL AUDIT 2001 DIRCTELI 1,394 117 1,511 1,511 - - - - ENERGY AND FUEL MANAGEMENT ESI F5PCE13611 GENERAL LITIGATION-ENOI DIRCTENO 2,733 257 2,990 2,990 - - - - ENERGY AND FUEL MANAGEMENT ESI F5PCE13751 GENERAL LITIGATION- EGSI-LA DIRECTLG 4,399 388 4,787 4,787 - - - - ENERGY AND FUEL MANAGEMENT ESI F5PCE13759 JENKINS CLASS ACTION SUIT DIRECTTX 34,881 2,988 37,870 - 37,870 - 1,007 38,876 ENERGY AND FUEL MANAGEMENT ESI F5PCEDIVER DIVERSITY TRAINING DIRCTESI 495 - 495 495 - - - - ENERGY AND FUEL MANAGEMENT ESI F5PCGSL351 ELI 2001 SYSTEM AGREEMENT CASE DIRCTELI 1,234 125 1,359 1,359 - - - - ENERGY AND FUEL MANAGEMENT ESI F5PCGSL500 EGS FUEL AUDIT DIRECTLG 1,794 102 1,896 1,896 - - - - ENERGY AND FUEL MANAGEMENT ESI F5PCSVCAWD SERVICE AWARDS DIRCTESI 4,799 - 4,799 4,799 - - - - ENERGY AND FUEL MANAGEMENT ESI F5PCZCDEPT SUPERVISION & SUPPORT - CORPOR LBRCORPT 15,051 1,317 16,368 15,927 441 - 10 451 ENERGY AND FUEL MANAGEMENT ESI F5PCZU1422 REGULATORY AFFAIRS - LP&L DIRCTELI 10,036 985 11,021 11,021 - - - - ENERGY AND FUEL MANAGEMENT ESI F5PCZU1424 REGULATORY AFFAIRS - NOPSI DIRCTENO 37,547 3,228 40,775 40,775 - - - - ENERGY AND FUEL MANAGEMENT ESI F5PCZU1425 REGULATORY COORDINAT.-ELI & EG CUSELPSC 566 58 624 624 - - - - ENERGY AND FUEL MANAGEMENT ESI F5PCZU1573 REGULATORY AFFAIRS -- 100% EGS DIRECTTX - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI F5PCZU1574 REGULATORY AFFAIRS - 100% TX G DIRECTTX 33,986 2,760 36,745 - 36,745 - 719 37,464 ENERGY AND FUEL MANAGEMENT ESI F5PCZU1579 REGULATORY AFFAIRS -- 100% EGS DIRECTLG 5,045 439 5,485 5,485 - - - - ENERGY AND FUEL MANAGEMENT ESI F5PCZUDEPX DEPRECIATION AND AMORTIZATION ESIDEPRE 1,450 - 1,450 1,450 - - - - ENERGY AND FUEL MANAGEMENT ESI F5PCZXNLDW NEW LEADERSHIP DEVELOPMENT WOR EMPLOREG 35 - 35 33 2 - - 2 ENERGY AND FUEL MANAGEMENT ESI F5PCZZ4070 IMPACT AWARDS DIRCTESI 191 - 191 191 - - - - ENERGY AND FUEL MANAGEMENT ESI F5PP10011U Show Cause Docket No. 10-011-U DIRCTEAI 169,027 14,225 183,252 183,252 - - - - ENERGY AND FUEL MANAGEMENT ESI F5PP27836P ELI/EGS Purchase of Perryville DIRCTELI 14 - 14 14 - - - - ENERGY AND FUEL MANAGEMENT ESI F5PP4RFERC FERC Audit LVLSVCAL 1,999 187 2,185 1,975 210 - 7 217 ENERGY AND FUEL MANAGEMENT ESI F5PPBCNAVF Avian Flu Contingency Planning EMPLOYAL - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI F5PPBULKPW Minimize of Bulk Power Supply LOADOPCO 58,303 4,996 63,299 52,958 10,341 - 210 10,551 9-245

ENERGY AND FUEL MANAGEMENT ESI F5PPDOEETR DOE-Dept of Energy Studies Coo LOADOPCO 458 186 644 544 100 - 7 106 ENERGY AND FUEL MANAGEMENT ESI F5PPE14427 Regulatory Info RFIs-EAI-Dock DIRCTEAI 6,118 543 6,660 6,660 - - - - ENERGY AND FUEL MANAGEMENT ESI F5PPETX009 2009 Texas Rate Case Support DIRECTTX 15,273 1,828 17,101 - 17,101 (3,549) (13,552) - ENERGY AND FUEL MANAGEMENT ESI F5PPETX011 2011 Texas Rate Case Support DIRECTTX 222 25 247 - 247 - 8 255 ENERGY AND FUEL MANAGEMENT ESI F5PPFALCON Project Falcon DIRECTNI 4,987 382 5,370 5,370 - - - - ENERGY AND FUEL MANAGEMENT ESI F5PPFERCCM FERC Compliance Program EMPLOREG 67 - 67 63 4 - - 4 ENERGY AND FUEL MANAGEMENT ESI F5PPHREXEC HR Executive Financial Counsel ASSTSALL - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI F5PPLEGRB3 Regulatory Filings - River Ben CUSELGLA 176 - 176 176 - - - - ENERGY AND FUEL MANAGEMENT ESI F5PPMSFA09 2009 EMI Fuel Aud t Horne Grou DIRCTEMI 1,113 98 1,210 1,210 - - - - ENERGY AND FUEL MANAGEMENT ESI F5PPMSFA9A 2009 EMI Fuel Aud t McFadden G DIRCTEMI 518 57 575 575 - - - - ENERGY AND FUEL MANAGEMENT ESI F5PPPAPDIS Paper Barrier Case DIRCTEAI - - - - - - - - Amounts may not add or tie to other schedules due to rounding. EXHIBIT PJC-B Cicio, Patrick Page 3 of 4 ENTERGY TEXAS, INC. EXHIBIT PJC-B 2011 ETI Rate Case

Affiliate Billings - by Witness, Class and Project 2011 TX Rate Case For the Twelve Months Ended June 30, 2011 Page 4 of 4 Amounts in Dollars (A) (B) (C) (D) (E) (F) (G) (H) Total Billings Billing Activity / ESI Billing Service Company ETI Per Pro Forma Total ETI Class Entity Project Code Activity / Project Description Method Support Recipient Total All Other BU's Books Exclusions Amount Adjusted ENERGY AND FUEL MANAGEMENT ESI F5PPSPE044 PMO Support Initiative-System- LOADOPCO 74,598 6,137 80,735 67,333 13,401 - (13,401) - ENERGY AND FUEL MANAGEMENT ESI F5PPSPPCBA ICT/RTO Cost Benefit Analysis LOADOPCO 34,464 3,240 37,704 31,745 5,958 - (5,958) - ENERGY AND FUEL MANAGEMENT ESI F5PPSUPICT Support of ICT LOADOPCO 71,151 6,083 77,234 64,739 12,495 - 247 12,742 ENERGY AND FUEL MANAGEMENT ESI F5PPWE0485 2010 EPA Request for Informati CAPAOPCO 45 4 48 43 5 - 0 5 ENERGY AND FUEL MANAGEMENT ESI F5PPZUWELL Entergy Wellness Program EMPLOYAL 11,227 840 12,068 11,478 590 - 13 603 ENERGY AND FUEL MANAGEMENT ESI F5PPZZ580B REGULATORY AFFAIRS-A&G CUSTEGOP 1,064 82 1,146 988 158 - 3 161 ENERGY AND FUEL MANAGEMENT Total ESI 23,521,673 1,732,183 25,253,856 21,510,774 3,743,083 (7,029) 6,260 3,742,314 Total ENERGY AND FUEL MANAGEMENT 23,521,673 1,732,183 25,253,856 21,510,774 3,743,083 (7,029) 6,260 3,742,314 Total Cicio Patrick 23,521,673 1,732,183 25,253,856 21,510,774 3,743,083 (7,029) 6,260 3,742,314 9-246

Amounts may not add or tie to other schedules due to rounding. EXHIBIT PJC-B Cicio, Patrick Page 4 of 4 ENTERGY TEXAS, INC. EXHIBIT PJC-C 2011 ETI Rate Case

Affiliate Billings - by Witness, Class, Department and Project 2011 TX Rate Case For the Twelve Months Ended June 30, 2011 Page 1 of 11 Amounts in Dollars (A) (B) (C) (D) (E) (F) (G) (H) Total Billings Activity / Project ESI BIlling Service Company ETI Per Pro Forma Total ETI Class Billing Entity Dept Code Activity / Project Description Method Support Recipient Total All Other BU's Books Exclusions Amount Adjusted ENERGY AND FUEL MANAGEMENT ESI CP204 E1PPEFF003 EAI ENERGY EFFCNCY NON-INCREME DIRCTEAI 11,515 1,145 12,660 12,660 - - - - ENERGY AND FUEL MANAGEMENT ESI CP204 F3PCCSPGST SYSTEM PLANNING - EGSI-TX DIRECTTX 1,032 105 1,137 - 1,137 - 24 1,161 ENERGY AND FUEL MANAGEMENT ESI CP204 F3PCCSPSYS SYSTEM PLANNING AND STRATEGIC ASSTSALL 257,660 151 257,811 231,925 25,886 - 4 25,890 ENERGY AND FUEL MANAGEMENT ESI CP204 F3PCCSPUTI SYSTEM PLANNING & STRATEGIC AD LOADOPCO 1,189,449 43,430 1,232,879 1,042,896 189,983 - 1,714 191,697 ENERGY AND FUEL MANAGEMENT ESI CP204 F3PCE14420 REGULATORY AFFAIRS - EAI DIRCTEAI 2,599 149 2,748 2,748 - - - - ENERGY AND FUEL MANAGEMENT ESI CP204 F3PPAMPDEV Advanced Mgmt Dev Program EMPLOYAL 4,112 - 4,112 3,921 192 - - 192 ENERGY AND FUEL MANAGEMENT ESI CP204 F3PPDSMALL DSM/Energy Efficiency -A l Jur CUSTEGOP 3,059 258 3,318 2,858 460 - (460) - ENERGY AND FUEL MANAGEMENT ESI CP204 F3PPEAI011 EAI 2011 Rate Fi ing DIRCTEAI 1,337 141 1,479 1,479 - - - - ENERGY AND FUEL MANAGEMENT ESI CP204 F3PPSPE013 SPO PROMOD License for LPSC CUSELGLA 70,620 - 70,620 70,620 - - - - ENERGY AND FUEL MANAGEMENT ESI CP204 F3PPUD0802 ENO Integrated Resource Plan DIRCTENO 1,377 84 1,461 1,461 - - - - ENERGY AND FUEL MANAGEMENT ESI CP204 F5PPE14427 Regulatory Info RFIs-EAI-Dock DIRCTEAI 1,891 159 2,050 2,050 - - - - ENERGY AND FUEL MANAGEMENT ESI CP204 F5PPZUWELL Entergy Wellness Program EMPLOYAL 439 36 475 451 23 - 0 24 ENERGY AND FUEL MANAGEMENT ESI CP204 Total 1,545,092 45,658 1,590,750 1,373,069 217,681 - 1,282 218,963 ENERGY AND FUEL MANAGEMENT ESI CP218 C1PPRNE010 New Nuclear -Regulatory Fi ing NWDVRBGG (1,445) (114) (1,559) (1,559) - - - - ENERGY AND FUEL MANAGEMENT ESI CP218 C1PPSP0008 SPO ELL&ENOI Purchase Option I OWNISES2 (4,441) (471) (4,911) (4,911) - - - - ENERGY AND FUEL MANAGEMENT ESI CP218 C6PCN32144 GRAND GULF EXTENDED POWER UPRA DIRCTSER 3,459 313 3,772 3,772 - - - - ENERGY AND FUEL MANAGEMENT ESI CP218 C6PPGN0020 New Nuclear Reg Filing EGSL On DIRECTLG 723 57 779 779 - - - - ENERGY AND FUEL MANAGEMENT ESI CP218 C6PPLN0020 New Nuclear Reg Filing ELL Ong DIRCTELI 723 57 779 779 - - - - ENERGY AND FUEL MANAGEMENT ESI CP218 C6PPRN0002 New Nuclear - Entergy DIRCTR1 - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI CP218 C6PPSP0012 SPO Project Gator Transact/Tra DIRCTELI 2,359 179 2,537 2,537 - - - - ENERGY AND FUEL MANAGEMENT ESI CP218 C6PPSP0029 SPO Evange ine DIRCTELI 236 20 256 256 - - - - ENERGY AND FUEL MANAGEMENT ESI CP218 C6PPSP0038 SPO Project Lamar Transaction DIRCTEAI 6,126 595 6,721 6,721 - - - - ENERGY AND FUEL MANAGEMENT ESI CP218 C6PPSP0046 SPO Project Burnet Transaction DIRCTEMI 6,719 678 7,397 7,397 - - - - ENERGY AND FUEL MANAGEMENT ESI CP218 C6PPWS0628 SPO W-WOTAB CT Development Spe DIRECTTX - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI CP218 C6PPWS0783 Ninem le 6 Development DIRCTELI 1,501 153 1,654 1,654 - - - - ENERGY AND FUEL MANAGEMENT ESI CP218 F3PCCSPSYS SYSTEM PLANNING AND STRATEGIC ASSTSALL 2,282 - 2,282 2,050 232 - - 232 ENERGY AND FUEL MANAGEMENT ESI CP218 F3PCCSPUTI SYSTEM PLANNING & STRATEGIC AD LOADOPCO 510,111 41,302 551,413 464,460 86,954 - 101 87,055 ENERGY AND FUEL MANAGEMENT ESI CP218 F3PCF07300 CORP PLANNING & ANALYSIS- REGU CUSTEGOP 3,378 203 3,582 3,088 494 - 7 501 ENERGY AND FUEL MANAGEMENT ESI CP218 F3PCF21600 CORP RPTG ANALYSIS & POLICY AL GENLEDAL - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI CP218 F3PCFF1003 BOARD SUPPORT ASSTSALL 4,920 377 5,297 4,771 526 - 9 535 ENERGY AND FUEL MANAGEMENT ESI CP218 F3PCSYSAGR SYSTEM AGREEMENT-2001 CUSEOPCO 2,906 236 3,142 2,679 463 - 11 475 ENERGY AND FUEL MANAGEMENT ESI CP218 F3PCW18300 OPNS-COAL SUPPLY COALARGS - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI CP218 F3PCW19510 ENERGY MANAGEMENT OPERATIONS LOADOPCO - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI CP218 F3PCW54035 VICE PRESIDENT OF ENERGY MANAG LOADOPCO 57 - 57 48 8 - - 8 ENERGY AND FUEL MANAGEMENT ESI CP218 F3PCWE0058 AWARDS & RECOGNITIONS PROGRAM LOADOPCO 551 93 644 548 96 - 2 98 ENERGY AND FUEL MANAGEMENT ESI CP218 F3PCWE0092 EMS OPERATIONS & MAINTENANCE S LOADOPCO - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI CP218 F3PCWE0135 NEL. 6 JOINT OWNERSHIP PART. A DIRECTLG (88) - (88) (88) - - - - ENERGY AND FUEL MANAGEMENT ESI CP218 F3PCWE0140 EMO REGULATORY AFFAIRS LOADOPCO - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI CP218 F3PPADSENT Analytic/Decision Support-Ente ASSTSALL 614 - 614 555 58 - - 58 ENERGY AND FUEL MANAGEMENT ESI CP218 F3PPE14434 EAI POST SYS AGMT INCREMENTAL DIRCTEAI 239 26 266 266 - - - - ENERGY AND FUEL MANAGEMENT ESI CP218 F3PPINVDOJ DOJ Anti Trust Investigation CUSEOPCO 1,961 171 2,131 1,817 314 - 6 320 ENERGY AND FUEL MANAGEMENT ESI CP218 F3PPMSFA10 2010 EMI Fuel Audit DIRCTEMI 887 77 964 964 - - - - ENERGY AND FUEL MANAGEMENT ESI CP218 F3PPSPE003 SPO Summer 2009 RFP Expense LOADOPCO 151 - 151 128 23 - (2) 21 ENERGY AND FUEL MANAGEMENT ESI CP218 F3PPSPE011 SPO NISCO Contract DIRECTLG 4,591 383 4,974 4,974 - - - - ENERGY AND FUEL MANAGEMENT ESI CP218 F3PPSPE017 SPO 2010 Renewable RFP LOADOPCO 7,022 629 7,651 6,509 1,142 - 24 1,167 ENERGY AND FUEL MANAGEMENT ESI CP218 F3PPSPE025 SPO 2010 Renewable RFP - LA on CUSELGLA 2,816 188 3,004 3,004 - - - - ENERGY AND FUEL MANAGEMENT ESI CP218 F3PPSPE027 SPO ESI Project Houston PPA DIRCTESI - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI CP218 F3PPSPE042 SPO Expense ISES Purchase Opti OWNISES2 9,358 869 10,227 10,227 - - - - ENERGY AND FUEL MANAGEMENT ESI CP218 F3PPSPSENI Strategic Planning SVCS-ENI DIRCTENU 497 39 536 536 - - - - ENERGY AND FUEL MANAGEMENT ESI CP218 F3PPSPSENT Strategic Planning SVCS-Enterg ASSTSALL 16,152 1,416 17,568 15,832 1,736 - 37 1,774 ENERGY AND FUEL MANAGEMENT ESI CP218 F3PPSPSREG Strategic Planning SVCS-Utilit ASSTSREG 5,833 459 6,292 5,352 939 - 20 960 ENERGY AND FUEL MANAGEMENT ESI CP218 F3PPTDERSC Entergy Regional State Committ LOADOPCO 27,888 2,375 30,263 25,372 4,891 - 94 4,985 9-247

ENERGY AND FUEL MANAGEMENT ESI CP218 F3PPTDERSD MISO Transition ALL OPCO LOADOPCO 2,778 199 2,977 2,483 494 - (494) - ENERGY AND FUEL MANAGEMENT ESI CP218 F3PPWE0402 SPO Regulatory Compliance LOADOPCO 24,145 - 24,145 20,137 4,008 - - 4,008 ENERGY AND FUEL MANAGEMENT ESI CP218 F3PPWE0437 SPO Expense KGen Hinds DIRCTEMI - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI CP218 F3PPWE0438 SPO Expense KGen Hot Springs DIRCTEAI - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI CP218 F3PPWET300 SPO 2008 Western Region RFP-Te DIRECTTX 473 39 512 - 512 - 11 523 ENERGY AND FUEL MANAGEMENT ESI CP218 F3PPWET302 SPO 2008 Winter Western Region DIRECTTX 2,630 227 2,857 - 2,857 - 55 2,912 ENERGY AND FUEL MANAGEMENT ESI CP218 F3PPWET305 SPO WWOTAB Expense DIRECTTX - - - - - - (0) (0) ENERGY AND FUEL MANAGEMENT ESI CP218 F3PPWET306 SPO 2011 Western Region RFP DIRECTTX 1,628 119 1,748 - 1,748 - 38 1,786 ENERGY AND FUEL MANAGEMENT ESI CP218 F3PPWET308 SPO Calpine PPA/Project Housto DIRECTTX 2,004 176 2,180 - 2,180 - 42 2,222 ENERGY AND FUEL MANAGEMENT ESI CP218 F5PCSVCAWD SERVICE AWARDS DIRCTESI - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI CP218 F5PCZU1425 REGULATORY COORDINAT.-ELI & EG CUSELPSC (88) - (88) (88) - - - - ENERGY AND FUEL MANAGEMENT ESI CP218 F5PCZU1574 REGULATORY AFFAIRS - 100% TX G DIRECTTX 2,881 253 3,134 - 3,134 - 67 3,202 Amounts may not add or tie to other schedules due to rounding.

EXHIBIT PJC-C Cicio, Patrick Page 1 of 11 ENTERGY TEXAS, INC. EXHIBIT PJC-C 2011 ETI Rate Case

Affiliate Billings - by Witness, Class, Department and Project 2011 TX Rate Case For the Twelve Months Ended June 30, 2011 Page 2 of 11 Amounts in Dollars (A) (B) (C) (D) (E) (F) (G) (H) Total Billings Activity / Project ESI BIlling Service Company ETI Per Pro Forma Total ETI Class Billing Entity Dept Code Activity / Project Description Method Support Recipient Total All Other BU's Books Exclusions Amount Adjusted ENERGY AND FUEL MANAGEMENT ESI CP218 F5PCZU1579 REGULATORY AFFAIRS -- 100% EGS DIRECTLG - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI CP218 F5PCZUDEPX DEPRECIATION AND AMORTIZATION ESIDEPRE 1,450 - 1,450 1,450 - - - - ENERGY AND FUEL MANAGEMENT ESI CP218 F5PP10011U Show Cause Docket No. 10-011-U DIRCTEAI 986 39 1,025 1,025 - - - - ENERGY AND FUEL MANAGEMENT ESI CP218 F5PPETX009 2009 Texas Rate Case Support DIRECTTX 473 39 512 - 512 - (512) - ENERGY AND FUEL MANAGEMENT ESI CP218 F5PPFALCON Project Falcon DIRECTNI 4,987 382 5,370 5,370 - - - - ENERGY AND FUEL MANAGEMENT ESI CP218 F5PPHREXEC HR Executive Financial Counsel ASSTSALL - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI CP218 F5PPSPE044 PMO Support Initiative-System- LOADOPCO 5,279 442 5,721 4,771 950 - (950) - ENERGY AND FUEL MANAGEMENT ESI CP218 F5PPSUPICT Support of ICT LOADOPCO 2,576 193 2,768 2,344 425 - 7 432 ENERGY AND FUEL MANAGEMENT ESI CP218 Total 670,285 52,421 722,706 608,009 114,697 - (1,424) 113,273 ENERGY AND FUEL MANAGEMENT ESI CP227 C1PPRNE010 New Nuclear -Regulatory Fi ing NWDVRBGG (3,593) (282) (3,876) (3,876) - - - - ENERGY AND FUEL MANAGEMENT ESI CP227 C6PCN32144 GRAND GULF EXTENDED POWER UPRA DIRCTSER 10,060 928 10,988 10,988 - - - - ENERGY AND FUEL MANAGEMENT ESI CP227 C6PPGN0020 New Nuclear Reg Filing EGSL On DIRECTLG 2,904 231 3,135 3,135 - - - - ENERGY AND FUEL MANAGEMENT ESI CP227 C6PPLN0020 New Nuclear Reg Filing ELL Ong DIRCTELI 2,903 231 3,135 3,135 - - - - ENERGY AND FUEL MANAGEMENT ESI CP227 C6PPN66876 Cladding Failure Root Cause & DIRCTWF3 5,748 545 6,293 6,293 - - - - ENERGY AND FUEL MANAGEMENT ESI CP227 C6PPRN0002 New Nuclear - Entergy DIRCTR1 - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI CP227 C6PPSP0012 SPO Project Gator Transact/Tra DIRCTELI 1,826 175 2,001 2,001 - - - - ENERGY AND FUEL MANAGEMENT ESI CP227 C6PPSP0038 SPO Project Lamar Transaction DIRCTEAI 6,260 619 6,880 6,880 - - - - ENERGY AND FUEL MANAGEMENT ESI CP227 C6PPSP0046 SPO Project Burnet Transaction DIRCTEMI 12,482 1,158 13,640 13,640 - - - - ENERGY AND FUEL MANAGEMENT ESI CP227 C6PPWS0534 System Planning Pet Coke Repow DIRCTELI 374 11 384 384 - - - - ENERGY AND FUEL MANAGEMENT ESI CP227 C6PPWS0783 Ninem le 6 Development DIRCTELI 13,723 1,274 14,997 14,997 - - - - ENERGY AND FUEL MANAGEMENT ESI CP227 F3PCCSPEAI SYSTEM PLANNING - EAI DIRCTEAI 8,526 729 9,255 9,255 - - - - ENERGY AND FUEL MANAGEMENT ESI CP227 F3PCCSPEEI SYSTEM PLANNING - NONREG - EEI ASSTNREG 548 48 596 596 - - - - ENERGY AND FUEL MANAGEMENT ESI CP227 F3PCCSPELI SYSTEM PLANNING - ELI DIRCTELI 26,965 2,403 29,368 29,368 - - - - ENERGY AND FUEL MANAGEMENT ESI CP227 F3PCCSPEMI SYSTEM PLANNING - EMI DIRCTEMI 2,182 182 2,364 2,364 - - - - ENERGY AND FUEL MANAGEMENT ESI CP227 F3PCCSPENO SYSTEM PLANNING - ENOI DIRCTENO 26,340 2,267 28,607 28,607 - - - - ENERGY AND FUEL MANAGEMENT ESI CP227 F3PCCSPGSL SYSTEM PLANNING - EGSI-LA DIRECTLG 12,199 1,068 13,266 13,266 - - - - ENERGY AND FUEL MANAGEMENT ESI CP227 F3PCCSPGST SYSTEM PLANNING - EGSI-TX DIRECTTX 19,618 1,785 21,402 - 21,402 - 441 21,843 ENERGY AND FUEL MANAGEMENT ESI CP227 F3PCCSPSYS SYSTEM PLANNING AND STRATEGIC ASSTSALL 1,220 49 1,269 1,144 125 - 1 126 ENERGY AND FUEL MANAGEMENT ESI CP227 F3PCCSPUTI SYSTEM PLANNING & STRATEGIC AD LOADOPCO 740,225 60,509 800,734 674,202 126,531 - 2,492 129,023 ENERGY AND FUEL MANAGEMENT ESI CP227 F3PCSYSRAS SYSTEM REGULATORY AFFAIRS-STAT CUSTEGOP 1 - 1 1 0 - - 0 ENERGY AND FUEL MANAGEMENT ESI CP227 F3PCW15830 SYSTEM GENERATION PLANNING LOADOPCO - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI CP227 F3PPSPE003 SPO Summer 2009 RFP Expense LOADOPCO 28,138 2,350 30,489 25,937 4,552 - 81 4,633 ENERGY AND FUEL MANAGEMENT ESI CP227 F3PPSPE017 SPO 2010 Renewable RFP LOADOPCO 1,972 314 2,286 1,945 341 - 6 347 ENERGY AND FUEL MANAGEMENT ESI CP227 F3PPSPE025 SPO 2010 Renewable RFP - LA on CUSELGLA 85,008 7,809 92,817 92,817 - - - - ENERGY AND FUEL MANAGEMENT ESI CP227 F3PPSPE027 SPO ESI Project Houston PPA DIRCTESI - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI CP227 F3PPSPE042 SPO Expense ISES Purchase Opti OWNISES2 8,107 791 8,897 8,897 - - - - ENERGY AND FUEL MANAGEMENT ESI CP227 F3PPTDERSD MISO Transition ALL OPCO LOADOPCO 2,220 168 2,388 1,992 396 - (396) - ENERGY AND FUEL MANAGEMENT ESI CP227 F3PPUD0802 ENO Integrated Resource Plan DIRCTENO 3,466 261 3,726 3,726 - - - - ENERGY AND FUEL MANAGEMENT ESI CP227 F3PPWET306 SPO 2011 Western Region RFP DIRECTTX 10,562 882 11,445 - 11,445 - 250 11,695 ENERGY AND FUEL MANAGEMENT ESI CP227 F3PPWET308 SPO Calpine PPA/Project Housto DIRECTTX 11,630 1,095 12,726 - 12,726 - 270 12,996 ENERGY AND FUEL MANAGEMENT ESI CP227 F5PCSVCAWD SERVICE AWARDS DIRCTESI 89 - 89 89 - - - - ENERGY AND FUEL MANAGEMENT ESI CP227 F5PCZCDEPT SUPERVISION & SUPPORT - CORPOR LBRCORPT 15,051 1,317 16,368 15,927 441 - 10 451 ENERGY AND FUEL MANAGEMENT ESI CP227 Total 1,056,752 88,917 1,145,669 967,710 177,959 - 3,154 181,114 ENERGY AND FUEL MANAGEMENT ESI CP235 C1PCN70859 RIVER BEND EXTENDED POWER UPRA DIRCTEOI - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI CP235 C1PPSP0008 SPO ELL&ENOI Purchase Option I OWNISES2 (103,294) (2,027) (105,321) (105,321) - - - - ENERGY AND FUEL MANAGEMENT ESI CP235 C6PCN70858 RIVER BEND EXTENDED POWER UPRA - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI CP235 C6PPSP0012 SPO Project Gator Transact/Tra DIRCTELI 33,913 2,091 36,004 36,004 - - - - ENERGY AND FUEL MANAGEMENT ESI CP235 C6PPSP0038 SPO Project Lamar Transaction DIRCTEAI 256,430 5,319 261,749 261,749 - - - - ENERGY AND FUEL MANAGEMENT ESI CP235 C6PPSP0046 SPO Project Burnet Transaction DIRCTEMI 309,730 5,627 315,357 315,357 - - - - ENERGY AND FUEL MANAGEMENT ESI CP235 C6PPWGP516 SBC CIP Compliance DIRECTTX 120 - 120 - 120 (120) - - 9-248

ENERGY AND FUEL MANAGEMENT ESI CP235 C6PPWS0628 SPO W-WOTAB CT Development Spe DIRECTTX - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI CP235 C6PPWS0783 Ninem le 6 Development DIRCTELI 342 36 378 378 - - - - ENERGY AND FUEL MANAGEMENT ESI CP235 F3PCCSPUTI SYSTEM PLANNING & STRATEGIC AD LOADOPCO 324 - 324 271 53 - (17) 35 ENERGY AND FUEL MANAGEMENT ESI CP235 F3PCW18300 OPNS-COAL SUPPLY COALARGS 8,363 743 9,106 9,106 - - - - ENERGY AND FUEL MANAGEMENT ESI CP235 F3PCW19512 ENERGY MGMT - FUEL & ENERGY AN LOADOPCO (47) - (47) (40) (7) - (0) (7) ENERGY AND FUEL MANAGEMENT ESI CP235 F3PCW29607 POWER SYSTEM ACCOUNTING LOADWEPI - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI CP235 F3PCWE0034 DIRECTOR - PLANT SUPPORT CAPAOPCO - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI CP235 F3PCWE0046 PLANT SUPPORT SERVICES - BIG C ASSTTXLG 15,342 1,291 16,632 9,775 6,857 - 139 6,996 ENERGY AND FUEL MANAGEMENT ESI CP235 F3PCWE0135 NEL. 6 JOINT OWNERSHIP PART. A DIRECTLG 5,017 463 5,480 5,480 - - - - ENERGY AND FUEL MANAGEMENT ESI CP235 F3PPDOWPPA Dow 3 Year PPA (2011-2014) DIRECTLG 497 52 549 549 - - - - ENERGY AND FUEL MANAGEMENT ESI CP235 F3PPE14434 EAI POST SYS AGMT INCREMENTAL DIRCTEAI 2,856 259 3,115 3,115 - - - - ENERGY AND FUEL MANAGEMENT ESI CP235 F3PPINVDOJ DOJ Anti Trust Investigation CUSEOPCO 1,932 82 2,014 1,717 297 - 2 299 Amounts may not add or tie to other schedules due to rounding.

EXHIBIT PJC-C Cicio, Patrick Page 2 of 11 ENTERGY TEXAS, INC. EXHIBIT PJC-C 2011 ETI Rate Case

Affiliate Billings - by Witness, Class, Department and Project 2011 TX Rate Case For the Twelve Months Ended June 30, 2011 Page 3 of 11 Amounts in Dollars (A) (B) (C) (D) (E) (F) (G) (H) Total Billings Activity / Project ESI BIlling Service Company ETI Per Pro Forma Total ETI Class Billing Entity Dept Code Activity / Project Description Method Support Recipient Total All Other BU's Books Exclusions Amount Adjusted ENERGY AND FUEL MANAGEMENT ESI CP235 F3PPMSFA10 2010 EMI Fuel Audit DIRCTEMI 334 28 362 362 - - - - ENERGY AND FUEL MANAGEMENT ESI CP235 F3PPSPE001 SPO NISCO JOPOA MANAGEMENT EXP DIRECTLG - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI CP235 F3PPSPE002 SPO 2009 Renewable RFI Expense LOADOPCO 9,446 928 10,373 8,825 1,549 - 32 1,581 ENERGY AND FUEL MANAGEMENT ESI CP235 F3PPSPE003 SPO Summer 2009 RFP Expense LOADOPCO 35,551 3,363 38,914 33,097 5,817 - (3) 5,814 ENERGY AND FUEL MANAGEMENT ESI CP235 F3PPSPE011 SPO NISCO Contract DIRECTLG 1,101 93 1,194 1,194 - - - - ENERGY AND FUEL MANAGEMENT ESI CP235 F3PPSPE015 SPO Compliance and Business Su LOADOPCO - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI CP235 F3PPSPE017 SPO 2010 Renewable RFP LOADOPCO 5,690 454 6,144 5,226 917 - 18 935 ENERGY AND FUEL MANAGEMENT ESI CP235 F3PPSPE025 SPO 2010 Renewable RFP - LA on CUSELGLA 34,620 3,254 37,874 37,874 - - - - ENERGY AND FUEL MANAGEMENT ESI CP235 F3PPSPE027 SPO ESI Project Houston PPA DIRCTESI - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI CP235 F3PPSPE042 SPO Expense ISES Purchase Opti OWNISES2 138,034 2,789 140,823 140,823 - - - - ENERGY AND FUEL MANAGEMENT ESI CP235 F3PPSPE048 SPO Cottonwood Expense LOADOPCO 486 37 522 435 87 - 2 89 ENERGY AND FUEL MANAGEMENT ESI CP235 F3PPTDERSC Entergy Regional State Committ LOADOPCO 1,912 176 2,088 1,744 344 - 7 351 ENERGY AND FUEL MANAGEMENT ESI CP235 F3PPTDERSD MISO Transition ALL OPCO LOADOPCO 959 72 1,032 861 171 - (171) - ENERGY AND FUEL MANAGEMENT ESI CP235 F3PPWE0292 System Planning Asset Manageme LOADOPCO 292,780 25,337 318,116 267,550 50,566 - 878 51,444 ENERGY AND FUEL MANAGEMENT ESI CP235 F3PPWE0420 SPO EGSL-SupplyProcuremt/Asset DIRECTLG 1,026 93 1,119 1,119 - - - - ENERGY AND FUEL MANAGEMENT ESI CP235 F3PPWET302 SPO 2008 Winter Western Region DIRECTTX 1,286 129 1,415 - 1,415 - 30 1,444 ENERGY AND FUEL MANAGEMENT ESI CP235 F3PPWET304 SPO Frontier 10 Year PPA DIRECTTX - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI CP235 F3PPWET305 SPO WWOTAB Expense DIRECTTX - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI CP235 F3PPWET306 SPO 2011 Western Region RFP DIRECTTX 8,778 726 9,504 - 9,504 - 209 9,714 ENERGY AND FUEL MANAGEMENT ESI CP235 F3PPWET308 SPO Calpine PPA/Project Housto DIRECTTX 11,407 1,128 12,535 - 12,535 - 266 12,801 ENERGY AND FUEL MANAGEMENT ESI CP235 F5PCZU1574 REGULATORY AFFAIRS - 100% TX G DIRECTTX 2,264 203 2,467 - 2,467 - 82 2,549 ENERGY AND FUEL MANAGEMENT ESI CP235 F5PP27836P ELI/EGS Purchase of Perryville DIRCTELI 14 - 14 14 - - - - ENERGY AND FUEL MANAGEMENT ESI CP235 F5PPETX009 2009 Texas Rate Case Support DIRECTTX (728) 29 (699) - (699) (272) 971 - ENERGY AND FUEL MANAGEMENT ESI CP235 F5PPMSFA09 2009 EMI Fuel Audit Horne Grou DIRCTEMI - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI CP235 F5PPZUWELL Entergy Wellness Program EMPLOYAL 278 23 301 286 15 - 0 15 ENERGY AND FUEL MANAGEMENT ESI CP235 Total 1,076,761 52,798 1,129,559 1,037,552 92,007 (392) 2,445 94,059 ENERGY AND FUEL MANAGEMENT ESI CP236 F3PCCSPUTI SYSTEM PLANNING & STRATEGIC AD LOADOPCO 89 - 89 75 14 - - 14 ENERGY AND FUEL MANAGEMENT ESI CP236 Total 89 - 89 75 14 - - 14 ENERGY AND FUEL MANAGEMENT ESI CP237 C1PPSP0008 SPO ELL&ENOI Purchase Option I OWNISES2 (48,165) (2,955) (51,120) (51,120) - - - - ENERGY AND FUEL MANAGEMENT ESI CP237 C6PPSP0012 SPO Project Gator Transact/Tra DIRCTELI 46 - 46 46 - - - - ENERGY AND FUEL MANAGEMENT ESI CP237 F3PCWE0046 PLANT SUPPORT SERVICES - BIG C ASSTTXLG 75 - 75 43 31 - - 31 ENERGY AND FUEL MANAGEMENT ESI CP237 F3PCWE0135 NEL. 6 JOINT OWNERSHIP PART. A DIRECTLG - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI CP237 F3PPSPE001 SPO NISCO JOPOA MANAGEMENT EXP DIRECTLG - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI CP237 F3PPSPE002 SPO 2009 Renewable RFI Expense LOADOPCO - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI CP237 F3PPSPE003 SPO Summer 2009 RFP Expense LOADOPCO 239 - 239 203 36 - - 36 ENERGY AND FUEL MANAGEMENT ESI CP237 F3PPSPE004 SPO Summer09RFP IM&PropslSubmt LOADOPCO - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI CP237 F3PPSPE008 SPO July 09 Flex Baseld RFP IM LOADOPCO - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI CP237 F3PPSPE010 SPO Divers ty In tiative LOADOPCO - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI CP237 F3PPSPE017 SPO 2010 Renewable RFP LOADOPCO 494 - 494 421 74 - - 74 ENERGY AND FUEL MANAGEMENT ESI CP237 F3PPSPE042 SPO Expense ISES Purchase Opti OWNISES2 48,165 2,955 51,120 51,120 - - - - ENERGY AND FUEL MANAGEMENT ESI CP237 F3PPWE0292 System Planning Asset Manageme LOADOPCO 117 - 117 99 18 - - 18 ENERGY AND FUEL MANAGEMENT ESI CP237 F3PPWE0420 SPO EGSL-SupplyProcuremt/Asset DIRECTLG - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI CP237 F3PPWET300 SPO 2008 Western Region RFP-Te DIRECTTX - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI CP237 F3PPWET302 SPO 2008 Winter Western Region DIRECTTX - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI CP237 F3PPWET304 SPO Frontier 10 Year PPA DIRECTTX - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI CP237 F5PCSVCAWD SERVICE AWARDS DIRCTESI - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI CP237 F5PPETX009 2009 Texas Rate Case Support DIRECTTX - - - - - (30) 30 - ENERGY AND FUEL MANAGEMENT ESI CP237 F5PPZUWELL Entergy Wellness Program EMPLOYAL - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI CP237 Total 971 - 971 812 159 (30) 30 159 9-249

ENERGY AND FUEL MANAGEMENT ESI CP23K C1PPSP0008 SPO ELL&ENOI Purchase Option I OWNISES2 (11,335) (1,509) (12,844) (12,844) - - - - ENERGY AND FUEL MANAGEMENT ESI CP23K C6PCN32144 GRAND GULF EXTENDED POWER UPRA DIRCTSER 843 74 918 918 - - - - ENERGY AND FUEL MANAGEMENT ESI CP23K C6PPSP0012 SPO Project Gator Transact/Tra DIRCTELI 7,071 620 7,692 7,692 - - - - ENERGY AND FUEL MANAGEMENT ESI CP23K C6PPSP0029 SPO Evange ine DIRCTELI 7,696 653 8,348 8,348 - - - - ENERGY AND FUEL MANAGEMENT ESI CP23K C6PPSP0030 SPO Ouachita Fuel Meter Common DIRCTEAI 539 45 584 584 - - - - ENERGY AND FUEL MANAGEMENT ESI CP23K C6PPSP0038 SPO Project Lamar Transaction DIRCTEAI 33,847 3,185 37,032 37,032 - - - - ENERGY AND FUEL MANAGEMENT ESI CP23K C6PPSP0046 SPO Project Burnet Transaction DIRCTEMI 34,195 3,386 37,582 37,582 - - - - ENERGY AND FUEL MANAGEMENT ESI CP23K C6PPWS0783 Ninem le 6 Development DIRCTELI 937 96 1,033 1,033 - - - - ENERGY AND FUEL MANAGEMENT ESI CP23K C6PPWS0984 SPO EGSL Purchase of Ouachita DIRECTLG - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI CP23K F3PCCPM001 CORPORATE PERFORMANCE MANAGEME ASSTSALL - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI CP23K F3PCE14420 REGULATORY AFFAIRS - EAI DIRCTEAI 1,293 98 1,390 1,390 - - - - Amounts may not add or tie to other schedules due to rounding.

EXHIBIT PJC-C Cicio, Patrick Page 3 of 11 ENTERGY TEXAS, INC. EXHIBIT PJC-C 2011 ETI Rate Case

Affiliate Billings - by Witness, Class, Department and Project 2011 TX Rate Case For the Twelve Months Ended June 30, 2011 Page 4 of 11 Amounts in Dollars (A) (B) (C) (D) (E) (F) (G) (H) Total Billings Activity / Project ESI BIlling Service Company ETI Per Pro Forma Total ETI Class Billing Entity Dept Code Activity / Project Description Method Support Recipient Total All Other BU's Books Exclusions Amount Adjusted ENERGY AND FUEL MANAGEMENT ESI CP23K F3PCF07300 CORP PLANNING & ANALYSIS- REGU CUSTEGOP 13,590 963 14,553 12,547 2,007 - 30 2,036 ENERGY AND FUEL MANAGEMENT ESI CP23K F3PCW15830 SYSTEM GENERATION PLANNING LOADOPCO 8,581 704 9,285 7,744 1,541 - 31 1,572 ENERGY AND FUEL MANAGEMENT ESI CP23K F3PCW18300 OPNS-COAL SUPPLY COALARGS 699 64 764 764 - - - - ENERGY AND FUEL MANAGEMENT ESI CP23K F3PCW19511 ENERGY MANAGEMENT OPERATIONS P LOADOPCO 13,071 1,208 14,279 12,040 2,239 - 43 2,283 ENERGY AND FUEL MANAGEMENT ESI CP23K F3PCWE0046 PLANT SUPPORT SERVICES - BIG C ASSTTXLG 687 88 775 450 325 - 6 331 ENERGY AND FUEL MANAGEMENT ESI CP23K F3PCWE0140 EMO REGULATORY AFFAIRS LOADOPCO 1,893 157 2,050 1,735 315 - 7 322 ENERGY AND FUEL MANAGEMENT ESI CP23K F3PPAMPDEV Advanced Mgmt Dev Program EMPLOYAL 4,112 - 4,112 3,921 192 - - 192 ENERGY AND FUEL MANAGEMENT ESI CP23K F3PPE14434 EAI POST SYS AGMT INCREMENTAL DIRCTEAI 2,964 311 3,274 3,274 - - - - ENERGY AND FUEL MANAGEMENT ESI CP23K F3PPSPE001 SPO NISCO JOPOA MANAGEMENT EXP DIRECTLG 2,796 229 3,026 3,026 - - - - ENERGY AND FUEL MANAGEMENT ESI CP23K F3PPSPE002 SPO 2009 Renewable RFI Expense LOADOPCO 627 56 683 581 102 - 2 104 ENERGY AND FUEL MANAGEMENT ESI CP23K F3PPSPE003 SPO Summer 2009 RFP Expense LOADOPCO 22,332 2,157 24,488 20,833 3,656 - 76 3,732 ENERGY AND FUEL MANAGEMENT ESI CP23K F3PPSPE004 SPO Summer09RFP IM&PropslSubmt LOADOPCO 269,064 - 269,064 227,046 42,018 - - 42,018 ENERGY AND FUEL MANAGEMENT ESI CP23K F3PPSPE008 SPO July 09 Flex Baseld RFP IM LOADOPCO - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI CP23K F3PPSPE010 SPO Divers ty In tiative LOADOPCO 1,619 140 1,759 1,483 276 - (8) 268 ENERGY AND FUEL MANAGEMENT ESI CP23K F3PPSPE011 SPO NISCO Contract DIRECTLG 15,565 1,324 16,889 16,889 - - - - ENERGY AND FUEL MANAGEMENT ESI CP23K F3PPSPE016 Addendum-WE0418 Summer 08 IM LOADOPCO - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI CP23K F3PPSPE017 SPO 2010 Renewable RFP LOADOPCO 61,600 2,221 63,820 54,293 9,528 - 82 9,610 ENERGY AND FUEL MANAGEMENT ESI CP23K F3PPSPE025 SPO 2010 Renewable RFP - LA on CUSELGLA (185,612) 9,242 (176,370) (176,370) - - - - ENERGY AND FUEL MANAGEMENT ESI CP23K F3PPSPE027 SPO ESI Project Houston PPA DIRCTESI - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI CP23K F3PPSPE042 SPO Expense ISES Purchase Opti OWNISES2 30,539 3,149 33,688 33,688 - - - - ENERGY AND FUEL MANAGEMENT ESI CP23K F3PPSPE049 SPO 2011 EAI RFP DIRCTEAI 2,593 196 2,789 2,789 - - - - ENERGY AND FUEL MANAGEMENT ESI CP23K F3PPTDERSC Entergy Regional State Committ LOADOPCO 508 38 546 455 91 - 3 94 ENERGY AND FUEL MANAGEMENT ESI CP23K F3PPTDERSD MISO Transition ALL OPCO LOADOPCO 30 - 30 25 5 - (5) - ENERGY AND FUEL MANAGEMENT ESI CP23K F3PPWE0403 SPO Performance Mngmnt/Special LOADOPCO 434,710 36,063 470,773 396,023 74,750 - 1,609 76,359 ENERGY AND FUEL MANAGEMENT ESI CP23K F3PPWET302 SPO 2008 Winter Western Region DIRECTTX 303 33 335 - 335 - 7 342 ENERGY AND FUEL MANAGEMENT ESI CP23K F3PPWET303 SPO2008WinterWestnRegionRFP-IM DIRECTTX 4,200 - 4,200 - 4,200 - - 4,200 ENERGY AND FUEL MANAGEMENT ESI CP23K F3PPWET304 SPO Frontier 10 Year PPA DIRECTTX - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI CP23K F3PPWET306 SPO 2011 Western Region RFP DIRECTTX 25,766 2,245 28,011 - 28,011 - 597 28,608 ENERGY AND FUEL MANAGEMENT ESI CP23K F3PPWET307 SPO2011WestnRegionRFP-IM&PropS DIRECTTX 19,469 - 19,469 - 19,469 - - 19,469 ENERGY AND FUEL MANAGEMENT ESI CP23K F3PPWET308 SPO Calpine PPA/Project Housto DIRECTTX 28,791 2,794 31,584 - 31,584 - 668 32,253 ENERGY AND FUEL MANAGEMENT ESI CP23K F5PCSVCAWD SERVICE AWARDS DIRCTESI - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI CP23K F5PCZU1425 REGULATORY COORDINAT.-ELI & EG CUSELPSC - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI CP23K F5PCZU1574 REGULATORY AFFAIRS - 100% TX G DIRECTTX 9,627 881 10,508 - 10,508 - 223 10,731 ENERGY AND FUEL MANAGEMENT ESI CP23K F5PPETX009 2009 Texas Rate Case Support DIRECTTX 328 130 457 - 457 (382) (75) - ENERGY AND FUEL MANAGEMENT ESI CP23K F5PPSPE044 PMO Support Initiative-System- LOADOPCO 1,403 132 1,535 1,280 255 - (255) - ENERGY AND FUEL MANAGEMENT ESI CP23K F5PPZUWELL Entergy Wellness Program EMPLOYAL 1,298 92 1,389 1,321 68 - 1 69 ENERGY AND FUEL MANAGEMENT ESI CP23K Total 868,238 71,263 939,501 707,570 231,931 (382) 3,043 234,592 ENERGY AND FUEL MANAGEMENT ESI CPSLG C1PPSP0008 SPO ELL&ENOI Purchase Option I OWNISES2 (1,901) (196) (2,097) (2,097) - - - - ENERGY AND FUEL MANAGEMENT ESI CPSLG C6PCN32144 GRAND GULF EXTENDED POWER UPRA DIRCTSER 749 65 814 814 - - - - ENERGY AND FUEL MANAGEMENT ESI CPSLG C6PCN70858 RIVER BEND EXTENDED POWER UPRA 3,104 283 3,386 3,386 - - - - ENERGY AND FUEL MANAGEMENT ESI CPSLG C6PPSP0012 SPO Project Gator Transact/Tra DIRCTELI 84,812 209 85,022 85,022 - - - - ENERGY AND FUEL MANAGEMENT ESI CPSLG C6PPSP0038 SPO Project Lamar Transaction DIRCTEAI 58,180 443 58,622 58,622 - - - - ENERGY AND FUEL MANAGEMENT ESI CPSLG C6PPSP0046 SPO Project Burnet Transaction DIRCTEMI 47,758 69 47,827 47,827 - - - - ENERGY AND FUEL MANAGEMENT ESI CPSLG C6PPWS0628 SPO W-WOTAB CT Development Spe DIRECTTX - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI CPSLG C6PPWS0783 Ninem le 6 Development DIRCTELI 3,133 191 3,324 3,324 - - - - ENERGY AND FUEL MANAGEMENT ESI CPSLG F3PCCSPSYS SYSTEM PLANNING AND STRATEGIC ASSTSALL 28,841 325 29,166 26,223 2,943 - 8 2,951 ENERGY AND FUEL MANAGEMENT ESI CPSLG F3PCCSPUTI SYSTEM PLANNING & STRATEGIC AD LOADOPCO 335,569 24,721 360,290 303,252 57,038 - 1,245 58,283 ENERGY AND FUEL MANAGEMENT ESI CPSLG F3PCFBLETR BELOW THE LINE EXPENSES -ETR DIRCTETR - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI CPSLG F3PCW54035 VICE PRESIDENT OF ENERGY MANAG LOADOPCO - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI CPSLG F3PPAMPDEV Advanced Mgmt Dev Program EMPLOYAL - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI CPSLG F3PPISP717 Integration Planning Studies 7 LOADOPCO 23,997 2,510 26,507 22,313 4,193 - 86 4,279 ENERGY AND FUEL MANAGEMENT ESI CPSLG F3PPSPE003 SPO Summer 2009 RFP Expense LOADOPCO 18,973 1,594 20,567 17,294 3,274 - 71 3,344 9-250

ENERGY AND FUEL MANAGEMENT ESI CPSLG F3PPSPE017 SPO 2010 Renewable RFP LOADOPCO 2,666 218 2,883 2,453 430 - 9 440 ENERGY AND FUEL MANAGEMENT ESI CPSLG F3PPSPE024 SPO Power Delivery & Tech Serv LOADOPCO 347,682 30,035 377,718 318,197 59,520 - 1,127 60,648 ENERGY AND FUEL MANAGEMENT ESI CPSLG F3PPSPE025 SPO 2010 Renewable RFP - LA on CUSELGLA 17,258 1,407 18,665 18,665 - - - - ENERGY AND FUEL MANAGEMENT ESI CPSLG F3PPSPE027 SPO ESI Project Houston PPA DIRCTESI - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI CPSLG F3PPSPE042 SPO Expense ISES Purchase Opti OWNISES2 1,901 196 2,097 2,097 - - - - ENERGY AND FUEL MANAGEMENT ESI CPSLG F3PPSPE045 PMO Support Initiative - EAI DIRCTEAI 2,817 234 3,051 3,051 - - - - ENERGY AND FUEL MANAGEMENT ESI CPSLG F3PPSPE049 SPO 2011 EAI RFP DIRCTEAI 758 - 758 758 - - - - ENERGY AND FUEL MANAGEMENT ESI CPSLG F3PPTCGS11 TX Docket Competitive Generati DIRECTTX 2,786 259 3,046 - 3,046 - 64 3,110 ENERGY AND FUEL MANAGEMENT ESI CPSLG F3PPTDERSC Entergy Regional State Committ LOADOPCO 18,139 1,368 19,507 16,276 3,231 - 59 3,290 ENERGY AND FUEL MANAGEMENT ESI CPSLG F3PPTDERSD MISO Transition ALL OPCO LOADOPCO 4,880 369 5,249 4,378 871 - (871) - ENERGY AND FUEL MANAGEMENT ESI CPSLG F3PPWE0292 System Planning Asset Manageme LOADOPCO 5,502 - 5,502 4,627 876 - - 876 ENERGY AND FUEL MANAGEMENT ESI CPSLG F3PPWET301 SPO ETI-SupplyProcuremt/AssetM DIRECTTX - - - - - - - - Amounts may not add or tie to other schedules due to rounding.

EXHIBIT PJC-C Cicio, Patrick Page 4 of 11 ENTERGY TEXAS, INC. EXHIBIT PJC-C 2011 ETI Rate Case

Affiliate Billings - by Witness, Class, Department and Project 2011 TX Rate Case For the Twelve Months Ended June 30, 2011 Page 5 of 11 Amounts in Dollars (A) (B) (C) (D) (E) (F) (G) (H) Total Billings Activity / Project ESI BIlling Service Company ETI Per Pro Forma Total ETI Class Billing Entity Dept Code Activity / Project Description Method Support Recipient Total All Other BU's Books Exclusions Amount Adjusted ENERGY AND FUEL MANAGEMENT ESI CPSLG F3PPWET302 SPO 2008 Winter Western Region DIRECTTX - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI CPSLG F3PPWET304 SPO Frontier 10 Year PPA DIRECTTX - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI CPSLG F3PPWET305 SPO WWOTAB Expense DIRECTTX - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI CPSLG F3PPWET306 SPO 2011 Western Region RFP DIRECTTX 37,953 1,440 39,394 - 39,394 - 408 39,802 ENERGY AND FUEL MANAGEMENT ESI CPSLG F3PPWET308 SPO Calpine PPA/Project Housto DIRECTTX 612 61 673 - 673 - 14 688 ENERGY AND FUEL MANAGEMENT ESI CPSLG F5PCSVCAWD SERVICE AWARDS DIRCTESI 65 - 65 65 - - - - ENERGY AND FUEL MANAGEMENT ESI CPSLG F5PPBULKPW Minimize of Bulk Power Supply LOADOPCO 10,688 868 11,556 9,638 1,918 - 39 1,957 ENERGY AND FUEL MANAGEMENT ESI CPSLG F5PPSPE044 PMO Support Initiative-System- LOADOPCO 5,161 455 5,615 4,683 932 - (932) - ENERGY AND FUEL MANAGEMENT ESI CPSLG F5PPZUWELL Entergy Wellness Program EMPLOYAL 319 26 344 327 17 - 0 17 ENERGY AND FUEL MANAGEMENT ESI CPSLG Total 1,062,402 67,150 1,129,552 951,196 178,356 - 1,328 179,684 ENERGY AND FUEL MANAGEMENT ESI CPSLQ C1PPSP0008 SPO ELL&ENOI Purchase Option I OWNISES2 (4,709) (485) (5,194) (5,194) - - - - ENERGY AND FUEL MANAGEMENT ESI CPSLQ C6PPSP0038 SPO Project Lamar Transaction DIRCTEAI 4,635 346 4,981 4,981 - - - - ENERGY AND FUEL MANAGEMENT ESI CPSLQ C6PPSP0046 SPO Project Burnet Transaction DIRCTEMI 2,460 245 2,704 2,704 - - - - ENERGY AND FUEL MANAGEMENT ESI CPSLQ F3PCW18300 OPNS-COAL SUPPLY COALARGS 761,242 65,256 826,498 826,498 - - - - ENERGY AND FUEL MANAGEMENT ESI CPSLQ F3PCWE0046 PLANT SUPPORT SERVICES - BIG C ASSTTXLG 12,126 969 13,095 7,700 5,395 - 109 5,504 ENERGY AND FUEL MANAGEMENT ESI CPSLQ F3PPSPE006 SPO ISES Mining Asset Evaluati DIRCTEAI - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI CPSLQ F3PPSPE011 SPO NISCO Contract DIRECTLG 50 - 50 50 - - - - ENERGY AND FUEL MANAGEMENT ESI CPSLQ F3PPSPE017 SPO 2010 Renewable RFP LOADOPCO (78) - (78) (67) (12) - (0) (12) ENERGY AND FUEL MANAGEMENT ESI CPSLQ F3PPSPE025 SPO 2010 Renewable RFP - LA on CUSELGLA 3,697 373 4,071 4,071 - - - - ENERGY AND FUEL MANAGEMENT ESI CPSLQ F3PPSPE042 SPO Expense ISES Purchase Opti OWNISES2 4,810 493 5,303 5,303 - - - - ENERGY AND FUEL MANAGEMENT ESI CPSLQ F3PPWE0292 System Planning Asset Manageme LOADOPCO 21,464 1,948 23,412 19,566 3,846 - 74 3,920 ENERGY AND FUEL MANAGEMENT ESI CPSLQ F5PPETX009 2009 Texas Rate Case Support DIRECTTX 2,042 327 2,369 - 2,369 (923) (1,446) - ENERGY AND FUEL MANAGEMENT ESI CPSLQ F5PPPAPDIS Paper Barrier Case DIRCTEAI - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI CPSLQ F5PPWE0485 2010 EPA Request for Informati CAPAOPCO 45 4 48 43 5 - 0 5 ENERGY AND FUEL MANAGEMENT ESI CPSLQ F5PPZUWELL Entergy Wellness Program EMPLOYAL 439 36 475 451 23 - 0 24 ENERGY AND FUEL MANAGEMENT ESI CPSLQ Total 808,223 69,511 877,734 866,107 11,627 (923) (1,263) 9,442 ENERGY AND FUEL MANAGEMENT ESI SE08B C1PPRNE010 New Nuclear -Regulatory Fi ing NWDVRBGG (4,804) (378) (5,182) (5,182) - - - - ENERGY AND FUEL MANAGEMENT ESI SE08B C1PPSP0008 SPO ELL&ENOI Purchase Option I OWNISES2 (105) (40) (145) (145) - - - - ENERGY AND FUEL MANAGEMENT ESI SE08B C6PPGN0020 New Nuclear Reg Filing EGSL On DIRECTLG 2,402 189 2,591 2,591 - - - - ENERGY AND FUEL MANAGEMENT ESI SE08B C6PPLN0020 New Nuclear Reg Filing ELL Ong DIRCTELI 3,041 241 3,282 3,282 - - - - ENERGY AND FUEL MANAGEMENT ESI SE08B C6PPMN0020 New Nuclear Reg Filing EMI Ong DIRCTEMI - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI SE08B C6PPRN0010 New Nuclear - Regulatory Fi in DIRCTR1 - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI SE08B C6PPSP0012 SPO Project Gator Transact/Tra DIRCTELI 7,328 660 7,988 7,988 - - - - ENERGY AND FUEL MANAGEMENT ESI SE08B C6PPWS0534 System Planning Pet Coke Repow DIRCTELI - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI SE08B C6PPWS0783 Ninem le 6 Development DIRCTELI 217 23 240 240 - - - - ENERGY AND FUEL MANAGEMENT ESI SE08B F3PCE14420 REGULATORY AFFAIRS - EAI DIRCTEAI 15,842 1,373 17,216 17,216 - - - - ENERGY AND FUEL MANAGEMENT ESI SE08B F3PCE14423 REGULATORY AFFAIRS - EMI DIRCTEMI 7,187 678 7,865 7,865 - - - - ENERGY AND FUEL MANAGEMENT ESI SE08B F3PCFF1003 BOARD SUPPORT ASSTSALL 514 - 514 462 52 - (0) 52 ENERGY AND FUEL MANAGEMENT ESI SE08B F3PCSYSAGR SYSTEM AGREEMENT-2001 CUSEOPCO 252,418 20,096 272,514 232,235 40,279 - 1,118 41,397 ENERGY AND FUEL MANAGEMENT ESI SE08B F3PCSYSRAS SYSTEM REGULATORY AFFAIRS-STAT CUSTEGOP 2,615 257 2,871 2,473 398 - 13 411 ENERGY AND FUEL MANAGEMENT ESI SE08B F3PCW15822 RESOURCE PLANNING COORDINATOR LOADOPCO 122,890 11,496 134,385 113,301 21,085 - 694 21,779 ENERGY AND FUEL MANAGEMENT ESI SE08B F3PCW19501 WHOLESALE PURCHASING & SALES LOADOPCO 50,737 (9,302) 41,435 34,558 6,878 - 236 7,114 ENERGY AND FUEL MANAGEMENT ESI SE08B F3PCW19512 ENERGY MGMT - FUEL & ENERGY AN LOADOPCO 3,049 - 3,049 2,574 474 - - 474 ENERGY AND FUEL MANAGEMENT ESI SE08B F3PCWE0058 AWARDS & RECOGNITIONS PROGRAM LOADOPCO - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI SE08B F3PCWE0140 EMO REGULATORY AFFAIRS LOADOPCO 444,824 40,418 485,242 409,175 76,067 - 1,855 77,923 ENERGY AND FUEL MANAGEMENT ESI SE08B F3PCZU1571 EGSI TX FUEL RELATED MATTERS DIRECTTX 67 - 67 - 67 - - 67 ENERGY AND FUEL MANAGEMENT ESI SE08B F3PPADTFL9 ELL Fuel Audit 2005-2009 DIRCTELI 1,541 141 1,682 1,682 - - - - ENERGY AND FUEL MANAGEMENT ESI SE08B F3PPDOWPPA Dow 3 Year PPA (2011-2014) DIRECTLG 1,125 99 1,224 1,224 - - - - ENERGY AND FUEL MANAGEMENT ESI SE08B F3PPEAIMIS MISO Transition EAI Path 1 cos DIRCTEAI 4,725 357 5,082 5,082 - - - - ENERGY AND FUEL MANAGEMENT ESI SE08B F3PPEMI381 EMI-2010 PMR Docket 2008-UN-38 DIRCTEMI 1,048 109 1,157 1,157 - - - - 9-251

ENERGY AND FUEL MANAGEMENT ESI SE08B F3PPEMI884 EMI-2010 ECR Docket 2008-UN-88 DIRCTEMI 1,058 108 1,166 1,166 - - - - ENERGY AND FUEL MANAGEMENT ESI SE08B F3PPINVDOJ DOJ Anti Trust Investigation CUSEOPCO 11,929 1,107 13,036 11,111 1,925 - 64 1,989 ENERGY AND FUEL MANAGEMENT ESI SE08B F3PPMSEE10 MS Docket2010-AD-02 Ergy Effic DIRCTEMI - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI SE08B F3PPMSFA10 2010 EMI Fuel Audit DIRCTEMI 4,023 359 4,382 4,382 - - - - ENERGY AND FUEL MANAGEMENT ESI SE08B F3PPPGA010 PGA Audit 2010 DIRECTLG 3,163 301 3,463 3,463 - - - - ENERGY AND FUEL MANAGEMENT ESI SE08B F3PPR56620 WHOLESALE - EGSI LA DIRECTLG - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI SE08B F3PPSPE010 SPO Divers ty In tiative LOADOPCO 396 39 435 366 69 - 1 70 ENERGY AND FUEL MANAGEMENT ESI SE08B F3PPSPE011 SPO NISCO Contract DIRECTLG 2,171 171 2,342 2,342 - - - - ENERGY AND FUEL MANAGEMENT ESI SE08B F3PPSPE042 SPO Expense ISES Purchase Opti OWNISES2 1,993 201 2,195 2,195 - - - - ENERGY AND FUEL MANAGEMENT ESI SE08B F3PPTDERSC Entergy Regional State Committ LOADOPCO 108,613 7,240 115,852 97,008 18,845 - 435 19,279 ENERGY AND FUEL MANAGEMENT ESI SE08B F3PPTDERSD MISO Transition ALL OPCO LOADOPCO 18,016 1,003 19,019 15,862 3,157 - (3,157) - ENERGY AND FUEL MANAGEMENT ESI SE08B F3PPWE0432 SPOManagement of Sys IRP Activ LOADOPCO 1,286 107 1,393 1,177 216 - 7 223 Amounts may not add or tie to other schedules due to rounding.

EXHIBIT PJC-C Cicio, Patrick Page 5 of 11 ENTERGY TEXAS, INC. EXHIBIT PJC-C 2011 ETI Rate Case

Affiliate Billings - by Witness, Class, Department and Project 2011 TX Rate Case For the Twelve Months Ended June 30, 2011 Page 6 of 11 Amounts in Dollars (A) (B) (C) (D) (E) (F) (G) (H) Total Billings Activity / Project ESI BIlling Service Company ETI Per Pro Forma Total ETI Class Billing Entity Dept Code Activity / Project Description Method Support Recipient Total All Other BU's Books Exclusions Amount Adjusted ENERGY AND FUEL MANAGEMENT ESI SE08B F5PC25116F ELI FUEL AUDIT 2001 DIRCTELI 1,394 117 1,511 1,511 - - - - ENERGY AND FUEL MANAGEMENT ESI SE08B F5PCE13751 GENERAL LITIGATION- EGSI-LA DIRECTLG 4,125 364 4,489 4,489 - - - - ENERGY AND FUEL MANAGEMENT ESI SE08B F5PCE13759 JENKINS CLASS ACTION SUIT DIRECTTX 23,848 2,024 25,872 - 25,872 - 773 26,645 ENERGY AND FUEL MANAGEMENT ESI SE08B F5PCEDIVER DIVERSITY TRAINING DIRCTESI 45 - 45 45 - - - - ENERGY AND FUEL MANAGEMENT ESI SE08B F5PCGSL351 ELI 2001 SYSTEM AGREEMENT CASE DIRCTELI 1,234 125 1,359 1,359 - - - - ENERGY AND FUEL MANAGEMENT ESI SE08B F5PCGSL500 EGS FUEL AUDIT DIRECTLG 1,794 102 1,896 1,896 - - - - ENERGY AND FUEL MANAGEMENT ESI SE08B F5PCSVCAWD SERVICE AWARDS DIRCTESI 675 - 675 675 - - - - ENERGY AND FUEL MANAGEMENT ESI SE08B F5PCZU1422 REGULATORY AFFAIRS - LP&L DIRCTELI 8,668 829 9,498 9,498 - - - - ENERGY AND FUEL MANAGEMENT ESI SE08B F5PCZU1424 REGULATORY AFFAIRS - NOPSI DIRCTENO 35,320 3,047 38,366 38,366 - - - - ENERGY AND FUEL MANAGEMENT ESI SE08B F5PCZU1425 REGULATORY COORDINAT.-ELI & EG CUSELPSC 654 58 712 712 - - - - ENERGY AND FUEL MANAGEMENT ESI SE08B F5PCZU1573 REGULATORY AFFAIRS -- 100% EGS DIRECTTX - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI SE08B F5PCZU1574 REGULATORY AFFAIRS - 100% TX G DIRECTTX 1,596 145 1,741 - 1,741 - 58 1,799 ENERGY AND FUEL MANAGEMENT ESI SE08B F5PCZU1579 REGULATORY AFFAIRS -- 100% EGS DIRECTLG 2,045 185 2,230 2,230 - - - - ENERGY AND FUEL MANAGEMENT ESI SE08B F5PP10011U Show Cause Docket No. 10-011-U DIRCTEAI 65,919 5,576 71,495 71,495 - - - - ENERGY AND FUEL MANAGEMENT ESI SE08B F5PP4RFERC FERC Audit LVLSVCAL 1,999 187 2,185 1,975 210 - 7 217 ENERGY AND FUEL MANAGEMENT ESI SE08B F5PPE14427 Regulatory Info RFIs-EAI-Dock DIRCTEAI 4,227 383 4,610 4,610 - - - - ENERGY AND FUEL MANAGEMENT ESI SE08B F5PPETX009 2009 Texas Rate Case Support DIRECTTX 5,001 437 5,439 - 5,439 (812) (4,626) - ENERGY AND FUEL MANAGEMENT ESI SE08B F5PPETX011 2011 Texas Rate Case Support DIRECTTX 222 25 247 - 247 - 8 255 ENERGY AND FUEL MANAGEMENT ESI SE08B F5PPLEGRB3 Regulatory Filings - River Ben CUSELGLA 176 - 176 176 - - - - ENERGY AND FUEL MANAGEMENT ESI SE08B F5PPMSFA09 2009 EMI Fuel Audit Horne Grou DIRCTEMI 648 54 702 702 - - - - ENERGY AND FUEL MANAGEMENT ESI SE08B F5PPMSFA9A 2009 EMI Fuel Audit McFadden G DIRCTEMI - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI SE08B F5PPSPE044 PMO Support Initiative-System- LOADOPCO 142 - 142 118 24 - (24) - ENERGY AND FUEL MANAGEMENT ESI SE08B F5PPSUPICT Support of ICT LOADOPCO 8,380 535 8,915 7,531 1,384 - 30 1,414 ENERGY AND FUEL MANAGEMENT ESI SE08B F5PPZUWELL Entergy Wellness Program EMPLOYAL 1,138 78 1,216 1,157 59 - 1 61 ENERGY AND FUEL MANAGEMENT ESI SE08B Total 1,238,559 91,322 1,329,881 1,125,393 204,488 (812) (2,507) 201,168 ENERGY AND FUEL MANAGEMENT ESI SESEE F3PCCSPUTI SYSTEM PLANNING & STRATEGIC AD LOADOPCO 343 38 381 318 63 - 1 65 ENERGY AND FUEL MANAGEMENT ESI SESEE F3PCWE0046 PLANT SUPPORT SERVICES - BIG C ASSTTXLG 798 60 858 511 347 - 7 354 ENERGY AND FUEL MANAGEMENT ESI SESEE F3PCWE0058 AWARDS & RECOGNITIONS PROGRAM LOADOPCO 797 108 905 770 135 - 3 138 ENERGY AND FUEL MANAGEMENT ESI SESEE F3PCWE0140 EMO REGULATORY AFFAIRS LOADOPCO 303 - 303 254 48 - - 48 ENERGY AND FUEL MANAGEMENT ESI SESEE F3PPE14434 EAI POST SYS AGMT INCREMENTAL DIRCTEAI 2,772 210 2,982 2,982 - - - - ENERGY AND FUEL MANAGEMENT ESI SESEE F3PPSPE003 SPO Summer 2009 RFP Expense LOADOPCO (28) 12 (16) (14) (2) - (0) (3) ENERGY AND FUEL MANAGEMENT ESI SESEE F3PPSPE015 SPO Compliance and Business Su LOADOPCO 38,521 3,536 42,057 35,327 6,730 - 131 6,861 ENERGY AND FUEL MANAGEMENT ESI SESEE F3PPSPE025 SPO 2010 Renewable RFP - LA on CUSELGLA 399 34 433 433 - - - - ENERGY AND FUEL MANAGEMENT ESI SESEE F3PPTDERSD MISO Transition ALL OPCO LOADOPCO 980 76 1,056 881 175 - (175) - ENERGY AND FUEL MANAGEMENT ESI SESEE F3PPWE0402 SPO Regulatory Compliance LOADOPCO 521,697 47,326 569,024 479,121 89,902 - 1,882 91,784 ENERGY AND FUEL MANAGEMENT ESI SESEE F5PCSVCAWD SERVICE AWARDS DIRCTESI - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI SESEE F5PPETX009 2009 Texas Rate Case Support DIRECTTX 471 37 508 - 508 (51) (457) - ENERGY AND FUEL MANAGEMENT ESI SESEE F5PPFERCCM FERC Compliance Program EMPLOREG 67 - 67 63 4 - - 4 ENERGY AND FUEL MANAGEMENT ESI SESEE F5PPZUWELL Entergy Wellness Program EMPLOYAL 527 34 561 534 27 - 1 28 ENERGY AND FUEL MANAGEMENT ESI SESEE Total 567,647 51,472 619,119 521,181 97,938 (51) 1,392 99,280 ENERGY AND FUEL MANAGEMENT ESI SESKA F3PCW15830 SYSTEM GENERATION PLANNING LOADOPCO 9 - 9 7 1 - - 1 ENERGY AND FUEL MANAGEMENT ESI SESKA F3PCW19512 ENERGY MGMT - FUEL & ENERGY AN LOADOPCO 4 - 4 4 1 - - 1 ENERGY AND FUEL MANAGEMENT ESI SESKA F3PCW54035 VICE PRESIDENT OF ENERGY MANAG LOADOPCO 1,067,079 310 1,067,389 900,287 167,103 - 8 167,111 ENERGY AND FUEL MANAGEMENT ESI SESKA F3PCWE0058 AWARDS & RECOGNITIONS PROGRAM LOADOPCO 9,047 1,241 10,288 8,732 1,556 - 33 1,589 ENERGY AND FUEL MANAGEMENT ESI SESKA F3PPSPE010 SPO Divers ty In tiative LOADOPCO 604 - 604 510 94 - - 94 ENERGY AND FUEL MANAGEMENT ESI SESKA F3PPWE0478 Parkwood II Safety Team CAPAOPCO 8,234 - 8,234 7,343 890 - (147) 743 ENERGY AND FUEL MANAGEMENT ESI SESKA Total 1,084,977 1,551 1,086,528 916,884 169,644 - (106) 169,538 ENERGY AND FUEL MANAGEMENT ESI SESKB C6PPLN0020 New Nuclear Reg Filing ELL Ong DIRCTELI 1,371 105 1,477 1,477 - - - - 9-252

ENERGY AND FUEL MANAGEMENT ESI SESKB F3PCSYSAGR SYSTEM AGREEMENT-2001 CUSEOPCO 5,642 1,001 6,643 5,664 979 - 25 1,004 ENERGY AND FUEL MANAGEMENT ESI SESKB F3PCSYSRAS SYSTEM REGULATORY AFFAIRS-STAT CUSTEGOP 76 8 84 72 12 - 0 12 ENERGY AND FUEL MANAGEMENT ESI SESKB F3PCW15830 SYSTEM GENERATION PLANNING LOADOPCO 18 - 18 16 3 - - 3 ENERGY AND FUEL MANAGEMENT ESI SESKB F3PCW18200 OPNS-OIL SUPPLY OWNISFI 3,198 318 3,516 3,516 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKB F3PCW19501 WHOLESALE PURCHASING & SALES LOADOPCO - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI SESKB F3PCW19512 ENERGY MGMT - FUEL & ENERGY AN LOADOPCO 1,012,944 90,454 1,103,399 929,008 174,390 - 3,337 177,727 ENERGY AND FUEL MANAGEMENT ESI SESKB F3PCW29607 POWER SYSTEM ACCOUNTING LOADWEPI 420,638 38,815 459,453 387,423 72,031 - 1,389 73,419 ENERGY AND FUEL MANAGEMENT ESI SESKB F3PCWE0064 LONG TERM ENERGY LOADOPCO 1,228 - 1,228 1,038 190 - - 190 ENERGY AND FUEL MANAGEMENT ESI SESKB F3PCWE0151 FOSSIL DIVERSITY INITIATIVE - CAPAOPCO 68 5 73 65 8 - 0 8 ENERGY AND FUEL MANAGEMENT ESI SESKB F3PCZU1582 EGSI LA 3RD EARNINGS REVIEW DIRECTLG (43) - (43) (43) - - - - ENERGY AND FUEL MANAGEMENT ESI SESKB F3PPAMPDEV Advanced Mgmt Dev Program EMPLOYAL 6,037 - 6,037 5,747 289 - - 289 ENERGY AND FUEL MANAGEMENT ESI SESKB F3PPEAIMIS MISO Transition EAI Path 1 cos DIRCTEAI 3,214 243 3,457 3,457 - - - - Amounts may not add or tie to other schedules due to rounding.

EXHIBIT PJC-C Cicio, Patrick Page 6 of 11 ENTERGY TEXAS, INC. EXHIBIT PJC-C 2011 ETI Rate Case

Affiliate Billings - by Witness, Class, Department and Project 2011 TX Rate Case For the Twelve Months Ended June 30, 2011 Page 7 of 11 Amounts in Dollars (A) (B) (C) (D) (E) (F) (G) (H) Total Billings Activity / Project ESI BIlling Service Company ETI Per Pro Forma Total ETI Class Billing Entity Dept Code Activity / Project Description Method Support Recipient Total All Other BU's Books Exclusions Amount Adjusted ENERGY AND FUEL MANAGEMENT ESI SESKB F3PPMSFA10 2010 EMI Fuel Audit DIRCTEMI 20,663 2,060 22,723 22,723 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKB F5PCE13759 JENKINS CLASS ACTION SUIT DIRECTTX 9,520 851 10,371 - 10,371 - 203 10,574 ENERGY AND FUEL MANAGEMENT ESI SESKB F5PCEDIVER DIVERSITY TRAINING DIRCTESI 45 - 45 45 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKB F5PCSVCAWD SERVICE AWARDS DIRCTESI 336 - 336 336 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKB F5PCZU1422 REGULATORY AFFAIRS - LP&L DIRCTELI 1,408 156 1,564 1,564 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKB F5PCZU1579 REGULATORY AFFAIRS -- 100% EGS DIRECTLG 3,000 255 3,255 3,255 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKB F5PP10011U Show Cause Docket No. 10-011-U DIRCTEAI 29,566 2,744 32,310 32,310 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKB F5PP4RFERC FERC Audit LVLSVCAL - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI SESKB F5PPMSFA09 2009 EMI Fuel Audit Horne Grou DIRCTEMI 465 44 508 508 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKB F5PPMSFA9A 2009 EMI Fuel Audit McFadden G DIRCTEMI 518 57 575 575 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKB F5PPSPE044 PMO Support Initiative-System- LOADOPCO 4,691 422 5,113 4,264 849 - (849) - ENERGY AND FUEL MANAGEMENT ESI SESKB F5PPZUWELL Entergy Wellness Program EMPLOYAL 439 36 475 451 23 - 0 24 ENERGY AND FUEL MANAGEMENT ESI SESKB Total 1,525,041 137,574 1,662,615 1,403,471 259,144 - 4,105 263,250 ENERGY AND FUEL MANAGEMENT ESI SESKC C1PPSP0008 SPO ELL&ENOI Purchase Option I OWNISES2 (22) - (22) (22) - - - - ENERGY AND FUEL MANAGEMENT ESI SESKC F3PCW18300 OPNS-COAL SUPPLY COALARGS 491 - 491 491 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKC F3PPSPE042 SPO Expense ISES Purchase Opti OWNISES2 22 - 22 22 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKC Total 491 - 491 491 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKD C6PPSP0012 SPO Project Gator Transact/Tra DIRCTELI 114 10 124 124 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKD C6PPSP0029 SPO Evange ine DIRCTELI 26,099 1,749 27,848 27,848 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKD C6PPSP0038 SPO Project Lamar Transaction DIRCTEAI 7,009 5 7,013 7,013 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKD C6PPSP0046 SPO Project Burnet Transaction DIRCTEMI 56 5 61 61 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKD C6PPWS0783 Ninem le 6 Development DIRCTELI 171 18 189 189 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKD F3PCFBLFOS BELOW THE LINE - FOSSIL OPERAT CAPAOPCO 3,684 - 3,684 3,286 398 (398) - - ENERGY AND FUEL MANAGEMENT ESI SESKD F3PCFVARAS ADMIN SUPRT - VARIBUS CORPORAT DIRECTLG 40,766 3,739 44,505 44,505 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKD F3PCW18100 OPNS-GAS SUPPLY CAPXCOPC 984,445 88,994 1,073,438 926,742 146,696 - 2,795 149,491 ENERGY AND FUEL MANAGEMENT ESI SESKD F3PCW18200 OPNS-OIL SUPPLY OWNISFI 133,587 12,416 146,004 146,004 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKD F3PCW19512 ENERGY MGMT - FUEL & ENERGY AN LOADOPCO - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI SESKD F3PCW51400 SFI FUEL OIL O&M DIRCTSFI 108 11 119 119 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKD F3PCW54035 VICE PRESIDENT OF ENERGY MANAG LOADOPCO 83 - 83 71 12 - - 12 ENERGY AND FUEL MANAGEMENT ESI SESKD F3PCWE0012 1998 FUELS MANAGEMENT TELEMETR CAPAOPCO 140,071 - 140,071 124,928 15,143 - - 15,143 ENERGY AND FUEL MANAGEMENT ESI SESKD F3PPUTLDER Utility Derivatives Compliance LOADOPCO 2,881 261 3,142 2,620 521 - 11 533 ENERGY AND FUEL MANAGEMENT ESI SESKD F5PCZU1422 REGULATORY AFFAIRS - LP&L DIRCTELI (83) - (83) (83) - - - - ENERGY AND FUEL MANAGEMENT ESI SESKD F5PPETX009 2009 Texas Rate Case Support DIRECTTX (580) 30 (550) - (550) (183) 733 - ENERGY AND FUEL MANAGEMENT ESI SESKD F5PPZUWELL Entergy Wellness Program EMPLOYAL 23 1 24 23 1 - 0 1 ENERGY AND FUEL MANAGEMENT ESI SESKD Total 1,338,433 107,239 1,445,672 1,283,449 162,223 (581) 3,539 165,181 ENERGY AND FUEL MANAGEMENT ESI SESKE C1PPRTOSOF RTO Implement Software ALLCOS LOADOPCO 13,959 1,480 15,439 12,876 2,563 (2,563) - - ENERGY AND FUEL MANAGEMENT ESI SESKE C6PPSP0045 SPO Real Time Calcasieu RTU DIRECTLG 25,835 156 25,991 25,991 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKE C6PPWS0783 Ninem le 6 Development DIRCTELI 2,572 273 2,845 2,845 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKE F3PCWE0046 PLANT SUPPORT SERVICES - BIG C ASSTTXLG 459 48 507 294 214 - 4 218 ENERGY AND FUEL MANAGEMENT ESI SESKE F3PCWE0058 AWARDS & RECOGNITIONS PROGRAM LOADOPCO 319 40 359 305 54 - 1 55 ENERGY AND FUEL MANAGEMENT ESI SESKE F3PCWE0092 EMS OPERATIONS & MAINTENANCE S LOADOPCO 89,299 - 89,299 74,476 14,823 - 279 15,102 ENERGY AND FUEL MANAGEMENT ESI SESKE F3PCWE0133 EMO INFORMATION TECHNOLOGY SUP LOADOPCO 7,521 - 7,521 6,273 1,248 - - 1,248 ENERGY AND FUEL MANAGEMENT ESI SESKE F3PPEGSLMI MISO Transition EGSL costs DIRECTLG 235 - 235 235 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKE F3PPELLMIS MISO Transition ELL costs DIRCTELI 235 - 235 235 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKE F3PPINVDOJ DOJ Anti Trust Investigation CUSEOPCO 74 - 74 63 11 - - 11 ENERGY AND FUEL MANAGEMENT ESI SESKE F3PPSPE001 SPO NISCO JOPOA MANAGEMENT EXP DIRECTLG (449) - (449) (449) - - - - ENERGY AND FUEL MANAGEMENT ESI SESKE F3PPSPE010 SPO Divers ty In tiative LOADOPCO 804 - 804 671 134 - - 134 ENERGY AND FUEL MANAGEMENT ESI SESKE F3PPSPE015 SPO Compliance and Business Su LOADOPCO 821,572 74,551 896,124 754,239 141,884 - 2,518 144,402 9-253

ENERGY AND FUEL MANAGEMENT ESI SESKE F3PPSPE019 SPO IT Infrastructure Maint. LOADOPCO 100,713 - 100,713 83,996 16,718 - - 16,718 ENERGY AND FUEL MANAGEMENT ESI SESKE F3PPSPE020 SPO SOFTWARE SUPPORT/LICENSING LOADOPCO 24,665 - 24,665 20,571 4,094 - - 4,094 ENERGY AND FUEL MANAGEMENT ESI SESKE F3PPSPE022 SPO Communications Infrastruct LOADOPCO 52,135 - 52,135 43,481 8,654 - - 8,654 ENERGY AND FUEL MANAGEMENT ESI SESKE F3PPSPE024 SPO Power Delivery & Tech Serv LOADOPCO 125 12 137 114 23 - 0 23 ENERGY AND FUEL MANAGEMENT ESI SESKE F3PPSPE028 SPO CIP Expense LOADOPCO 85,786 - 85,786 71,547 14,240 - - 14,240 ENERGY AND FUEL MANAGEMENT ESI SESKE F3PPSPE038 SPO Pwr Del & Tech Svcs - EMI DIRCTEMI - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI SESKE F3PPSPE042 SPO Expense ISES Purchase Opti OWNISES2 1,286 113 1,399 1,399 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKE F3PPSPE047 SPO Telecommunications LOADOPCO 6,086 - 6,086 5,075 1,010 - - 1,010 ENERGY AND FUEL MANAGEMENT ESI SESKE F3PPTDERSC Entergy Regional State Committ LOADOPCO 2,288 179 2,466 2,057 409 - 9 419 ENERGY AND FUEL MANAGEMENT ESI SESKE F3PPTDERSD MISO Transition ALL OPCO LOADOPCO 2,217 167 2,384 1,989 396 - (396) - ENERGY AND FUEL MANAGEMENT ESI SESKE F3PPWET304 SPO Frontier 10 Year PPA DIRECTTX - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI SESKE F5PCE13611 GENERAL LITIGATION-ENOI DIRCTENO 2,733 257 2,990 2,990 - - - - Amounts may not add or tie to other schedules due to rounding.

EXHIBIT PJC-C Cicio, Patrick Page 7 of 11 ENTERGY TEXAS, INC. EXHIBIT PJC-C 2011 ETI Rate Case

Affiliate Billings - by Witness, Class, Department and Project 2011 TX Rate Case For the Twelve Months Ended June 30, 2011 Page 8 of 11 Amounts in Dollars (A) (B) (C) (D) (E) (F) (G) (H) Total Billings Activity / Project ESI BIlling Service Company ETI Per Pro Forma Total ETI Class Billing Entity Dept Code Activity / Project Description Method Support Recipient Total All Other BU's Books Exclusions Amount Adjusted ENERGY AND FUEL MANAGEMENT ESI SESKE F5PCE13751 GENERAL LITIGATION- EGSI-LA DIRECTLG 274 24 297 297 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKE F5PCEDIVER DIVERSITY TRAINING DIRCTESI 45 - 45 45 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKE F5PCSVCAWD SERVICE AWARDS DIRCTESI 412 - 412 412 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKE F5PCZU1574 REGULATORY AFFAIRS - 100% TX G DIRECTTX 161 14 175 - 175 - 4 179 ENERGY AND FUEL MANAGEMENT ESI SESKE F5PP10011U Show Cause Docket No. 10-011-U DIRCTEAI 2,917 287 3,204 3,204 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKE F5PPSPE044 PMO Support Initiative-System- LOADOPCO 1,681 - 1,681 1,402 279 - (279) - ENERGY AND FUEL MANAGEMENT ESI SESKE F5PPSUPICT Support of ICT LOADOPCO 3,501 344 3,845 3,206 638 - 21 659 ENERGY AND FUEL MANAGEMENT ESI SESKE F5PPZUWELL Entergy Wellness Program EMPLOYAL 1,104 87 1,190 1,132 58 - 1 60 ENERGY AND FUEL MANAGEMENT ESI SESKE Total 1,250,562 78,031 1,328,594 1,120,970 207,624 (2,563) 2,163 207,224 ENERGY AND FUEL MANAGEMENT ESI SESKF C1PPSP0008 SPO ELL&ENOI Purchase Option I OWNISES2 0 (5) (5) (5) - - - - ENERGY AND FUEL MANAGEMENT ESI SESKF C6PCN32144 GRAND GULF EXTENDED POWER UPRA DIRCTSER 816 77 893 893 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKF C6PPGN0020 New Nuclear Reg Filing EGSL On DIRECTLG 324 25 349 349 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKF C6PPLN0020 New Nuclear Reg Filing ELL Ong DIRCTELI 324 25 349 349 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKF C6PPSP0012 SPO Project Gator Transact/Tra DIRCTELI 725 66 791 791 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKF C6PPSP0038 SPO Project Lamar Transaction DIRCTEAI 2 0 2 2 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKF C6PPSP0046 SPO Project Burnet Transaction DIRCTEMI 2 0 2 2 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKF C6PPWS0783 Ninem le 6 Development DIRCTELI 3,543 329 3,872 3,872 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKF F3PCCSPEAI SYSTEM PLANNING - EAI DIRCTEAI 568 47 616 616 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKF F3PCCSPELI SYSTEM PLANNING - ELI DIRCTELI 1,088 106 1,194 1,194 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKF F3PCCSPENO SYSTEM PLANNING - ENOI DIRCTENO 1,088 106 1,194 1,194 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKF F3PCCSPGSL SYSTEM PLANNING - EGSI-LA DIRECTLG 3,058 282 3,340 3,340 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKF F3PCCSPUTI SYSTEM PLANNING & STRATEGIC AD LOADOPCO 976 67 1,042 869 173 - 4 177 ENERGY AND FUEL MANAGEMENT ESI SESKF F3PCE14423 REGULATORY AFFAIRS - EMI DIRCTEMI 1,046 82 1,128 1,128 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKF F3PCSYSAGR SYSTEM AGREEMENT-2001 CUSEOPCO 8,214 702 8,916 7,593 1,323 - 32 1,355 ENERGY AND FUEL MANAGEMENT ESI SESKF F3PCW15830 SYSTEM GENERATION PLANNING LOADOPCO 906,526 79,321 985,847 830,499 155,348 - 3,013 158,361 ENERGY AND FUEL MANAGEMENT ESI SESKF F3PCW15840 PLANNING MODELING & ANALYSIS G LOADOPCO 294,177 26,854 321,031 270,703 50,328 - 960 51,288 ENERGY AND FUEL MANAGEMENT ESI SESKF F3PCWE0058 AWARDS & RECOGNITIONS PROGRAM LOADOPCO 319 40 359 305 54 - 1 55 ENERGY AND FUEL MANAGEMENT ESI SESKF F3PPAMPDEV Advanced Mgmt Dev Program EMPLOYAL - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI SESKF F3PPE14432 EAI SPP RTO Study DIRCTEAI 1,053 109 1,162 1,162 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKF F3PPEAIMIS MISO Transition EAI Path 1 cos DIRCTEAI 1,563 118 1,681 1,681 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKF F3PPEMI884 EMI-2010 ECR Docket 2008-UN-88 DIRCTEMI 307 32 338 338 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKF F3PPISP717 Integration Planning Studies 7 LOADOPCO 1,653 145 1,798 1,499 298 - 6 305 ENERGY AND FUEL MANAGEMENT ESI SESKF F3PPMSFA10 2010 EMI Fuel Audit DIRCTEMI 200 21 221 221 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKF F3PPSPE003 SPO Summer 2009 RFP Expense LOADOPCO 10,932 1,416 12,348 10,499 1,850 - 35 1,885 ENERGY AND FUEL MANAGEMENT ESI SESKF F3PPSPE010 SPO Divers ty In tiative LOADOPCO 581 64 645 548 96 - 2 98 ENERGY AND FUEL MANAGEMENT ESI SESKF F3PPSPE024 SPO Power Delivery & Tech Serv LOADOPCO 640 57 697 581 116 - 2 118 ENERGY AND FUEL MANAGEMENT ESI SESKF F3PPSPE025 SPO 2010 Renewable RFP - LA on CUSELGLA 513 46 559 559 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKF F3PPSPE027 SPO ESI Project Houston PPA DIRCTESI - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI SESKF F3PPSPE042 SPO Expense ISES Purchase Opti OWNISES2 626 65 690 690 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKF F3PPTCGS11 TX Docket Competitive Generati DIRECTTX 84 7 91 - 91 - 2 93 ENERGY AND FUEL MANAGEMENT ESI SESKF F3PPTDERSC Entergy Regional State Committ LOADOPCO 12,659 1,123 13,782 11,638 2,144 - 46 2,189 ENERGY AND FUEL MANAGEMENT ESI SESKF F3PPTDERSD MISO Transition ALL OPCO LOADOPCO 13,372 1,010 14,382 11,995 2,387 - (2,387) - ENERGY AND FUEL MANAGEMENT ESI SESKF F3PPWE0516 EPA Section 114 Request for In DIRCTEAI 3,836 365 4,201 4,201 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKF F3PPWET308 SPO Calpine PPA/Project Housto DIRECTTX 3,131 301 3,432 - 3,432 - 72 3,505 ENERGY AND FUEL MANAGEMENT ESI SESKF F5PCEDIVER DIVERSITY TRAINING DIRCTESI 90 - 90 90 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKF F5PCSVCAWD SERVICE AWARDS DIRCTESI 40 - 40 40 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKF F5PP10011U Show Cause Docket No. 10-011-U DIRCTEAI 866 - 866 866 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKF F5PPBULKPW Minimize of Bulk Power Supply LOADOPCO 47,615 4,128 51,743 43,320 8,423 - 171 8,594 ENERGY AND FUEL MANAGEMENT ESI SESKF F5PPDOEETR DOE-Dept of Energy Studies Coo LOADOPCO 458 186 644 544 100 - 7 106 ENERGY AND FUEL MANAGEMENT ESI SESKF F5PPETX009 2009 Texas Rate Case Support DIRECTTX 7,009 645 7,654 - 7,654 (570) (7,084) - ENERGY AND FUEL MANAGEMENT ESI SESKF F5PPSPPCBA ICT/RTO Cost Benefit Analysis LOADOPCO 527 54 581 494 87 - (87) - ENERGY AND FUEL MANAGEMENT ESI SESKF F5PPSUPICT Support of ICT LOADOPCO 4,664 464 5,129 4,363 766 - 16 781 9-254

ENERGY AND FUEL MANAGEMENT ESI SESKF F5PPZUWELL Entergy Wellness Program EMPLOYAL 1,357 116 1,472 1,400 72 - 2 74 ENERGY AND FUEL MANAGEMENT ESI SESKF Total 1,336,569 118,596 1,455,165 1,220,425 234,741 (570) (5,187) 228,983 ENERGY AND FUEL MANAGEMENT ESI SESKG F3PCW15840 PLANNING MODELING & ANALYSIS G LOADOPCO 659 - 659 550 109 - - 109 ENERGY AND FUEL MANAGEMENT ESI SESKG Total 659 - 659 550 109 - - 109 ENERGY AND FUEL MANAGEMENT ESI SESKH C1PPSP0008 SPO ELL&ENOI Purchase Option I OWNISES2 (964) (100) (1,064) (1,064) - - - - ENERGY AND FUEL MANAGEMENT ESI SESKH C6PPSP0012 SPO Project Gator Transact/Tra DIRCTELI 2,931 241 3,171 3,171 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKH C6PPSP0038 SPO Project Lamar Transaction DIRCTEAI 266 24 290 290 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKH C6PPSP0046 SPO Project Burnet Transaction DIRCTEMI 353 35 388 388 - - - - Amounts may not add or tie to other schedules due to rounding.

EXHIBIT PJC-C Cicio, Patrick Page 8 of 11 ENTERGY TEXAS, INC. EXHIBIT PJC-C 2011 ETI Rate Case

Affiliate Billings - by Witness, Class, Department and Project 2011 TX Rate Case For the Twelve Months Ended June 30, 2011 Page 9 of 11 Amounts in Dollars (A) (B) (C) (D) (E) (F) (G) (H) Total Billings Activity / Project ESI BIlling Service Company ETI Per Pro Forma Total ETI Class Billing Entity Dept Code Activity / Project Description Method Support Recipient Total All Other BU's Books Exclusions Amount Adjusted ENERGY AND FUEL MANAGEMENT ESI SESKH F3PCFVARAS ADMIN SUPRT - VARIBUS CORPORAT DIRECTLG - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI SESKH F3PCSYSAGR SYSTEM AGREEMENT-2001 CUSEOPCO - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI SESKH F3PCW19501 WHOLESALE PURCHASING & SALES LOADOPCO - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI SESKH F3PCW19510 ENERGY MANAGEMENT OPERATIONS LOADOPCO 144,037 13,246 157,282 131,852 25,430 - 491 25,921 ENERGY AND FUEL MANAGEMENT ESI SESKH F3PCW19511 ENERGY MANAGEMENT OPERATIONS P LOADOPCO 1,506,076 129,082 1,635,158 1,376,511 258,647 - 4,838 263,485 ENERGY AND FUEL MANAGEMENT ESI SESKH F3PCW54035 VICE PRESIDENT OF ENERGY MANAG LOADOPCO - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI SESKH F3PCWE0058 AWARDS & RECOGNITIONS PROGRAM LOADOPCO 398 50 448 382 67 - 2 69 ENERGY AND FUEL MANAGEMENT ESI SESKH F3PPAMPDEV Advanced Mgmt Dev Program EMPLOYAL 4,112 - 4,112 3,921 192 - - 192 ENERGY AND FUEL MANAGEMENT ESI SESKH F3PPSPE003 SPO Summer 2009 RFP Expense LOADOPCO 563 60 623 530 93 - 2 95 ENERGY AND FUEL MANAGEMENT ESI SESKH F3PPSPE010 SPO Divers ty In tiative LOADOPCO 30 - 30 26 4 - - 4 ENERGY AND FUEL MANAGEMENT ESI SESKH F3PPSPE025 SPO 2010 Renewable RFP - LA on CUSELGLA 486 40 527 527 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKH F3PPSPE027 SPO ESI Project Houston PPA DIRCTESI - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI SESKH F3PPSPE042 SPO Expense ISES Purchase Opti OWNISES2 964 100 1,064 1,064 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKH F3PPTDERSC Entergy Regional State Committ LOADOPCO 10,491 949 11,439 9,541 1,899 - 40 1,939 ENERGY AND FUEL MANAGEMENT ESI SESKH F3PPTDERSD MISO Transition ALL OPCO LOADOPCO 20,788 1,664 22,453 18,726 3,727 - (3,727) - ENERGY AND FUEL MANAGEMENT ESI SESKH F3PPWE0420 SPO EGSL-SupplyProcuremt/Asset DIRECTLG 3,199 263 3,462 3,462 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKH F3PPWET304 SPO Frontier 10 Year PPA DIRECTTX 88 7 95 - 95 - 2 97 ENERGY AND FUEL MANAGEMENT ESI SESKH F3PPWET308 SPO Calpine PPA/Project Housto DIRECTTX 29,013 2,801 31,814 - 31,814 - 663 32,477 ENERGY AND FUEL MANAGEMENT ESI SESKH F5PCSVCAWD SERVICE AWARDS DIRCTESI 653 - 653 653 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKH F5PCZU1424 REGULATORY AFFAIRS - NOPSI DIRCTENO 923 73 995 995 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKH F5PCZZ4070 IMPACT AWARDS DIRCTESI 155 - 155 155 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKH F5PP10011U Show Cause Docket No. 10-011-U DIRCTEAI 27,194 2,447 29,641 29,641 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKH F5PP4RFERC FERC Audit LVLSVCAL - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI SESKH F5PPBCNAVF Avian Flu Contingency Planning EMPLOYAL - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI SESKH F5PPETX009 2009 Texas Rate Case Support DIRECTTX (1,125) - (1,125) - (1,125) (212) 1,337 - ENERGY AND FUEL MANAGEMENT ESI SESKH F5PPMSFA9A 2009 EMI Fuel Audit McFadden G DIRCTEMI - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI SESKH F5PPSPE044 PMO Support Initiative-System- LOADOPCO 12,129 980 13,109 10,933 2,176 - (2,176) - ENERGY AND FUEL MANAGEMENT ESI SESKH F5PPSUPICT Support of ICT LOADOPCO (119) - (119) (101) (18) - (0) (18) ENERGY AND FUEL MANAGEMENT ESI SESKH F5PPZUWELL Entergy Wellness Program EMPLOYAL 1,988 142 2,131 2,026 104 - 2 106 ENERGY AND FUEL MANAGEMENT ESI SESKH F5PPZZ580B REGULATORY AFFAIRS-A&G CUSTEGOP 769 59 828 714 114 - 2 117 ENERGY AND FUEL MANAGEMENT ESI SESKH Total 1,765,397 152,163 1,917,560 1,594,341 323,219 (212) 1,476 324,483 ENERGY AND FUEL MANAGEMENT ESI SESKJ F3PCW19501 WHOLESALE PURCHASING & SALES LOADOPCO 626,065 39,537 665,602 560,815 104,787 - 1,982 106,769 ENERGY AND FUEL MANAGEMENT ESI SESKJ F3PCW19510 ENERGY MANAGEMENT OPERATIONS LOADOPCO 2,324,822 206,432 2,531,254 2,131,786 399,469 - 7,468 406,936 ENERGY AND FUEL MANAGEMENT ESI SESKJ F3PCW19511 ENERGY MANAGEMENT OPERATIONS P LOADOPCO 8,802 845 9,647 8,046 1,601 - 31 1,632 ENERGY AND FUEL MANAGEMENT ESI SESKJ F3PCW54035 VICE PRESIDENT OF ENERGY MANAG LOADOPCO 6,325 - 6,325 5,297 1,028 - - 1,028 ENERGY AND FUEL MANAGEMENT ESI SESKJ F5PCEDIVER DIVERSITY TRAINING DIRCTESI 135 - 135 135 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKJ F5PCSVCAWD SERVICE AWARDS DIRCTESI 233 - 233 233 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKJ F5PCZXNLDW NEW LEADERSHIP DEVELOPMENT WOR EMPLOREG 35 - 35 33 2 - - 2 ENERGY AND FUEL MANAGEMENT ESI SESKJ F5PP4RFERC FERC Audit LVLSVCAL - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI SESKJ F5PPBCNAVF Avian Flu Contingency Planning EMPLOYAL - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI SESKJ F5PPMSFA9A 2009 EMI Fuel Audit McFadden G DIRCTEMI - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI SESKJ F5PPZUWELL Entergy Wellness Program EMPLOYAL 149 12 161 154 8 - 0 8 ENERGY AND FUEL MANAGEMENT ESI SESKJ Total 2,966,567 246,827 3,213,393 2,706,497 506,896 - 9,480 516,376 ENERGY AND FUEL MANAGEMENT ESI SESKQ F3PCCSPUTI SYSTEM PLANNING & STRATEGIC AD LOADOPCO 60 - 60 51 9 - - 9 ENERGY AND FUEL MANAGEMENT ESI SESKQ F3PCE14420 REGULATORY AFFAIRS - EAI DIRCTEAI 184 18 203 203 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKQ F3PCSYSAGR SYSTEM AGREEMENT-2001 CUSEOPCO 99,830 7,752 107,582 91,701 15,881 - 373 16,254 ENERGY AND FUEL MANAGEMENT ESI SESKQ F3PCW15830 SYSTEM GENERATION PLANNING LOADOPCO 1,417 136 1,552 1,319 233 - 4 238 ENERGY AND FUEL MANAGEMENT ESI SESKQ F3PCW18200 OPNS-OIL SUPPLY OWNISFI 277 27 304 304 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKQ F3PCWE0064 LONG TERM ENERGY LOADOPCO 935 - 935 787 148 - - 148 ENERGY AND FUEL MANAGEMENT ESI SESKQ F3PPE14432 EAI SPP RTO Study DIRCTEAI 2,491 257 2,748 2,748 - - - - 9-255

ENERGY AND FUEL MANAGEMENT ESI SESKQ F3PPE14434 EAI POST SYS AGMT INCREMENTAL DIRCTEAI 8,439 569 9,008 9,008 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKQ F3PPE14435 EAI POST SYS AGMT NON-INCREMEN DIRCTEAI 2,616 270 2,886 2,886 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKQ F3PPEAIMIS MISO Transition EAI Path 1 cos DIRCTEAI 19,544 1,268 20,813 20,813 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKQ F3PPEMIMIS MISO Transition EMI costs DIRCTEMI 1,299 84 1,382 1,382 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKQ F3PPENOIMI MISO Transition ENOI costs DIRCTENO 47 4 50 50 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKQ F3PPETIMIS MISO Transition ETI costs DIRECTTX 358 27 385 - 385 - (385) - ENERGY AND FUEL MANAGEMENT ESI SESKQ F3PPINVDOJ DOJ Anti Trust Investigation CUSEOPCO 2,362 151 2,513 2,142 370 - 6 376 ENERGY AND FUEL MANAGEMENT ESI SESKQ F3PPMSFA10 2010 EMI Fuel Audit DIRCTEMI 184 20 205 205 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKQ F3PPSPE001 SPO NISCO JOPOA MANAGEMENT EXP DIRECTLG 56 - 56 56 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKQ F3PPSPE010 SPO Divers ty In tiative LOADOPCO 135 11 146 121 24 - 1 25 ENERGY AND FUEL MANAGEMENT ESI SESKQ F3PPSPE011 SPO NISCO Contract DIRECTLG 4,861 414 5,275 5,275 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKQ F3PPSPE017 SPO 2010 Renewable RFP LOADOPCO 154 - 154 131 23 - - 23 Amounts may not add or tie to other schedules due to rounding.

EXHIBIT PJC-C Cicio, Patrick Page 9 of 11 ENTERGY TEXAS, INC. EXHIBIT PJC-C 2011 ETI Rate Case

Affiliate Billings - by Witness, Class, Department and Project 2011 TX Rate Case For the Twelve Months Ended June 30, 2011 Page 10 of 11 Amounts in Dollars (A) (B) (C) (D) (E) (F) (G) (H) Total Billings Activity / Project ESI BIlling Service Company ETI Per Pro Forma Total ETI Class Billing Entity Dept Code Activity / Project Description Method Support Recipient Total All Other BU's Books Exclusions Amount Adjusted ENERGY AND FUEL MANAGEMENT ESI SESKQ F3PPSPE018 SPO VP of Strategic Initiative LOADOPCO 371,895 34,263 406,158 343,181 62,977 - 1,120 64,097 ENERGY AND FUEL MANAGEMENT ESI SESKQ F3PPSPE025 SPO 2010 Renewable RFP - LA on CUSELGLA 505 48 553 553 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKQ F3PPTDERSC Entergy Regional State Committ LOADOPCO 88,884 6,164 95,049 79,752 15,297 - 319 15,615 ENERGY AND FUEL MANAGEMENT ESI SESKQ F3PPTDERSD MISO Transition ALL OPCO LOADOPCO 53,896 3,669 57,565 48,010 9,555 - (9,555) - ENERGY AND FUEL MANAGEMENT ESI SESKQ F3PPWE0403 SPO Performance Mngmnt/Special LOADOPCO 2,491 234 2,725 2,273 452 - 10 462 ENERGY AND FUEL MANAGEMENT ESI SESKQ F3PPWET306 SPO 2011 Western Region RFP DIRECTTX 2,536 208 2,743 - 2,743 - 61 2,804 ENERGY AND FUEL MANAGEMENT ESI SESKQ F5PCE13759 JENKINS CLASS ACTION SUIT DIRECTTX 1,513 114 1,627 - 1,627 - 30 1,657 ENERGY AND FUEL MANAGEMENT ESI SESKQ F5PCSVCAWD SERVICE AWARDS DIRCTESI 226 - 226 226 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKQ F5PCZU1422 REGULATORY AFFAIRS - LP&L DIRCTELI 43 - 43 43 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKQ F5PCZU1424 REGULATORY AFFAIRS - NOPSI DIRCTENO 551 50 601 601 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKQ F5PCZU1574 REGULATORY AFFAIRS - 100% TX G DIRECTTX 16,506 1,180 17,686 - 17,686 - 265 17,951 ENERGY AND FUEL MANAGEMENT ESI SESKQ F5PP10011U Show Cause Docket No. 10-011-U DIRCTEAI 37,874 2,841 40,715 40,715 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKQ F5PP4RFERC FERC Audit LVLSVCAL - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI SESKQ F5PPETX009 2009 Texas Rate Case Support DIRECTTX 2,238 143 2,382 - 2,382 (99) (2,283) - ENERGY AND FUEL MANAGEMENT ESI SESKQ F5PPSPE044 PMO Support Initiative-System- LOADOPCO 44,113 3,705 47,818 39,881 7,937 - (7,937) - ENERGY AND FUEL MANAGEMENT ESI SESKQ F5PPSPPCBA ICT/RTO Cost Benefit Analysis LOADOPCO 33,937 3,185 37,123 31,251 5,872 - (5,872) - ENERGY AND FUEL MANAGEMENT ESI SESKQ F5PPSUPICT Support of ICT LOADOPCO 51,936 4,526 56,462 47,197 9,266 - 173 9,438 ENERGY AND FUEL MANAGEMENT ESI SESKQ Total 854,394 71,339 925,732 772,863 152,869 (99) (23,673) 129,098 ENERGY AND FUEL MANAGEMENT ESI SESKU C6PPGN0020 New Nuclear Reg Filing EGSL On DIRECTLG 461 35 496 496 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKU C6PPLN0020 New Nuclear Reg Filing ELL Ong DIRCTELI 461 35 496 496 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKU C6PPSP0012 SPO Project Gator Transact/Tra DIRCTELI 1,592 155 1,747 1,747 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKU C6PPSP0038 SPO Project Lamar Transaction DIRCTEAI 8,708 842 9,550 9,550 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKU C6PPSP0046 SPO Project Burnet Transaction DIRCTEMI 322 28 351 351 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKU C6PPWS0783 Ninem le 6 Development DIRCTELI 7,794 768 8,562 8,562 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKU F3PCCSPEAI SYSTEM PLANNING - EAI DIRCTEAI 24,707 2,387 27,094 27,094 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKU F3PCCSPELI SYSTEM PLANNING - ELI DIRCTELI 2,799 273 3,073 3,073 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKU F3PCCSPEMI SYSTEM PLANNING - EMI DIRCTEMI 922 94 1,015 1,015 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKU F3PCCSPENO SYSTEM PLANNING - ENOI DIRCTENO 7,197 690 7,887 7,887 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKU F3PCCSPGST SYSTEM PLANNING - EGSI-TX DIRECTTX 2,178 180 2,358 - 2,358 - 51 2,409 ENERGY AND FUEL MANAGEMENT ESI SESKU F3PCCSPUTI SYSTEM PLANNING & STRATEGIC AD LOADOPCO 1,554 - 1,554 1,322 232 - - 232 ENERGY AND FUEL MANAGEMENT ESI SESKU F3PCSYSAGR SYSTEM AGREEMENT-2001 CUSEOPCO 12,170 1,027 13,197 11,247 1,950 - 40 1,990 ENERGY AND FUEL MANAGEMENT ESI SESKU F3PCW15830 SYSTEM GENERATION PLANNING LOADOPCO 809,798 75,495 885,293 746,610 138,683 - 2,677 141,360 ENERGY AND FUEL MANAGEMENT ESI SESKU F3PCW15840 PLANNING MODELING & ANALYSIS G LOADOPCO 417 - 417 354 63 - - 63 ENERGY AND FUEL MANAGEMENT ESI SESKU F3PPE14436 EAI MISO RTO STUDY DIRCTEAI 1,103 93 1,196 1,196 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKU F3PPEAIMIS MISO Transition EAI Path 1 cos DIRCTEAI 10,103 1,071 11,174 11,174 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKU F3PPEAIPAT Maintain EAI Paths 2 and 3 RTO DIRCTEAI 7,481 565 8,046 8,046 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKU F3PPISP717 Integration Planning Studies 7 LOADOPCO 14,486 1,200 15,686 13,112 2,574 - 57 2,631 ENERGY AND FUEL MANAGEMENT ESI SESKU F3PPSPE003 SPO Summer 2009 RFP Expense LOADOPCO 27,286 2,859 30,145 25,645 4,501 - 92 4,592 ENERGY AND FUEL MANAGEMENT ESI SESKU F3PPSPE007 SPO July 2009 Flexible Baseloa LOADOPCO - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI SESKU F3PPSPE017 SPO 2010 Renewable RFP LOADOPCO 503 40 542 461 81 - 2 83 ENERGY AND FUEL MANAGEMENT ESI SESKU F3PPSPE025 SPO 2010 Renewable RFP - LA on CUSELGLA 48,223 4,424 52,647 52,647 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKU F3PPSPE049 SPO 2011 EAI RFP DIRCTEAI 1,617 122 1,739 1,739 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKU F3PPTDERSD MISO Transition ALL OPCO LOADOPCO 388 29 418 348 69 - (69) - ENERGY AND FUEL MANAGEMENT ESI SESKU F3PPUD0802 ENO Integrated Resource Plan DIRCTENO 1,424 118 1,542 1,542 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKU F3PPWET300 SPO 2008 Western Region RFP-Te DIRECTTX - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI SESKU F3PPWET302 SPO 2008 Winter Western Region DIRECTTX - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI SESKU F5PCEDIVER DIVERSITY TRAINING DIRCTESI 135 - 135 135 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKU F5PCSVCAWD SERVICE AWARDS DIRCTESI 210 - 210 210 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKU F5PCZU1424 REGULATORY AFFAIRS - NOPSI DIRCTENO 754 58 812 812 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKU F5PCZZ4070 IMPACT AWARDS DIRCTESI 36 - 36 36 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKU F5PP10011U Show Cause Docket No. 10-011-U DIRCTEAI 3,705 291 3,996 3,996 - - - - ENERGY AND FUEL MANAGEMENT ESI SESKU F5PPSUPICT Support of ICT LOADOPCO 212 22 234 199 35 - 1 36 9-256

ENERGY AND FUEL MANAGEMENT ESI SESKU F5PPZUWELL Entergy Wellness Program EMPLOYAL 696 51 747 711 36 - 1 37 ENERGY AND FUEL MANAGEMENT ESI SESKU Total 999,442 92,955 1,092,397 941,814 150,582 - 2,851 153,434 ENERGY AND FUEL MANAGEMENT ESI SESLA F3PCFBLFOS BELOW THE LINE - FOSSIL OPERAT CAPAOPCO 3,684 - 3,684 3,286 398 (398) - - ENERGY AND FUEL MANAGEMENT ESI SESLA F3PCSYSAGR SYSTEM AGREEMENT-2001 CUSEOPCO - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI SESLA F3PCW19501 WHOLESALE PURCHASING & SALES LOADOPCO 824,308 75,638 899,946 758,065 141,882 - 2,726 144,607 ENERGY AND FUEL MANAGEMENT ESI SESLA F3PCWE0064 LONG TERM ENERGY LOADOPCO - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI SESLA F5PCSVCAWD SERVICE AWARDS DIRCTESI 1,861 - 1,861 1,861 - - - - ENERGY AND FUEL MANAGEMENT ESI SESLA F5PP4RFERC FERC Audit LVLSVCAL - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI SESLA F5PPZUWELL Entergy Wellness Program EMPLOYAL 439 29 468 445 23 - 0 23

Amounts may not add or tie to other schedules due to rounding.

EXHIBIT PJC-C Cicio, Patrick Page 10 of 11 ENTERGY TEXAS, INC. EXHIBIT PJC-C 2011 ETI Rate Case

Affiliate Billings - by Witness, Class, Department and Project 2011 TX Rate Case For the Twelve Months Ended June 30, 2011 Page 11 of 11 Amounts in Dollars (A) (B) (C) (D) (E) (F) (G) (H) Total Billings Activity / Project ESI BIlling Service Company ETI Per Pro Forma Total ETI Class Billing Entity Dept Code Activity / Project Description Method Support Recipient Total All Other BU's Books Exclusions Amount Adjusted ENERGY AND FUEL MANAGEMENT ESI SESLA Total 830,292 75,667 905,959 763,656 142,303 (398) 2,726 144,631 ENERGY AND FUEL MANAGEMENT ESI SESLB C6PPSP0029 SPO Evange ine DIRCTELI 161 17 178 178 - - - - ENERGY AND FUEL MANAGEMENT ESI SESLB C6PPWS0783 Ninem le 6 Development DIRCTELI 1,045 111 1,156 1,156 - - - - ENERGY AND FUEL MANAGEMENT ESI SESLB F3PCSYSAGR SYSTEM AGREEMENT-2001 CUSEOPCO - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI SESLB F3PCW19502 WHOLESALE TRXN - EAI CUSTOMERS DIRCTEAI 56 - 56 56 - - - - ENERGY AND FUEL MANAGEMENT ESI SESLB F3PCW19511 ENERGY MANAGEMENT OPERATIONS P LOADOPCO 21,026 1,979 23,005 19,571 3,434 - 65 3,499 ENERGY AND FUEL MANAGEMENT ESI SESLB F3PCWE0064 LONG TERM ENERGY LOADOPCO 325,424 28,335 353,759 298,125 55,634 - 1,019 56,653 ENERGY AND FUEL MANAGEMENT ESI SESLB F3PPAMPDEV Advanced Mgmt Dev Program EMPLOYAL 4,112 - 4,112 3,921 192 - - 192 ENERGY AND FUEL MANAGEMENT ESI SESLB F3PPAPSCLG APSC Complaint - FERC Investig CUSEOPCO - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI SESLB F3PPTDERSC Entergy Regional State Committ LOADOPCO - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI SESLB F3PPTDERSD MISO Transition ALL OPCO LOADOPCO 2,144 162 2,306 1,923 383 - (383) - ENERGY AND FUEL MANAGEMENT ESI SESLB F3PPWE0315 Dir. Southeast Region-TXT_ ELI CAPASTHN 18,259 1,717 19,976 19,976 - - - - ENERGY AND FUEL MANAGEMENT ESI SESLB F5PCZU1422 REGULATORY AFFAIRS - LP&L DIRCTELI - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI SESLB F5PP10011U Show Cause Docket No. 10-011-U DIRCTEAI - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI SESLB F5PP4RFERC FERC Audit LVLSVCAL - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI SESLB F5PPBCNAVF Avian Flu Contingency Planning EMPLOYAL - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI SESLB F5PPETX009 2009 Texas Rate Case Support DIRECTTX - - - - - (9) 9 - ENERGY AND FUEL MANAGEMENT ESI SESLB F5PPMSFA9A 2009 EMI Fuel Audit McFadden G DIRCTEMI - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI SESLB F5PPSUPICT Support of ICT LOADOPCO - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI SESLB F5PPZUWELL Entergy Wellness Program EMPLOYAL 595 43 638 607 31 - 1 32 ENERGY AND FUEL MANAGEMENT ESI SESLB F5PPZZ580B REGULATORY AFFAIRS-A&G CUSTEGOP 296 23 318 274 44 - 1 45 ENERGY AND FUEL MANAGEMENT ESI SESLB Total 373,117 32,386 405,504 345,786 59,718 (9) 712 60,421 ENERGY AND FUEL MANAGEMENT ESI SESLC F3PCWE0138 POWER CONTRACTS LOADOPCO 508 - 508 427 81 - - 81 ENERGY AND FUEL MANAGEMENT ESI SESLC Total 508 - 508 427 81 - - 81 ENERGY AND FUEL MANAGEMENT ESI SESLE F3PCW19510 ENERGY MANAGEMENT OPERATIONS LOADOPCO 1,074 - 1,074 912 162 - - 162 ENERGY AND FUEL MANAGEMENT ESI SESLE F3PCWE0064 LONG TERM ENERGY LOADOPCO 1 - 1 1 0 - - 0 ENERGY AND FUEL MANAGEMENT ESI SESLE F5PPZUWELL Entergy Wellness Program EMPLOYAL - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI SESLE Total 1,076 - 1,076 914 162 - - 162 ENERGY AND FUEL MANAGEMENT ESI SESLT C6PPSP0012 SPO Project Gator Transact/Tra DIRCTELI 398 34 431 431 - - - - ENERGY AND FUEL MANAGEMENT ESI SESLT C6PPSP0029 SPO Evange ine DIRCTELI 7,474 509 7,983 7,983 - - - - ENERGY AND FUEL MANAGEMENT ESI SESLT F3PCFVARAS ADMIN SUPRT - VARIBUS CORPORAT DIRECTLG 373 40 413 413 - - - - ENERGY AND FUEL MANAGEMENT ESI SESLT F3PCW18100 OPNS-GAS SUPPLY CAPXCOPC 166,313 15,649 181,962 157,095 24,867 - 471 25,338 ENERGY AND FUEL MANAGEMENT ESI SESLT F3PCW19501 WHOLESALE PURCHASING & SALES LOADOPCO 119,159 10,643 129,802 109,438 20,364 - 339 20,703 ENERGY AND FUEL MANAGEMENT ESI SESLT F3PCW51400 SFI FUEL OIL O&M DIRCTSFI 144 15 159 159 - - - - ENERGY AND FUEL MANAGEMENT ESI SESLT F3PPAMPDEV Advanced Mgmt Dev Program EMPLOYAL - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI SESLT F3PPMSFA10 2010 EMI Fuel Audit DIRCTEMI 1,016 85 1,102 1,102 - - - - ENERGY AND FUEL MANAGEMENT ESI SESLT F3PPSPE003 SPO Summer 2009 RFP Expense LOADOPCO 2,288 190 2,479 2,109 370 - 6 376 ENERGY AND FUEL MANAGEMENT ESI SESLT F3PPSPE011 SPO NISCO Contract DIRECTLG 144 12 156 156 - - - - ENERGY AND FUEL MANAGEMENT ESI SESLT F3PPTDERSC Entergy Regional State Committ LOADOPCO 582 57 639 538 101 - 2 103 ENERGY AND FUEL MANAGEMENT ESI SESLT F3PPTDHY11 Transmission Comp iance FERC A TRSBLNOP 144 15 159 140 19 - 1 19 ENERGY AND FUEL MANAGEMENT ESI SESLT F5PCZU1425 REGULATORY COORDINAT.-ELI & EG CUSELPSC - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI SESLT F5PCZU1574 REGULATORY AFFAIRS - 100% TX G DIRECTTX 951 83 1,034 - 1,034 - 20 1,054 ENERGY AND FUEL MANAGEMENT ESI SESLT F5PP4RFERC FERC Audit LVLSVCAL - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI SESLT F5PPETX009 2009 Texas Rate Case Support DIRECTTX 144 11 155 - 155 (7) (148) - ENERGY AND FUEL MANAGEMENT ESI SESLT F5PPMSFA9A 2009 EMI Fuel Audit McFadden G DIRCTEMI - - - - - - - - ENERGY AND FUEL MANAGEMENT ESI SESLT Total 299,128 27,344 326,472 279,563 46,909 (7) 692 47,594 9-257

ENERGY AND FUEL MANAGEMENT Total ESI 23,521,673 1,732,183 25,253,856 21,510,774 3,743,083 (7,029) 6,260 3,742,314 Total ENERGY AND FUEL MANAGEMENT 23,521,673 1,732,183 25,253,856 21,510,774 3,743,083 (7,029) 6,260 3,742,314 Total Cicio Patrick 23,521,673 1,732,183 25,253,856 21,510,774 3,743,083 (7,029) 6,260 3,742,314

Amounts may not add or tie to other schedules due to rounding.

EXHIBIT PJC-C Cicio, Patrick Page 11 of 11 This page has been intentionally left blank.

2011 ETI Rate Case 9-258 ENTERGY TEXAS, INC. EXHIBIT PJC-D 2011 ETI Rate Case

Affiliate Billings - Pro Forma Summary - By Witness, Class, & Pro Forma 2011 TX Rate Case For the Twelve Months Ended June 30, 2011 Page 1 of 1 Amounts in Dollars Billing Pro Forma Class Entity Number Pro Forma Description Supporting Witness Pro Forma ENERGY AND FUEL MANAGEMENT ESI AJ16 Remove MISO Costs Considine, Michael P (41,533) ENERGY AND FUEL MANAGEMENT ESI AJ21-03 Remove Rate Case Support Costs Considine, Michael P (13,552) ENERGY AND FUEL MANAGEMENT ESI AJ21-04 PwC - Changes in Billing Methods Tumminello, Stephanie B (147) ENERGY AND FUEL MANAGEMENT ESI AJ21-05 Remove Ticket Costs Barrilleaux, Chris (344) ENERGY AND FUEL MANAGEMENT ESI AJ21-07 Remove Non-Recoverable Costs Barrilleaux, Chris (2,705) ENERGY AND FUEL MANAGEMENT ESI AJ22 Affiliate Portion of Employee Changes and Wage Increases Considine, Michael P 64,541 ESI 6,260 ENERGY AND FUEL MANAGEMENT Total 6,260 Total 6,260 9-259

Amounts may not add or tie to other schedules due to rounding. EXHIBIT PJC-D Cicio, Patrick Page 1 of 1 This page has been intentionally left blank.

2011 ETI Rate Case 9-260 SOAH Docket No. XXX-XX-XXXX PUC Docket No. 39896 ETI 2011 Rate Case ETI EXHIBIT NO. 46 SOAH DOCKET NO. XXX-XX-XXXX PUC DOCKET NO. 39896 APPLICATION OF ENTERGY § TEXAS, INC. FOR AUTHORITY TO § BEFORE THE CHANGE RATES, RECONCILE § STATE OFFICE OF FUEL COSTS, AND OBTAIN § ADMINISTRATIVE HEARINGS DEFERRED ACCOUNTING § TREATMENT §

REBUTTAL TESTIMONY

OF

MICHAEL P. CONSIDINE

ON BEHALF OF

ENTERGY TEXAS, INC.

APRIL 2012

ENTERGY TEXAS, INC. REBUTTAL TESTIMONY OF MICHAEL P. CONSIDINE PUC DOCKET NO. 39896

TABLE OF CONTENTS Page I. Introduction 1 A. Introduction and Qualifications 1 II. Rebuttal Issues 2 A. Spindletop Gas Storage Facility 2 B. MISO Transition Expenses 5 C. Hurricane Rita Regulatory Asset 16 D. Pension Asset in Rate Base 22 E. Property Insurance Reserve 25 F. Payroll and Incentive Compensation 29 G. DSM Costs 35 H. MSS-2 Costs 36 I. Nuclear Decommissioning 38 J. Depreciation 40 K. Fully Accrued Depreciation 43 L. Net Salvage 48 M. Accounting For Removal Costs 51

EXHIBITS Exhibit MPC-R-1 MISO Transition Expenses for the Nine Months Ended March 2012 Exhibit MPC-R-2 Rita Regulatory Asset Calculation Exhibit MPC-R-3 Company Response to Cities 6-2 RFI Exhibit MPC-R-4 1995 Storm Damage Policy Exhibit MPC-R-5 ETI Payroll Adjustment Exhibit MPC-R-6 ESI Payroll Adjustment Exhibit MPC-R-7 Full Time Equivalent Calculation Exhibit MPC-R-8 ETI Direct Costs of Incentive Comp Adjustment Exhibit MPC-R-9 ESI Allocated Costs of Incentive Comp Adjustment Exhibit MPC-R-10 March 2012 MSS-2 Bill to ETI Exhibit MPC-R-11 Railroad Commission of Texas PFDs and Orders

Entergy Texas, Inc. Page 1 of 55 Rebuttal Testimony of Michael P. Considine Docket No. 39896

1 I. INTRODUCTION 2 A. Introduction and Qualifications Q. PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.

4 A. My name is Michael P. Considine. My business address is 425 West 5 Capitol Avenue, Little Rock, Arkansas 72201.

7 Q. DID YOU PREVIOUSLY FILE DIRECT TESTIMONY ON BEHALF OF 8 ENTERGY TEXAS, INC. (“ETI” OR “THE COMPANY”) IN THIS 9 PROCEEDING?

10 A. Yes.

12 Q. WHAT IS THE PURPOSE OF THIS TESTIMONY?

13 A. The purpose of my Rebuttal Testimony is to respond to various issues 14 raised in Staff and Intervenor Direct Testimonies.

16 Q. DO YOU SPONSOR ANY EXHIBITS?

17 A. Yes. I sponsor the exhibits listed in the Table of Contents to this 18 testimony.

Entergy Texas, Inc. Page 2 of 55 Rebuttal Testimony of Michael P. Considine Docket No. 39896

1 II. REBUTTAL ISSUES 2 A. Spindletop Gas Storage Facility Q. WHAT ISSUES DO YOU ADDRESS IN THIS SECTION OF YOUR 4 REBUTTAL TESTIMONY?

5 A. I will address certain aspects of Cities’ witness Karl J. Nalepa’s 6 recommendation regarding the Spindletop Gas Storage Facility 7 (“Spindletop”) and I will address Staff witness Anna Givens 8 recommendation to remove an Electric Plant Acquisition asset related to 9 Spindletop from rate base.

10 Mr. Nalepa recommends removing Spindletop costs from base 11 rates and also recommends removing variable non-gas operating costs 12 from eligible fuel expense because he believes the supply reliability and 13 swing flexibility provided by Spindletop can be obtained elsewhere at a 14 lower cost. Company witness Karen M. McIlvoy will address Mr. Nalepa’s 15 concerns regarding supply reliability and swing flexibility. I will address his 16 recommendation to remove the costs from base rates and eligible fuel 17 expense.

19 Q. PLEASE DISCUSS MR. NALEPA’S RECOMMENDATION TO REMOVE 20 SPINDLETOP FROM RATES.

21 A. Mr. Nalepa recommends that Spindletop be removed from rates and he 22 recommends selling the facility or removing it from regulated service if

Entergy Texas, Inc. Page 3 of 55 Rebuttal Testimony of Michael P. Considine Docket No. 39896

1 necessary.1 He has prepared a Total Cost Impact table,2 which shows 2 what he claims to be the total annual costs of operating the facility. He 3 further claims that ETI’s customers pay 100% of the costs of operating 4 Spindletop.3

6 Q. DO YOU AGREE WITH MR. NALEPA’S ANALYSIS AND HIS CLAIM 7 THAT ETI’S CUSTOMERS PAY 100% OF THE COSTS OF OPERATING 8 SPINDLETOP?

9 A. No. Mr. Nalepa’s calculation fails to recognize that 57.50% of the costs 10 associated with Spindletop are billed to Entergy Gulf States Louisiana, Inc. 11 (“EGSL”) as part of the MSS-4 billing process between ETI and EGSL for 12 its “legacy” plants (that is, the generation-related facilities now owned 13 separately by either ETI or EGSL that, prior to the jurisdictional separation, 14 were owned by Entergy Gulf States, Inc.). Mr. Nalepa’s recommendation 15 as it is currently proposed is to remove all of the Spindletop costs from 16 rates and to leave the MSS-4 revenues in rates, thereby creating a 17 windfall for customers. Mr. Nalepa’s recommendation also fails to address 18 what ETI should do if it were to sell or de-regulate the facility as he 19 suggests or what to do with the gas inventory that is currently in 20 Spindletop.

Nalepa Direct at 5, line 18 and at 27, line 2.

Id. at 19, Table 9.

Id. at 19, line 3.

Entergy Texas, Inc. Page 4 of 55 Rebuttal Testimony of Michael P. Considine Docket No. 39896

1 Q. WHAT IS YOUR RECOMMENDATION REGARDING MR. NALEPA’S 2 SPINDLETOP ADJUSTMENT?

3 A. The Commission should reject Mr. Nalepa’s Spindletop adjustment. He 4 has failed to consider all of the impacts associated with his adjustment 5 and, as discussed by Company witness McIlvoy, the Spindletop facility 6 continues to provide customers with supply reliability and swing flexibility.

7 It should also be noted that ever since and including Docket No. 10894, 8 the Commission has consistently allowed the Company to recover its 9 costs associated with the Spindletop Facility because it is a used and 10 useful gas storage facility that provides benefits to ratepayers.

12 Q. ON PAGE 35 OF 36, LINES 8-13, MS. GIVENS REMOVES AN 13 ELECTRIC PLANT ACQUISITION ASSET FROM THE RATE BASE OF 14 ETI. WHAT ARE THE FACTS REGARDING THE ORIGINATION OF 15 THAT ELECTRIC PLANT ACQUISITION ASSET?

16 A. The acquisition asset represents the incurred closing costs of $211,209 17 and legal and internal costs of $916,568 the Company incurred in 18 acquiring the Spindletop gas storage facility. Prior to December 2009 19 those amounts were included in the Electric Plant in Service (FERC 20 Account 101). Furthermore, these amounts were included in the 21 Company’s filed rate base amounts in PUCT Docket Nos. 34800 and 22 37744. On January 11, 2010, the FERC issued Opinion No. 505 in FERC 23 Docket No. ER07-956-001. The FERC ordered the Company to transfer

Entergy Texas, Inc. Page 5 of 55 Rebuttal Testimony of Michael P. Considine Docket No. 39896

1 the amounts above from Account 101 to FERC Account 114, Electric Plant 2 Acquisition Adjustments.

4 Q. SHOULD THIS AMOUNT BE REMOVED FROM THE COMPANY’S RATE 5 BASE?

6 A. No. The Company incurred this cost in conjunction with the purchase of a 7 viable asset that benefits its retail customers. The amount has previously 8 been included in the Company rate base. The only thing that has 9 changed is that the amount is in a different account. It would be 10 inappropriate to penalize the Company because of an accounting 11 technicality.

13 B. MISO Transition Expenses Q. WHAT ISSUES DO YOU ADDRESS IN THIS SECTION OF YOUR 15 REBUTTAL TESTIMONY?

16 A. I will address various concerns regarding ETI’s MISO transition expenses 17 expressed by Cities’ witnesses James Z. Brazell and Mark E. Garrett and 18 TIEC witness Jeffry Pollock and Staff witness Joe Luna. Company 19 witnesses Jay A. Lewis and Bret R. Perlman also address certain aspects 20 of their recommendations.

Entergy Texas, Inc. Page 6 of 55 Rebuttal Testimony of Michael P. Considine Docket No. 39896

1 Q. WHAT IS MR. BRAZELL’S CONCERN REGARDING ETI’S MISO 2 TRANSITION EXPENSES?

3 A. Mr. Brazell has expressed a concern that the Company has not been clear 4 with the Commission and the other parties in this case regarding its 5 request related to MISO transition expenses. 4

7 Q. WHAT IS THE COMPANY’S PRIMARY REQUEST REGARDING MISO 8 TRANSITION EXPENSES?

9 A. The Company’s primary request regarding MISO transition expenses is 10 that the Commission issue an accounting order permitting it to defer all 11 MISO-related transition O&M expenses incurred on or after January 1, 12 2011 as a Regulatory Asset. This is clearly explained in the filing the 13 Company made in Docket No. 39741 (which has been consolidated with 14 the instant docket) and in the supplemental direct testimony of Company 15 witness Lewis in this Docket.

17 Q. WHAT IS THE COMPANY’S ALTERNATIVE REQUEST REGARDING 18 MISO TRANSITION EXPENSES?

19 A. The Company’s alternative request is that it be allowed to include 20 $4 million of O&M expenses in base rates for costs associated with these 21 MISO transition expenses. This is explained in my direct testimony 22 starting on page 21, line 29 through page 22, line 7, in Mr. Lewis’ Brazell Direct at 23, line 12.

Entergy Texas, Inc. Page 7 of 55 Rebuttal Testimony of Michael P. Considine Docket No. 39896

1 supplemental direct testimony starting on page 4, line 16 through page 5, 2 line 7 and in Company Adjustment 16L, WP/P AJ 16.20 through WP/P AJ 3 16.23.

5 Q. WHY DOES MR. BRAZELL BELIEVE THAT THE COMPANY HAS NOT 6 BEEN CLEAR REGARDING ITS PROPOSED AND ALTERNATIVE 7 TREAMENT OF MISO TRANSITION EXPENSES?

8 A. Mr. Brazell states that he was unaware that the Company’s $111.8 million 9 rate increase request included the $4 million amortization of MISO 10 transition expenses until my deposition.5 He states that he has reviewed 11 various documents, including the documents I reference above, which 12 discuss MISO transition expenses but was not made fully aware of the 13 Company’s proposed and alternative recommendations regarding MISO 14 transition expenses. 6 15 Contrary to Mr. Brazell’s testimony, my direct testimony and 16 workpapers make clear that the $4 million for MISO transition expenses is 17 included in the Company’s proposed rate increase, but will be withdrawn 18 in the event that deferred accounting is allowed. My direct testimony sets 19 out that all the “adjustments” therein represent items that are either 20 included in or excluded from the Company’s cost of service.7 Adjustment 21 16, to include an amortized recovery of MISO transition expense, is Id. at 22, line 13. Id. at 20, lines 15-20 and at 22 lines 1-14.

Considine Direct at 13, lines 11-16.

Entergy Texas, Inc. Page 8 of 55 Rebuttal Testimony of Michael P. Considine Docket No. 39896

1 therefore defined in my testimony as part of the Company’s request. This 2 is further supported by the explanatory discussion of the adjustment, 3 which states that the adjustment will be “withdrawn” if deferred accounting 4 is authorized.8

6 Q. PLEASE DISCUSS MR. BRAZELL’S CONCERN THAT THE COMPANY 7 “HAS BEEN LESS THAN FORTHCOMING”9 WHEN ADDRESSING ITS 8 REQUEST RELATED TO MISO TRANSITION EXPENSES.

9 A. Mr. Brazell refers to what he characterizes as a footnote in the workpaper 10 to Schedule P, Adjustment 16L of the Rate Filing Package, and includes a 11 quote in his testimony as if it is directly from this “footnote.” 10 His quote 12 states “ETI is not seeking base rate recovery of these costs in this filing 13 because all the costs have not yet been incurred.”11 From this quote, Mr. 14 Brazell concludes that ETI expressly represented that it was not including 15 the MISO transition expenses in its request.

16 The quote Mr. Brazell is referring to is included in the Company’s 17 explanatory description of the adjustment included on page WP/P AJ 18 16.23 in the filing package, and takes the form of full text discussion, not a 19 footnote. The actual quote from the workpaper reads: “The Company is 20 not seeking rate base treatment of these costs in this filing because all the 21 costs have not yet been incurred.” Mr. Brazell inverted the words “rate” RF Page WP/P AJ 16.23.

Brazell Direct at 23, line 13. Id. at 23, line 14. Id. at 23, line 15.

Entergy Texas, Inc. Page 9 of 55 Rebuttal Testimony of Michael P. Considine Docket No. 39896

1 and “base,” which completely and erroneously alters the intent and 2 meaning of the Company’s explanation.

3 The difference between the use of the words base rate and rate 4 base is significant. The proposed treatment in this filing (which will be 5 withdrawn upon grant of deferred accounting) allows the Company to 6 recover most of these costs as they are being incurred.12 The Company 7 made clear that it is not seeking “rate base” treatment (i.e., include the 8 unamortized balance of MISO transition expenses in rate base and earn a 9 return) because under this alternative treatment the Company would be 10 recovering most of the expenses as they are incurred, such that it would 11 be reasonable to forgo the recovery of carrying costs on the unamortized 12 balance. This explanation is fully consistent with the inclusion of the MISO 13 expense in the Company’s proposed base rate increase.

15 Q. HAVE YOUR READ MR. BRAZELL’S DEPOSITION THAT WAS TAKEN 16 APRIL 4, 2012 IN THIS DOCKET?

17 A. Yes.

WP/P AJ 16.23, SCHED_COS_WP_7-139.

Entergy Texas, Inc. Page 10 of 55 Rebuttal Testimony of Michael P. Considine Docket No. 39896

1 Q. DID HE MAKE ANY ACKNOWLEDGEMENTS OR CONCESSIONS 2 DURING HIS DEPOSITION REGARDING THE COMPANY’S MISO 3 ADJUSTMENT?

4 A. Yes. Mr. Brazell acknowledged a number of issues in his deposition that 5 are pertinent to his discussion of the Company’s MISO transition 6 adjustment. First, he acknowledged that he had not reviewed my direct 7 testimony.13 Second, he acknowledges that adjustments included in 8 Schedule A-3 either include or exclude expenses from the cost of 9 service.14 Third, he acknowledges that he made an error in using the term 10 “base rate” instead of “rate base” in his discussion of the Company’s 11 Adjustment 16L.15 Lastly, he acknowledges that if the Company had not 12 included the $4 million alternative amortization in its initial rate filing that it 13 could not have included it in the cost-of service after the initial rate filing 14 had been made.16

Brazell deposition at 91, lines 11-16.

Brazell deposition at 91, line 17 through page 92 line 24.

Brazell deposition at 95, line 25.

Brazell deposition at 100, lines 17-21.

Entergy Texas, Inc. Page 11 of 55 Rebuttal Testimony of Michael P. Considine Docket No. 39896

1 Q. DID ANY OF THE OTHER INTERVENOR OR STAFF WITNESSES 2 EXPRESS MR. BRAZELL’S CONCERN THAT THE COMPANY’S 3 REQUEST REGARDING MISO TRANSITION EXPENSES WAS NOT 4 CLEAR?

5 A. No. Mr. Garrett, to whom Mr. Brazell refers,17 does not express this 6 concern and in fact his testimony accurately describes the Company’s 7 proposed and alternative request regarding MISO transition expenses.18 8 Mr. Pollock and Mr. Joe Luna also accurately describe the Company’s 9 request in their direct testimony.19

11 Q. CAN YOU ADDRESS MR. GARRETT’S AND MR. POLLOCK’S 12 RECOMMENDATION REGARDING THE COMPANY’S ALTERNATIVE 13 MISO TRANSITION EXPENSE ADJUSTMENT SHOULD THE 14 COMMISSION DENY THE COMPANY’S REQUEST FOR DEFERRED 15 ACCOUNTING?

16 A. Both Mr. Garrett and Mr. Pollock recommend that ETI be allowed to 17 include only the test year level of expenses related to MISO transition 18 expenses. The primary reason for their recommendation of the test year 19 level of expenses is because they do not believe that the MISO transition 20 costs are known and measurable.

Brazell Direct at 24, line 9.

Garrett Direct at 61, line 15 through 62, line 9.

Pollock Direct at 45, line 7 through 46, line 9.

Entergy Texas, Inc. Page 12 of 55 Rebuttal Testimony of Michael P. Considine Docket No. 39896

1 These costs are known and measurable. The $4 million that the 2 Company has included in this filing is a conservative estimate of the 3 amount of costs that the Company will incur during its transition to MISO.

4 During the nine months since the end of the test year through March 2012, 5 the Company has incurred approximately $3.6 million in MISO transition 6 expenses as shown on Exhibit MPC-R-1. On an annualized basis, this 7 would be $4.8 million. Mr. Lewis will further address the issue of future 8 MISO transition expenses in his rebuttal testimony.

10 Q. PLEASE ADDRESS MR. LUNA’S RECOMMENDATIONS IN THIS 11 DOCKET.

12 A. Mr. Luna indicated that his direct testimony would address issues 6, 7 and 13 8 that were identified in the Commission’s Preliminary Order, dated 14 December 19, 2011 in this docket.20 He is not providing testimony on the 15 Company’s request to defer MISO transition expenses. I will address 16 issues 6 through 8 and Mr. Luna’s recommendation regarding each of 17 these issues below.

18 Issue 6 - What amount of expenses, if any, related to analyzing and 19 planning for a transition to a regional transmission organization is included 20 in Entergy’s requested cost of service? If an amount is included, how is 21 Entergy proposing to recover these costs? If so, should such expenses 22 be recovered in Entergy’s base rates?

24 The Company’s primary request is that it be allowed to defer costs 25 related to analyzing and planning for a transition to a regional transmission Luna Direct at 4, lines 15 through Page 5, line 4.

Entergy Texas, Inc. Page 13 of 55 Rebuttal Testimony of Michael P. Considine Docket No. 39896

1 organization (“MISO transition expenses”) it has incurred on or after 2 January 1, 2011. The mechanics of any transition expense recovery is 3 proposed to be determined in a future rate proceeding. Company 4 witnesses Lewis and Perlman further discuss this deferral issue in their 5 testimonies.

6 In the alternative, should the Commission deny the Company’s 7 deferred accounting request, the Company has included MISO transition 8 expenses in its requested cost-of-service (“COS”). The Company’s 9 alternative recommendation regarding MISO transition expenses incurred 10 on or after January 1, 2011, has included $4 million in COS expenses 11 related to MISO transition expenses that are estimated to be incurred over 12 a three-year period beginning January 1, 2011.21 13 The Company has also included in COS expense, amortization of 14 $52,782 in MISO transition expenses and $137,232 in rate base for 15 capitalized MISO transition expenses incurred during the time period July 16 1, 2010 through December 31, 2010 (the first six months of the test 17 year).22 In the Company’s instant application it is seeking to defer these 18 MISO related transition expenses incurred during the first six months of 19 the test year and to recover them over a five-year period.23 20 The Company is proposing to include the MISO transition expenses 21 incurred on or after January 1, 2011 in base rates should the Commission RF Page WP/P AJ 16.23. $211,126 in MISO transition expenses less $73,894 in deferred Federal Income Taxes.

RF Page WP/P AJ 16.21 – WP/P AJ 16.22.

Entergy Texas, Inc. Page 14 of 55 Rebuttal Testimony of Michael P. Considine Docket No. 39896

1 deny the Company’s proposed deferred accounting. The Company’s 2 MISO transition expenses incurred during the first six months of the test 3 year are requested to be included in base rates as part of the instant 4 proceeding.

5 This is the only issue that Mr. Luna addresses in his direct 6 testimony. He recommends removing all of the amounts discussed above 7 from the COS. He has not proposed a recovery mechanism for these 8 expenses and his recommendation in effect disallows the Company any 9 opportunity to recover these expenses should the Commission deny the 10 Company’s deferral request. He does not discuss the reasonableness or 11 necessity of these expenses and he does not express an explicit opinion 12 as to whether or not MISO transition expenses should be recovered 13 through base rates or through some other mechanism.

14 At a minimum, Mr. Luna should have included the Company’s test 15 year level of expenses in base rates should the Commission deny the 16 Company’s request for deferred accounting.

17 Issue 7 – What amount, if any, related to analyzing and planning for a 18 transition to a regional transmission organization were in Entergy’s books 19 during the test year? Were any such amounts removed from the test year, 20 and if so what were those amounts? Are any such amounts included in 21 the costs for which Entergy seeks deferral in Docket No. 39741?

22 During the test year, the Company recorded $916,535 on its books 23 for MISO related transition expenses.24

See WP/P AJ 16.21.

Entergy Texas, Inc. Page 15 of 55 Rebuttal Testimony of Michael P. Considine Docket No. 39896

1 The $916,535 was removed from the test year expenses. See 2 discussion above regarding Issue 6 for a further description of how the 3 Company is requesting to treat pre- and post- January 1, 2011, transition 4 expenses.

5 $652,627 of the $916,535 identified above is included in the costs 6 for which Entergy seeks deferral in Docket No. 39741.25 7 Issue 8 – Has Entergy made any adjustments for costs related to 8 analyzing and planning for a transition to a regional transmission 9 organization incurred outside of the test year, and if so, what is the 10 amount and how is Entergy proposing to recover such costs?

11 As discussed above in Issue 6, the Company’s primary request is 12 to defer costs related to MISO transition expenses incurred on or after 13 January 1, 2011. Should the Commission deny the Company’s deferred 14 accounting request, the Company’s alternative recommendation includes 15 these costs in base rates through an amortization of transition expenses 16 which will be incurred during the transition period. The Company has 17 included $3,347,373 in the COS for expenses incurred outside of the test 18 year through its $4 million amortization adjustment.26 As noted above, 19 Exhibit MPC-R-1 shows that the Company has incurred approximately 20 $3.6 million in MISO transition expenses in the nine months since the end 21 of the test year.

See WP/P AJ 16.21 ($32,173+$620,454=$652,627). ($4,000,000-$652,627=$3,347,373).

Entergy Texas, Inc. Page 16 of 55 Rebuttal Testimony of Michael P. Considine Docket No. 39896

1 Q. PLEASE SUMMARIZE YOUR RESPONSE TO THE CONCERNS ABOUT 2 MISO TRANSITION EXPENSES EXPRESSED BY THE VARIOUS 3 PARTIES.

4 A. The Company’s proposed deferred accounting treatment and its proposed 5 alternative recommendation regarding MISO transition expenses are 6 clearly set out in this filing. This concern expressed by Mr. Brazell 7 regarding the MISO transition expenses should not be given any weight by 8 the Commission when reviewing the Company’s deferred accounting 9 request. Should the Commission deny the Company’s proposed deferred 10 accounting request, then it is appropriate to include the Company’s 11 proposed alternative recommendation to include $4 million in MISO 12 transition expenses in its rate request as a known and measurable 13 adjustment to test year expense.

15 C. Hurricane Rita Regulatory Asset Q. WHAT ISSUES DO YOU ADDRESS IN THIS SECTION OF YOUR 17 REBUTTAL TESTIMONY?

18 A. I will address concerns regarding ETI’s Hurricane Rita Regulatory Asset 19 expressed by Mr. Garrett and Ms. Givens.

Entergy Texas, Inc. Page 17 of 55 Rebuttal Testimony of Michael P. Considine Docket No. 39896

1 Q. HAVE YOU REVIEWED MR. GARRETT’S TESTIMONY REGARDING 2 THE HURRICANE RITA REGULATORY ASSET AS DESCRIBED ON 3 PAGES 11 AND 12 OF HIS DIRECT TESTIMONY?

4 A. Yes. Mr. Garrett claims that ETI was required to amortize the regulatory 5 balance presented in the Company’s last rate case, Docket No. 37744.

6 As a result, he contends that the asset should be reduced from its current 7 level of $26,229,627 to $10,714,557 effectively requiring the Company to 8 write off the difference of $15,515,070.

10 Q. DO YOU AGREE WITH MR. GARRETT’S POSITION REGARDING THE 11 REGULATORY ASSET?

12 A. No. There was no instruction in the Stipulation and Settlement Agreement 13 or the Final Order filed in Docket No. 37744 that states that ETI was to 14 begin amortizing this Rita Regulatory Asset, or otherwise directing the 15 treatment of the asset. Furthermore, the settlement agreement in Docket 16 No. 32097 (the case in which the level of recoverable Hurricane Rita costs 17 was identified) provided that the level of insurance credited against these 18 costs would be “trued up to reflect the difference between the $65.7 million 19 credited and all insurance payments actually received by the Company 20 related to Hurricane Rita for Texas Retail.” Moreover, this settlement 21 provided that carrying costs would apply to the true-up amount “until such 22 trued-up amount (plus associated carrying costs at the rate of 7.9% per 23 annum) is recovered in base rates.” ETI’s request to include the full

Entergy Texas, Inc. Page 18 of 55 Rebuttal Testimony of Michael P. Considine Docket No. 39896

1 Hurricane Rita regulatory asset in base rates here is consistent with the 2 provisions of the settlement that specifically apply to it.

4 Q. REGARDLESS OF THE FACT THAT YOU DISAGREE WITH MR. 5 GARRETT’S OPINION ON THE AMORTIZATION OF THE 6 REGULATORY ASSET, HAVE YOU REVIEWED THE PROPOSED 7 CALCULATION MR. GARRETT SUPPORTS IN EXHIBIT MG2.3?

8 A. Yes.

10 Q. DO YOU HAVE ANY CORRECTIONS OR CONCERNS WITH MR. 11 GARRETT’S CALCULATION IN EXHIBIT MG2.3?

12 A. In the event that his position were to prevail, which it should not, I have 13 two corrections to Mr. Garrett’s calculation. First, Mr. Garrett has 14 incorrectly assumed that the $26,229,627 Regulatory Asset does not 15 include the $5,678,960 the Company received in additional Hurricane Rita 16 insurance proceeds since the Docket No. 37744 filing. The $5,678,960 17 the Company received in additional Hurricane Rita insurance proceeds 18 since Docket No. 37744 is included in the $46,013,904 shown on WP/P 19 AJ 15.3 and the Company’s rate filing package (referring to WP/P AJ 15.3) 20 clearly shows that the $46,013,904 of insurance proceeds received is a 21 component of the $26,229,627. Mr. Garrett’s adjustment for this $5.6 22 million would remove the amount a second time from the regulatory asset

Entergy Texas, Inc. Page 19 of 55 Rebuttal Testimony of Michael P. Considine Docket No. 39896

1 balance. Accordingly, this amount should not be removed a second time 2 as Mr. Garrett does on Line 9 of Exhibit MG-2.3.

3 Secondly, even if Mr. Garrett’s assumption that the Company was 4 required to amortize this balance were true, the Company would not have 5 incurred 22.5 months of amortization at the time of the filing. Mr. Garrett 6 calculates the amortization period to be from the time rates went into 7 effect as a result of Docket No. 37744 (August 15, 2010) through the time 8 revised rates are to go into effect in this docket (June 30, 2012).

9 Effectively, Mr. Garrett is making post-test year adjustments for rate base 10 items. Again, assuming Mr. Garrett’s assumption that the Company was 11 allowed to amortize this Regulatory Asset were true, it would be 12 appropriate to amortize the Asset for 10.5 months only (August 15, 2010 13 through June 30, 2011). These two corrections adjust Mr. Garrett’s 14 Exhibit MG2.3 remaining regulatory asset balance from $10,714,557 to 15 $21,805,940. Please see my Exhibit MPC-R-2.

17 Q. DOES ANY OTHER WITNESS DISCUSS MR. GARRETT’S 18 CALCULATION OF THE HURRICANE RITA REGULATORY ASSET?

19 A. Yes. Cities’ witness Mr. Jacob Pous is recommending that the balance be 20 added to and amortized in the storm reserve over twenty years.

Entergy Texas, Inc. Page 20 of 55 Rebuttal Testimony of Michael P. Considine Docket No. 39896

1 Q. DO YOU AGREE WITH THIS RECOMMENDATION?

2 A. No. Securitization, which is the explicit reason for the creation of the 3 Regulatory Asset, is intended to provide the Company with cost recovery 4 in an expedited manner. Mr. Pous’ recommendation would extend the 5 recovery over a twenty year period, which is clearly contrary to the 6 objective of securitization.

8 Q. PLEASE DISCUSS MS. GIVENS’ TESTIMONY WITH REGARD TO THE 9 HURRICANE RITA REGULATORY ASSET?

10 A. Ms. Givens testifies that it is reasonable to assume that the Hurricane Rita 11 regulatory asset was considered as part of the settlement in Docket No. 12 37744 and because PURA 36.402(c) requires the Company to request 13 recovery in its next base rate proceeding, Docket No. 37744, the 14 Company isn’t allowed to do so in this proceeding. She recommends that 15 the entire regulatory asset be removed from rate base.

17 Q. DO YOU AGREE WITH MS. GIVENS’ OPINION?

18 A. No. As I explained above, there was no instruction in the Stipulation and 19 Settlement Agreement or the Final Order filed in Docket No. 37744 that 20 states that ETI was to begin amortizing this Hurricane Rita Regulatory 21 Asset, or otherwise directing the treatment of the asset. Moreover, as 22 previously explained, the Docket No. 32907 settlement does specifically 23 address the treatment of this asset and supports the Company’s position.

Entergy Texas, Inc. Page 21 of 55 Rebuttal Testimony of Michael P. Considine Docket No. 39896

1 Finally, PURA § 36.402(c) does not apply to Hurricane Rita costs. The 2 securitization provisions for Hurricane Rita are found in Chapter 39, 3 Subchapter J of PURA, not Chapter 36.27 4 Moreover, even erroneously assuming that Docket No. 37744 5 somehow resolved the recovery of the Hurricane Rita regulatory asset as 6 it was presented at that time, it still makes no sense to disallow the entire 7 asset. ETI did not seek recovery of the entire asset all at once at that 8 time, but instead recovery over a period of years through amortization. At 9 most, Ms. Givens’ erroneous reading of the settlement could relate to the 10 portion of the amortization that would result from Docket No. 37744, not 11 the entire amount of the asset.

13 Q. SHOULD THE FACT THAT ETI DID NOT AMORTIZE THE 14 REGULATORY ASSET FOLLOWING DOCKET NO. 37744 PRECLUDE 15 ETI FROM BEING ALLOWED TO RECOVER THESE COSTS?

16 A. No.

See, for example, PURA § 39.459(a)(1) (defining “hurricane reconstruction costs” as those related to Hurricane Rita).

Entergy Texas, Inc. Page 22 of 55 Rebuttal Testimony of Michael P. Considine Docket No. 39896

1 D. Pension Asset in Rate Base Q. MR. GARRETT STATES THAT ETI’S PENSION CONTRIBUTIONS IN 3 EXCESS OF SFAS 87 COSTS ARE DISCRETIONARY PAYMENTS.28 IS 4 THAT A TRUE STATEMENT?

5 A. No. ETI has made contributions to the pension fund in accordance with 6 contribution guidelines established by the Employee Retirement Income 7 Security Act of 1974, as amended, and the Internal Revenue Code of 8 1986, as amended. These contributions were fully within the range of 9 contributions deductible for tax purposes.

11 Q. IS THERE ANY OTHER GUIDANCE ETI USES TO DETERMINE THE 12 PENSION CONTRIBUTIONS?

13 A. Yes. The required pension contributions are also affected by guidance 14 pursuant to the Pension Protection Act of 2006 rules, effective beginning 15 with the 2008 plan year.

17 Q. MR. GARRETT IMPLIES THAT RATEPAYER BENEFITS ARE LIMITED 18 TO THE LEVEL PROVIDED BY THE ACTUAL PENSION FUND 19 EARNINGS. DO YOU AGREE?

20 A. No. Ratepayers benefit from contributions made to the pension fund.

21 ASC 715-30 (formerly FAS 87) pension cost included in COS includes the 22 expected rate of return on assets. The expected long-term rate of return Garrett at 8, Line 5.

Entergy Texas, Inc. Page 23 of 55 Rebuttal Testimony of Michael P. Considine Docket No. 39896

1 is 8.5%, not the actual earnings as implied by Mr. Garrett. While there are 2 market fluctuations that affect the value of the pension assets, Mr. 3 Garrett’s reference to the performance of the pension assets over the last 4 five years simply points out that the customer is receiving a benefit from 5 pension contributions 6 times greater (8.5% compared to 1.37% according 6 to Mr. Garrett) than the actual return on the funds during that period, and 7 Mr. Garrett's proposed adjustment to increase expenses to reflect the 8 benefit to customers from the return on these funds should similarly be 9 increased by a factor of more than 6.

11 Q. DOES THE COMPANY’S RATE BASE TREATMENT OF THE 12 CONTRIBUTIONS TO THE PENSION FUND IN EXCESS OF FAS 87 13 COST REPRESENT COMPANY-SUPPLIED FUNDS OR CUSTOMER- 14 SUPPLIED FUNDS?

15 A. The debit balance in the pension liability account represents the excess of 16 Company supplied funds above the amount of ASC 715-30 (formerly FAS 17 87) cost assumed to be recovered from customers and should earn the 18 Company’s requested return on rate base. This balance is no different 19 than other prepayments, which are included in rate base and earn a full 20 return on rate base. Furthermore, the Company would be allowed to earn 21 a full return on rate base had the Company invested these same dollars in 22 Plant in Service, but the Company in this case used funds to contribute to 23 a still under-funded pension plan and at the same time provided a timely

Entergy Texas, Inc. Page 24 of 55 Rebuttal Testimony of Michael P. Considine Docket No. 39896

1 reduction to ASC 715-30 (formerly FAS 87) annual pension cost 2 immediately benefitting ratepayers.

4 Q. DO YOU HAVE ANY OTHER COMMENTS REGARDING THIS ISSUE?

5 A. Yes. Should the Commission reject the Company’s position and instead 6 apply in this case the previous Commission ruling that distinguishes the 7 portion of the pension asset related to Construction Work in Progress 8 (“CWIP”) from the remainder of the asset, it should fully apply the effect of 9 that precedent. In Docket No. 33309, Finding of Fact 32, the Commission 10 concluded that “the pension prepayment asset of $112.4 million, less the 11 $22.79 million portion included in CWIP, should be included in rate 12 base.”29 However, following court litigation regarding the issue, the courts 13 reversed the Commission’s ruling and the Commission altered its 14 treatment on remand. In the remand proceeding, Docket No. 38772,30 the 15 Commission modified its treatment of the CWIP-related portion of the 16 asset, ruling in Finding of Fact 15A: “in accordance with P.U.C. SUBST. R. 17 25.72(g) the portion of the pension prepayment asset included in CWIP 18 shall accrue allowance for funds used during construction beginning as of 19 the date of the changed rates in this docket.” The CWIP-related portion of 20 the Company’s pension asset ($25,311,236 out of the total asset) should 21 receive the same treatment, should the Commission reject the Company’s Application of AEP Texas Central Co. for Authority to Change Rates.

Remand of Docket No. 33309 (Application of AEP Texas Central Company For Authority to Change Rates.

Entergy Texas, Inc. Page 25 of 55 Rebuttal Testimony of Michael P. Considine Docket No. 39896

1 primary position that the entire asset should be included in rate base as 2 Company supplied capital that reduces the pension costs otherwise 3 included in customer rates.

5 E. Property Insurance Reserve Q. MR. POUS HAS RECOMMENDED SEVERAL REDUCTIONS TO RATE 7 BASE FOR THE PROPERTY INSURANCE RESERVE. DO YOU AGREE 8 WITH HIS RECOMMENDATIONS?

9 A. No. Company witness Shawn Corkran will address Mr. Pous’ claims 10 regarding the 1997 ice storm; Company witness Greg Wilson addresses 11 the requested level of the storm accrual. I will address the balance of Mr. 12 Pous’ recommendations for reductions to the storm reserve balance.

14 Q MR. POUS OBJECTS TO THE $12,498,325 STORM RESERVE 15 RECLASSIFICATION AS A RESULT OF THE JURISDICTIONAL 16 SEPARATION OF EGSI INTO ETI AND EGSL. PLEASE EXPLAIN THIS 17 RECLASSIFICATION.

18 A. An analysis of the storm reserve charges was performed prior to the 19 jurisdictional separation to determine if the storm charges were incurred 20 for Louisiana or Texas property. The reclassification was made as a result 21 of this analysis to properly reflect the state in which the storm charges 22 were incurred. See page 25 of Exhibit MPC-R-3 for this analysis.

Entergy Texas, Inc. Page 26 of 55 Rebuttal Testimony of Michael P. Considine Docket No. 39896

1 Q. MR. POUS RECOMMENDS A $10.95 MILLION REDUCTION TO THE 2 RESERVE BALANCE FOR WHAT HE DEEMS TO BE A $50,000 3 DEDUCTIBLE, WHICH HE RETROACTIVELY APPLIED TO PAST 4 STORMS. IS THIS REDUCTION APPROPRIATE?

5 A. No. The $50,000 threshold has been consistently used by the Company 6 to designate a storm that will accumulate costs to be charged to the storm 7 reserve. A storm whose total costs are estimated to be less than $50,000 8 would be treated as normal O&M costs and not charged to the reserve.

9 This was never intended to be a “deductible” amount and is called “Major 10 Storm Damage Threshold” in Entergy’s current storm damage policy.

11 That policy is provided in the Company’s response to Cities’ RFI 6-2, 12 attached as my Exhibit MPC-R-3. The fact that these costs have been 13 charged to the reserve and not to O&M means these costs have never 14 been reflected in base rates. To retroactively make this adjustment as 15 proposed by Mr. Pous would be inconsistent with past base rate case 16 treatment and result in a permanent disallowance of these storms costs. If 17 such a policy change from a threshold to a deductible should be made, it 18 would need to be made on a prospective basis so that the amounts 19 charged to reserve and normal O&M would be reflected in the on-going 20 cost level.

Entergy Texas, Inc. Page 27 of 55 Rebuttal Testimony of Michael P. Considine Docket No. 39896

1 Q. HAVE YOU REVIEWED MR. POUS’ DEPOSITION IN THIS DOCKET?

2 A. Yes. During the line of questions asked of Mr. Pous regarding Docket No. 3 16705 and the rationale for adjusting for 219 storms since that time. Mr. 4 Pous seems to imply that the Company has a different storm damage 5 policy than was in place during the Docket No. 16705 test year.31

7 Q. CAN YOU PROVIDE EVIDENCE THAT THE SAME $50,000 8 THRESHOLD WAS A COMPONENT OF THE STORM DAMAGE POLICY 9 IN EFFECT FOR THE ENTIRE DOCKET NO. 16705 TEST YEAR?

10 A. Yes. Please refer to Exhibit MPC-R-4.

12 Q. DOES ANY ENTERGY COMPANY HAVE A DEDUCTIBLE?

13 A. Yes. Entergy Mississippi moves the first $250,000 charged to the reserve 14 each year to O&M expense as outlined in the “Storm Damage Deductible” 15 section of Entergy’s storm damage policy.

17 Q. MR. POUS CONTENDS THAT BY NOT HAVING A DEDUCTIBLE, 18 ENTERGY IS DOUBLE RECOVERING THE AMOUNTS. IS THIS TRUE?

19 A. No. The costs that are charged to the reserve are only recovered once 20 through the storm damage accrual. They are not also charged to O&M 21 expense to be recovered twice.

Pous, Docket No. 39896 deposition at 93-95.

Entergy Texas, Inc. Page 28 of 55 Rebuttal Testimony of Michael P. Considine Docket No. 39896

1 Q. MR. POUS RECOMMENDS RAISING THE MINIMUM THRESHOLD FOR 2 STORM RESERVE CHARGES TO $500,000 FROM $50,000. DO YOU 3 AGREE WITH MR. POUS’ RECOMMENDATION?

4 A. No. As I note above, the $50,000 storm minimum has been consistently 5 applied by the Company and there is no basis for a change. Furthermore, 6 the storm reserve charges at issue should be recovered in either O&M or 7 through the storm reserve. Mr. Pous’ recommendation, however, would 8 result in the recovery through neither of these avenues. If Mr. Pous’ 9 recommendation is adopted, then more of the Company’s storm costs will 10 be charged to normal O&M instead of the storm reserve. Mr. Pous does 11 not recommend the necessary increase to normal O&M for those storm 12 costs that are less than $500,000. By failing to do so, he is, again, 13 recommending no recovery at all of reasonable, actual storm-related 14 costs.

16 Q. HOW MUCH WOULD NORMAL O&M HAVE TO BE INCREASED TO 17 REFLECT MR. POUS’ RECOMMENDATION?

18 A. The test year level of storms under $500,000 that would be charged to 19 normal O&M instead of the storm reserve is $1,532,000. If Mr. Pous’ 20 recommended $500,000 minimum is adopted, O&M would need to 21 increase by $1,532,000.

Entergy Texas, Inc. Page 29 of 55 Rebuttal Testimony of Michael P. Considine Docket No. 39896

1 Q. MR. POUS AND OPUC WITNESS NATHAN BENEDICT BOTH SAY ETI 2 SHOULD HAVE REASONABLY ANTICIPATED THESE STORM COSTS.

3 DO YOU AGREE?

4 A. No. As shown on Exhibit MPC-R-3, the annual expenditures are 5 extremely variable. Moreover, they are unpredictable as to timing. As 6 such, the level of expenses could not reasonably be anticipated.

8 Q. MR. BENEDICT SAYS THAT SOME LEVEL OF MAINTENANCE 9 EXPENSE IS INCLUDED IN BASE RATES AND ONLY INCREMENTAL 10 AMOUNTS SHOULD BE CHARGED TO THE RESERVE. DO YOU 11 AGREE?

12 A. No. The Company has been consistent in charging all costs related to 13 major storm work to the storm reserve. Base rates reflected only costs 14 charged to normal O&M in a test year. This would not include the costs 15 charged to the storm reserve in the test year. If the costs related to major 16 storm work had not been charged to the storm reserve, base rates for 17 normal O&M expense would have been higher.

19 F. Payroll and Incentive Compensation Q. WHAT ISSUES DO YOU ADDRESS IN THIS SECTION OF YOUR 21 REBUTTAL TESTIMONY?

22 A. I will address issues raised by Mr. Garrett and Ms. Givens regarding 23 payroll.

Entergy Texas, Inc. Page 30 of 55 Rebuttal Testimony of Michael P. Considine Docket No. 39896

1 Q. PLEASE COMMENT FIRST ON MR. GARRETT’S PAYROLL 2 ADJUSTMENT.

3 A. Mr. Garrett states the Company’s proposed adjustment includes a wage 4 increase nine months after the test year but omits workforce changes and 5 changes in salary mix. The Company’s requested level of payroll began 6 with the test year payroll and was increased for known and measurable 7 changes in compliance with PUCT Substantive Rule 25.231(b). These 8 changes were for known wage increases stipulated in the bargaining 9 contracts and for a board approved non-bargaining wage increase 10 effective April 1, 2012. Rather than simply adjusting for known and 11 measurable changes to the Company’s test year historical expense, Mr. 12 Garrett also proposes applying a productivity statistic to determine 13 recoverable payroll expense.

15 Q. DOES MR. GARRETT’S PRODUCTIVITY ADJUSTMENT COMPLY WITH 16 SUBSTANTIVE RULE 25.231(b)?

17 A. No. His productivity adjustment is not a known and measurable change 18 specific to the Company’s test year payroll.

20 Q. WHY IS IT NOT KNOWN AND MEASURABLE TO THE COMPANY?

21 A. Mr. Garrett quotes national averages for productivity indices and assumes 22 they are reasonable and representative of the Company’s productivity. By

Entergy Texas, Inc. Page 31 of 55 Rebuttal Testimony of Michael P. Considine Docket No. 39896

1 the very nature of averages, some companies are much above and some 2 are much below the average.

4 Q. DOES MR. GARRETT PROVIDE ANY STUDIES THAT CONFIRM HIS 5 2.1% PRODUCTIVITY ADJUSTMENT IS APPLICABLE IN THIS CASE?

6 A. No. He has not provided any study to show that his percentage in any 7 way applies to the Company in this case.

9 Q. MR. GARRETT STATES THE COMPANY CHOSE TO UPDATE 10 PAYROLL FOR THE APRIL 1, 2012 INCREASE BUT DID NOT UPDATE 11 THE FILING FOR OTHER ITEMS SUCH AS ACCUMULATED 12 DEPRECIATION AND ACCUMULATED DEFERRED INCOME TAX. DO 13 YOU AGREE?

14 A. No. The Company has adjusted for known and measurable changes.

15 Rate base items such as those he references cannot, by rule, be updated 16 past the test year.

18 Q. DOES MR. GARRETT PROPOSE ANY OTHER CHANGES TO THE 19 COMPANY’S PAYROLL?

20 A. Yes. Mr. Garrett cites the Company’s response to Cities’ RFI 18-8(b), 21 which shows the 2010 base salary is 1.8% above the market median.

22 Based on this, he reduces the test year base payroll by 1.8%.

Entergy Texas, Inc. Page 32 of 55 Rebuttal Testimony of Michael P. Considine Docket No. 39896

1 Q. DO YOU AGREE WITH THIS ADJUSTMENT?

2 A. No. Company witness Kevin G. Gardner states on page 23 of his direct 3 testimony that “Towers Watson provides competitive analysis of the 4 Entergy Companies’ executive compensation to the market and support 5 for the Entergy Companies’ approach that a value between 90% and 6 110% of the median level of compensation is “at market.” In fact, Towers 7 Watson stated in its 2010 Competitive Compensation Analysis that 8 because of differing job duties, individual characteristics, and experience 9 levels, Towers Watson believes that a company's pay levels are 10 competitive if they fall between 85% and 115% of the marketplace”. Mr. 11 Garrett ignores the fact that Towers Watson considers “at market” to be a 12 10-15% spread from median. ETI was well within this spread and, 13 therefore, Mr. Garrett’s adjustment is not appropriate.

15 Q. DO YOU AGREE WITH MR. GARRETT’S PROPOSED PAYROLL 16 ADJUSTMENTS?

17 A. The Company’s payroll adjustment is the more appropriate approach to 18 establishing test year payroll expense, and Mr. Garrett’s recommendations 19 should be rejected.

21 Q. PLEASE COMMENT ON MS. GIVENS’ PAYROLL ADJUSTMENT.

22 A. I have reviewed her adjustment and, for the most part, I agree with her 23 findings. However, Ms. Givens used different headcounts for the end of

Entergy Texas, Inc. Page 33 of 55 Rebuttal Testimony of Michael P. Considine Docket No. 39896

1 the test year for ETI and ESI than are appropriate and included in my 2 payroll adjustment. The Company’s payroll adjustment reduced ETI 3 headcount to 675 and ESI headcount to 3,054. Ms. Givens’ adjustment 4 begins with end of the test year ETI headcount of 678 and ESI headcount 5 of 3,055 which caused a double counting of three ETI and one ESI 6 employee. These four employees are already reflected in my adjustment.

7 I also corrected an error in the ESI benefits calculation. Ms. Givens 8 inadvertently used the ETI percentage in the calculation rather than the 9 ESI percentage shown on her exhibit. I also do not agree with the 10 calculation of the savings plan adjustment or the calculation of the full time 11 equivalents.

13 Q. PLEASE EXPLAIN WHY YOU DO NOT AGREE WITH THE SAVINGS 14 PLAN LOADER CALCULATION.

15 A. Ms. Givens inappropriately applied both the benefits and savings plan 16 loader percentages to the headcount adjustment.

18 Q. HOW SHOULD THE SAVINGS PLAN LOADER BE CALCULATED?

19 A. The savings plan loader should not be calculated on the headcount 20 change because it is already included in the benefits loader rate and 21 should not be applied to the headcount change again.

Entergy Texas, Inc. Page 34 of 55 Rebuttal Testimony of Michael P. Considine Docket No. 39896

1 Q. HOW WOULD YOU CHANGE THE FULL TIME EQUIVALENT 2 CALCULATION?

3 A. Ms. Givens assumed that part time employee’s average salary is 50% of 4 the full time average salary. Responses to Cities’ RFI 12-6 and 12-7 allow 5 for the calculation of the actual part time average salary by providing the 6 test year wages and monthly headcounts. Ms. Givens relied on Staff RFI 7 7-4 for part time headcount, which consists of part time headcount of 35 8 and temporary employee headcount of 39 for a total of 74 instead of 73.

9 Exhibit MPC-R-3 is a correct calculation of full time equivalents.

11 Q. HOW DO THESE CHANGES AFFECT MS. GIVENS’ ADJUSTMENT?

12 A. Her ETI headcount adjustment (AG-7) has overstated her O&M payroll 13 reduction by $224,217. Her ESI headcount adjustment (AG-7) has 14 understated her O&M payroll increase by $37,531. Exhibit MPC-R-1 15 shows the ETI calculation and Exhibit MPC-R-2 shows ESI calculation.

17 Q. DO YOU AGREE WITH MS. GIVENS’ INCENTIVE COMPENSATION 18 PAYROLL TAX ADJUSTMENT?

19 B. No. She calculated FICA at 7.65% on the Staff adjustments to all 20 incentive plans. The executive plans (Executive Annual Incentive Plan, 21 Restricted Stock Incentive, Long-Term Incentive Plan, Restricted Share 22 and Equity Awards) include only highly compensated executives that are

Entergy Texas, Inc. Page 35 of 55 Rebuttal Testimony of Michael P. Considine Docket No. 39896

1 predominantly over the limit for the social security portion of FICA and are 2 only subject to the 1.45% Medicare component of FICA.

4 Q. HAVE YOU REVISED MS. GIVENS’ PAYROLL TAX ADJUSTMENT 5 CALCULATIONS?

6 A. Yes. I applied the entire 7.65% FICA rate to the non-executive incentive 7 plans (Management Incentive Plan, Exempt Incentive Plan, Teamshare 8 Incentive Plan, and the Teamshare Bargaining Incentive Plan) and only 9 the Medicare component (1.45%) on the executive plans. Ms. Givens’ ETI 10 payroll tax adjustment is overstated by $15,933 and is summarized in 11 Exhibit MPC-R-4. Ms. Givens’ ESI payroll tax adjustment is overstated by 12 $269,362 and is summarized in Exhibit MPC-R-5.

14 G. DSM Costs Q. OPUC WITNESS DR. CAROL SZERSZEN RECOMMENDS 16 DISALLOWING ONE HALF ($171,032) OF ETI’s PROJECT CODE 17 F3PPE9981S TEST YEAR COSTS BECAUSE SHE STATES THAT SHE 18 WAS UNABLE TO DETERMINE HOW MUCH OF THIS PROJECT’S 19 COSTS PERTAINED TO ENERGY EFFICIENCY, DSM, AND SUPPLY 20 SIDE INITIATIVES, WHICH SHE ASSERTS SHOULD BE RECOVERED 21 THROUGH THE COMPANY’S ENERGY EFFICIENCY COST 22 RECOVERY FACTOR RIDER (“EECRF”). DO YOU AGREE WITH THIS 23 ADJUSTMENT?

Entergy Texas, Inc. Page 36 of 55 Rebuttal Testimony of Michael P. Considine Docket No. 39896

1 A. No. As addressed in Company witness Phillip R. May’s rebuttal testimony, 2 this project code captures the cost of general activities of the Company’s 3 Integrated Energy Management department and are not included in the 4 Company’s EECRF rider. Because these are not costs that must be, or 5 are currently being recovered through the EECRF, they are not double 6 recovered and should be included in the Company’s cost of service.

8 H. MSS-2 Costs Q. PLEASE COMMENT ON CITIES’ WITNESS DENNIS W. GOINS’ MSS-2 10 ADJUSTMENT.

11 A. Mr. Goins recommends that the MSS-2 expense level in this docket be set 12 to the twelve months ended December 31, 2011 level of $4,370,600 and 13 then adjusted for load growth.32 Company witness Pat Cicio will discuss 14 the load growth adjustment that Mr. Goins proposes. I will address the 15 appropriate level of MSS-2 expense only.

17 Q. DO YOU AGREE WITH MR. GOINS’ MSS-2 ADJUSTMENT?

18 A. No. Mr. Goins’ recommended expense level is based on the twelve 19 months ended December 31, 2011 expense and as such does not 20 recognize a full year’s effect of ongoing equalizable transmission 21 investment or the change in responsibility ratios.

Goins HSPM WP/MSS-2-dg.xls.

Entergy Texas, Inc. Page 37 of 55 Rebuttal Testimony of Michael P. Considine Docket No. 39896

1 Q. IS THERE ANY OTHER INFORMATION THAT SUPPORTS YOUR 2 OPINION THAT THE TWELVE MONTHS ENDED DECEMBER 31, 2011 3 EXPENSE IS NOT APPROPRIATE TO USE IN CALCULATING THE 4 RATE YEAR LEVEL OF MSS-2 EXPENSE?

5 A. Yes. Mr. Goins’ own workpapers show that the monthly MSS-2 expense 6 has increased over 62% between January 2011 ($235,205) and 7 December 2011 ($624,352). This fact supports that the twelve months 8 leading up to the December 2011 expense level do not reflect a 9 reasonable MSS-2 expense level to include in the cost of service.

11 Q. HAVE YOU CALCULATED A MORE APPROPRIATE EXPENSE LEVEL 12 ASSUMING THE COMMISSION DOES NOT AGREE WITH THE 13 COMPANY’S PRO FORMA ADJUSTMENT FOR RATE YEAR MSS-2 14 EXPENSE?

15 A. Yes. It is more appropriate to set the MSS-2 expense level based on the 16 most current month’s expense times twelve, assuming the Commission 17 does not grant the Company’s original request. The February 2012 Intra- 18 System Bill (“ISB”) indicates that ETI had monthly MSS-2 expense of 19 $698,290; therefore, the annual MSS-2 expense that should be included in 20 the cost of service is $8,379,480.

Entergy Texas, Inc. Page 38 of 55 Rebuttal Testimony of Michael P. Considine Docket No. 39896

1 Q. IS THE COMPANY RECOMMENDING THE $8,379,480 MSS-2 2 EXPENSE LEVEL YOU HAVE CALCULATED?

3 A. No. It is appropriate to set the MSS-2 expense level in the docket to the 4 rate year level. As further explained by Company witness Mark McCulla, 5 this level is based on known and measurable equalizable transmission 6 investments that are appropriately included in the calculation of projected 7 MSS-2 expense and should be approved.

9 I. Nuclear Decommissioning Q. PLEASE COMMENT ON MR. GARRETT’S RECOMMENDATION TO 11 REDUCE THE ANNUAL REVENUE REQUIREMENT FOR THE 70% 12 REGULATED RIVER BEND NUCLEAR STATION FROM $2,019,000 TO 13 $1,126,000 AS PROVIDED IN THE COMPANY’S RESPONSE TO 14 CITIES’ RFI 10-22. DO YOU AGREE WITH THIS ADJUSTMENT?

15 A. No. First, the $2,019,000 stipulated in the Commission’s Final Order for 16 Docket No. 37744 was approved quite recently, on December 13, 2010.

17 Secondly, Mr. Garrett notes that PUCT Substantive Rule 25.231(b)(F)(i) 18 states that the annual cost of decommissioning for ratemaking purposes 19 must be determined and expressly included in the COS established by the 20 Commission’s order. Staff witness Slade Cutter’s testimony, however, 21 correctly points out that the Company is in compliance with this rule.33 22 The Company submits that the current $2,019,000 level of annual Cutter Direct at 6.

Entergy Texas, Inc. Page 39 of 55 Rebuttal Testimony of Michael P. Considine Docket No. 39896

1 decommissioning expense represents the most current information 2 reasonably available, based upon the August 9, 2011 Nuclear Regulatory 3 Commission letter (included in my direct testimony as Exhibit MPC-2), 4 which approves that amount as meeting the required minimum funding 5 criteria based on current funding level, length of time remaining on the 6 license, expected earnings on the trust fund, and future collections to the 7 trust fund. It should not be the policy of the Commission to inject volatility 8 into the rate of decommissioning expense recovery, which can impact the 9 minimum funding level based on fluctuations of calculation factors over 10 short periods of time.

12 Q. WHY DO YOU SAY THAT IT SHOULD NOT BE THE COMMISSION’S 13 POLICY TO INJECT VOLATILITY INTO THE ANNUAL RATE OF 14 DECOMMISSIONING EXPENSE RECOVERY?

15 A. Substantive Rule 25.231(b)(F)(iii) & (iv) notes that in the event a utility 16 does not file a rate case within a five year period (which the Company 17 has), the utility must perform a study or redetermination of the previous 18 study and file it with the Commission. The Company submits that this five 19 year requirement reflects the Commission’s recognition that a 20 normalization of decommissioning expense recovery over a reasonable 21 extended period of time is in the best interest of the customer by 22 normalizing the swings that otherwise might occur in more frequent 23 decommissioning expense requirement calculations.

Entergy Texas, Inc. Page 40 of 55 Rebuttal Testimony of Michael P. Considine Docket No. 39896

1 Q. WHAT DOES THE COMPANY RECOMMEND THE COMMISSION 2 ORDER REGARDING THIS MATTER?

3 A. Consistent with the position of Commission Staff, the Company 4 recommends that the Commission reject Mr. Garrett’s recommendation 5 and approve that the most recent Commission-approved level of annual 6 decommissioning expense remain unchanged at $2,019,000.

8 J. Depreciation Q. WHAT DEPRECIATION ISSUES WILL YOU ADDRESS IN THIS 10 SECTION OF YOUR REBUTTAL TESTIMONY?

11 A. I will address certain contentions presented by Mr. Pous in Section IV of 12 his direct testimony; 13 1. pages 7-8 regarding generating unit life span, 14 2. pages 39-45 regarding fully accrued depreciation, 15 3. pages 14-15 regarding positive net salvage on power plants, and 16 4. pages 25-26 regarding suggested problems with the Company’s 17 accounting procedure for the booking of cost of removal.

Entergy Texas, Inc. Page 41 of 55 Rebuttal Testimony of Michael P. Considine Docket No. 39896

1 Plant Lives Q. WHAT IS MR. POUS’ POSITION REGARDING GENERATING UNIT LIFE 3 SPAN?

4 A. Mr. Pous insinuates on page 7, lines 1-9 of his direct testimony that the 5 Company has routinely attempted to misstate the life expectancy of its 6 generating units. Mr. Pous bases his opinion on his representation of the 7 Company’s position in two rate cases.34

9 Q. IS MR. POUS WRONG IN HIS REPRESENTATION?

10 A. Yes. The Company has always attempted to present its best estimate of 11 when generating units would be retired based on the facts and 12 circumstances every time it has filed a depreciation study with a rate 13 proceeding. In those situations where no depreciation study is presented 14 by the Company, it reports the retirement dates underlying the 15 depreciation rates in the case as last approved. There is nothing 16 nefarious in the Company’s practice in either regard. The Company 17 respects Mr. Pous’ ability to make his determinations of his estimated life 18 spans. It is unfair of Mr. Pous to not pay the Company the same due 19 respect regarding life spans, as it is always a contentious issue in every 20 regulatory proceeding without regard to the basis of either position.

21 Finally, the Company has proposed different plant retirement dates 22 for depreciation purposes in this proceeding than those previously PUCT Docket Nos. 16705 and 37744.

Entergy Texas, Inc. Page 42 of 55 Rebuttal Testimony of Michael P. Considine Docket No. 39896

1 proposed. For some units, the depreciation retirement dates are sooner 2 than previously presented, and for others the depreciation retirement 3 dates are further out that previously presented. None of the information 4 presented in this proceeding represents an attempt by the Company to 5 “underestimate the life spans for its various generating units”.35 What it 6 does represent is the Company’s best estimate of a responsible and 7 reasonable estimate of an uncertain event for a determination of when 8 depreciation expense should cease to be accrued on an asset. Mr. Pous 9 opposed only one of the several plant life spans proposed by the 10 Company (relating to the Sabine Plant Units 4 and 5).

12 Q. WHO IS PRESENTING INFORMATION TO SUBSTANTIATE THE 13 COMPANY’S PROPOSED RETIREMENT DATES FOR DEPRECIATION 14 PURPOSES?

15 A. An explanation of the basis for the Sabine Units’ retirement date and 16 impact of operating and maintaining generating units on the life span of 17 the Sabine Units is discussed in the rebuttal testimony of Company 18 witnesses Winfred W. Garrison and Cooper and their testimony supports 19 the Company’s position regarding the expected life span of the Sabine 20 Units for the determination of depreciation accruals.

Exhibit JP-1 at 7, line 3.

Entergy Texas, Inc. Page 43 of 55 Rebuttal Testimony of Michael P. Considine Docket No. 39896

1 K. Fully Accrued Depreciation Q. WHAT IS MR. POUS’ POSITION REGARDING FULLY ACCRUED 3 DEPRECIATION?

4 A. As I understand it, Mr. Pous has presented a new regulatory theory 5 claiming that there must be an exact matching of the level of depreciation 6 expenses recovered under previously authorized electric utility rates and 7 current revenues. His theory is that depreciation expenses, unlike other 8 expense items originally included in the determination of utility rates, are in 9 some way a permanent component of revenues from the moment electric 10 utility rates are set until such rates are re-determined in some future rate 11 case and if any item in plant in service remains in plant in service beyond 12 the point that its service value is fully amortized, depreciation expense 13 should continue to be accrued. Another way of stating his position could 14 be that Mr. Pous has determined that the setting of rates creates an exact 15 recovery mechanism that requires periodic true up. It is difficult to 16 determine which theory he is espousing. Regardless, Mr. Pous ultimately 17 erroneously concludes that ETI has reset its approved depreciation rates 18 to zero without regulatory approval.

19 What Mr. Pous has failed to recognize is that time passes and that 20 all costs change, as do all other factors that initially formed the 21 determination of historical electric utility rates. In addition, Mr. Pous has 22 presented an opinion that is not in concert with the Uniform System of 23 Accounts (“USoA”) as it is written.

Entergy Texas, Inc. Page 44 of 55 Rebuttal Testimony of Michael P. Considine Docket No. 39896

1 Q. WHY IS MR. POUS’ THEORY IN ERROR?

2 A. Depreciation is calculated and designed to reflect an asset’s loss in 3 service value over time. Ideally, that time period is the life span of the 4 asset being depreciated and the asset would neither be under-accrued at 5 the time it is retired nor over-accrued prior to its retirement. Estimates are 6 imperfect by their very nature. It is virtually impossible to precisely 7 determine what date units will be retired and what the cost of retirement 8 will be at that time. As such, estimates must be employed and periodically 9 revised as more information becomes available.

11 Q. WHAT IS SERVICE VALUE?

12 A. Service value is defined in the USoA as the original cost of plant less net 13 salvage. Net salvage is defined in the USoA the cost of removing plant 14 from service (“cost of removal”) less any proceeds realized upon its 15 disposition (“salvage”). When cost of removal exceeds salvage, net 16 salvage is negative, and when salvage exceeds cost of removal, net 17 salvage is positive. Once that service value has been fully amortized 18 through the application of the depreciation rate(s) most recently approved 19 by the regulator, there is no further loss in service value to be recognized 20 unless and until the regulator determines that other factors require further 21 evaluation. The other factors would be the incurred cost of removal

Entergy Texas, Inc. Page 45 of 55 Rebuttal Testimony of Michael P. Considine Docket No. 39896

1 versus the cost of removal underlying the depreciation rate and the 2 realized salvage versus the salvage underlying the depreciation rate.

4 Q. ARE THERE OTHER CONSIDERATIONS?

5 A. Yes. The Company constantly adds, removes, retires, and replaces 6 various assets and components of assets between rate cases. It does 7 not, however, defer the depreciation expense on the new plant additions 8 for future recovery, nor does it “unilaterally” continue to recognize 9 depreciation on assets where the service value has been fully 10 depreciated. Neither accounting procedure is appropriate for purposes of 11 recording depreciation expense.

13 Q. HAS THE COMPANY CONSISTENTLY ADHERED TO THE PRINCIPLE 14 THAT DEPRECIATION CEASES ONCE THE SERVICE VALUE OF 15 ASSETS ARE FULLY AMORTIZED?

16 A. Yes. That has been the Company’s policy for as long as I am aware.

18 Q. DO ANY OF ENTERGY’S OTHER REGULATORS ADHERE TO 19 MR. POUS’ POSITION ON THIS ITEM?

20 A. Not that I am aware of. In fact, APSC General Staff witness Ms. Gayle 21 Freier stated on page 24, lines 3 through 5 of her direct testimony in the 22 recent APSC Docket No. 09-084-U, “For ratemaking purposes, 23 depreciation expense should not be calculated on any account with a

Entergy Texas, Inc. Page 46 of 55 Rebuttal Testimony of Michael P. Considine Docket No. 39896

1 reserve ratio equal to or exceeding 100% unless the account has a 2 negative salvage value.” In that section of her testimony she was 3 discussing the calculation of depreciation expense on 22 accounts that 4 were fully amortized. Of the 22 accounts Ms. Freier identified, Entergy 5 Arkansas had stopped depreciating 20 prior to the date of filing (some as 6 early as 2005).

8 Q. WHAT RECENT EVENTS HAVE OCCURRED TO MAKE THIS ISSUE 9 RELEVANT TO ETI?

10 A. Two things have occurred. First, ESI put into place a new fixed-asset 11 accounting system in 2005 that enables ESI and the Entergy Operating 12 Companies to automate processes previously handled manually, such as 13 stopping the recording of depreciation expense when service value is fully 14 amortized. The second thing that occurred is that three accounts became 15 fully amortized since ETI’s last rate case. Neither of these things is 16 abnormal, nor do they change any company policy concerning 17 depreciation.

19 Q. ARE THE COMPANY’S ACTIONS IN ANY MANNER CONTRARY TO 20 ANY ORDERS OR REQUIREMENTS OF THE PUCT?

21 A. Not at all. The Company has continued at all times to observe the 22 Commission approved depreciation rates and to accrue depreciation 23 expense consistent with Commission rules and the FERC USoA.

Entergy Texas, Inc. Page 47 of 55 Rebuttal Testimony of Michael P. Considine Docket No. 39896

1 Q. IS THERE ANYTHING ELSE THE COMMISSION SHOULD CONSIDER 2 ON THIS MATTER?

3 A. Yes. First, depreciation expense accruals are only suspended so long as 4 the account is fully amortized. In other words, if a subsequent addition 5 occurs to the account in the future, depreciation will begin to be accrued 6 anew even though that item is not “in base rates” through the application 7 of approved depreciation rates. The Company does not defer that 8 depreciation until the next rate case. Second, the Company’s depreciation 9 accounting is subject to independent external audit, and the Company’s 10 external auditors would not allow the Company to “unilaterally cease” 11 depreciation expense accrual if such action required regulatory approval; 12 nor would they allow ETI to “unilaterally” continue to accrue depreciation, 13 as suggested by Mr. Pous, without specific expressed regulatory approval.

15 Q. WHY WOULD THE COMPANY’S EXTERNAL AUDITORS REJECT AN 16 ATTEMPT BY THE COMPANY TO CONTINUE TO ACCRUE 17 DEPRECIATION EXPENSE ON FULLY DEPRECIATED ACCOUNTS?

18 A. It would be a violation of Generally Accepted Accounting Principles 19 (“GAAP”) to continue to record depreciation expense on items which are 20 fully depreciated. The external auditors must also present a CPA 21 Certification Statement at the beginning of the Company’s FERC Form 1 22 which should:

Entergy Texas, Inc. Page 48 of 55 Rebuttal Testimony of Michael P. Considine Docket No. 39896

1 a) Attest to the conformity, in all material aspects, of the 2 below listed (schedules and pages) with the Commission’s 3 applicable Uniform System of Accounts (including applicable 4 notes relating thereto and the Chief Accountant’s published 5 accounting releases).36 Q. HAS THE COMPANY VIOLATED ANY REGULATORY PRINCIPLE AS 8 SUGGESTED BY MR. POUS?

9 A. No. However, the refund of under-accrued depreciation expense as Mr. 10 Pous recommends would constitute retroactive ratemaking.

12 L. Net Salvage Q. WHAT IS MR. POUS’ POSITION REGARDING NET SALVAGE OF 14 EXISTING GENERATING UNITS?

15 A. Mr. Pous has suggested that negative salvage is inappropriate for existing 16 generating facilities. His recommendation is contrary to long standing 17 practice of the PUCT to provide for a negative salvage value that 18 represents terminal salvage of regulated utility generating units. I will not 19 address the general issue of negative salvage as that will be addressed by 20 Company witness Dane A. Watson. What I will address is the suggestion 21 in Mr. Pous’ testimony on pages 14-15 that the Company received a 22 “substantial positive net salvage”37 due to the retirement of Neches Station 23 and Nelson Generating Units 1 and 2 and those transactions are a 24 reasonable representation of probable future events.

Instructions for filing FERC Form Nos. 1 and 3-Q, Paragraph III, (d) a).

Direct Testimony of Mr. Pous, page 14 line 24.

Entergy Texas, Inc. Page 49 of 55 Rebuttal Testimony of Michael P. Considine Docket No. 39896

1 Q. HAS MR. POUS PROVIDED ANY INFORMATION REGARDING THE 2 EVENTS SURROUNDING THE NECHES STATION GENERATING 3 UNITS?

4 A. He has not. Mr. Pous cites Neches Station on page 14, lines 24 and 25 of 5 his direct testimony but presents no specific information regarding the 6 facts surrounding that facility. A discussion of those specific facts, 7 however, is essential to understanding why the salvage associated with 8 the Neches Station provides no support for Mr. Pous’ position.

10 Q. WHAT ARE THE FACTS REGARDING THE FACILITY?

11 A. Neches Station was a generating station in Beaumont, Texas that was 12 built between 1926 (Unit 1) and 1959 (Unit 8). Units 1 and 2 (total 13 capacity 57 MW) were retired and dismantled in 1966 at no additional cost 14 to the customer or to the Company. The boiler for Unit 7 exploded in 15 1983. The Company subsequently retired that unit as a result of that 16 incident. The Company received an insurance reimbursement for that 17 facility. The insurance reimbursement was in excess of the net book value 18 of the entire station. The benefit of that insurance reimbursement above 19 the original cost of Neches Unit 7 was refunded to the customer through a 20 subsequent rate action. The remaining generating units were placed in 21 long term storage in 1985. The remaining units were demolished in 2002 22 and 2003 at a net cost of $14.491 million. The Company sought recovery

Entergy Texas, Inc. Page 50 of 55 Rebuttal Testimony of Michael P. Considine Docket No. 39896

1 of the negative salvage costs through amortization in PUCT Docket No. 2 34800.

4 Q. DOES THIS FACT PATTERN SUPPORT MR. POUS’ CONTENTION?

5 A. No. It is unreasonable to predicate a positive salvage value based on a 6 boiler explosion, particularly when customers received the benefit of the 7 excess insurance reimbursement, and the Company ultimately incurred a 8 considerable cost for dismantling the Neches Station facility. These facts 9 are obviously quite unique and atypical, and not indicative of normally 10 recurring retirement activity.

12 Q. WHAT ARE THE FACTS REGARDING NELSON UNITS 1 AND 2?

13 A. Nelson Units 1 and 2 were situated adjacent to an industrial complex, and 14 thus uniquely situated to enable industrial customers near the site to form 15 a joint venture that would acquire two of the units at Nelson Station (83% 16 depreciated at the time) to convert into a co-generation facility. Those 17 facilities were substantially reconfigured (converted to a Fluidized Bed 18 Combustion heat source) at the cost of the industrial participants in the 19 Joint Venture. The gain on the transaction was passed through to 20 customers in subsequent rate actions.

Entergy Texas, Inc. Page 51 of 55 Rebuttal Testimony of Michael P. Considine Docket No. 39896

1 Q. WOULD THIS UNIQUE SITUATION BE LIKELY TO OCCUR AGAIN?

2 A. I do not know. However, such a unique set of circumstances has not 3 repeated itself at any of ETI’s facilities in the last 24 years. Nor has such 4 a set of circumstances ever occurred at any Entergy Operating Company 5 facility other than the two Nelson units. Lastly, what I do know from 6 internal discussions is that the units were largely depreciated and 7 inoperable without significant modification (such as the modification 8 performed by the Joint Venture participants) and that most of the benefits 9 of the transaction were passed on to customers. It would be wrong in my 10 opinion to suggest that the Nelson situation is likely to recur or suggest 11 that it is reasonable to base a decision on whether to reflect negative 12 salvage in the production depreciation rates on the unique circumstances 13 of the Nelson 1 and 2 generating units.

15 M. Accounting For Removal Costs Q. WOULD YOU SUMMARIZE YOUR UNDERSTANDING OF MR. POUS’ 17 STATEMENTS ON PAGES 25-25 OF HIS DIRECT TESTIMONY?

18 A. Mr. Pous is suggesting that the Company’s books and records 19 inappropriately reflect the amounts of cost of removal incurred due to the 20 removal of distribution assets on projects where both additions to and 21 removals from plant in service are the purpose of the project.

Entergy Texas, Inc. Page 52 of 55 Rebuttal Testimony of Michael P. Considine Docket No. 39896

1 Q. HOW DOES THE COMPANY RECORD COST OF REMOVAL OF 2 DISTRIBUTION FACILITIES ON ITS BOOKS AND RECORDS WHEN 3 PROJECTS INCLUDE BOTH ADDITIONS TO AND REMOVALS FROM 4 PLANT IN SERVICE?

5 A. The Company allocates the incurred costs of such projects between 6 installation and removal based upon estimates prepared by engineers 7 using the Company’s Distribution Information System (“DIS”). The 8 process of developing those estimates, including the development of “as 9 built” estimates is discussed in the rebuttal testimony of Company witness 10 Corkran.

12 Q. HOW DOES THE ALLOCATION PROCESS WORK?

13 A. Costs are aggregated on work orders in the Company’s accounting 14 systems and allocated between cost of removal and installation based on 15 the original estimated cost of the project until the project’s completion.

16 This ensures that the costs are reasonably reflected on the books in 17 FERC Accounts 107 (CWIP) and 108 (Accumulated Provision for 18 Depreciation as Retirement Work in Progress (“RWIP")). Upon completion 19 of the work request, the construction department enters field changes into 20 DIS’s AsBuilt screen after which DIS runs the final estimate which the 21 accountants refer to as an “as built estimate” that reflects actual items 22 installed and a standard cost of adding and removing the particular items 23 added and removed. The reason it is an estimate is because, primarily

Entergy Texas, Inc. Page 53 of 55 Rebuttal Testimony of Michael P. Considine Docket No. 39896

1 due to timing, the per unit rates in the estimate may not reflect the actual 2 hourly labor rates, transportation rates, or material costs. For instance, 3 the hourly labor rate standard may be $30 per hour whereas the individual 4 who performed the work would be a higher or lower rate than the 5 standard.

6 Upon completion and receipt of the as built estimate into the 7 Company’s PowerPlant accounting system, the Company reflects a final 8 allocation of the actual non-material costs to installation and removal, 9 using the allocation percentages provided by the estimated non-material 10 costs. Material amounts and indirect costs such as AFUDC, Store Costs, 11 and Construction overheads are added to the amount of non-material 12 costs allocated to installation, and the installation costs are then closed to 13 plant in service. The residual calculated amount composed of direct labor, 14 labor loaders, transportation and transportation loaders is added to 15 remaining indirect costs accrued in RWIP and transferred to the reserve 16 by plant account. For instance, the estimated non-material costs on the 17 project discussed in the testimony of Company witness Corkran resulted 18 in a final ratio of the costs of roughly 86% to installation and 14% to 19 removal. This is before assignment of indirect costs such as construction 20 overheads, AFUDC, and Store Costs and Associated Stock (FERC 21 Account 163) or the inclusion of material costs in the total CWIP amount.

22 The final result was as follows:

Entergy Texas, Inc. Page 54 of 55 Rebuttal Testimony of Michael P. Considine Docket No. 39896

1 As built estimate: 2 CWIP $48,081 93% 3 RWIP $3,410 7% 4 Actual Cost including overheads: 5 CWIP $54,552 96% 6 RWIP $2,546 4% 7 The slight differences are driven by the addition of construction overheads 8 and AFUDC.

10 Q. DO THE DIFFERENCES SUGGEST TO YOU THAT SOME FLAW 11 EXISTS IN THE PROCEDURE FOR ALLOCATION OF COSTS 12 BETWEEN INSTALLATION AND REMOVAL?

13 A. No. The differences between the as built estimate provided by the DIS 14 and the final amounts booked to the Company’s property accounts reflect 15 the addition of AFUDC and other construction overhead allocation 16 amounts. Those would be difficult to determine with any degree of 17 accuracy in a construction estimating system and would not drive the 18 results Mr. Pous suggests in his testimony. The process is driven by 19 experts in estimating the activities for installing and removing distribution 20 utility property and there is no reason to believe that the accounting 21 process would result in amounts that were not representative of the actual 22 costs to remove distribution utility property.

Entergy Texas, Inc. Page 55 of 55 Rebuttal Testimony of Michael P. Considine Docket No. 39896

1 Q. DOES THIS CONCLUDE YOUR REBUTTAL TESTIMONY?

2 A. Yes.

Exhibit MPC-R-1 Docket No. 39896 Page 1 of 1 Entergy Texas, Inc. MISO Transition Expenses July 2011 through March 2012

Expenses by Account Account and Description Jul-11 Aug-11 Sep-11 Oct-11 Nov-11 Dec-11 Jan-12 Feb-12 Mar-12 Totals 4031AM - Deprec Exp billed from Serv Co 12,584 17,439 (759) 5,274 7,248 7,931 3,065 7,192 6,904 66,879 408110 - Employment Taxes 7,042 5,127 4,574 5,353 4,470 5,582 3,888 4,884 5,887 46,808 500000 - Oper Supervision & Engineerin 773 962 1,062 386 (128) 516 (11) (115) 171 3,616 506000 - Misc Steam Power Expenses 1,001 1,836 569 3,406 556000 - System Control & Load Disp. 267 1,292 1,066 115 3 34 7 2,784 557000 - Other Expenses 31 (9) 749 36 276 435 146 (261) (99) 1,305 560000 - Oper Super & Engineering 2,553 367 81 715 130 50 (63) 124 3,955 561000 - Load Dispatching 138 (270) 134 2 561200 - Load Dispatch- transm system 1,943 (730) 1,129 472 531 152 518 (171) 488 4,331 561300 - Load disptch-transm serv & sch 334 4 64 146 548 566000 - Misc. Transmission Expenses 728 6,018 (169) 74 1,460 4,768 (3,863) 240 9,257 575100 - Regional Energy Mkts-Oper Supv (16,713) (888) 0 17 2 (17,583) 909000 - Information & Instruct Adv Ex 103 90 (35) 745 (78) (670) 304 458 920000 - Adm & General Salaries 128,451 83,682 76,235 90,436 73,950 119,792 62,735 86,326 92,317 813,925 921000 - Office Supplies And Expenses 16,869 26,316 (5,178) 9,024 16,083 16,989 2,732 3,096 4,664 90,594 923000 - Outside Services Employed 384,449 264,867 80,933 428,767 (112,530) 1,059,754 (4,757) 72,756 78,906 2,253,145 924000 - Property Insurance Expense 3,313 (398) (0) 2,915 926000 - Employee Pension & Benefits 50,975 30,600 27,857 30,403 28,107 41,683 18,669 30,508 32,455 291,257 928000 - Regulatory Commission Expense 4,023 5,326 1,375 766 1,860 20,906 819 (3,228) 39 31,885 930100 - General Advertising Expenses 4,596 6,120 551 838 242 135 12,482 930200 - Miscellaneous General Expense 34 34 Totals 603,221 447,559 189,894 572,044 20,964 1,276,976 92,681 196,121 222,544 3,622,005

Expenses by Project Project and Description Jul-11 Aug-11 Sep-11 Oct-11 Nov-11 Dec-11 Jan-12 Feb-12 Mar-12 Totals F3PPETIMIS - MISO Transition ETI costs 156,365 145,437 101,245 89,188 44,993 320,545 (32,977) 62,528 50,690 938,014 F3PPRTOICE - O&M ICT Transition Costs 2,556 17,957 20,512 F3PPSPE018 - SPO VP of Strategic Initiatives 3,379 4,412 4,039 1,827 1,297 3,654 214 (74) 79 18,826 F3PPTDERSD - MISO Transition ALL OPCO 471,149 297,712 84,283 481,029 (25,326) 952,680 125,444 131,111 153,804 2,671,886 F5PPSPE044 - PMO Support Initiative-System-wide (30,244) (1) (40) 0 (30,284) F5PPSPPCBA - ICT/RTO Cost Benefit Analysis Sty 2,572 367 98 15 3,051 Totals 603,221 447,559 189,894 572,044 20,964 1,276,976 92,681 196,121 222,544 3,622,005

The above costs are Entergy Texas, Inc. MISO transition expenses which have been incurred and recorded on the books for the nine months since the end of the June 30, 2011 Test Year in in Docket No. 39896.

Page 1 of 1 Docket No. 39896 Exhibit MPC-R-1 Exhibit MPC-R-2 Docket No. 39896 Page 1 of 1 ENTERGY TEXAS, INC. ADJUSTMENT TO RITA REGULATORY COSTS IN RATE BASE TEST YEAR ENDED JUNE 30, 2011 DOCKET NO. 39896

LINE DESCRIPTION REF. AMOUNT 1 Rita Regulatory Asset Balance in Pro Forma Rate Base (Docket 39896) Sch P, P.19, L.23 $ 26,229,627 AJ15.2 2 Annual Amortization in Cost of Service Sch P, P.27, L.4 $ 5,245,925 3 Rita Regulatory Asset Balance in Pro Forma Rate Base (Docket 37744) AJ15.8 $ 25,278,210 4 Amount Amortized after Dk. 37744 (Aug 15, 2010 - June 30, 2011) 10.5 Months $ 4,423,687 5 Remaining Balance after Amortization [Line 1 - Line 4] $ 21,805,940

Exhibit MPC-R-3 Docket No. 39896 Page 1 of 25 ENTERGY TEXAS, INC. PUBLIC UTILITY COMMISSION OF TEXAS SOAH DOCKET NO. XXX-XX-XXXX PUC DOCKET NO. 39896 - 2011 ETI Rate Case Response of: Entergy Texas, Inc. Prepared By: Steve Bridges to the Sixth Set of Data Requests Sponsoring Witness: Michael P. Considine of Requesting Party: Cities Beginning Sequence No. Ending Sequence No. Question No.: Cities 6-2 Part No.: Addendum: Question: In reference to Schedule B-1, line 7, Property Insurance Reserve, $59,799,744, please provide the following information: a. The annual Property Insurance Reserve balance by year for the period 2000 through 2010; b. The amount of Hurricane Ike charges included in the Property Insurance Reserve; c. A copy of the Company’s current written policy explaining when costs may be charged to the Property Insurance Reserve; d. A list of all charges, showing amounts and date of charges, made to the Property Insurance Reserve as a result of the implementation of the Jurisdictional Separation Plan, along with a complete explanation as to why such charges should be made to the Property Insurance Reserve.

Response: a. Please see the attached schedule of reserve balances and activity from June 30, 1996 to June 30, 2011.

b. The Hurricane Ike charges in the storm reserve as of June 30, 2011 are ($6,054,297).

c. Please see the attached.

d. Please see the attached schedule.

39896 CITIES 6-2 BB272 ENTERGY TEXAS, INC. DOCKET NO. 39896 ETI COS 6/30/11 CITIES 6TH SET QUESTION 2 (a) Exhibit MPC-R-3 STORM RESERVE ACTIVITY AND BALANCES FROM 6/30/96 - 6/30/11 Docket No. 39896 Page 2 of 25

ORDERED BEGINNING ADJUSTMENTS ENDING DATE BALANCE ACCRUALS CHARGES NOTE 5 OTHER NOTE BALANCE

6/30/96 (12,074,581) 7/1/96-12/31/96 (12,074,581) (1,374,246) (421,088) (66) 4 (13,869,981) 1997 (13,869,981) (2,748,492) 13,470,336 294,332 4 (2,853,805) 1998 (2,853,805) (2,748,492) 9,473,714 2,834,702 (47,499) 4 6,658,620 1999 6,658,620 (1,650,996) 1,943,786 10,867 4 6,962,277 2000 6,962,277 (1,650,996) 2,525,929 (4) 4 7,837,205 2001 7,837,205 (1,650,996) 3,572,550 145,560 4 9,904,319 2002 9,904,319 (1,650,996) 3,611,751 17,127 4 11,882,201 2003 11,882,201 (1,650,996) 2,224,744 928 4 12,456,877 2004 12,456,877 (1,650,996) 1,914,249 329 4 12,720,459 2005 12,720,459 (1,650,996) 181,422,456 192,491,919 2006 192,491,919 (1,650,996) 55,695,163 (205,518,030) 2 41,018,056 2007 41,018,056 (1,650,996) 24,724,965 (11,901,675) 2 52,190,350 2008 52,190,350 (1,650,996) 266,962,880 12,498,325 1 330,000,559 2009 330,000,559 (3,699,996) 96,050,815 (362,068,336) 6 60,283,043 2010 60,283,043 (3,699,996) (368,762) 3,457,091 3 59,671,376 1/1/11-6/30/11 59,671,376 (1,849,998) 1,978,366 59,799,744

NOTE 1: Correction of state balances due to analysis during JSP split.

NOTE 2: Adjustments to remove Storm Securitization and Insurance recoveries from the reserve.

NOTE 3: Adjustment to Insurance recoveries recorded in 2009.

NOTE 4: Other adjustments.

NOTE 5: Docket 16705 ordered reserve accrual adjustment back to 6/1/96 (6/1/96-12/31/98--31mos * 91,442) 2,834,702 NOTE 6: Adjustments to remove Storm Securitization and Insurance recoveries from the reserve for ($355,289,136) and to record the effects of the Texas Storm Securitization Settlement booked in August 2009 for ($6,779,200) for IKE.

39896 CITIES 6-2 BB273 Exhibit MPC-R-3 Docket No. 39896 Page 3 of 25

I. POLICY SUMMARY • This Policy provides rules for the reporting of major storm damage expenditures for Entergy’s regulated Legal Entities including the corporate functions supporting them. • All employees, agents and contractors of Entergy shall immediately report known, suspected or potential violations of this Policy by following the procedures described in the Reporting Violations Policy. • Please refer to the following detailed Policy for further information.

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II. DETAILED POLICY 1.0 PURPOSE AND APPLICABILITY The purpose of this Policy is to establish a uniform set of rules for the reporting of major storm damage expenditures for the Entergy Corporation regulated Legal Entities (i.e., EAI, EGSL, ELL, EMI, ENOI, & ETI) with significant production, transmission, distribution, general plant, and/or related information technology (IT) facilities. This Policy will also provide the framework to ensure that storm project charges and storm reserve charges are accurate and that the appropriate internal accountabilities are established.

This Policy applies to any and all employees of any Entergy System Company, unless otherwise expressly excluded, as well as agents and contractors of any Entergy System Company. For purposes of this paragraph, Entergy System Company shall mean Entergy Corporation and all of its subsidiaries and affiliates in which Entergy Corporation has a direct or indirect majority ownership in such subsidiary or affiliate.

For employees covered by a collective bargaining agreement, the applicable collective bargaining agreement will govern to the extent it conflicts with this Policy.

Nothing contained in this Policy should be construed to suggest that employees of a particular subsidiary or affiliate of Entergy Corporation are also employees of Entergy Corporation or any other affiliate or subsidiary of Entergy Corporation.

Moreover, this Policy does not create any employment relationship between any person and any Entergy System Company.

2.0 REFERENCES & CROSS REFERENCES 39896 CITIES 6-2 BB275 Exhibit MPC-R-3 Docket No. 39896 Page 5 of 25

2.1 The following policies should be read in conjunction with this Policy: 2.1.1 Entergy Accounting Policies • Capital Funding Project Approval Policy • External Job Order Policy 2.1.2 Entergy System Policies • Code of Entegrity • Reporting Violations 3.0 DEFINITIONS

3.1 Incremental Costs – For EMI only, defined by the Mississippi Public Service Commission as, “those costs incurred for restoring service….that are beyond the normal costs the Company would have incurred absent the event.” Incremental Costs include incremental labor, transportation, and material costs. Normal costs would include, for example, compensation for normal workdays, including normal overtime, for those working on restoration, their transportation costs, and meals. Loaned Labor from other Legal Entities to EMI is considered incremental labor.

3.2 Legal Entity– Refers to Entergy’s direct and indirect subsidiaries. The term is equivalent to PeopleSoft’s standard term “business unit” for accounting purposes.

3.3 Major Storm Damage Threshold – A Storm Event with combined O&M and capital repair costs estimated to be $50,000 or more per occurrence for a particular Legal Entity, except for EMI (see Section 3.6). Also, for ENOI, there are additional requirements that will be reported and maintained by Property Accounting. (The details of these requirements can be obtained by request from Property Accounting.) When storm damage is sustained to production, distribution, transmission, general 39896 CITIES 6-2 BB276 Exhibit MPC-R-3 Docket No. 39896 Page 6 of 25

plant, and/or related IT facilities, a combined cost for all functions within the Legal Entity affected should be used to estimate the $50,000 threshold amount.

3.4 Policy – this Storm Damage Policy.

3.5 Property Insurance Account For Storm Damage – Account at each Legal Entity that is used to capture the approved regulatory accrual for storm damage expenses (also known as the Storm Damage Reserve).

The offset for the accrual is captured in a Property Insurance expense account (i.e., FERC Account 924).

3.6 Storm Damage Deductible – For EMI only, on an annual basis the initial $250,000 of incremental storm damage costs that will be absorbed by the Company. Once the annual deductible has been met, EMI incremental storm damage costs may be applied against the Property Insurance Account for Storm Damage 3.7 Storm Damage Work Order - Term used to refer to Storm Work Orders and Storm Expense Work Orders collectively.

3.8 Storm Expense Work Order – A Work Order used to accumulate all O&M costs for all functions other than distribution lines (e.g. transmission, gas, substations, IT).

3.9 Storm Event – Hurricanes, floods, tornadoes, ice storms, high winds or any other act of nature that causes extensive damage to Entergy’s production, transmission, distribution, general plant, and/or related Information Technology facilities in a particular Legal Entity (i.e., EAI, EGSL, ELL, EMI, ENOI, & ETI).

3.10 Capital Storm Work Order – A Work Order used to accumulate all costs (both O&M and Capital) for distribution lines storm damage and capital costs only for all other functions (e.g. transmission, gas, substations, IT). For Distribution Lines, Property Accounting will perform a monthly allocation to move O&M costs to the Property Insurance Account for Storm.

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3.11 Work Order – The accounting code block element or chart field for projects used to accumulate costs.

3.12 Catastrophic Event – A sudden event which causes significant damage to facilities in Entergy’s service territory (e.g. damage of the magnitude experienced by Hurricane Katrina, Hurricane Rita, and significant ice storms). This would include several storm project codes per function and typically would include more than one Legal Entity.

This classification of an event would be implemented at the discretion of the Chief Accounting Officer.

3.13 Resource Manager – Jurisdictional manager in charge of managing manpower and material resources for a jurisdiction.

3.14 Material Financial Impact – Storm impacting more than 5% of customers and/or having a repair estimate of $5 million or more in any jurisdiction. Items of material financial impact do not necessarily have to involve specifics related to finance. For example, an initial message reporting outage of the number of customers could require pre-approval of the CAO.

3.15 Storm Escrow Account – A dedicated “lock-box” account which is held in escrow for future storm events. Funds removed from this account may be used to reimburse Entergy for storm expenditures. The rules for when funds may be drawn vary by legal entity.

4.0 RESPONSIBILITIES- Attachment A has a comprehensive chart of accountabilities.

4.1 The Storm Incident Commander is responsible for making the decision to implement the storm process.

4.2 The Chief Accounting Officer is responsible for any external filings necessary related to the storm, sign off on any estimates for the event 39896 CITIES 6-2 BB278 Exhibit MPC-R-3 Docket No. 39896 Page 8 of 25

released externally, and sign off on any internal and external financial communications that directly or indirectly include a material financial impact related to storm. Other accountabilities of the CAO include: determining if a storm event will be classified as a catastrophic event, approving this policy and determining any exceptions to this policy.

4.3 The Distribution Operations Area (DOA) Director and the appropriate transmission, substation, general plant and IT managers are responsible for coordinating and providing the initial dollar estimate of the Storm Event in order to determine the need for Storm Damage Work Orders. They are also responsible for all related Work Orders.

4.4 Resource Managers are responsible for overseeing the review of Distribution charges to Storm Work Orders to determine the accuracy of these charges and to correct inaccurate charges.

4.5 Transmission, Substation, and IT managers are responsible for overseeing the review of their charges to their own Storm Damage Work Order as well as to Distribution Storm Work Orders, and for making corrections to charges, when appropriate.

4.6 Budget Analysts are responsible for obtaining chargeable Storm Damage Work Orders when the estimated dollar amount is expected to meet the Major Storm Damage Threshold. They are also responsible for monitoring charges to Storm Damage Work Orders and the timely closing of Storm Damage Work Orders for their respective groups.

4.7 The Property Accounting group is responsible for:

• issuing Storm Damage Work Orders and activating these work orders for charges when notified by Budget Analysts; • monitoring and reviewing the storm damage charges prior to 39896 CITIES 6-2 BB279 Exhibit MPC-R-3 Docket No. 39896 Page 9 of 25

moving the charges from the Storm Damage Work Order to the Property Insurance Account for Storm Damage; • reversing any non-qualifying charges to appropriate expense accounts; • providing reporting tools to the functional areas to assist in monitoring of storm charges; • providing the Tax Department with storm damage losses for use in tax-return preparation and tax planning; • application of the annual Storm Damage Deductible to EMI’s Incremental Costs; • running the monthly allocation for Distribution Lines to split costs between the reserve and capital; • accounting for reimbursement or recovery of storm damage charges, both capital and expense.

4.8 Jurisdictional Finance Directors are responsible for monitoring reserve expense accruals to ensure accuracy, for providing internal reporting of reserve balance information upon request and for providing annual budget to Legal Entity cost managers.

4.9 The Tax Department is responsible for the reporting of storm damage casualty losses based on information provided by Property Accounting and the DOA Directors to ensure proper recovery of tax benefits associated with storm damage.

4.10 Jurisdictional Finance Directors, in conjunction with the DOA Directors, Resource Managers and Budget Analysts, are responsible for training the appropriate functional area personnel in these policies and procedures. They are also responsible for forwarding and coordinating estimates on an as needed basis for storm estimates during a catastrophic event in conjunction with the Storm Incident Commander.

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4.11 External Reporting is responsible for recording the storm reserve accruals to the Property Insurance Account for Storm Damage.

4.12 Corporate Reporting is responsible for quarterly reporting requirements relating to large Storm Events that have a material impact on quarterly financial statements. They are also responsible for monitoring reserve accruals and reserve balances in conjunction with Regulatory Accounting, Jurisdictional Business Managers and Property Accounting. For EMI only, quarterly reports summarizing the accruals and charges to the Property Insurance Account for Storm Damage should be furnished to Regulatory Affairs for filing with the Mississippi Public Utilities Staff.

5.0 DETAILS 5.1 Charging Guidelines for typical storm 5.1.1 Project Codes- In the event of a storm, project codes typically will be distributed by each functional business unit. When setup, project codes should include the name of the storm. Property Accounting will then fill out the storm name in the major storm field in PowerPlant as part of the approval process. This will be the basis for all storm reporting.

5.1.2 Activity Codes- Attachment B has a listing of approved activity codes to be used during a storm. This attribute will only be used for internal tracking purposes.

5.1.3 Storm Work Orders and Storm Expense Work Orders should only be issued for the accumulation of cost associated with the restoration of storm damage when the total cost is expected to meet the Major Storm Damage Threshold. Should storm damage 39896 CITIES 6-2 BB281 Exhibit MPC-R-3 Docket No. 39896 Page 11 of 25

be incurred which will not meet the Major Storm Damage Threshold, the total cost should be charged against the responsible organization’s normal project codes (both capital and O&M, as appropriate). Damage costs are generally related to repair and replacement work associated with production, distribution, transmission, substations, general plant, and/or related IT facilities.

Examples of valid storm damage charges include: • All labor and material costs directly related to the restoration of production, distribution, transmission, general plant, and communication facilities, whether by replacement or repair. • All food, lodging, fuel and travel expenses associated with the restoration effort. • All Customer Service Center (CSC), Transmission Operations Center (TOC), Distribution Operations Center (DOC), and Transportation Department costs, above normal operating expenses, directly associated with the restoration effort. • Communications cost associated with the restoration effort. • Public safety announcements associated with the restoration effort. • Tool, equipment, and vehicle repair costs directly attributable to the restoration effort. • All incidental costs directly associated with the restoration effort.

Examples of invalid storm damage charges include: • Alcoholic beverages and tobacco products. • Purchases of any tools or equipment not specifically required for the restoration effort that will be used beyond the restoration effort unless these tools were purchased to replace tools or equipment lost in the storm.

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• Purchases of personal clothing, except under extraordinary circumstances. • Ramp up and mobilization costs when an event does not meet the major storm damage threshold amount. • Facility upgrades not specifically required for the restoration effort such as new carpeting on the second floor of a building with flooding on the first floor only. • Vegetation removal not specifically required for the restoration effort unless mandated by municipal or governmental authority. • Replacement labor cost for any operating area that has supplied construction and support personnel to the restoration effort.

5.1.4 Costs incurred for advance preparation of a Storm Event should be charged to the Legal Entity or entities expected to benefit from this advance preparation, including CSC charges. Storm Damage Work Orders should be credited with unused materials returned to the storerooms.

5.1.5 For all legal entities, valid charges may be recorded to the Storm Damage Work Order in order to meet the Major Storm Damage Threshold (or in the case of EMI the $250,000 annual Storm Damage Deductible). However, for EMI, only Incremental Costs may be applied against the Property Insurance Account for Storm Damage once the deductible has been met. This includes incremental labor, transportation, and non-capitalized material costs. For EAI, non-incremental straight-time payroll and payroll loaders may not be applied against the Property Insurance Account for Storm Damage. For all other legal entities, all valid O&M charges may be applied against the Property Insurance Account for Storm Damage once the threshold has been met. If the Major 39896 CITIES 6-2 BB283 Exhibit MPC-R-3 Docket No. 39896 Page 13 of 25

Storm Damage Threshold is not met, valid charges to the Storm Damage Work Order should be reversed and recorded against normal project codes (both capital and O&M, as appropriate). For EMI and EAI Distribution, budget analysts will work with Property Accounting to make any non-incremental cost adjustments needed.

5.2 Charging Guidelines for Catastrophic Event 5.2.1 Project Codes- In the event of a catastrophic event, all communications will occur via the IE StormNet, Inside Entergy, and any other communication avenue activated. When setup, project codes are to include the name of the catastrophic event. Property Accounting will then fill out the storm name in the major storm field in PowerPlant as part of the approval process. This will be the basis for all storm reporting.

5.2.2 Activity Codes- Attachment B has a listing of approved activity codes to be used during a storm. This attribute will only be used for internal tracking purposes.

5.2.3 Storm Restoration Activities – Storm Work Orders and Storm Expense Work Orders should only be issued for the accumulation of cost associated with the restoration of storm damage when the total cost is expected to meet the Major Storm Damage Threshold.

Should storm damage be incurred which will not meet the Major Storm Damage Threshold, the total cost should be charged against the responsible organization’s normal operating budgets (both capital and O&M, as appropriate). Damage costs are generally related to repair and replacement work associated with Production, distribution, transmission, substations, general plant, and/or related IT facilities.

Examples of valid storm damage charges include: 39896 CITIES 6-2 BB284 Exhibit MPC-R-3 Docket No. 39896 Page 14 of 25

• All labor and material costs directly related to the restoration of production, distribution, transmission, general plant, and communication facilities, whether by replacement or repair. • All food, lodging, fuel and travel expenses associated with the restoration effort; unless a Logistics code exists for the event. • All Customer Service Center (CSC) costs, Transmission Operations Center (TOC), Distribution Operations Center (DOC), and Transportation Department above normal operating expenses, directly associated with the restoration effort. • Communications cost associated with the restoration effort. • Public safety announcements associated with the restoration effort. • Tool, equipment, and vehicle repair costs directly attributable to the restoration effort. • All incidental costs directly associated with the restoration effort.