Public Utility Commission of Texas // City of Denton Operating as Denton Municipal Electric v. City of Denton Operating as Denton Municipal Electric // Cross-Appellee Public Utility Commission of Texas

ACCEPTED 15-25-00018-CV FIFTEENTH COURT OF APPEALS AUSTIN, TEXAS 5/14/2025 3:17 PM No. 15-25-00018-CV CHRISTOPHER A. PRINE CLERK IN THE COURT OF APPEALS FILED IN 15th COURT OF APPEALS FOR THE FIFTEENTH JUDICIAL DISTRICT AUSTIN, TEXAS AUSTIN, TEXAS 5/14/2025 3:17:02 PM CHRISTOPHER A. PRINE Clerk PUBLIC UTILITY COMMISSION OF TEXAS, Appellant, v. CITY OF DENTON, OPERATING AS DENTON MUNICIPAL ELECTRIC, Appellee.

On Appeal from the 459th District Court of Travis County, Texas The Hon. Maya Guerra Gamble, Presiding Judge, Cause No. D-1-GN-23-008974

BRIEF OF APPELLANT PUBLIC UTILITY COMMISSION OF TEXAS

KEN PAXTON JORDAN PRATT Attorney General of Texas Assistant Attorney General State Bar No. 24140277 BRENT WEBSTER [email protected] First Assistant Attorney General RALPH MOLINA JOHN R. HULME Deputy First Assistant Attorney General Special Counsel State Bar No. 10258400 AUSTIN KINGHORN [email protected] Deputy Attorney General for Civil Litigation Environmental Protection Division Office of the Attorney General KELLIE E. BILLINGS-RAY P.O. Box 12548, MC-066 Chief, Environmental Protection Austin, Texas 78711-2548 Division (512) 463-2012 | Fax: (512) 320-0911 ATTORNEYS FOR APPELLANT PUBLIC UTILITY COMMISION OF May 14, 2025 TEXAS ORAL ARGUMENT REQUESTED IDENTITY OF PARTIES AND COUNSEL Party Counsel Appellant Public Utility Commission Ken Paxton of Texas Attorney General of Texas Brent Webster First Assistant Attorney General Ralph Molina Deputy First Assistant Attorney General Austin Kinghorn Deputy Attorney General for Civil Litigation Kellie E. Billings-Ray Chief, Environmental Protection Division Jordan Pratt Assistant Attorney General [email protected] John R. Hulme Special Counsel [email protected] Office of the Attorney General of Texas Environmental Protection Division P.O. Box 12548 (MC-066) Austin, Texas 78711-2548 (512) 463-2012 | Fax: (512) 320-0911 ii Party Counsel Appellee City of Denton, Operating as Jose E. de la Fuente Denton Municipal Electric [email protected] Gabrielle C. Smith [email protected] Jamie L. Mauldin [email protected] Roslyn M. Warner [email protected] Lloyd Gosselink Rochelle & Townsend, P.C.

816 Congress Ave, Suite 1900 Austin, Texas 78701 (512) 322-5800 | Fax: (512) 472-0532

Intervenor Texas Industrial Energy Katherine L. Coleman Consumers [email protected] Michael A. McMillin [email protected] John R. Hubbard [email protected] O’Melveny & Myers, LLP Colorado St., Suite 2750 Austin, Texas 78701 (737) 261-8600 iii Party Counsel Intervenor Office of Public Utility Sharbel A. Sfeir Counsel [email protected] Justin Swearingen [email protected] Chris Ekoh [email protected] Office of Public Utility Counsel 1701 N. Congress Avenue Suite 9-180 Austin, Texas 78701 (512) 936-7500 | Fax: (512) 936-7525 iv TABLE OF CONTENTS IDENTITY OF PARTIES AND COUNSEL ........................................................... ii INDEX OF AUTHORITIES.................................................................................. viii GLOSSARY OF ACRONYMS AND TECHNICAL TERMS ............................. xiii STATEMENT OF THE CASE .............................................................................. xiv STATEMENT REGARDING ORAL ARGUMENT .............................................xv STATEMENT REGARDING CITATIONS ...........................................................xv ISSUES PRESENTED........................................................................................... xvi INTRODUCTION .....................................................................................................1 STATEMENT OF FACTS ........................................................................................2 I. Legal and regulatory background..........................................................2 A. The Commission sets wholesale transmission rates. ............................................................................................2 B. MOUs can select the debt service coverage method to calculate their rate of return. ......................................4 II. The Commission suspected Denton was overearning on its transmission rates and ordered Denton to file a comprehensive transmission rate application........................................6 III. The Commission processed Denton’s transmission rate application. .....................................................................................9 STANDARD OF REVIEW .....................................................................................13 SUMMARY OF THE ARGUMENT ......................................................................15 ARGUMENT ...........................................................................................................18 v I. The Commission’s conclusion to set Denton’s DSCR at 1.25x was supported by substantial evidence, regardless of whether the old or modified RFP is used. .............................................................................................................18 A. Commission Staff, OPUC, and TIEC all rebutted the presumption in the old RFP that an additional 0.25x of DSCR was reasonable. ..............................20 B. The Commission concluded that a DSCR of 1.25x provided Denton with a reasonable rate of return. ........................................................................................24 II. The Commission’s modification of the RFP was not a significant change requiring publication in the Texas Register before implementation. .........................................................27 A. The Commission properly modified the RFP. ..........................29 i. Even if the modification to the RFP were a significant change, Denton was not prejudiced because it was not published in the Texas Register. .....................................................35 B. The modified RFP applied to Denton’s amended application. ................................................................37 III. An alleged violation of the Open Meetings Act does not provide the basis for reversal of the Commission’s order adopting Denton’s rate of return. ...............................................39 A. The scope of judicial review is determined by the specific issues raised in the motion for rehearing at the Commission. ...................................................40 B. Even if Denton had preserved the alleged error, the Commission’s modification of the RFP did not violate the Open Meetings Act. ..........................................43 CONCLUSION ........................................................................................................46 vi PRAYER ..................................................................................................................47 CERTIFICATE OF COMPLIANCE .......................................................................49 CERTIFICATE OF SERVICE ................................................................................50 INDEX TO APPENDIX ..........................................................................................51 vii INDEX OF AUTHORITIES Cases Page(s) BFI Waste Sys. of N. Am., Inc. v. Martinez Env’t Grp., 93 S.W.3d 570 (Tex. App.—Austin [3rd Dist.] 2002, pet. denied).......................................................................................................... 40, 41 Burke v. Cent. Educ. Agency, 725 S.W.2d 393 (Tex. App.—Austin [3rd Dist.] 1987, writ ref’d n.r.e.) ...................................................................................................................40 Cent. Power and Light Co. v. Pub. Util. Comm’n of Tex., 36 S.W.3d 547 (Tex. App.—Austin [3rd Dist.] 2000, pet. denied).............................................................................................. 19, 25, 26, 28 Cities for Fair Util. Rates v. Pub. Util. Comm’n of Tex., 924 S.W.2d 933 (Tex. 1996) ..............................................................................24 Citizens Against Landfill Location v. Tex. Comm’n on Env’t Quality, 169 S.W.3d 258 (Tex. App.—Austin [3rd Dist.] 2005, pet. denied)..........................................................................................................14 City of Corpus Christi v. Pub. Util. Comm’n of Tex., 51 S.W.3d 231 (Tex. 2001).................................................................................19 City of Corpus Christi v. Pub. Util. Comm’n of Tex., 572 S.W.2d 290 (Tex. 1978) ..............................................................................24 City of El Paso v. Pub. Util. Comm’n of Tex., 883 S.W.2d 179 (Tex. 1994) ..............................................................................25 City of San Antonio v. Fourth Court of Appeals, 820 S.W.2d 762 (Tex. 1991) ..............................................................................44 Coal. for Long Point Pres. v. Tex. Comm’n on Env’t Quality, 106 S.W.3d 363 (Tex. App.—Austin [3rd Dist.] 2003, pet. denied).................................................................................................... 40, 41, 42 Combined Am. Ins. Co. v. Blanton, 353 S.W.2d 847 (Tex. 1962) ....................................................................... 20, 21 viii Dyer v. Tex. Comm’n on Env’t Quality, 646 S.W.3d 498 (Tex. 2022) ..............................................................................13 Etheridge v. Opitz, 580 S.W.3d 167 (Tex. App.—Tyler 2019 pet. dism’d) ......................................38 Ex parte Abell, 613 S.W.2d 255 (Tex. 1981) ..............................................................................37 EXLP Leasing, LLC v. Galveston Cent. Appraisal Dist., 554 S.W.3d 572 (Tex. 2018) ..............................................................................30 Gen. Motors Corp. v. Saenz, 873 S.W.2d 353 (Tex. 1993) ....................................................................... 20, 21 Heritage on San Gabriel Homeowners Ass’n v. Tex. Comm’n on Env’t Quality, 393 S.W.3d 417 (Tex. App.—Austin [3rd Dist.] 2012, pet. denied).......................................................................................................... 14, 15 Imperial Am. Res. Fund, Inc. v. R.R. Comm’n of Tex., 557 S.W.2d 280 (Tex. 1977) ................................................................. 18, 19, 35 Morath v. Lampasas Indep. Sch. Dist., 686 S.W.3d 725 (Tex. 2024) ..............................................................................30 Pantera Energy Co. v. R.R. Comm'n of Tex., 150 S.W.3d 466 (Tex. App.—Austin [3rd Dist.] 2004, no pet.) ........................38 Pub. Util. Comm’n v. GTE-Southwest, Inc., 901 S.W.2d 401 (Tex. 1995) ..............................................................................24 R.R. Comm’n of Tex. v. City of Austin, 524 S.W.2d 262 (Tex. 1975) ..............................................................................14 Rettberg v. Tex. Dep’t of Health, 873 S.W.2d 408 (Tex. App.—Austin [3rd Dist.] 1994, no writ)........................44 Suburban Util. Corp. v. Pub. Util. Comm’n of Tex., 652 S.W.2d 358 (Tex. 1983) ..............................................................................40 ix Sw. Bell Tel. Co. v. Pub. Util. Comm’n of Tex., 571 S.W.2d 503 (Tex. 1978) ........................................................... 19, 24, 28, 34 Tex. A & M Univ. v. Chambers, 31 S.W.3d 780 (Tex. App.—Austin [3rd Dist.] 2000, pet. denied).................................................................................................................20 Tex. Comm’n on Env’t Quality v. Friends of Dry Comal Creek, 669 S.W.3d 506 (Tex. App.—Austin [3rd Dist.] 2023, pet. denied).................................................................................................................15 Tex. Comm’n on Env’t Quality v. Maverick Cnty., 642 S.W.3d 537 (Tex. 2022) ....................................................................... 14, 29 Tex. Health Facilities Comm’n v. Charter Med.-Dall., Inc., 665 S.W.2d 446 (Tex. 1984) ..............................................................................15 Tex. Turnpike Auth. v. City of Fort Worth, 554 S.W.2d 675 (Tex. 1977) ..............................................................................46 TGS-NOPEC Geophysical Co. v. Combs, 340 S.W.3d 432 (Tex. 2011) ..............................................................................29 Willacy Cnty. Appraisal Dist. v. Sebastian Cotton & Grain, Ltd., 555 S.W.3d 29 (Tex. 2018).................................................................................30 Statutes Tex. Gov’t Code § 2001.145(a) ......................................................................................................40 § 2001.146(g) ......................................................................................................40 § 2001.174...........................................................................................................14 § 2001.174(2) ............................................................................................... 13, 18 § 2001.174(2)(F) .................................................................................................14 § 2001.175(e) ......................................................................................................14 § 2002.002...........................................................................................................31 § 311.023(1) ........................................................................................................30 § 312.002(a) ........................................................................................................30 § 551.041.............................................................................................................44 § 551.042(a) ........................................................................................................44 § 551.042(b) ........................................................................................................43 x Tex. Util. Code § 11.002(a) ............................................................................................................2 § 15.001...............................................................................................................13 § 35.004(d) ............................................................................................................3 § 39.151.................................................................................................................2 § 40.004(1) ............................................................................................................1 Rules & Regulations 16 Tex. Admin. Code § 22.80................................................................................................ 4, 30, 31, 35 § 25.192(b)(1) .......................................................................................................3 § 25.192(c) ......................................................................................................3, 19 § 25.192(c)(3) ................................................................................ 4, 5, 20, 25, 29 § 25.192(c)(5) .................................................................................................4, 31 § 25.192(h)(1) .......................................................................................................3 Other Authorities Jones on Evidence § 32 (2d ed.) ..............................................................................21 Public Utility Commission of Texas, Open Meeting Information and Agenda (Oct. 6, 2022), Texas Secretary of State: Open Meetings, https://texas-sos.appianportalsgov.com/rules-and- meetings?interface=VIEW_OPEN_MEETINGS_SUMMARY& recordId=249725 (accessed May 13, 2025). ......................................................45 Significant, Merriam-Webster Dictionary, https://www.merriam- webster.com/dictionary/significant (accessed May 13, 2025). ..........................31 Tex. Pub. Util. Comm’n, Application of Rayburn Country Electric Cooperative, Inc. to Change Wholesale Transmission Service Rates, Docket No. 52353 ......................................................................................7 Tex. Pub. Util. Comm’n, Application of Rayburn Country Electric Cooperative, Inc. to Change Wholesale Transmission Service Rates, Docket No. 52353 (Aug. 4, 2022), https://interchange.puc.texas.gov/search/documents/?controlNu xi mber=52353&itemNumber=41 (order remanding proceeding to docket management) ...........................................................................................33 xii GLOSSARY OF ACRONYMS AND TECHNICAL TERMS Term Meaning ALJ Administrative Law Judge City City of Denton Commission Public Utility Commission of Texas Denton City of Denton, operating as Denton Municipal Electric DSCR Debt Service Coverage Ratio ERCOT Electric Reliability Council of Texas MOU Municipally Owned Utility PFD Proposal for Decision OPUC Office of Public Utility Counsel Policy The City of Denton’s Debt Management Policy PUCT Public Utility Commission of Texas PURA Public Utility Regulatory Act RFP Rate-Filing Package SOAH State Office of Administrative Hearings TIEC Texas Industrial Energy Consumers TCOS Transmission Cost of Service xiii STATEMENT OF THE CASE Nature of the Underlying Plaintiff–Appellee City of Denton, operating as Case: Denton Municipal Electric (“Denton”), filed suit for judicial review of a Final Order of the Public Utility Commission of Texas (“PUCT” or “Commission”) setting the wholesale transmission rates for Denton.

Trial Court: The Honorable Maya Guerra Gamble, Judge of the 459th Judicial District Court, Travis County, Texas, sitting as the Presiding Judge for this case in the 459th Judicial District Court, Travis County, Texas.

Course of Proceedings The court reversed and remanded the Below: Commission’s final order, finding that it prejudiced the substantial rights of Denton.

Specifically, the court found the Commission’s decision to set Denton’s debt service coverage ratio (“DSCR”) at 1.25x was arbitrary and capricious and was improperly based on a Rate- Filing Package (“RFP”) that was modified in violation of state law (the Texas Open Meetings Act) and Commission Rule, thus violating both a statutory provision and required procedure.

Orders on Appeal: The trial court’s Final Judgement and Order, dated January 16, 2025. CR 60.

xiv STATEMENT REGARDING ORAL ARGUMENT The Commission respectfully requests oral argument. This case involves the complex statutory and regulatory scheme surrounding wholesale transmission rates and how the Commission sets a utility’s rate of return. Oral argument will provide an opportunity for the Commission to answer questions regarding its transmission rate application procedures to aid in the Court’s decision-making process.

STATEMENT REGARDING CITATIONS In this brief, citations to the Clerk’s Record will be in the following form: CR at [Page number]. Citations to the Supplemental Clerk’s Record will be in the following form: Suppl. CR at [Page number]. Citations to the Reporter’s Record will be in the following form: RR at [Page number]. Citations to the Administrative Record, which was admitted into evidence in the Reporter’s Record, will be in the following form: RR, AR [Item number] at [Page number]. All cited page numbers refer to the document’s original page numbers when practical. Otherwise, the PDF page number will be cited in the following form: RR, AR [Item number] at PDF [Page number].

xv ISSUES PRESENTED 1. Do any of the alleged errors in the PUCT’s Final Order prejudice Denton’s substantial rights such that the errors are reversible under the Administrative Procedure Act?

2. Does substantial evidence support the provision in the PUCT’s Final Order setting Denton’s DSCR at 1.25x?

3. Did Denton preserve error on the alleged violation of the Open Meetings Act?

xvi INTRODUCTION This case is an appeal of a Public Utility Commission of Texas (“PUCT” or “Commission”) order setting Denton Municipal Electric’s (“Denton”) transmission cost of service (“TCOS”) rates. These rates are paid by participants in the Electric Reliability Council of Texas (“ERCOT”) wholesale market to compensate Denton for the use of its transmission facilities interconnected with the ERCOT grid. The Commission sets these rates for all ERCOT transmission providers. Although the City of Denton (“City”) sets the retail rates for power that the utility charges its retail customers, the Commission sets the wholesale TCOS rates that are paid by all ERCOT utilities and thus recovered from all electric consumers in the ERCOT market. Tex. Util. Code § 40.004(1).

The Commission sets transmission rates to allow the utility to recover its reasonable and necessary expenses related to providing transmission service as well as a reasonable rate of return on transmission investment. Under the Public Utility Regulatory Act (“PURA”), the Commission has the discretion to set a utility’s rate of return as a question of fact. Under the Commission’s rules, a Municipally Owned Utility (“MOU”) can choose to calculate its rate of return based on the debt service coverage method. Applying this rule, the Commission set Denton’s Debt Service Coverage Ratio (“DSCR”) at 1.25x—the ratio required by Denton’s bonds—and concluded that this ratio provided Denton with a reasonable rate of return of 6.21%.

The evidence supports the Commission determination, and the district court erred in reversing it.

STATEMENT OF FACTS I. Legal and regulatory background A. The Commission sets wholesale transmission rates.

In 1975, in response to consumers being burdened by high electricity rates, the Texas Legislature enacted PURA to create a comprehensive regulatory scheme over the electric industry. PURA created the Commission and charged it with the general power to regulate and supervise the utilities within its jurisdiction to ensure that electricity rates were just and reasonable. Tex. Util. Code § 11.002(a).

This case involves specifically how transmission providers in ERCOT are compensated for the use of their transmission systems by electric consumers.1 Electricity travels across transmission lines owned by numerous utilities and other electric providers. Under PURA, all transmission-owning entities must provide “open access” to their transmission facilities for wholesale transmission. This allows electricity to freely flow across the electric grid without the need for individual contracts with transmission operators. The Commission sets transmission rates for all types of providers that participate in the ERCOT system: investor-owned

ERCOT refers to both the intrastate electric grid and the independent organization certified by the Commission under Tex. Util. Code § 39.151 to operate and maintain the intrastate electric grid.

transmission and distribution utilities, electric cooperatives, and municipalities.

These transmission rates are paid by other providers that use the transmission system and are passed on to all electric consumers in ERCOT.

The Commission calculates transmission rates based on the transmission provider’s TCOS, also known as the transmission revenue requirement. Tex. Util.

Code § 35.004(d). This allows providers to recover both the costs they incur in the management and maintenance of their transmission systems and an appropriate return on investment. Id. A utility’s revenue requirement is calculated using allowable expenses and the Commission-allowed rate of return. 16 Tex. Admin.

Code § 25.192(c). The Commission then sets an appropriate transmission rate based on a utility’s combined annual costs of transmission, divided by the total demand placed on the combined transmission systems of all transmission-owning utilities within the ERCOT region. Tex. Util. Code § 35.004(d). The data used for the annual costs of transmission and total demand is based on a test year that includes the average of ERCOT coincident peak demand for the months of June, July, August, and September. 16 Tex. Admin. Code § 25.192(b)(1). Additionally, utilities are permitted to file interim proceedings to add transmission investments into the utility’s rate base, but they retain the rate of return authorized under the comprehensive rate case. Id. § 25.192(h)(1).

Under Commission rules, the Commission is authorized to adopt “rate-filing requirements that provide additional details concerning the costs that may be included in the transmission costs and how such costs should be reported in a proceeding to establish transmission rates.” Id. § 25.192(c)(5). The Commission may require that utilities submit rate applications on standard forms and require that the applications contain all matters designated in, and substantially comply with, the standard form. Id. § 22.80. The Commission is authorized to modify the standard forms, but any “significant changes” must be published in the Texas Register before implementation. Id. Under this authority, the Commission adopted the Rate-Filing Package (“RFP”), which contains the instructions, requirements, and procedures for all transmission service providers to follow when submitting transmission rate applications with the Commission.

B. MOUs can select the debt service coverage method to calculate their rate of return.

By rule, the Commission provides multiple methods for an MOU to calculate its rate of return. Unlike investor-owned utilities, an MOU does not have equity shareholders and does not need to earn a traditional rate of return on its invested capital. However, an MOU does need sufficient return dollars over and above its actual operating expenses to meet its cash needs. Under the debt service coverage method, an MOU’s return can be based on its actual debt service obligations and a reasonable coverage ratio. 16 Tex. Admin. Code § 25.192(c)(3). In determining a reasonable coverage ratio, the Commission considers the coverage ratio stated in an MOU’s bond indentures or a ratio provided in a city ordinance. Id. The level of an MOU’s debt service coverage is the ratio of funds available to meet debt service requirements divided by the debt service requirements. RR, AR Item 112 at 9:6-7.

To calculate the rate of return under this method, the Commission takes an MOU’s historical test-year debt service, which consists of both interest and principal payments, adjusted for known and measurable changes, and multiplies it by a reasonable DSCR to reach the requirement for debt service and additional coverage.

Id. at 8:25-28. This means that the MOU’s full debt obligations are provided for plus additional coverage above its debt obligations as the equivalent of a return on investment for an investor-owned utility. For example, a DSCR of 1.25x provides for 100% of the MOU’s debt obligations plus an additional 25% of those debt obligations as an additional financial cushion. The Commission then reaches a percentage rate of return by dividing the total return dollars from the DSCR calculation by the rate base on a total company level. Id. at 9:1-2. This percentage is then applied to the rate base allocated to the transmission function to reach a return dollar amount in the MOU’s transmission revenue requirement.

II. The Commission suspected Denton was overearning on its transmission rates and ordered Denton to file a comprehensive transmission rate application.

Denton’s last comprehensive TCOS rate application was in 2005. In that case, Denton was awarded a 28.05% authorized rate of return on its invested capital. RR, AR Item 219 at 4. In the years following Denton’s 2005 rate case establishing its rate of return, Denton came before the Commission for numerous updates to its wholesale transmission rates to add additional transmission facility investment to its rate base. 2 During this time, Denton’s operational and financial circumstances changed significantly, with its transmission revenues increasing by thirteen times and its rate base growing by sixteen times. RR, AR Item 219 at 2. While the 28.05% authorized rate of return may have been appropriate when it was set in 2005 when Denton was a relatively small utility, by 2019, it was out of line with the returns approved for other comparable utilities in the state and the changes and growth in the intervening years to Denton’s operations. Id. The Commission suspected that Denton was overearning based on Commission Staff’s investigation into Denton’s 2019 earnings monitoring report, but outside of a comprehensive rate proceeding, the Commission is limited to reviewing only a small amount of financial information an MOU provides the

Denton has filed an interim TCOS application every year since 2014 (Docket Nos. 42770, 45071, 46348, 47900, 48963, 50110, 51345, 52449).

Commission in its annual earnings reports. RR, AR Item 112 at 21:13-16. Therefore, on October 16, 2020, the Commission ordered Denton to file a comprehensive transmission rate application by November 1, 2021, based on a test year ending on September 30, 2020, to determine whether Denton was overearning.

On November 1, 2021, Denton complied with the Commission’s order and filed a comprehensive rate application. RR, AR Item 2. Denton’s rate application tacitly admitted that it was overearning—it requested a transmission revenue requirement of $37,227,597, RR, AR Item 199 at 8:14-9:2, a reduction of $22.5 million per year from its previously approved revenue requirement of $59,752,472.

RR, AR Item 112 at 18:18-19. However, the Commission’s ability to set lower rates was delayed by Denton’s failure to provide a required depreciation study. After months of delay, on May 12, 2022, the Commission issued an order requiring Denton to amend its application to include a depreciation study. RR, AR Item 45 at 3.

During this delay, the Commission modified the RFP instructions while processing another utility’s transmission rate application. This modification was discussed in an open meeting on October 6, 2022. 3 The Commissioners acknowledged that the RFP was 20 years old and in need of review. RR, AR Item at PDF 35:4-6. The modifications removed a statement in the instructions for

Tex. Pub. Util. Comm’n, Application of Rayburn Country Electric Cooperative, Inc. to Change Wholesale Transmission Service Rates, Docket No. 52353.

the debt service coverage method that the DSCR in the MOU’s most recently issued bond indentures plus an additional 0.25x of coverage ratio would be presumed reasonable. The Commissioners commented when adopting the modifications that they needed “to clean up the rate filing package.” Id. at PDF 36:13-24. They explained that the additional coverage was “a huge amount” and “an extraordinary rate burden on our ratepayers” that “doesn’t get it to even the threshold of reasonable.” Id. at PDF 34:20-35:2, 36:3-4. Additionally, they explained that the changes were necessary because the RFP needed to provide clear instructions that an MOU’s rate of return needs to be supported by evidence in the application. Id. at PDF 36:5-11. In recognizing they could make these limited modifications during the open meeting, they put off more substantial changes to the requirements in the RFP for a future project. Id. at PDF 38:5-6.

On December 1, 2022, six months after being ordered to file a depreciation study and nearly two months after the Commission modified the RFP instructions, Denton filed an amended application including a depreciation study. RR, AR Item 90. Denton’s amended application also modified the original application by requesting a transmission revenue requirement of $38,446,435—an increase of $1.2 million from its original application. RR, AR Item 113 at 4:3.

Denton elected to use the debt service coverage method to determine an appropriate rate of return. Both the old and the modified RFP provide that the

Commission will first look at the coverage ratio stated in the MOU’s bond indentures but will look to a ratio provided by a city policy if the bond indentures do not provide a coverage ratio. RR, AR Item 117 at PDF 21, and AR Item 206 at 15. Denton’s bond indentures all state that it is required to maintain a DSCR of 1.25x. RR, AR Item 159 at 8 (Finding of Fact 51). However, Denton requested in its application to receive a DSCR of 1.75x. RR, AR Item 185 at 3:11-14. Denton reached this ratio based on the City’s Debt Management Policy (“City Policy”) that directs municipal utilities to seek to maintain bonds with a DSCR of 1.5x. RR, AR Item 112 at 11:16- 18. Denton then requested, based on an incorrect reading of the presumption in the old RFP, an additional 0.25x of coverage on top of the 1.5x provided for in the City Policy.

III. The Commission processed Denton’s transmission rate application.

The Commission referred the case to the State Office of Administrative Hearings (“SOAH”) on August 3, 2022. A hearing on the merits was held on May 11, 2023.

Commission Staff, the Office of Public Utility Counsel (“OPUC”), and Texas Industrial Energy Consumers (“TIEC”) all challenged the reasonableness of Denton’s requested rate of return. OPUC witness Mark Garrett provided extensive analysis supporting his conclusion that Denton’s request was unreasonable. As Mr. Garrett explained, based on Denton’s requested total electric utility debt service obligations of $61.6 million, even a slight 0.1x increase in its DSCR would increase the costs for ratepayers by $6.16 million per year. RR, AR Item 110 at 7:17-18.

Therefore, Denton’s requested additional 0.5x to the ratio stated in its bond indentures would result in massive costs of $30.8 million to ratepayers. Mr. Garrett performed comparative analysis of other utilities to find a ratio that would be reasonable for Denton. By comparing the rates of return recently requested by other utilities he concluded that a DSCR of 1.42x was reasonable. Id. at 8:1-9. Based on the Commission’s rule, Mr. Garrett concluded that the floor was the 1.25x ratio stated in Denton’s most recently issued bonds and the maximum was the rates of return received by other utilities. RR, AR Item 168 at 73:22-74:3. Mr. Garrett explained that a DSCR of 1.42x was the maximum rate he could come up with that would be considered reasonable. Id. at 74:4-6. Thus, anything above 1.42x was unreasonable.

Commission Staff’s witness, Mark Filarowicz, also challenged the reasonableness of Denton’s requested rate of return. Mr. Filarowicz reviewed the facts and circumstances surrounding Denton’s application and concluded that there was no compelling reason to adjust Denton’s DSCR above the 1.25x ratio stated in its bonds. RR, AR Item 112 at 17:19-21. He pointed out that the known and measurable changes that Denton requested to its debt service needs provided confirmation that its current and actual DSCR was 1.25x. Id. at 17:22-24. Denton’s requested DSCR of 1.75x, when allocated to its transmission function, resulted in a rate of return of $23,305,897. Id. at 14:20-21. On the other hand, Commission Staff’s recommendation based on a DSCR of 1.25x resulted in a return of $14,475,026, a reduction of $8,830,871. Id. at 14:18-20. Mr. Filarowicz explained that any incremental adjustment above a ratio of 1.00x must be balanced by the need to provide just and reasonable rates for ratepayers. RR, AR Item 112 at 18:6-7. A utility would need to put on robust evidence documenting the circumstances that justify a request for coverage above that stated in the bond indentures, and Denton failed to provide evidence supporting its requested DSCR of 1.75x. Id. at 18:9-12.

Similarly, TIEC also challenged the reasonableness of Denton’s requested rate of return. TIEC first explained that Denton’s request should be rejected because it incorrectly applied the presumption in the RFP to the coverage ratio in the City Policy rather than the coverage ratio stated in the bonds, and this was reason enough to find its requested rate of return was unreasonable. RR, AR Item 132 at 5. The old RFP provided that a request for the DSCR stated in its bonds plus an additional 0.25x would be presumed reasonable. Denton did not ask for this but instead improperly argued that the presumption applied to the DSCR in the City Policy. Therefore, Denton never actually requested for the presumption to apply as the old RFP provided. Furthermore, TIEC explained that the DSCR ratio stated in the City Policy was in no way binding on the Commission because the rule only requires the

Commission consider the coverage ratios required in the transmission service provider’s bond indentures or ordinances. Id. at 4. Therefore, the Commission has discretion to look at the bond indentures or ordinances, and the rule only requires the Commission to “consider” these coverage ratios when determining a reasonable coverage ratio. Id. Thus, TIEC argued that the presumption in the old RFP was overcome because the facts provided by Denton in its application only supported a DSCR of 1.25x. RR, AR Item 137 at 4.

On August 8, 2023, the Administrative Law Judge (“ALJ”) issued a proposal for decision (“PFD”) addressing the main issues that were still in dispute. Relevant to this case, the ALJ found that Denton’s DSCR should be set at 1.25x. RR, AR Item at 2.

On October 12, 2023, the Commission adopted a modified PFD consistent with the ALJ’s findings and issued a Final Order setting Denton’s reasonable and necessary total operating expenses at $13,548,937 and return on transmission rate base at $11,930,303 for a total transmission revenue requirement of $25,462,927 after deductions. RR, AR Item 159 at 12 (Ordering Paragraphs 3).

On December 14, 2023, Denton filed a petition for judicial review of the Final Order in Travis County District Court. On November 13, 2024, a hearing on the merits was held on Denton’s petition for judicial review. On January 16, 2025, the district court issued its judgment reversing and remanding the provision setting

Denton’s DSCR at 1.25x, finding that it was arbitrary and capricious because it was improperly based on the modified RFP. The district court otherwise affirmed the Final Order.

STANDARD OF REVIEW This is an administrative appeal of a final order of the PUCT following a contested-case hearing. PURA authorizes judicial review of a final order of the PUCT under the substantial evidence standard. Tex. Util. Code § 15.001.

Under the substantial evidence standard, the Court may reverse and remand for further proceedings an agency decision that is in violation of a constitutional or statutory provision; in excess of the agency’s statutory authority; made through unlawful procedure; affected by other error of law; not reasonably supported by substantial evidence; or is otherwise arbitrary, capricious, or characterized by abuse of discretion. Tex. Gov’t Code § 2001.174(2). However, even if the Court finds error on any of these bases, the Court may only reverse the agency’s decision if the substantial rights of the appellant have been prejudiced by the error. Id.; Dyer v. Tex. Comm’n on Env’t Quality, 646 S.W.3d 498, 514 (Tex. 2022). Review of an agency decision under the substantial evidence standard is confined to the record developed before the agency, and the Court may not substitute its judgment for that of the agency on the weight of the evidence on questions committed to agency discretion.

Tex. Gov’t Code §§ 2001.174, 2001.175(e); Tex. Comm’n on Env’t Quality v. Maverick Cnty., 642 S.W.3d 537, 544 (Tex. 2022).

In reviewing an agency’s factual findings and conclusions for substantial evidence, the issue before the Court is not whether the agency reached the correct conclusions but whether there is some basis in the record for its action. Citizens Against Landfill Location v. Tex. Comm’n on Env’t Quality, 169 S.W.3d 258, 264 (Tex. App.—Austin [3rd Dist.] 2005, pet. denied). Although substantial evidence is more than a mere scintilla, the evidence in the record may preponderate against the agency’s decision and nonetheless amount to substantial evidence. Id. The Court may even disagree with the reasons given by the agency in its order and still affirm the order as long as the Court finds that a valid basis exists in the record for the action taken by the agency. R.R. Comm’n of Tex. v. City of Austin, 524 S.W.2d 262, 279 (Tex. 1975). The Court presumes that the agency’s findings, inferences, conclusions, and decisions are supported by substantial evidence. Heritage on San Gabriel Homeowners Ass’n v. Tex. Comm’n on Env’t Quality, 393 S.W.3d 417, 424 (Tex. App.—Austin [3rd Dist.] 2012, pet. denied). The burden to prove otherwise is on the party challenging the agency decision. Id. The reviewing court also considers whether an agency decision is arbitrary, capricious, or characterized by an abuse of discretion. Tex. Gov’t Code § 2001.174(2)(F). “Although an administrative decision that is supported by substantial evidence is generally not arbitrary and capricious,” there are a few “narrow circumstances” where a court may reverse an agency order as arbitrary and capricious even when it is supported by substantial evidence. Tex. Comm’n on Env’t Quality v. Friends of Dry Comal Creek, 669 S.W.3d 506, 517 (Tex. App.—Austin [3rd Dist.] 2023, pet. denied) (internal quotation omitted). Those circumstances may arise when the agency fails to consider a factor the legislature directs it to consider; fails to follow the clear, unambiguous language of its own regulations; denies the appellant due process so as to prejudice its substantial rights; considers an irrelevant factor; or considers only relevant factors but still reaches a completely unreasonable result. Id. Essentially, the reviewing court must determine whether the agency genuinely engaged in reasoned decision-making. Heritage on San Gabriel Homeowners Ass’n, 393 S.W.3d at 423. While the arbitrary and capricious standard encourages the Court to examine whether the agency has “taken a hard look at the salient problems,” it should not be interpreted as a broad, all-encompassing standard for reviewing the rationale of agency decisions. Friends of Dry Comal Creek, 669 SW.3d at 518; see also Tex. Health Facilities Comm’n v. Charter Med.-Dall., Inc., 665 S.W.2d 446, 454 (Tex. 1984).

SUMMARY OF THE ARGUMENT The district court erred by reversing the Commission’s Final Order setting Denton’s DSCR at 1.25x. Substantial evidence supports the Commission’s conclusion, and the provision in the Final Order setting Denton’s DSCR at 1.25x was not arbitrary or capricious. The Court should reverse the district court’s judgment and render judgment affirming the Final Order.

First, the Commission exercises its discretion when setting a utility’s rate of return. For MOUs that choose to use the debt service coverage method for calculating the rate of return, the Commission applies its rule to determine a reasonable coverage ratio. The RFP is not binding law but only provides instructions for filing transmission rate applications and the required documents that must be submitted with the application. Under both the old and the modified RFP, the Commission would have come to the same conclusion and set Denton’s DSCR at 1.25x. Although the Commission ultimately applied the modified RFP, the record shows that the rebuttable presumption in the old RFP was overcome and that Denton’s requested rate of return was unreasonable. Applying the rule governing an MOU’s rate of return, the Commission set Denton’s DSCR at 1.25x, the ratio stated in Denton’s most recently issued bonds. The Commission concluded that the DSCR of 1.25x provided Denton with a reasonable rate of return. Thus, even if the Commission had improperly modified the RFP (it did not), Denton’s substantial rights were not prejudiced, and substantial evidence supported the Commission’s conclusion.

Second, the Commission properly modified the RFP during the October 2022 open meeting and removed the provision that an additional 0.25x on top of the DSCR stated in an MOU’s most recently issued bonds was presumed reasonable. The modification clarified instructions in the RFP for how the Commission weighs the evidence and exercises its discretion when calculating an MOU’s rate of return and did not change any filing requirements. The Commission is authorized under its procedural rules to modify standardized application forms, and only significant changes need to be published in the Texas Register before implementation. The modifications to the instructions for the debt service coverage method in the RFP were not a significant change. Denton filed an amended application two months after the Commission modified the RFP, and the Commission properly applied the modified RFP to Denton’s amended application.

Lastly, Denton waived the alleged Open Meetings Act violation by not raising it in its motion for rehearing at the Commission. To preserve error for judicial review, Denton was required to explicitly state in its motion for rehearing (1) the particular finding of fact or conclusion of law it asserted was error, and (2) the legal basis upon which the claim of error rests. An alleged Open Meetings Act violation is an entirely new legal basis for challenging the Commission’s modification of the RFP. Denton did not state this legal basis in its motion for rehearing but instead raised it for the first time in its reply brief in the district court. Thus, Denton failed to preserve the alleged error for judicial review, and the district court erred by basing its judgment on an alleged violation of the Open Meetings Act. However, even if Denton had properly preserved error, the Commission did not violate the Open Meetings Act. The Commission properly provided notice for the subject of the October 6, 2022 open meeting, and the rebuttable presumption in the old RFP was not a “subject of the inquiry” as alleged by Denton.

ARGUMENT I. The Commission’s conclusion to set Denton’s DSCR at 1.25x was supported by substantial evidence, regardless of whether the old or modified RFP is used.

The Commission’s conclusion that a DSCR of 1.25x provides Denton with a reasonable rate of return was supported by substantial evidence in the record.

Although the Commission ultimately applied the modified RFP, the evidence in the record shows that it would have reached the same conclusion under the old RFP.

Under the substantial evidence standard of review, a reviewing court may reverse the Commission’s decision if the decision was arbitrary and capricious and it prejudiced Denton’s substantial rights. Tex. Gov’t Code § 2001.174(2); Imperial Am. Res. Fund, Inc. v. R.R. Comm’n of Tex., 557 S.W.2d 280, 288 (Tex. 1977) (“We do not agree with Imperial that this procedural error requires a remand in the present case. No harm or prejudice has been shown because of the Commission’s failure to give notice”); City of Corpus Christi v. Pub. Util. Comm’n of Tex., 51 S.W.3d 231,

264 (Tex. 2001) (Owen, J., concurring) (“[W]e have previously held that failure to follow procedural requirements of statutes or rules is not reversible error without a showing of harm.” (citing Imperial Am. Res. Fund, Inc., 557 S.W.2d at 288)).

Additionally, a reviewing court is not bound by the reasons given by the Commission, provided there is a valid basis for the Commission’s conclusion. Cent. Power and Light Co. v. Pub. Util. Comm’n of Tex., 36 S.W.3d 547, 559 (Tex. App.— Austin [3rd Dist.] 2000, pet. denied). Therefore, even if the RFP was improperly modified (it was not), the Commission’s conclusion was not arbitrary or capricious, and the district court erred by reversing the provision in the Commission’s Final Order setting Denton’s DSCR at 1.25x.

Denton does not have a substantial right to its requested rate of return.

Denton’s rate of return is set by the Commission as part of its transmission revenue requirement when the Commission sets Denton’s transmission rates. 16 Tex. Admin.

Code § 25.192(c). Under PURA, the Commission has the discretion to determine a utility’s reasonable rate of return as a question of fact. Sw. Bell Tel. Co. v. Pub. Util.

Comm’n of Tex., 571 S.W.2d 503, 515-16 (Tex. 1978). Additionally, the issue of which RFP should apply to Denton’s application was extensively litigated during the administrative proceedings. The issue concerned what “reasonable coverage ratio” Denton should receive on its debt service obligations. Under the Commission’s rules, the Commission determines a reasonable coverage ratio that will be used to calculate an MOU’s rate of return. 16 Tex. Admin. Code § 25.192(c)(3). The old RFP contained a presumption that an additional DSCR of 0.25x on top of the DSCR stated in the MOU’s most recently issued bond indentures would be presumed reasonable. RR, AR Item 117 at PDF 21. Denton requested a DSCR of 1.75x based on the City’s Policy of 1.50x and an improper reading of the presumption in the old RFP for an additional 0.25x of coverage. Commission Staff, OPUC, and TIEC all rebutted the presumption from the old RFP and provided evidence that Denton’s requested DSCR was unreasonable. Thus, the Commission applied its rule to the evidence in the record and concluded that a DSCR of 1.25x, as required by Denton’s most recently issued bonds, provides Denton with a reasonable rate of return.

A. Commission Staff, OPUC, and TIEC all rebutted the presumption in the old RFP that an additional 0.25x of DSCR was reasonable.

A legal presumption is defined as “a rule of law laid down by the courts which attaches to facts certain procedural consequences.” Combined Am. Ins. Co. v. Blanton, 353 S.W.2d 847, 849 (Tex. 1962). Presumptions are related to weighing evidence and provide guidance in locating the burden of production at a particular time. Tex. A & M Univ. v. Chambers, 31 S.W.3d 780, 784 (Tex. App.—Austin [3rd Dist.] 2000, pet. denied). The effect of a presumption is to shift the burden of producing evidence to the party against whom it operates. Gen. Motors Corp. v. Saenz, 873 S.W.2d 353, 359 (Tex. 1993). “Once that burden is discharged and evidence contradicting the presumption has been offered, the presumption disappears and ‘is not to be weighed or treated as evidence.’” Id. (quoting Blanton, 353 S.W.2d at 849). As the Supreme Court has explained, “a presumption is an artificial thing, a mere house of cards, which one moment stands with sufficient force to determine an issue, but at the next, by reason of the slightest rebutting evidence, topples utterly out of consideration of the trier of facts.” Blanton, 353 S.W.2d at 849 (quoting Jones on Evidence § 32 (2d ed.)).

Denton requested a coverage ratio of 1.75x based on the City’s Policy directing utilities to acquire bonds with the DSCR of 1.5x and the additional 0.25x under the rebuttable presumption in the original RFP. As an initial matter, this request was a plainly incorrect reading of the plain language of the old RFP. The old RFP instead provided that the DSCR stated in the utility’s most recently issued bond indentures and an additional 0.25x of coverage would be presumed reasonable. RR, AR Item 117 at PDF 21. The RFP also stated that if the utility’s most recently issued bonds do not state a DSCR, only then will the Commission look at a city’s policy or ordinance that provides a DSCR. The RFP did not provide that an additional 0.25x on top of a ratio stated in a city policy or ordinance would be presumed reasonable.

Denton’s most recently issued bonds provide for a DSCR of 1.25x. The presumption only applied to the ratio stated in the bond indentures and did not provide for an additional 0.25x of coverage on top of any ratio stated in a city policy or ordinance.

Thus, the most that Denton could receive based on the presumption was 1.5x, an additional 0.25x on top of the 1.25x stated in its most recently issued bond indentures. However, Denton did not request this.

Commission Staff, OPUC, and TIEC all challenged the reasonableness of Denton’s requested rate of return. OPUC’s witness provided extensive analysis showing that the highest DSCR that would be reasonable was 1.42x. Thus, anything above 1.42x was unreasonable, and the presumption that a coverage ratio of 1.5x was reasonable was rebutted. Additionally, Commission Staff provided testimony explaining that the facts of Denton’s application did not support any DSCR above the 1.25x stated in its most recently issued bond indentures. And TIEC similarly concluded that Denton had improperly applied the presumption to the DSCR stated in its City Policy and that the presumption had been overcome by the facts in Denton’s application. Thus, Commission Staff, OPUC, and TIEC all rebutted Denton’s request by putting forward evidence that a DSCR of 1.5x was unreasonable.

Denton never put forward evidence to support a DSCR of 1.5x (the ratio under the old RFP’s presumption). Rather, Denton consistently argued for, and its application requested, a DSCR of 1.75x that improperly included the additional 0.25x on top of the City Policy of 1.5x. Denton provided no support for the additional 0.25x, but instead insisted that it was a “vested right” that the Commission had no discretion to exclude from its rate of return. RR, AR Item 117 at 9:8-9. This absurd conclusion was contrary to the nature of presumptions, the instructions in the old RFP, and basic transmission ratemaking procedures. In fact, Denton’s own witness even acknowledged that the presumption was rebuttable and could be overcome. RR, AR Item 168 at 102:12-14. Furthermore, both the old and modified RFP provide that if the utility uses any calculation other than the DSCR stated in its bonds, then it must provide the reasonable basis for the alternative calculation. RR, AR Item 117 at PDF 21 and AR Item 206 at 15. The alternative calculation provision in both the old and modified RFP does not contain any presumption, and Denton was required to provide the reasonable basis for its rate of return calculation based on the City Policy. Denton did not provide a reasonable basis for its requested DSCR of 1.75x and resulting rate of return calculation.

Denton never requested the additional 0.25x be applied to the ratio included in its bonds as provided in the old RFP but instead has consistently and incorrectly argued that the additional 0.25x should be applied to the City Policy. That policy already included an additional 0.25x on top of the amount reflected in the debt indentures. What Denton asked for was over and above the presumption. For that reason alone, the presumption did not apply. However, even if the presumption did apply, Commission Staff, OPUC, and TIEC all put forward evidence demonstrating that a DSCR of 1.5x was unreasonable. Denton’s requested ratio of 1.75x was certainly unreasonable. The record contains substantial evidence that the presumption was rebutted, and the Commission was free to exercise its discretion in setting Denton’s rate of return.

B. The Commission concluded that a DSCR of 1.25x provided Denton with a reasonable rate of return.

“An administrative agency is created to centralize expertise in a certain regulatory area and, thus, is to be given a large degree of latitude by the courts in the methods by which it accomplishes its regulatory function.” Pub. Util. Comm’n v. GTE-Southwest, Inc., 901 S.W.2d 401, 409 (Tex. 1995) (quoting City of Corpus Christi v. Pub. Util. Comm’n of Tex., 572 S.W.2d 290, 297 (Tex. 1978)). The Supreme Court has recognized that the process of setting rates for utilities is “far from a precise process; instead, ratemaking relies substantially upon informed judgment and expertise and utilizes projections and estimates in virtually all areas.” Id. at 411.

The Commission sets a utility’s rates at a level “sufficient to repay its expenses, without a return or profit on those expenses, and to provide a return on the invested capital included in its rate base, without repaying that investment.” Cities for Fair Util. Rates v. Pub. Util. Comm’n of Tex., 924 S.W.2d 933, 935 (Tex. 1996).

PURA does not establish a percentage rate of return that utilities must receive. Sw.

Bell Tel. Co., 571 S.W.2d at 515. Rather, the Commission has discretion to determine a utility’s rate of return as a question of fact. Id. at 515-516. Furthermore, courts do not review how the Commission reached a rate of return but only whether the overall rate of return set by the Commission has sufficient support in the record.

Cent. Power and Light Co., 36 S.W.3d at 559. When the evidence provides a range of reasonable alternatives, the Commission has discretion to select within that range.

City of El Paso v. Pub. Util. Comm’n of Tex., 883 S.W.2d 179, 186 (Tex. 1994) (“[W]e hold that there is a reasonable basis for the Commission to, in its discretion, select an amount within the range of figures provided by expert testimony of the parties.”).

For MOUs that choose the debt service coverage method to calculate their rate of return, the Commission by rule determines a reasonable coverage ratio. 16 Tex. Admin. Code § 25.192(c)(3). Under the rule, the Commission will consider the DSCR stated in the MOUs most recently issued bonds or a DSCR provided by a city ordinance. Id. Under both the old and modified RFP, the Commission first looks at the bonds for a DSCR, and only if the bonds do not provide a DSCR will the Commission look to a city ordinance. RR, AR Item 117 at PDF 21, and AR Item 206 at 15. Denton’s bonds require that Denton maintain a DSCR of 1.25x. But, again, Denton requested a DSCR of 1.75x based upon the City Policy directing city utilities to acquire bonds with a DSCR of 1.5x and then adding an additional 0.25x based on an incorrect reading of the instructions in the old RFP. Mr. Filarowicz explained that the City Policy would only be relevant if the bonds did not provide a coverage ratio or if Denton had complied with the policy and acquired bonds with a DSCR of 1.5x, and those bonds were held in the test year for calculating transmission rates. See RR, AR Item 112 at 11:18-22. Neither was the case. Furthermore, the City Policy was not adopted until two weeks after Denton submitted its application to change transmission rates. The City’s prior debt management policy, and the policy in effect during the test year, directed utilities to acquire bonds with a DSCR of 1.25x. RR, AR Item 207 at 15:9-12. The Commission applied its rule to conclude that the 1.25x DSCR stated in Denton’s bonds provided it with a reasonable coverage ratio.

The record evidence supported the Commission’s conclusion that a DSCR of 1.25x was a reasonable coverage ratio. Mr. Garrett concluded that the maximum DSCR that Denton could receive that would be reasonable was 1.42x. Commission Staff and TIEC both concluded that the DSCR of 1.25x stated in Denton’s bonds provided a reasonable rate of return. “In weighing evidence, the [Commission] may accept or reject the testimony of witnesses or may accept part of a witness’s testimony and disregard the remainder.” Cent. Power and Light Co., 36 S.W.3d at 561. Under these circumstances, it was within the Commission’s discretion to accept that Mr. Garrett had rebutted the presumption and that any DSCR above 1.42x would be unreasonable without accepting the ratio of 1.42x. Therefore, the evidence supports that the Commission could select from a range of 1.25x and 1.42x for a reasonable DSCR. The Commission applied its rule, the instructions in both the old and modified RFP, and the evidence in the record to conclude that the DSCR of 1.25x stated in Denton’s bonds provided a reasonable coverage ratio. RR, AR Item at 11 (Conclusion of Law 11A).

The Commission applied the DSCR of 1.25x and concluded that it provides Denton with a reasonable rate of return. Using the DSCR of 1.25x, the Commission calculated Denton’s rate of return at 6.21%. Applying the rate of return of 6.21% to Denton’s transmission rate base resulted in the return on rate base of $11,930,303.

This number reflects recovery of its full debt obligations and an additional 25% of those debt obligations as an additional return on investment. Therefore, Denton’s transmission rates allow it to recover its full operating expenses and debt obligations as well as a return on its invested capital above its operating expenses and debt obligations. Based on the record evidence, the Commission concluded that a rate of return of 6.21% provides Denton with a reasonable opportunity to earn a reasonable rate of return on its invested capital. RR, AR Item 159 at 9 (Finding of Fact 58G).

Thus, substantial record evidence supports the Commission’s conclusion under both the old and modified RFP, and the district court erred by finding the Final Order setting Denton’s DSCR at 1.25x was arbitrary and capricious.

II. The Commission’s modification of the RFP was not a significant change requiring publication in the Texas Register before implementation.

The evidence supports the coverage ratio the Commission used in setting Denton’s rate of return, and the modification to the RFP does not change that. In any event, the Commission’s modification of the RFP was not improper, and thus, the district court improperly reversed the Commission’s rate of return calculation on this basis.

The Commission’s modification of the RFP presents no error here. The Commission correctly applied its procedural rules and properly modified the RFP during the open meeting on October 6, 2022. The Commissioners explained that the instructions in the RFP were not clear and required limited modifications to bring them in line with the Commission’s rule governing the debt service coverage method for calculating the rate of return. Under the Commission’s procedural rules, the Commission can modify its standard forms and is only required to publish significant changes in the Texas Register. The Commission concluded that the limited modifications to the instructions were not a significant change to the standardized application form that required publication in the Texas Register before implementation. RR, AR Item 159 at 10 (Conclusion of Law 10).

Regardless of the circumstances surrounding the modification of the RFP, the Commission’s ultimate determination of the appropriate rate of return (a fact issue) is supported by substantial evidence. The Commission is the fact finder and sole judge of the weight of the evidence. Cent. Power and Light Co., 36 S.W.3d at 561.

Under PURA, the Commission has the discretion to set a utility’s reasonable rate of return. Sw. Bell Tel. Co., 571 S.W.2d at 515-16. The RFP is not law, and the modifications to the instructions clarify that the Commission has the authority to determine a reasonable rate of return. Under the Commission’s rule for the debt service coverage method, a utility’s rate of return is based on its actual debt service and a reasonable coverage ratio determined by the Commission. 16 Tex. Admin.

Code § 25.192(c)(3). The old instructions described how the Commission would weigh the evidence and reach its conclusion of setting a reasonable rate of return, but it never removed the discretion from the Commission in determining a reasonable coverage ratio under the rule. Furthermore, the modifications to the instructions did not change the rule that requires the DSCR be reasonable. Under both the old and modified RFP, an applicant requests a DSCR, and the Commission exercises its discretion granted under PURA to determine if its request is reasonable.

A. The Commission properly modified the RFP.

Courts interpret administrative rules using the same statutory interpretation principles as applied to statutes. TGS-NOPEC Geophysical Co. v. Combs, 340 S.W.3d 432, 438 (Tex. 2011). Additionally, courts will uphold an agency’s interpretation of its own rule when the interpretation is reasonable and consistent with the plain language of the rule. Maverick Cnty., 642 S.W.3d at 544. Courts recognize that it is “a fundamental principle of statutory construction that words’ meanings cannot be determined in isolation but must be drawn from the context in which they are used.” Willacy Cnty. Appraisal Dist. v. Sebastian Cotton & Grain,

Ltd., 555 S.W.3d 29, 39 (Tex. 2018). In construing the Commission’s intent in adopting a rule, courts will read the rule as a whole to harmonize all the various provisions and “do not consider isolated sections, provisions, or terms in a vacuum.”

EXLP Leasing, LLC v. Galveston Cent. Appraisal Dist., 554 S.W.3d 572, 582 (Tex. 2018). In construing a rule, courts may consider the object sought to be attained by the rule. Tex. Gov’t Code § 311.023(1). Lastly, courts will give undefined words their ordinary meaning. Tex. Gov’t Code § 312.002(a).

The RFP is the agency-prescribed form that utilities must follow when submitting transmission rate applications at the Commission. The Commission’s modification of the instructions to the debt service coverage method in the RFP was not a significant change requiring publication in the Texas Register. The Commission is only required to publish significant changes to standardized forms in the Texas Register. 16 Tex. Admin. Code § 22.80. However, the rule does not define “significant.” To determine the ordinary meaning of “significant,” the Court should thus look to the dictionary definition of the term. Morath v. Lampasas Indep. Sch. Dist., 686 S.W.3d 725, 735 (Tex. 2024) (“To ascertain the meaning of an undefined term . . . we generally consult dictionaries for the term’s commonly understood meaning.”). Merriam-Webster Dictionary defines “significant” as “having or likely to have influence or effect.”4 By specifying that only “significant changes” must be published in the Texas Register, the rule indicates that not every change to an agency prescribed form must be published in the Texas Register. Therefore, to determine which changes are significant, the Court must read that provision of the rule in relation to the rule as a whole and the purpose of the rule.

The Commission adopts applications under its rules to provide standard forms that utilities must comply with when submitting an application to the Commission. 16 Tex. Admin. Code § 22.80. Specifically in this case, the RFP provides the costs that may be included in transmission rates and how those costs are reported in a proceeding to establish transmission rates. Id. § 25.192(c)(5). Consequently, a significant change to the RFP would be one that changed, or had an effect on, the filing requirements in the Commission’s standard form. It makes sense that only these types of changes are required to be published in the Texas Register. The purpose of the Texas Register is to provide notice of proposed agency actions to the public. Tex. Gov’t Code § 2002.002. By publishing significant changes to filing requirements for Commission applications, the Commission provides notice of the updated rate filing requirements.

Significant, Merriam-Webster Dictionary, https://www.merriam- webster.com/dictionary/significant (accessed May 13, 2025).

The RFP for non-investor-owned utilities is a 38-page document that outlines the information utilities are required to submit with a transmission rate application and the instructions for how the Commission processes an application. The RFP contains multiple schedules, or categories, of information used to calculate a MOU’s transmission revenue requirement and its rate base. These schedules provide the documents and information that a utility must submit with its application. To give one example relevant to this proceeding, Schedule C provides different methods that an MOU can use to calculate its rate of return. RR, AR Item 206 at 15. Under Schedule C-2, an MOU can use the debt service coverage method, which requires “a schedule showing the debt service requirement for each debt issue outstanding at the end of the fiscal year . . . as well as relevant excerpts of the bond and debt covenants supporting the debt service coverage utilized.” Id. at 16. Additionally, Schedule C-2 requires an MOU provide “[a]n additional schedule showing the calculation of return and rate of return on invested capital in total plant (rate base)” and then explains the calculation method the MOU is required to use. Id. These are the filing requirements for an MOU that selects the debt service coverage method.

The modifications to the instructions did not change any filing requirements in the RFP. An MOU under either the old or modified RFP is permitted to request any DSCR that it wishes. Once the MOU has made the request in its application, the Commission then weighs the evidence to determine if it is reasonable. The filing requirements for the debt service coverage method remain the same; the MOU must provide the debt service requirements for all its outstanding debt, relevant excerpts from its bond and debt covenants supporting the DSCR utilized, and calculations showing the rate of return on invested capital.

The only difference under the modified RFP is in the instructions describing how the Commission weighs the evidence when it applies the rule governing an MOU’s rate of return. As the fact finder and sole judge of the weight of the evidence, the Commission has always been authorized to weigh the evidence and conclude that the facts provided by a utility in its application rebutted any presumption that the requested DSCR was reasonable. In other proceedings, the Commission had previously applied the rebuttable presumption in the old RFP and found that the evidentiary record did not support a DSCR greater than the ratio stated in the utility’s bond covenants. 5 The Commission then required the utility to provide further evidence to support its rate of return calculation. RR, AR Item 112 at PDF 35:15- 18. The RFP is not law, and a presumption in the RFP instructions has never

Tex. Pub. Util. Comm’n, Application of Rayburn Country Electric Cooperative, Inc. to Change Wholesale Transmission Service Rates, Docket No. 52353 (Aug. 4, 2022), https://interchange.puc.texas.gov/search/documents/?controlNumber=52353&itemNumber=41 (order remanding proceeding to docket management) (“The Commission found the evidentiary record does not support the use of a debt-service-coverage ratio greater than the 1.20 debt-service- coverage ratio required by the debt covenants in evidence to calculate Rayburn’s return on transmission rate base.”).

superseded the Commission’s statutory authority to determine a reasonable rate of return and ensure that rates are just and reasonable.

The debt service coverage method is just one method in the RFP that an MOU can choose to use when calculating its rate of return. For a utility that chooses this method, the limited changes merely removed the provision that an additional 0.25x to the actual, stated DSCR in the MOU’s bonds was presumed reasonable. The instructions never said that the request was reasonable. Again, under the old RFP, the presumption was rebuttable and could be contested by any party, and the Commission still had the authority, as the sole fact finder, to weigh the evidence to determine whether the facts provided in the application rebutted the presumption.

Further, the modifications to the instructions in the RFP did not change what rate of return a utility can receive, and a utility can still request any DSCR that it thinks is appropriate. The filing requirements remain the same under both the old and modified RFP. The modified RFP is consistent with the statutory framework for setting transmission rates and how the Commission exercises its discretion when setting a reasonable rate of return. PURA grants the Commission the discretion to set rates that are just and reasonable based on the evidence in the record. Sw. Bell Tel. Co., 571 S.W.2d at 515-16. A sentence in the RFP instructions that a rate of return is “presumed reasonable” does not somehow override the Commission’s authority to ensure that the utility’s rate of return is reasonable. Therefore, the limited modifications were not a significant change to the RFP that required publication in the Texas Register. Accordingly, the district court erred by finding that the RFP was improperly modified.

i. Even if the modification to the RFP were a significant change, Denton was not prejudiced because it was not published in the Texas Register.

Even if the modification were a significant change (it was not), there is nothing in the Commission’s rule that prohibits the Commission from making it. The only requirement in the rule is that significant changes to standardized forms be published in the Texas Register before implementation. Commission Rule 22.80 does not provide a timeline before the changes may become effective or require that the Commission receive, or respond to, comments on the changes. The rules include only a Texas Register notice requirement to inform interested parties that a Commission prescribed form has been modified and that they must comply with the new form. Thus, the only possible basis for an injury here is that Denton did not receive notice of the change. But it is undisputed that Denton did receive notice of the change, and there is no basis to allege injury here.

Under the substantial evidence standard of review, the Court can only reverse the Commission’s Final Order if Denton can show that the failure to provide notice prejudiced its substantial rights. Imperial Am. Res. Fund, Inc., 557 S.W.2d at 288 (“We do not agree with Imperial that this procedural error requires a remand in the present case. No harm or prejudice has been shown because of the Commission’s failure to give notice.”). Denton acknowledges that the modified RFP was posted on the Commission’s website on November 9, 2022, nearly one month before Denton filed its amended application. RR, AR Item 117 at 5:18-19. Additionally, the issue of which RFP should apply to Denton’s amended application was extensively litigated in the administrative proceeding.

Although the Commission did not post the change on the Texas Register, Denton was aware of the changes and knew that its amended application would be processed under the modified RFP. Denton had every opportunity during the administrative proceeding to provide additional evidence to support its requested DSCR. Indeed, Denton filed rebuttal testimony, but rather than providing evidence to support its requested DSCR, it instead argued the additional 0.25x was a “vested right.” Id. at 9:7-9. Had Denton received notice of the modifications through the Texas Register it would not have affected how the application was processed or changed the Commission’s conclusion in the Final Order. As was previously explained, the record contains substantial evidence supporting the Commission’s conclusion, and the Commission would have reached the same result under either the old or modified RFP. Therefore, even if the modifications to the RFP were a significant change, Denton’s substantial rights were not prejudiced by the Commission not publishing the changes in the Texas Register.

B. The modified RFP applied to Denton’s amended application.

Denton supplanted its original application with a comprehensive amended application on December 1, 2022. Because Denton filed an amended rate application, the instructions that applied were the instructions adopted two months earlier on October 6, 2022. Therefore, the amended application was processed using the modified RFP.

Even if the date that Denton filed its initial rate application controlled over the date of the amended application, the modified instructions were still applicable. The modified presumption constitutes a procedural change that applied retroactively to Denton’s pending application. Although the RFP application instructions are not law, it is instructive to look at how courts determine whether a law applies retroactively. It is long-established that “no litigant has a vested right in a statute or rule which affects remedy or is procedural in nature and which affects no vested substantive right.” Ex parte Abell, 613 S.W.2d 255, 260 (Tex. 1981). Such changes are considered remedial in nature, and courts have held retroactive application does not violate the provisions of Article 1, sec. 16 of the Texas Constitution. Id. To be considered a vested right, “it must have become a title, legal or equitable to the present or future enjoyment of a demand or a legal exemption from the demand made by another.” Id. at 261. A mere expectancy based upon the anticipated continuance of the present general laws is not a vested right. Id. at 261-62.

In Pantera Energy Company v. Railroad Commission of Texas, the court found that a rule amended by the state agency constituted a procedural change and therefore retroactively applied to pending applications. 150 S.W.3d 466, 476-77 (Tex. App.—Austin [3rd Dist.] 2004, no pet.). The court concluded that the amended rule adding a notice requirement to applications was a procedural change because notice requirements have long been considered procedural in nature. Id. at 472.

Additionally, the court found that Pantera had an expectation, not a right, to dissolve its pooled oil and gas units and that the remedy was still available after the rule was amended. Id. at 476. The court explained that the production of oil and gas is subject to the Railroad Commission’s jurisdiction and control and that Pantera had no absolute right to do whatever it wanted with its property outside the Railroad Commission’s oversight and regulation. Id. Therefore, the procedural limits regarding what Pantera could do with its property were within the Railroad Commission’s authority to regulate and did not interfere with a vested property right. Id. Like in Pantera, the changes to Denton’s application process were procedural in nature. “A presumption is a procedural device by which the existence of one fact (presumed fact) is assumed from evidence of the existence of another fact (basic or predicate fact).” Etheridge v. Opitz, 580 S.W.3d 167, 179 (Tex. App.—Tyler 2019 pet. dism’d). Under the old RFP, if the utility requested the DSCR stated in its bonds, then an additional 0.25x would be presumed reasonable. This provision merely provided a procedural device for how the Commission would weigh the evidence, shifting the burden to ratepayers to rebut that presumption. Thus, the Commission’s removal of this presumption was a procedural change and applies retroactively if it does not affect Denton’s vested substantive rights. Both before and after the change, evidence to justify the utility’s request was required if the ratepayers offered evidence to rebut it. Denton never had a vested substantive right in an additional 0.25x to its DSCR. The presumption in the old RFP did not grant title to the present or future enjoyment of the additional coverage in its rate of return. Therefore, the modification to the RFP was a procedural change that applied to Denton’s pending application.

III. An alleged violation of the Open Meetings Act does not provide the basis for reversal of the Commission’s order adopting Denton’s rate of return.

Denton waived any challenge to the rate of return the Commission awarded based upon an alleged violation of the Open Meetings Act because this issue was not raised in its motion for rehearing. Because only issues raised in a motion for rehearing are preserved for judicial review, the district court erred in concluding that the RFP was modified in violation of the Open Meetings Act. Moreover, there was no Open Meetings Act violation. The Commission complied with the Open Meetings Act requirements in directing the modification of the RFP during the open meeting on October 6, 2022.

A. The scope of judicial review is determined by the specific issues raised in the motion for rehearing at the Commission.

A timely motion for rehearing is a statutory prerequisite for judicial review of an agency’s final order. Tex. Gov’t Code § 2001.145(a); BFI Waste Sys. of N. Am., Inc. v. Martinez Env’t Grp., 93 S.W.3d 570, 578 (Tex. App.—Austin [3rd Dist.] 2002, pet. denied). To preserve error for judicial review, the motion for rehearing must state: (1) the particular finding of fact, conclusion of law, ruling or other agency action that the complaining party asserts was error; and (2) the legal basis upon which the claim of error rests. Tex. Gov’t Code § 2001.146(g); Burke v. Cent. Educ.

Agency, 725 S.W.2d 393, 397 (Tex. App.—Austin [3rd Dist.] 1987, writ ref’d n.r.e.).

Under the fair notice standard, the complaining party is required to succinctly set out both elements in its motion for rehearing. Id. The two elements may not be supplied in general terms, and the agency and reviewing court may not be forced to speculate about what the complaining party intended. Id. “The purpose of a motion for rehearing is to provide notice to the agency that the moving party is dissatisfied with its final order and will seek an appeal if the ruling is not changed; the motion must therefore be sufficiently definite to notify the agency of the error claimed in order to allow the agency the opportunity to correct it or prepare to defend it.” Coal. for Long Point Pres. v. Tex. Comm’n on Env’t Quality, 106 S.W.3d 363, 373 (Tex. App.—Austin [3rd Dist.] 2003, pet. denied) (citing Suburban Util. Corp. v. Pub. Util. Comm’n of Tex., 652 S.W.2d 358, 364-65 (Tex. 1983)).

In BFI Waste Systems, the Third Court of Appeals reversed the district court’s decision because the motion for rehearing did not address the agency action that the district court found to be in error. BFI Waste Sys., 93 S.W.3d at 579. In that case, the district court found that the agency erred by issuing a permit for life without any findings of fact or conclusions of law on the issue. Id. at 578. While the complainant did raise the issue in its exceptions to the ALJ’s PFD, the motion for rehearing did not. Id. at 578-79. The court of appeals found that the alleged errors in the motion for rehearing “cannot be construed as encompassing or implying a complaint about the lack of findings of fact and conclusions of law on the duration of the permit.” Id. at 579. Thus, the court concluded that the alleged error was not preserved for review. Id. Similarly, in Coalition for Long Point Preservation, the Third Court of Appeals found that the complainant failed to preserve error by not including the issue in its motion for rehearing. Coalition, 106 S.W.3d at 373. In that case, the motion for rehearing alleged that a finding of fact in the agency’s final order was erroneous because the agency incorrectly characterized the expert’s testimony. Id. However, on appeal the complainant raised the argument that the agency erred by admitting the expert testimony. Id. at 372. The court of appeals explained that “[a] finding of fact and an evidentiary ruling are distinct components of an administrative hearing.” Id. at 373. The court found that the motion for rehearing was sufficient to preserve a substantial evidence challenge; however, the motion for rehearing did not assert error relating to the admissibility of the witness testimony. Id. at 373-74. Therefore, the court concluded that the error was not preserved for review. Id. at 374.

Here, Denton failed to preserve the error because it did not raise its specific complaint (an alleged Open Meetings Act violation) that it contends requires reversal of the rate of return determination in its motion for rehearing. In fact, Denton did not even raise this specific complaint in its opening brief in the district court.

The first time that Denton mentioned any alleged Open Meetings Act violation was in its reply brief. Suppl. CR at 339. As it was never mentioned during the agency proceeding, the Commission was never given a chance to address the issue. Nor did it have any opportunity to respond to the alleged violation in its district court briefing. While Denton did assert that the Commission’s modification to the RFP was a significant change that allegedly violated the Commission’s procedural rules, Denton never asserted that the modification was a violation of the Open Meetings Act. Denton’s last-minute assertion that the Commission violated the Open Meetings Act is an entirely new legal basis for its complaint that the rate of return awarded was improper because the Commission improperly modified the RFP. The district court erred in reversing the Commission’s order based on an alleged violation of the Open Meetings Act that Denton never raised before the Commission or in its opening brief in district court.

B. Even if Denton had preserved the alleged error, the Commission’s modification of the RFP did not violate the Open Meetings Act.

The Commission complied with the Open Meetings Act and properly modified the RFP during the open meeting in October 2022. However, because the district court judgment did not specify how the Commission violated the Open Meetings Act, and Denton’s reply brief provides only a limited discussion of this, the Commission is forced to speculate which provision of the Open Meetings Act was allegedly violated. Denton’s scant briefing mischaracterizes the Commission’s action during the October 2022 open meeting and only references one inapplicable provision of the Open Meetings Act.

Although not clear from Denton’s reply brief, Denton seems to argue that the Commission made the modification because the RFP was a “subject of the inquiry” during the open meeting. Suppl. CR at 339. Denton’s district court reply brief cites to only one provision of the Open Meetings Act stating “[a]ny deliberation of or decision about the subject of the inquiry shall be limited to a proposal to place the subject on the agenda for a subsequent meeting.” Tex. Gov’t Code § 551.042(b).

Because, Denton argues, the agenda did not specify that the Commission would modify the RFP, and “the Commissioner’s October 6, 2022 comments were not forecasted by notice in the Public Register or a Commission agenda item,” the Commission was limited to placing the issue on a future agenda and the modification violated “Texas open government laws.” Suppl. CR at 340. However, this is a mischaracterization of the October 2022 open meeting because the modification to the RFP was not a “subject of the inquiry.”

The Open Meetings Act requires a governmental body to provide public notice of the date, hour, place, and subject of a meeting held by the governmental body. Tex. Gov’t Code § 551.041. If a member of the public, or of the governmental body, inquires about a new subject that had not been provided in the posted notice, then the members of the governmental body are limited to responding to the inquiry with factual information or a recitation of current policy. Tex. Gov’t Code § 551.042(a). The notice requirement is intended to benefit members of the interested public, not any individual citizen. City of San Antonio v. Fourth Court of Appeals, 820 S.W.2d 762, 765 (Tex. 1991). Notice is sufficient if a reader is alerted that some action will be taken relative to a given topic. Rettberg v. Tex. Dep’t of Health, 873 S.W.2d 408, 411 (Tex. App.—Austin [3rd Dist.] 1994, no writ). The Open Meetings Act does not require that notice provide detail of all the possible outcomes or the consequences of addressing a particular topic, only whether the topic will be part of a meeting. Id. During the open meeting on October 6, 2022, the Commissioners took up the agenda item described in the notice as “Application of Rayburn Country Electric

Cooperative, Inc. to Change Wholesale Transmission Service Rates. (Final Order).”6 Like this case, it involved a request to change transmission rates prepared using the RFP—thus, the RFP was part of the matter before the Commission in this open meeting. The Commission adopted that RFP as the standard form for all utilities to use when submitting their rate-change applications. The topic of consideration listed in the notice was the rate-change request prepared using the RFP. When addressing the application before it, the Commission was discussing the sufficiency of evidence in the record and whether the requested rate of return was reasonable—an issue implicating the language in the RFP that was ultimately modified. RR, AR Item 112 at PDF 33:21-34:12. This was not a “subject of the inquiry” raised by a Commissioner unrelated to the topic in the notice; rather, it was the very subject that the Commissioners were considering at the public meeting in accordance with the notice.

As a result of their discussion, the Commissioners concluded that the rebuttable presumption in the RFP was unclear to regulated utilities and that the RFP needed to be modified. Thus, a consequence of the Commission’s review of the utility’s application was the modification of the instructions in the RFP. The

Public Utility Commission of Texas, Open Meeting Information and Agenda (Oct. 6, 2022), Texas Secretary of State: Open Meetings, https://texas-sos.appianportalsgov.com/rules-and- meetings?interface=VIEW_OPEN_MEETINGS_SUMMARY&recordId=249725 (accessed May 13, 2025).

Commission was not required to list all consequences that could result from consideration of the subject listed in the notice. See Tex. Turnpike Auth. v. City of Fort Worth, 554 S.W.2d 675, 676 (Tex. 1977) (“There is no necessity . . . to state all of the consequences which may necessarily flow from the consideration of the subject stated.”). Therefore, the Commission properly modified the RFP and did not violate the Open Meetings Act.

CONCLUSION The Commission directed the modification of the RFP during the October 2022 open meeting and applied the modified RFP to Denton’s amended application.

Whether the modifications were a significant change or not does not alter the Commission’s conclusion regarding the DSCR, and the rate of return to award Denton, in the Final Order. The district court erred in reversing it. The Commission’s conclusion to set Denton’s DSCR at 1.25x was not arbitrary and capricious, nor did it prejudice Denton’s substantial rights.

Although the Commission applied the modified RFP to Denton’s application, the record shows that the rebuttable presumption in the old RFP was overcome by the Commission Staff, OPUC, and TIEC. OPUC provided expert testimony showing that any DSCR above 1.42x was unreasonable. The Commission Staff and TIEC provided expert testimony showing that the DSCR stated in Denton’s most recently issued bonds was reasonable. The record contains substantial evidence demonstrating that Denton’s requested DSCR of 1.75x was unreasonable and improperly applied the rebuttable presumption in the old RFP to the City Policy rather than the ratio stated in the bonds. Therefore, the Commission’s conclusion to set Denton’s DSCR at 1.25x—the ratio required by Denton’s bonds—was supported by substantial evidence.

Furthermore, even if the Court were to find that the modifications to the RFP were a significant change, the issue is whether the Commission’s failure to give notice of the changes, not whether the removal of the rebuttable presumption, prejudiced Denton’s substantial rights. Denton can point to no prejudice to its substantial rights by the Commission not publishing the modifications of the RFP in the Texas Register. Thus, the Commission properly exercised its discretion granted under its statutory authority and set Denton’s DSCR at 1.25x, resulting in a rate of return of 6.21%. The Commission’s Final Order is supported by substantial evidence, and any alleged violation of its procedural rule did not prejudice Denton’s substantial rights.

PRAYER Denton has not shown any reversible errors in the Commission’s Final Order setting Denton’s DSCR at 1.25x. Accordingly, the Commission respectfully requests that the Court reverse the district court’s judgment and render judgment affirming the Commission’s Final Order in all respects.

Respectfully submitted, KEN PAXTON Attorney General of Texas BRENT WEBSTER First Assistant Attorney General RALPH MOLINA Deputy First Assistant Attorney General AUSTIN KINGHORN Deputy Attorney General for Civil Litigation KELLIE E. BILLINGS-RAY Chief, Environmental Protection Division /s/ Jordan Pratt JORDAN PRATT Assistant Attorney General State Bar No. 24140277 [email protected] JOHN R. HULME Special Counsel State Bar No. 10258400 [email protected] Environmental Protection Division Office of the Attorney General P.O. Box 12548, MC 066 Austin, Texas 78711-2548 Phone: (512) 463-2012 Fax: (512) 320-0911 Attorneys for Appellant Public Utility Commission of Texas

CERTIFICATE OF COMPLIANCE Pursuant to Rule 9.4(i)(3) of the Texas Rules of Appellate Procedure, I certify that this brief contains 11,736 words, as calculated by Microsoft Word, the computer program used to create this document.

/s/ Jordan Pratt JORDAN PRATT

CERTIFICATE OF SERVICE I hereby certify that a true and correct copy of the foregoing document has been forwarded to the following attorneys via the Court’s electronic filing case management system and/or electronic mail on May 14, 2025.

Jose E. de la Fuente Sharbel A. Sfeir [email protected] [email protected] Gabrielle C. Smith Justin Swearingen [email protected] [email protected] Jamie L. Mauldin Chris Ekoh [email protected] [email protected] Roslyn M. Warner OFFICE OF PUBLIC UTILITY [email protected] COUNSEL LLOYD GOSSELINK ROCHELLE & 1701 N. Congress Avenue, Suite 9-180 TOWNSEND, P.C. P.O. Box 12397 Congress Avenue, Suite 1900 Austin, Texas 78711-2397 Austin, Texas 78701 Telephone: (512) 936-7500 Telephone: (512) 322-5800 Facsimile: (512) 936-7525 Facsimile: (512) 472-0532 Attorneys for Intervenor Attorneys for Appellee Office of Public Utility Counsel City of Denton, operating as Denton Municipal Electric Katherine L. Coleman [email protected] Michael A. McMillin [email protected] John R. Hubbard [email protected] O'MELVENY & MYERS LLP Colorado St., Suite 2750 Austin, Texas 78701 Telephone: (737) 261-8600 Attorneys for Intervenor Texas Industrial Energy Consumers /s/ Jordan Pratt JORDAN PRATT INDEX TO APPENDIX Tab 1 Tex. Pub. Util. Comm’n, Application of Denton Municipal Electric to Change Rates for Wholesale Transmission Service, Docket No. 52715 (Oct. 12, 2023) (Final Order) (AR 159) Tab 2 City of Denton’s Motion for Rehearing, Docket No. 52715, Tex. Pub.

Util. Comm’n (Nov. 3, 2023) (AR 162) Tab 3 Transmission Cost of Service Rate Filing Package for Non-Investor Owned Transmission Service Providers in the Electric Reliability Council of Texas, Project No. 21276, Tex. Pub. Util. Comm’n (OPUC Exhibit 15) (AR 206) Tab 4 16 Tex. Admin. Code § 25.192 Tab 5 16 Tex. Admin. Code § 22.80

Tab 1 Tex. Pub. Util. Comm’n, Application of Denton Municipal Electric to Change Rates for Wholesale Transmission Service, Docket No. 52715 (Oct. 12, 2023) (Final Order) (AR 159) Control Number: 52715

Item Number: 194 PUC DOCKET NO. 52715' \iC.t. _ j T-O SOAH DOCKET NO. 473:2*7€88 £.'l.i L i 12 F:l 0:,t. 7 O! [EV :*,, , r!: ;7 v n ,· . · APPLICATION OF DENTON § , 4-l·· t.2 f,LC i(A COMMISSION PUBUCJUTILITY MUNICIPAL ELECTRIC TO CHANGE § RATES FOR WHOLESALE § OF TEXAS TRANSMISSION SERVICE §

ORDER This Order addresses the application of Denton Municipal Electric (Denton) to change its transmission cost of service (TCOS) and wholesale transmission rates in the Electric Reliability Council of Texas (ERCOT) region. On August 8, 2023, the State Office of Administrative Hearings (SOAH) administrative law judges (ALJs) filed a proposal for decision (PFD) recommending that the Commission approve Denton's TCOS, with adjustments, and approve Denton's annual wholesale transmission rate, ERCOT export rates, and rate-case expenses.

The Commission adopts the proposal for decision, including findings of fact and conclusions of law, to the extent provided in this Order.

A new finding of fact is added after finding of fact 42 and a new finding of fact is added after finding of fact 46 to support the Commission's conclusions on the reasonableness of the general fund transfers. Findings of fact 43,47, and 48 are modified for clarity. Finding of fact is deleted because its contents are duplicative of information elsewhere in the order.

New findings of fact are added after finding of fact 48, finding of fact 49 is modified, and new findings of fact are added after finding of fact 58 to reflect the Commission-approved TCOS and to reflect the rate schedules produced by Commission Staffs number run. Findings of fact 60 and 61 are modified to make findings of fact rather than conclusions of law. A new finding of fact is added after finding of fact 61 to state the effective date of the rates approved by this Order.

Conclusion of law 1 is modified for accuracy. A new conclusion of law is added alter conclusion of law 11 to reflect the Commission-approved rate of return. Conclusion o f law 14 is modified for clarity. New conclusions of law are added after conclusion of law 16 to reflect the Commission-approved TCOS and to retlect the rate schedules produced by Commission stairs number run. Conclusion of law 17 is modified and a new conclusion of law is added before it to PUC Docket No. 52715 Order Page 2 of 14 SOAH Docket No. XXX-XX-XXXX support the Commission's order that Denton file an interim TCOS proceeding within 90 days after this Order is filed. Conclusions of law 7,8,9,12. 13, and 15 are modified to apply law to the facts of this case.

I. Findings of Fact The Commission adopts the following findings of fact.

Applicant 1. Denton Municipal Electric (Denton) is a municipally owned electric utility owned and operated by the City of Denton (City) under certificate of convenience and necessity number 30046.

2. Denton owns and operates for compensation in Texas facilities and equipment to transmit and distribute electricity in the Electric Reliability Council of Texas (ERCOT) region.

Application; Amended Application 3. On November 1. 2021, Denton filed an application with the Commission to change its transmission cost of service (TCOS) and wholesale transmission service rates.

4. On December 12.2021. Denton filed an amendment and supplement to its application.

5. Dentons application is based on a test year ending September 30,2020.

6. In Commission Order No. 4 filed on January 31, 2022, the Commission ALJ found that Denton was not required to submit a depreciation study as part of the Commission's rate- filing package for non-investor-owned transmission service providers.

7. Commission Staff and the Office of Public Utility Counsel (OPUC) filed an appeal of Order No. 4 on March 4.2022.

8. On May 12.2022. the Commission issued an Order on Appeal of Order No. 4 granting the appeal and ordering Denton to amend its application to include a depreciation study.

9. On December 1. 2022. Denton filed an amended application to change its TCOS and wholesale transmission service rates, which included additional testimony and a depreciation study.

PUC Docket No. 52715 Order Page 3 of 14 SOAH Docket No. XXX-XX-XXXX

10. In the amended application, Denton asked the Commission to approve an annual TCOS of $38,446,435, a transmission rate base of $194,443,862. and an annual wholesale transmission rate of $0.541980 per kilowatt (kW).

11. In the amended application, Denton requested a rate of return of 11.99% calculated using a debt service coverage (DSC) ratio of 1.75x.

12. The amended application includes an 11% general fund transfer (GFT) consisting of a franchise fee component (franchise fee GFT) and a 6% return on investment component (ROI GFT) in schedule IE-2, taxes other than income taxes.

13. Denton asked to recover its reasonable and necessary rate-case expenses from its wholesale transmission service customers through a surcharge over a six-month period.

14. In State Office of Administrative Hearings (SOAH) Order No. 14 filed on May 23.2023. the SOAH ALJs found the application administratively complete.

Notice 15. On November 5, 2021, Denton filed the affidavit of Lambeth Townsend. then-authorized legal representative for Denton, attesting that notice of the application was provided by first class mail on November 1, 2021, to the distribution service providers in Docket No. 51612,' all parties in the last complete review of Denton's transmission cost of service.

Docket No. 30358,2 and the OPUC.

16. In Commission Order No. 2 filed on November 23,2021, the Commission ALJ found the notice sufficient.

Intervenors 17. In Commission Order No. 2 filed on November 23, 2021, the Commission ALJ granted intervenor status to OPUC.

' Commission Staff's Petition to Set 2021 Wholesale Transmission Service Charges fc)r the Electric Reliability Council cd Texas, Inc., Docket No . 51612 , Order ( May 24 , 2021 ).

PUC Docket No. 52715 Order Page 4 of 14 SOAH Docket No. XXX-XX-XXXX

18. In Commission Order No. 7 filed on May 5,2022, the Commission ALJ granted intervenor status to Texas Industrial Energy Consumers (TIEC).

Referral to SOAH for HearinH 19. On May 27.2022. Commission Staff, OPUC, and TIEC requested that this case be referred to the SOAH.

20. On August 3,2022. the Commission referred this case to SOAH for assignment of an ALJ to conduct a hearing.

21. On August 4,2022, the Commission issued a preliminary order identitying 34 issues to be addressed in this proceeding.

22. On December 20.2022, the SOAH ALJs convened a hearing on interim rates. Denton offered seven exhibits, which were admitted, and Commission Staff offered three exhibits. which were admitted.

23. On December 20.2022, in Cause No. D-1-GN-22-006855 of the 200th Judicial District of rravis County, Texas. the court issued a temporary injunction enjoining the implementation of interim rates in this proceeding.

24. In SOAH Order No. 11 filed on January 18. 2023, the SOAH ALJs adopted a procedural schedule.

25. On May 11. 2023. SOAH ALJs Daniel Wiseman and Linda Brite convened a hearing on the merits via videoconference. The hearing on the merits concluded the same day.

26. The following parties appeared through legal counsel and participated in the hearing on the merits: Denton, Commission Staff, OPUC, and TIEC.

27. At the hearing on the merits, the SOAH ALJs admitted 19 exhibits offered by Denton, ten exhibits offered by Commission Staff, three exhibits offered by TIEC. and 11 exhibits offered by OPUC.

28. The parties filed post-hearing initial briefs on May 26,2023, and reply briefs and proposed findings of fact. conclusions of law, and ordering paragraphs on June 9,2023.

PUC Docket No. 52715 Order Page 5 of 14 SOAH Docket No. XXX-XX-XXXX

29. The record closed on June 9,2023. except that it was reopened for the limited purpose of admitting exhibits related to Denton's updated rate-case expenses incurred in this docket though June 30,2023.

Evidentiarv Record 30. On November 1, 2021, Denton filed the initial application. the schedules and workpapers under the non-investor owned utility TCOS rate-filing package, and the direct testimonies of Antonio Puente, Jr., Terrance P. Naulty, and Jill A. Schuepbach.

31. On December 12, 2021, Denton filed the first supplemental direct testimonies of Mr. Puente and Ms. Schuepbach.

32. On December 1, 2022, Denton filed the direct testimony of Laurie Tomczyk. and the second supplemental direct testimonies of Mr. Puente and Ms. Schuepbach.

33. On March 3.2023, OPUC filed the direct testimony of Mark Garrett.

34. On March 31,2023, Commission Staff filed the direct testimonies of Mark Filarowicz and Ruth Stark.

35. On April 10,2023, Commission Staff filed the direct testimony Ethan N. Blanchard.

Rebuttal Case 36. On April 24,2023, Denton filed its rebuttal case, consisting of the rebuttal testimonies of Mr. Puente and Ms. Schuepbach.

37. In its rebuttal case, Denton accepted certain recommendations by OPUC and Commission Staffrelated to plant held for future use and made specific corrections to Dentons expenses and revenues, leaving only three issues in dispute: (1) whether and to what extent Denton should recover its GFTs: (2) the appropriate debt service coverage (DSC) and rate of return: and (3) whether Denton should be required to offset its TCOS with export revenues.

38. Denton's rebuttal case asked the Commission to approve an annual TCOS of $35.030.428. a transmission rate base of $192,251,567. and an annual wholesale transmission rate of $0.49382 per kW.

39. Denton's rebuttal revenue requirement included $89,347 for taxes other than income -labor and $4,095.558 for operations and maintenance expense allocated to transmission.

PUC Docket No. 52715 Order Page 6 of 14 SOAH Docket No. XXX-XX-XXXX

40. Denton's rebuttal rate base included $827,846 for materials and supplies allocated to transmission, $523,113 in cash working capital allocated to transmission, and $3,792,668 in net general plant allocated to transmission.

41. Denton's rebuttal case asked for a rate of return of 10.19%.

General Fund Transfrrs 42. A trade-off for the benefits to the citizens of the City for local ownership and control of their own electric utility (i.e. control over issues like rate-setting and quality of service) is that the City does not collect all the other fees and taxes from its municipally owned utility that it would from utilities that were not owned by the City.

42A. The City requires other non-municipally owned utilities to pay a franchise fee similar to the franchise fee portion of the GFT.

43. Requiring a utility to substantiate all its transfers to the general fund that are included in transmission rates falls within the Commission's discretion to ascertain the reasonableness of such costs.

44. DELETED.

45. The City raised the ROI portion of the GFT for its electric utility to 6% of gross revenues while maintaining the previous 3.5% ROI for its water and wastewater utilities. The stated purpose of raising the rate (which was purported to be a temporary increase) was because ofCOVID-19.

46. The City provided no explanation or justification for reasonableness of the increased 6% ROI rate for its electric utility when its water and wastewater utilities pay a 3.5% ROI, or why the 6% electric ROI was made permanent when it was supposed to be a temporary increase due to COVID-19.

46A. Denton's transmission costs of service. like all transmission costs, are allocated to ratepayers across ERCOT; by contrast, City's water and wastewater utility expenses are paid by local ratepayers.

47. Requiring justification for Denton's requested ROI GFT included in transmission rates, as well as justification for a municipality's disparate treatment of its electric utility from its PUC Docket No. 52715 Order Page 7 of 14 SOAH Docket No. XXX-XX-XXXX water and wastewater utilities with respect to its ROI GFT, is not burdensome and within the Commission's authority.

48. Denton has established the reasonableness of the franchise fee component of its general fund transfer but has not sufficiently substantiated the remaining 6% for ROI component's inclusion in transmission rates.

Post-Test-Year Adjustments to Rate Base 48A Denton's rebuttal case requested $223,195,137 in original cost of transmission plant in service, including a post-test-year adjustment of $25.502.626 in additional transmission plant installed from October 1,2020 through June 30,2021.

48B. Denton's rebuttal case requested an accumulated depreciation of $36,087,186 in electric transmission plant, including a post-test-year adjustment of $3,923,648 in accumulated depreciation of electric transmission plant installed from October 1, 2020 through June 30,2021.

48C. Denton's rebuttal case requested an accumulated depreciation of $7,316,963 in general plant allocated to transmission functions, including a post-test-year adjustment for accumulated depreciation of general plant installed from October 1, 2020 through June 30, 2021.

48D. The post-test-year adjustment to invested capital reflects known and measurable changes to historical test-year data.

Cash Workini! Capital 48E. Denton's reasonable and necessary ERCOT transmission cash working capital is $523.113.

Total Rate Base 48F. Denton s investments are reasonable and necessary and used and useful to the public.

48G. Denton's total ERCOT transmission rate-base is $192,251,567.

Other Revenues - Export Revenue 49. Denton's TCOS should be offset by the amount of export revenues it should have collected during the test year, which is $16,313.

PUC Docket No. 52715 Order Page 8 of 14 SOAH Docket No. XXX-XX-XXXX

Debt Service Coveraue and Rate of Return 50. The instructions in the rate filing package, both before and after modification, provide that the Commission only resorts to consideration of the board of director' s policy in lieu of DSC requirements stated in the transmission service provider's (TSP) bond resolutions.

51. The stated DSC ratio in Denton's most recent debt issuance is 1.25x.

52. At the time of Denton' s initial application, the rate filing package provided that the DSC levels stated in the TSP's most recently issued bond covenants plus additional coverage of 0.25 for municipal utilities shall be presumed reasonable.

53. The rate filing package is not law.

54. The Commission's October 6, 2022 modification of the rate filing package removed a rebuttable presumption, which is a procedural change that does not affect a vested substantive right.

55. The modified rate filing package provides that an applicant may request an additional 0.25x to the DSC ratio if the applicant shows that it has utilized short-term debt financing as an alternative to long-term debt financing in a cost-effective manner.

56. Denton's amended application was filed on December 1,2022, after the rate filing package was modified.

57. No evidence was presented showing that Denton utilized short-term debt financing as an alternative to long-term debt financing.

58. The 1.25x DSC ratio set forth in Denton's most recent debt issuance should be adopted and applied to Denton's rebuttal case, which results in a rate of return of 6.21%.

58A. Denton ' s return on transmission rate base is $11,930,303.

Expenses 58B. Dentons reasonable and necessary total operating expenses for ERCOT transmission are $13.548,937.

58C. Denton's reasonable and necessary operation and maintenance expenses for ERCOT transmission are $4,095,558.

PUC Docket No. 52715 Order Page 9 of 14 SOAH Docket No. XXX-XX-XXXX

58D. Denton's reasonable and necessary administrative and general expenses for ERCOT transmission are $2,179,505.

58E. Denton's reasonable and necessary depreciation expenses for ERCOT transmission are $7,786,085.

58F. Denton's total operating expenses are reasonable and necessary to provide service to the public.

TCOS and Wholesale Transmission Rate 58G. The annual transmission revenue requirement that will allow Denton 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 is $25,479,240, which results in a TCOS of $25,462,927 after deductions.

58H. Denton's annual wholesale transmission rate is $$0.35895 per kW per year. based on the average four-coincident peak demand in ERCOT for 2020.

58I. Denton's TCOS and wholesale transmission rates are just and reasonable.

ERCOT Export Rate 58J. Denton's hourly rate for power to be exported from ERCOT is $0.000041 per kW.

Interim TCOS Filing and Rate-Case Expenses 59. Given the particular circumstances of this docket, it is in the public interest to require Denton to file an interim TCOS proceeding within 90 days of the final order in this docket.

60. Denton's proposed rate-case expenses of $738,327.89 incurred from October 1. 2021 through June 30,2023 are reasonable, as attested to by the affidavit of attorney Jamie L.

Mauldin filed on July 21, 2023.

61. It is appropriate that Denton should recover its rate-case expenses incurred in this docket through a separate surcharge of $$0.001604 per kW per month of coincidental peak demand. determined in accordance with 16 TAC § 25.192, over a six-month period.

Effrctive Date 61A. The effective date of Denton's wholesale transmission rate is the date of this Order.

PUC Docket No. 52715 Order Page 10 of 14 SOAH Docket No. XXX-XX-XXXX

II. Conclusions of Law The Commission adopts the following conclusions of law.

1. The Commission has authority over this proceeding under PURA §§ 35.004,35.006, and 40.004(1).

2. Denton is a municipally owned utility as defined in PURA § 11.003(11) and an electric utility as defined in PURA § 35.001 for the purpose of wholesale transmission service.

3. Denton is a TSP as defined in 16 Texas Administrative Code (TAC) § 25.5(141) that provides transmission service as defined in PURA § 31.002(20).

4. The Commission processed the application in accordance with the requirements of PURA, the Administrative Procedure Act,3 and Commission rules.

5. Denton provided notice of the application in compliance with 16 TAC § 22.55.

6. Denton's application complies with the requirements of 16 TAC § 25.192.

7. Under PURA § 35.004(c) the Commission must ensure that Denton recovers its reasonable costs in providing wholesale transmission service.

8. As a TSP in the ERCOT region, Denton may seek authority to change its transmission rates under 16 TAC § 25.192(g).

9. The return may be determined based on Denton's actual debt service and a reasonable coverage ratio. In determining a reasonable coverage ratio, the Commission will consider the coverage ratios required in Denton' s bond indentures or ordinances and the most recent rate action of the rate setting authority for Denton under 16 TAC § 25.192(c)(3).

10. The Commission's modifications to the rate filing package were not a significant change which would invoke the requirements of 16 TAC § 22.80.

11. Laws may not operate retroactively to deprive or impair vested substantive rights acquired under existing laws. or create new obligations, impose new duties, or adopt new disabilities in respect to transactions or considerations past; however, no litigant has a vested right in

1 Tex· Govt Code §§ 2001.001-.903.

PUC Docket No. 52715 Order Page 11 of 14 SOAH Docket No. XXX-XX-XXXX a statute or rule which affects remedy or is procedural in nature and which affects no vested substantive right. Changes in such statutes or rules are considered remedial in nature and have been held not to violate the provisions of Article 1, sec. 16 of the Constitution. Ex parte Abell, 613 S . W . 2d 255 , 260 ( Tex . 1981 ) ( citing Exxon Corp. r. Brecheen . 516 S . W . 2d . 525 ( Tex . 1975 ); Texas Water Rights Comm 'n v . Wright. 464 S.*.ld 641. 649 ( Tex .

1971 ); Deaconv. City of Euless . 405 S . W . 2d 59 , 62 ( Tex . 1966 ).

11A. A DSC ratio of 1.25x for Denton is reasonable under 16 TAC § 25.192(c)(3) for calculating Denton' s return on transmission rate base.

12. Texas Government Code § 1502.059 grants the City the authority to make transfers to its general fund from its municipally owned utilities but does not require such transfer to be included in the rates of those utilities.

13. Texas Government Code § 1502.057 explicitly identifies which expenses must be included in Denton' s rates and does not include general fund transfers as items that must be included.

14. PURA does not specify any required treatment in wholesale transmission rates of transfers to the City's general fund from its municipally owned utilities' funds.

15. Under 16 TAC § 25.192(e), Denton is required to charge exporting entities for the use of the ERCOT transmission system in exporting power from ERCOT. Subsection (f) of that rule specifies that such revenue must be credited to all transmission customers.

16. Denton did not collect export charges as required by 16 TAC § 25.192.

16A. Denton's post-test-year adjustments to expenses reflect known and measurable changes to historical test-year data under 16 TAC § 25.231(b), (c)(2)(F)(i).

168. Denton's annual TCOS revenue requirement in the amount of $25,462.927 is reasonable and necessary and calculated in accordance with 16 TAC § 25.192(c).

16C. Denton' s transmission-related investment is reasonable and necessary and is used and useful. consistent with the requirements of 16 TAC § 25.192(c).

16D. Denton's annual wholesale transmission rate of $0.35895 per kW per year is properly calculated under 16 TAC § 25.192.

PUC Docket No. 52715 Order Page 12 of 14 SOAH Docket No. XXX-XX-XXXX

16E. The wholesale transmission rate base additions since Denton's last full TCOS proceeding in Docket No. 30358 have been reconciled in accordance with 16 TAC § 25.192 and were prudently incurred.

16F. Denton s ERCOT export rates approved by this Order comply with 16 TAC § 25.192(e).

16G. The Commission's authority to initiate a rate proceeding for Denton under 16 TAC 25.247 is within the Commission's authority under PURA § 35.004(c) to ensure that a TSP recovers its reasonable costs in providing wholesale transmission service necessary for the transaction.

17. Nothing in 16 TAC 24.247 limits the Commission's authority to initiate a rate proceeding for Denton at any time under Title 16 of the Texas Administrative Code on the basis o f other criteria that the Commission determines are in the public interest, including but not limited to the information provided in a non-investor-owned transmission service provider's earnings monitoring report.

18. Denton may recover its reasonable rate-case expenses under PURA § 35.004(c).

III. Ordering Paragraph In accordance with these findings of fact and conclusions of law, the Commission issues the following orders.

I. The Commission adopts the proposal for decision, including findings of fact and conclusions of law, to the extent provided in this Order.

2. The Commission approves Denton's TCOS and wholesale transmission rates to the extent provided by this Order.

3. lhe Commission establishes Denton's annual TCOS revenue requirement as $25,462,927, effective the date of this Order.

4. The Commission establishes Denton's wholesale transmission rate as $0.35895 per kW per year. effective the date of this Order.

5. The Commission establishes Denton's export rates as described in finding of fact number 58J, effective the date of this Order.

PUC Docket No. 52715 Order Page 13 o f 14 SOAH Docket No. XXX-XX-XXXX

Denton must recover $738,327.89 for rate-case expenses incurred from October 1. 2021 through June 30,2023 in this proceeding through a separate surcharge of $0.001604 per kW per month of coincidental peak demand, determined in accordance with 16 TAC § 25.192, over a six-month period.

Denton must file a report documenting the calculation and collection of the monthly rate-case expense surcharge from customers in compliance with this Order. The filing must be made in a separate docket . Compliance Filing . for Docket No . 52715 ( Application oj Denton Municipal Electric to Change Wholesale Transmission Serrice Reiter ). Docket No. 55644.

Denton must file an interim TCOS proceeding no later than 90 days after this Order is filed.

Within ten days of the date this Order is filed, Denton must provide the Commission with a clean copy of the approved wholesale transmission service tariffto be stamped Approt'ed and retained by Central Records.

10. The Commission denies all other motions and any other requests for general or specific relief, if not expressly granted.

PUC Docket No. 52715 Order Page 14 of 14 SOAH Docket No. XXX-XX-XXXX I lit Signed at Austin, Texas the . ~- day of 0» 2023.

PUBLIC UTILITY COMMISSION OF TEXAS nA 144~lb L ad&,A UJ THLEEN JA< KSON, INTERIM CHAIR

'W:d. kuU- WILL MCADAMS, COMMISSIONER //-Uzph )6v--i Cabo-b ~-LORI COBOS, COMMISSIONER

()1!ice 16 q cailtn\ot lcis\1 i,al\52()(H)\52715 to docx Tab 2 City of Denton’s Motion for Rehearing, Docket No. 52715, Tex. Pub. Util. Comm’n (Nov. 3, 2023) (AR 162) PUBL~ 4 ~* TEX>~ Filing Receipt Filing Date - 2023-11-03 01:05:33 PM Control Number - 52715 Item Number - 197 DOCKET NO. 52715 SOAH DOCKET NO. 473-22-07688 APPLICATION OF DENTON § BEFORE THE MUNICIPAL ELECTRIC TO CHANGE § PUBLIC UTILITY COMMISSION RATES FOR WHOLESALE § TRANSMISSION SERVICE § OF TEXAS

CITY OF DENTON'S MOTION FOR REHEARING

NOVEMBER 3,2023 CITY OF DENTON'S MOTION FOR REHEARING TABLE OF CONTENTS I. INTRODUCTION AND EXECUTIVE SUMMARY 1 II. POINT OF ERROR #1: LIMITATION OF GENERAL FUND TRANSFER [FINDINGS OF FACT 42-48; CONCLUSIONS OF LAW 12-14] 3 A. The Commission's decision deprives DME of its statutory right to authorize and make a GFT for any purpose. 3 B. The Commission failed to rely on evidence, statutory language, and case law supporting the reasonableness of DME's 11% GFT 6 III. POINT OF ERROR #2: LIMITATION OF DEBT SERVICE COVERAGE RATIO [FINDINGS OF FACT 50-51, 53-54. 56-58A & CONCLUSIONS OF LAW 10 & 11Ad 9 A. The Commission improperly modified its Rate Filing Package and erroneously applied the modified Rate Filing Package to DME's application.

B. The Order errs in finding that the modification to the RFP does not affect DME's vested rights 12 C. The Commission's own rules and record support DME's requested DSC ratio. 16 IV. POINT OF ERROR #3: REQUIRING INTERIM TCOS WITHIN 90 DAYS OF FINAL ORDER [CONCLUSION OF LAW 59; ORDERING PARAGRAPH 8] .... 17 V. CONCLUSION & PRAYER -------.„„„„-„.-----.„„„„-„.-----.„„„„-„.-----.„ 18

DOCKET NO. 52715 SOAH DOCKET NO. 473-22-07688 APPLICATION OF DENTON § BEFORE THE MUNICIPAL ELECTRIC TO § PUBLIC UTILITY COMMISSION CHANGE RATES FOR WHOLESALE § TRANSMISSION SERVICE § OF TEXAS CITY OF DENTON'S MOTION FOR REHEARING TO THE HONORABLE PUBLIC UTILITY COMMISSION OF TEXAS: The City of Denton (Denton), operating its municipally owned electric utility under the name of Denton Municipal Electric (DME), files this Motion for Rehearing pursuant to 16 Texas Administrative Code (TAC) § 22.264 and Texas Government Code (TGC) § 2001.146(a) requesting that the Public Utility Commission of Texas (Commission) reconsider its October 12, 2023 Order (Order).1 Pursuant to TGC § 2001.146(a), a motion for rehearing in a contested case must be filed no later than the 25th day after the decision or order is signed.2 Therefore, this Motion for Rehearing is timely filed. In support thereof, DME respectfully shows the following: I. INTRODUCTION AND EXECUTIVE SUMMARY DME respectfully urges the Commission to reconsider its Order issued on October 12, 2023. Most ofthe Order's findings and conclusions are not based in law and/or on the evidentiary record. Importantly, the Order opens the door for sweeping policy and rule changes applicable to all non-investor owned utility transmission service providers (non-IOU TSPs) and effectively renders their ability to receive just and reasonable transmission cost of service (TCOS) rates null.

Municipalities have a proprietary right to own their own utilities.3 Home-rule cities, like Denton, possess the full power of self-government and look to the Legislature not for grants of power, but only for limitations on their power; such a limitation exists only when a statute speaks with "unmistakable clarity."4 Chapter 35 of the Public Utility Regulatory Act (PURA) provides the only statutory framework for impinging on Denton' s rate setting for its transmission service and the Texas Supreme Court has held that "chapter 35 is largely more of an oversight role for the

1 Order (Oct. 12,2023) (Order) The Order was signed on Oct. 12,2023. Twenty-five days after Oct. 12, 2023 is Nov. 6, 2023.

Commission with respect to wholesale transmission transactions" for municipally-owned utilities (MOUs).5 Unfortunately, the Order fails to adhere to this established legal principle and adopts a strategy of cherry-picking statutory language and Commission rules in an attempt to carve out additional authority over DME. In all issues, the Order oversteps the Commission' s regulatory authority over setting DME' s TCOS rate and sidesteps Commission precedent, statutes, and substantive rules in order to reach its findings.

Specifically, the Order errs by: • Arbitrarily finding that it has the legal authority to limit inclusion of a General Fund Transfer (GFT) in rates; • Effectively limiting DME' s inclusion of a GFT to 0% and therefore depriving DME of the statutory right to determine and make a GFT; • Prohibiting DME from receiving a reasonable return for its ownership of the utility; • Ignoring its own precedent and the evidentiary record in evaluating the reasonableness of DME's GFT; • Suggesting that DME may discriminatorily only recover its GFT from distribution customers; • Finding that the Commission did not violate its own substantive rules when modifying the non-IOU TSP rate-filing package (RFP); • Improperly relying on Commissioners' statements to support its findings; • Violating DME' s vested substantive rights by retroactively applying the modified RFP to DME' s application; • Ignoring the Commission' s own substantive rules and procedural record in approving a 1.25x debt service coverage (DSC) ratio to DME; and • Erroneously requiring DME to file an Interim TCOS within 90 days of the issuance ofthe Order.

Furthermore, the Order creates regulatory uncertainty by sending a loud signal to all regulated utilities that the Commission can and will ignore its own rules and precedent during the evaluation of a rate case. The Order upholds an analysis that effectively categorizes all non-IOU TSPs as "not significant" and at risk for rule changes mid-application review. Lastly, the Order creates a significant financial impact for DME-the effect of the improper modification to the

DSC ratio will cost DME $8.5 million peryear. The combined effect ofthe Order drastically chips away at the benefits DME's ratepayers received for Denton's risk and burden of utility ownership.

II. POINT OF ERROR #1: LIMITATION OF GENERAL FUND TRANSFER [FINDINGS OF FACT 42-48; CONCLUSIONS OF LAW 12-14] DME respectfully requests that the Commission reconsider its unprecedented decision to limit DME' s GFT to the 5% franchise fee component and entirely exclude the 6% Return on Investment (ROD component. The Commission does not have the authority to limit a MOU's GFT or to create standards for dictating how much of a GFT is recoverable in rates. Furthermore, the Commission's decision arbitrarily ignores municipal authority conferred by the Legislature and prevents Denton from receiving a reasonable return for its ownership of the utility. Crucially, because a franchise fee component is merely a service charge or form of cost recovery, the Commission's decision effectively limits DME' s GFT to 0%. The Commission has never once limited a MOU' s GFT inclusion in rates and has approved GFTs higher than DME' s requested GFT. Even if the Commission has the implied authority to limit inclusion of a GFT in rates, the evidence shows that DME's 11% transfer is within the range of reasonableness.

A. The Commission's decision deprives DME of its statutory right to authorize and make a GFT for any purpose.

The Commission's decision to deny inclusion of DME's full GFT in rates erroneously ignores the controlling statutory authority granting cities the power to determine and make a GFT.

The only statute addressing GFTs is TGC § 1502.059. GFTs are not addressed in PURA, nor are they addressed in the Commission' s substantive rules. Under TGC § 1502.059, a municipality may transfer revenue of any MOU system to the municipality' s general fund for general or special purposes.6 The statute does not provide any limitation on the purpose of the transfer or the amount, and it imposes no requirement that the transfer amount must be tied to a utility' s costs to be included in rates.7 Under the law, cities have broad discretion to authorize a GFT through an indenture, deed of trust, or ordinance.8 The Legislature makes no mention of limitations by other regulatory bodies such as the Commission. A municipality's authorizing instrument is the authority dictating the amount and purpose of a GFT. The Legislature specifically articulated a

Rates are the only source of revenue for a MOU-the use of "revenue" in TGC § 1502.059 demonstrates that a GFT cannot come from anywhere but rates. Allowing recovery qfonly the 5% franchisefee component e#ectively limits DME 's GFT to 0%. DME pays Denton a 5 % franchise fee to compensate the city for DME' s use of the public rights-of-way-this is a standard service charge and does not constitute a transfer of revenues from the utility to the city . If the Commission's decision stands and MOUs cannot recover a GFT in rates, the Commission has effectively voided the authority granted to municipalities under TGC § 1502.059. Based on the evidentiary record in this proceeding, the lowest possible total GFT the Commission could have ordered was 8.5%.10 Instead, the Commission is depriving DME of its right to recover a GFT at all. Whereas an IOU's ROI considers debt and equity, the Commission has inexplicably found that, DME should be limited to only its debt service coverage and receive no other compensation for ownership of the utility. A franchise fee is not a return for the risks of ownership. In granting an allowed rate of return for an IOU, the Commission treats franchise fees as an expense and allows the IOU to earn a return on equity. Here, the Commission equates the franchise fee to the return on equity. If DME's GFT is limited to only the franchise fee component, DME is effectively only recovering costs and its ratepayers see absolutely no benefit for the burden and risk of owning a utility. In addition, the Commission is asserting that collecting an ROI component is impermissible, which eviscerates authority conferred by the Legislature allowing cities to collect

a GFT for "general or special purposes."11 A benefit to the city for utility ownership fits squarely within the broad purposes permitted under the statute. Conclusion of Law No. 12 provides, "Texas Government Code 1502.059 grants the City the authority to make transfers to its general fund from its municipally owned utilities but does not require such transfer to be included in the rates of those utilities."12 The fact that the sole statute addressing a GFT does not address ratemaking does not somehow give the Commission authority to deny DME its statutory right to inclusion of any GFT whatsoever. The Commission' s decision to limit DME to a 0% GFT is facially unreasonable and plainly unsupported by the evidence. The final decision in this proceeding must give significant weight to DME's statutory right under the TGC. Moreover, the Commission lacks authority to arbitrarily disallow DME's entire ROI when it is lawful under the only authority governing GFT.

In addition to using general language from PURA to invalidate an explicit right granted by the controlling GFT statute, the Commission' s Order incorporates multiple incorrect applications of the law. For example, Conclusion of Law No. 13 provides that "Texas Government Code § 1502.057 explicitly identifies which expenses must be included in Denton' s rates and does not include general fund transfers as items that must be included."13 Relying on this provision as a legal basis for the outcome of this proceeding is erroneous. The Commission overlooks key language in the statute, which provides that a municipality shall impose and collect charges for services in amounts at least sufficient to pay the enumerated costs . 14 A simple reading ofthe plain language of the statute demonstrates that the list of enumerated costs is by no means exhaustive, and as a result, a MOU may be permitted to collect charges to pay for other unenumerated costs.

Put differently, the statute provides the floor for what costs may be included in a MOU' s rates, but it in no way imposes a limitation on inclusion of other costs beyond that floor. Simply because a GFT is not required as an inclusion does not give the Commission authority to disallow it altogether. It is undisputed that no authority exists explicitly addressing inclusion of a GFT in rates, and unreasonable reliance on TGC § 1502.057 cannot supersede a municipality's clear statutory authority to dictate and make a GFT. Similarly, according to Finding of Fact No. 46A, "Denton's transmission costs of service, like all transmission costs, are allocated to ratepayers

across ERCOT; by contrast, City's water and wastewater utility expenses are paid by local ratepayers." The Commission' s decision implies that DME may collect its GFT from distribution customers but not from transmission customers. Such an approach has no basis in law and would result in discriminatory rates. PURA § 35.004(c) establishes a reasonableness standard to ensure there is no disparity between customer classes.15 DME must be able to recover all of its reasonable costs in providing transmission service so that its distribution customers are not effectively subsidizing the transmission service provided to third parties. This reasonableness standard works in tandem with PURA § 35.004(a) to ensure that transmission service providers (TSPs) are not charging discriminatory or preferential rates. If DME is prohibited from recovering its full 11% GFT, it will be forced to recover the delta in GFT from its retail customers, which conflicts with the purpose of this subchapter of PURA. In sum, the Commission's decision to deny inclusion of DME' s 6% ROI effectively bars DME from including any of its statutorily authorized GFT in rates.

B. The Commission failed to rely on evidence, statutory language, and case law supporting the reasonableness of DME's 11% GFT.

The Commission' s Order finding that DME provided no explanation or justification for the reasonableness of its 6% ROI disregards the evidentiary record of this proceeding.16 The record demonstrates that on September 27,2022, Denton formalized an ROI payment for the Electric Fund equal to 6% of gross revenues.17 No statute, rule, or other authority requires justification beyond a city council' s decision to implement a transfer for a general or special purpose. Prior to formalizing the ROI in 2022, Denton had temporarily implemented a 6% ROI transfer in a 2020 ordinance.18 Rather than deferring to Denton' s statutory right to determine the amount and purpose of a GFT, the Order incorporates a skewed finding of fact alleging that Denton' s purpose for the change to 6% was only "stated" and that the original increase was "purported" to be temporary.19 In evaluating the 6% ROI component, the Commission did not base its decision on the evidence

presented; instead, the Commission blindly adopted accusatory findings proposed by the parties opposed to DME.20 Whether the change to 6% was temporary or not has no relevance-DME has substantiated the reasonableness of the transfer throughout the record and, importantly, the ROI is within a reasonable range because the Commission has approved inclusion of GFTs as high as 14%.2 The ROI component is specifically provided for in Section 12.03 of Denton' s Charter, which requires a "computed return on the net investment in the utility system" after the utility meets the requirements of various funds.22 As explained in the record, the ROI component of DME's GFT is akin to the dividends an Investor-Owned Utility (IOU) pays to its shareholders, or the capital credits an electric cooperative returns to its member customers.23 DME' s GFT accounts for costs DME would have to pay if not for the fact that it is a business unit of the city.24 Additionally, it is not unreasonable for a MOU to transfer a return for the city' s benefit. In San Antonio Independent School District v. City of San Antonio, customers of a MOU25 brought suit claiming that a transfer to the city' s general fund could not be included in rates.26 In rendering its decision, the sole authority the Texas Supreme Court evaluated was the version of TGC § 1502.059 in place at the time ofthe case, which is largely unchanged from the current version.27 Like DME' s ROI,28 under the City of San Antonio' s enabling instrument, the contested percentage was paid to

the City only after other specific categories were funded.29 The Court acknowledged that part of the 14% at issue reimbursed the City in lieu of ad valorem taxes that would be received if the systems were not municipally owned.30 Other portions of the 14% were dedicated to specific utility-related functions.31 After those allocations, the Court specifically explained that anything further was all a gain to the City.32 The Court recognized that "[al city which owns and operates its own public utility does so in its proprietary capacity" and applied a general rule "that the city is entitled to make a reasonable profit from its own utility system ." 33 Witnesses for both Commission Staff and the Office of Public Utility Counsel confirmed that if another utility pays taxes or additional fees to the city beyond only a franchise fee, then that utility would pay the city more than 5%.34 On that basis alone, it is discriminatory for the Commission to limit DME' s GFT to 5%, effectively denying inclusion of any GFT in DME' s rates.

Inclusion of DME's GFT in rates is also supported by language in PURA requiring that a MOU' s transmission rates and terms be tied to the use of its system.35 The Commission's decision does not consider that a city-ordered GFT is a financial obligation to DME, just like any other necessary expense. DME' s expert witness explained in testimony that the GFT is a required part of DME's total financial obligations.36 The transfer compensates the city for its ownership of the utility and the inherent risks associated with such ownership. It also provides cost recovery to the city with revenue streams it would receive if the utility was for-profit, such as ad valorem taxes and dividends.37 DME is mandated, through the City Charter, an ordinance, and a financial memo,

35 PURA § 35.004(a).

31 Id . at Bates 55 : 12 - 24 ; DME Ex . 15 at Bates 13 : 10 - 14 : 2 .

to make a GFT totaling 11%.38 The mandated GFT is a financial obligation DME must fulfill as part of its business and operations.39 In other words, the mandated GFT is an integral aspect of DME' s "own use of its [transmission] system." The Commission' s decision to entirely deny a component of GFT that is reasonable based on documentation and testimony in the record is reversible error. This is particularly true given that the Commission provides no explanation as to why a 3.5% ROI-in line with Denton' s water and wastewater utilities-should not be considered the floor for inclusion in DME' s rates. Throughout the record, DME explained the purpose of the ROI component and provided evidence to support the transfer as a reasonable aspect of the use of DME' s system that should be included in rates.

III. POINT OF ERROR #2: LIMITATION OF DEBT SERVICE COVERAGE RATIO [FINDINGS OF FACT 50-51, 53-54. 56-58A & CONCLUSIONS OF LAW 10 & 11A] The Order improperly limiting DME's DSC to 1.25x clearly constitutes reversible error. These findings are based on flawed legal analysis and an improper application of the Commission' s rules.

Furthermore, the Commission's actions in adopting the Proposal for Decision's (PFD) reasoning has broad policy implications and significant financial impacts on all non-IOU TSPs. Importantly, the Order creates more regulatory uncertainty for all regulated utilities by confirming that the Commission does not adhere to its own rules and regulations. DME respectfully urges the Commission to reconsider its decision and modify the Order accordingly.

A. The Commission improperly modified its Rate Filing Package and erroneously applied the modified Rate Filing Package to DME's application.

The Order improperly and incorrectly finds that the change to the Commission' s non-IOU TCOS RFP did not invoke the publication requirements of Commission Substantive Rule 22.80 because that rule only applies to "a significant change" to an existing form and that the modification was insignificant.40 The Texas Supreme Court construes administrative rules in the same manner as statutes because they have the same force as statutes.41 Unless the rule is ambiguous, the Court follows the rule' s clear language with the objective of giving effect to the agency' s intent.42 If there is

First, the fact that the modifications only apply to certain utilities is irrelevant.49 As discussed more thoroughly below, revising a utility's rate of return is one of the most substantive changes the Commission can make to a utility's rate application. There are few more impactful modifications the Commission could have made to the RFP for those non-IOUs who use the DSC method. The PFD provides absolutely no evidentiary basis for its finding that the change is not

significant, when in fact, that change alone impacts DME's rate of return by 398 basis points. That equates to S8. 5 million dollars per year ( or 2 . 76 % ofDME ' s 2022 annual revenue ) in lost revenue .

The Merriam-Webster definition of"significant" is "having or likely to have influence or effect."50 Removing $8.5 million from a total request of $35 million from a utility's annual revenues has a massive influence and effect on the utility's revenues. Therefore, this modification is, on its face, significant. To argue otherwise is absurd.

Almost more alarming is the Commission's explicit acknowledgment that the modification is insignificant because it only applies to all non-IOU TSPs who use the DSC method to calculate rate of return . The PFD arbitrarily finds that since this modification only applies to non - IOU TSPs51 it does not warrant RFP publication in the Texas Register.52 There are 72 MOUs in Texas, serving 4.1 million Texans. This change impacts electric cooperatives too. That is a significant number of electric utilities and there is no record evidence to support this finding, nor is there a policy argument worthy of categorizing one set of regulated entities as less significant than another. The Commission has singled out MOUs (and other non-IOUs) and the Order is therefore blatantly discriminatory.

Additionally, the PFD improperly relied on the Commissioners' comments at the October 6, 2022 Open Meeting as Commissioners' comments have absolutely no evidentiary weight.

Statements made by a Commissioner during the course of deliberation are not precedential.53 Texas courts have ruled that "it is immaterial what a commissioner may have said or thought in the process of arriving at his decision. The thought processes or motivations of an administrator „54 are irrelevant in the judicial determination whether the agency order is reasonably sustained.

As such, the PFD's reliance on the Commissioners' comments to "clean up the rate filing package" do not bear any evidentiary weight and the Commission should have disregarded that analysis.55 In response to DME' s Exceptions to the Proposal for Decision raising this evidentiary issue, the

51 The PFD states that it applies only to MOUs, but it applies to all non-IOU TSPs using DSC methodology.

52 PFD at 34.

53 City of Frisco v. Tex. Water Rights Comm 'n, 579 S . W . 2d 66 , 72 ( Tex . App .-Austin 1979 , writ ref' d n.r. e.).

54 Id. PFD at 34.

ALJs issued an Exceptions Letter stating that they "did not give the Commission' s comments precedential value" and only referenced the Commissioner' s discussion at the October 6,2022 meeting to address DME' s publication concerns.56 This is a complete mischaracterization of the plain language of the PFD and a basic misunderstanding of the rule. 16 TAC § 22.80 requires a "significant change" to be published in the Texas Register. Thus, the issues are identical-if the rule change is significant, it should have been published in the Texas Register. Put another way, DME' s "publication concerns" are one and the same as its "significant change" concerns. The PFD clearly relies on the Commissioners' statements to prove that they did not find the change significant, and thus the modification did not warrant publication.57 Thus, the SOAH ALJs gave improper evidentiary weight to Commissioners' statements at an open meeting.

The Order adopted findings that ignore the clear and unambiguous language of the Commission's rules. The impacts of the change to the RFP are very significant in that it impacts one of the most important aspects of a utility' s revenue recovery. The Order results in arbitrary and capricious findings58 constituting reversible error. The Commission should reverse its findings on this issue as they are clearly erroneous.

B. The Order errs in finding that the modification to the RFP does not affect DME's vested rights.

The Order also errs by violating DME's vested rights. The PFD's analysis errs in finding that a change impacting a utility' s rate of return is merely procedural and does not affect a vested substantive right.59 It is well settled that laws may not operate retroactively to deprive or impair vested substantive rights acquired under existing laws, or create new obligations, impose new duties, or adopt new disabilities in respect to transactions or considerations past.60 It is also well established that "no litigant has a vested right in a statute or rule that is remedial or procedural in nature and that affects no vested substantive right."61 The PFD's analysis erroneously makes a

56 SOAH Exceptions Letter at 2 (Sept. 21, 2023).

57 PFD at 34. The PFD states, "At the October 6,2022 Open Meeting, the Commissioners commented on the need "to clean up the rate filing package." The characterization of"cleaning up" the RFP implies that the change was not a significant change requiring publication in the Texas Register." Order, FoF Nos. 53,58.

59 pFD at 35. w In re K. N. P., 179 S . W . 3d 717 , 720 ( Tex . App . - Fort Worth 2005 , pet . denied).

61 Id., citing Subaru ofAm., Inc. v. DavidMcDavid Nissan, Inc., 84 S.W.3d 212,219 (Tex. 2002).

sweeping policy argument that amending the Commission' s process for evaluating a utility's rate of return is procedural in nature and therefore does not affect a utility's vested substantive right.

The Commission's adoption of that analysis will have broad policy implications and do nothing but create regulatory uncertainty.

The RFP in place when DME initially filed its application included a rebuttable presumption of including a 0.25x adder to a utility' s stated DSC.62 The Order improperly finds that the modification to the RFP merely removed the rebuttable presumption, and therefore was procedural in nature. Thus, the Order finds that the modification does not affect DME' s substantive rights.63 This is erroneous.

When DME filed its initial application on November 1, 2021, DME relied upon the RFP's rebuttable presumption to calculate and budget its proposed TCOS rates and rate of return. DME had no knowledge that the Commission would modify the section of the RFP that applies specifically to its rate of return methodology during the pendency of this case,64 without notice and without following the Commission's own rules. "The prohibition against retroactive laws derives largely from the sentiment that such laws unfairly deprive people of legitimate expectations. „65 It is clear that DME had a legitimate expectation to the pre-November 9,2022 rebuttable presumption of a 0.25x adder, and therefore did not provide any evidence required under the modified RFP. The Order' s finding violates that longstanding principle of law. Furthermore, the PFD' s analysis that DME should have amended its application using the modified RFP on December 1, 2022, ignores record evidence that the modified RFP did not appear online until November 9,2022.66 Moreover, the Commission issued no formal notification for the change to the RFP.67 Informally amending a rule through a contested case hearing without proper procedure or notice to affected parties, especially parties with pending applications, is unjust and discriminatory.

62 DME Ex. 15 at Bates 16-21, Attachment AP-3 at pg. 5 of 6.

63 Order, FoF No. 54.

64 The Commission modified the RPF almost a year after the application was filed.

65 Owens Corning v. Carter, 997 S.W.2d 560,572 (Tex. 1999) (citing Landgrafv. USIFilm Prods., 511 U.S. 244, 265, 114 S. Ct. 1483„ 128 L. Ed. 2d 229 (1994)).

66 DME Ex. 15 at Bates 22, Attachment AP-4.

67 Id at Bates 23, Attachment AP-5.

A utility' s rate of return is one of, if not the, most substantive piece of ratemaking. A regulated utility must be allowed a reasonable opportunity to recover its operating expenses together with a reasonable return on its invested capital.68 „This requirement is met only if the return is sufficient to assure confidence in the financial integrity of the enterprise, so as to maintain its credit and attract capital."69 For the PFD to argue, and the Order to adopt, that a utility does not have a vested, substantive right in its rate of return calculation goes against one of the most basic tenets of utility ratemaking. Furthermore, a Travis County District Court has already found in this proceeding that Commission action can imminently and irreparably harm a city's financial standing and credit, showing that those factors are substantive rights.70 DME is significantly financially harmed by this modification. Its credit ratings and the ability to obtain loans at reasonable rates will certainly be impacted. The record evidence shows that DME's current bonds are rated "A" by Fitch Ratings and "A+" by Standard & Poor' s (S&P) Ratings Services.71 One of the measures bond rating agencies use in determining the credit quality of public power debt issuers is the DSC ratio. S&P Ratings Services considers 1.60x or greater DSC to be an Extremely Strong coverage category.72 The PFD's analysis does not contest the rating agencies' analysis of DSC ratios, yet arbitrarily sets the DSC ratio for DME significantly lower than the recommended DSC rates, which all but guarantees that DME's current A/A+ rating will suffer a significant downgrade. The PFD performs absolutely no analysis on the impact of the recommended DSC to DME' s credit rating before adopting a significantly lower DSC coverage, despite having record evidence to support a higher DSC. The Commission's Order approving the PFD' s analysis is erroneous and not based on record evidence.

Put simply, the rule change should have been adopted through a formal rulemaking. "A presumption favors adopting rules of general applicability through the formal rulemaking

* State v. Pub. Util. Comm 'n of Ten , 8%3 S . W . 2d 190 , 196 - 97 ( Tex . 1994 ).

69 Id., citing Suburban Util. Corp. v. Pub. Util. Comm 'n of Tex., 651 S . W . 2d 358 , 362 ( Tex . 1983 ); Federal Power Comm 'n v. Hope Natural Gas Co ., 320 U . S . 591 , 603 , 64 S . Ct. 281 , 288 , 88 L . Ed . 333 ( 1944 ); Bluejield Water Works &Imp. Co. v. Pub. Serv. Comm'n ofthe State of West Virginia, 262 U.S. 679,692-93,43 S. Ct. 675,678-79, 67 L. Ed. 1176 (1923).

70 Ci (V of Denton v. Peter Lake et. al., Cause No . D - 1 - GN - 22 - 006855 , Final Judgment and Order Granting Permanent Injection at 3 (200th Dist. Ct., Travis County, Tex. Apr. 19, 2022) DME Ex. 8 at Bates 50:20-24.

72 DME Ex. 15 at Bates 7:7-10.

procedures as opposed to administrative adjudication."73 Allowing an agency to create broad amendments to its rules through administrative adjudication rather than through its rulemaking authority undercuts the Administrative Procedure Act (APA).74 While the RFP is not a "law," it is worth noting that when it was initially developed and approved in March 1996, it underwent a "notice and comment" process "similar to that embodied in the APA."75 The RFP acts similarly to a Commission rule in that if a utility does not comply with the RFP's directives, the Commission will not process its application.76 In applying the APA standard to the RFP, the change constitutes impermissible ad hoc rulemaking. Ad hoc rulemaking is appropriate and valid in the following established limited circumstances: (1) the issue is one of first impression, (2) the agency is confronted with a new or amended statutory scheme or administrative rules, or (3) the issue is complex and specialized and cannot be adequately captured within the bounds of a general rule.77 There were no circumstances to make the Commission' s ad hoc rulemaking at the Open Meeting on October 6,2022, appropriate and valid. The RFP was adopted in December 1999 pursuant to TAC § 25.192 and, therefore, the DSC standards have been implemented for decades. Further, this was not an issue of first impression nor was it a new or amended statutory scheme or administrative rule. Additionally, a change to this section is not too complex or specialized, thus it can and should be captured in a general rule. The ad hoc rulemaking that occurred at the Commission's Open Meeting on October 6, 2022, is invalid since it did not meet the narrow exceptions to the mandatory APA rulemaking procedures.

In sum, the Order errs in finding that DME did not have a vested, substantive right in the calculation used for its rate of return. There are few more important issues in an RFP than the calculation of a utility's rate of return and the Order's summary dismissal of its importance is erroneous.

73 Rodriquez, 991 S . W . 2d at 255 .

14 Id. Commission Staff and the Office of Public Utility Counsel's Joint Response to Order No. 4 and Request for Certification of Issues at 4 (Feb. 14, 2022); Commission Staff and the Office of Public Utility Counsel's Joint Appeal of Order No. 4 and No. 5 at 3 (Mar. 4,2022).

76 16 TAC § 22.75(c). n Tex. State Bd. Of Pharmacy v. Witcher, 441 S . W . 3d 520 , 542 ( Tex . App . - Austin 2014 , pet . granted)

C. The Commission's own rules and record support DME's requested DSC ratio.

The Order errs by wholly ignoring the Commission' s rules and procedural record in recommending a 1.25x DSC ratio. It further errs in stating that the stated DSC in Denton' s most recent bond covenants are 1.25x.78 The most recently issued bond covenants specify a times coverage of 1.25 or greater.79 The Order completely ignores that the bond covenants themselves show 1.25 as a floor, not a ceiling. The Order also errs in finding that Denton's policy would only be considered if DME did not have a stated DSC ratio in its actual debt covenants.80 In fact, the Order has conflicting findings and conclusions related to this issue. Finding of Fact 50 states, "[tlhe instructions in the rate filing package, both before and after modification, provide that the Commission only resorts to consideration of the board of director's policy in lieu of DSC requirements stated in the transmission service provider's bond resolutions."81 Conclusion of Law states, "...In determining a reasonable coverage ratio, the Commission will consider the coverage ratios required in Denton' s bond indentures or ordinances and the most recent rate action of the rate setting authority for Denton under 16 TAC § 25.192(c)(3)."82 The characterization of the RFP' s requirement to only consider the board of director's policy is a mischaracterization.

Furthermore , the RFP is not law . 83 But 16 TAC § 25 . 192 is law and it requires the Conlnlission to consider the coverage ratios in the City's ordinances and most recent rate actions of the rate setting authority 34 The RFP the Commission used at the time the Initial Application was filed (and until November 9,2022) states very clearly that a "return based on the TSP's debt service expenses at the end of the Historic Year, and the debt service coverage levels stated in the TSP' s most recently issued bond and debt covenants plus additional coverage of 0.25 for municipal utilities and river authorities shall be presumed reasonable."85 Therefore, when read together, Denton' s City Policy

78 Order, FoF No. 51.

79 DME Ex. 8, Voluminous WP/C 2-2.

80 Order, FoF No. 50.

81 Id. Order, CoL No. 9.

83 Order, FoF No. 53.

84 16 TAC § 25.192(c)(3).

85 DME Ex. 15 at Bates 16-21, Attachment AP-3 at pg. 5 of 6.

requiring a 1.50x DSC ratio on all outstanding bond covenants and the Commission's requirement to consider Denton' s ordinance and most recent rate action of the rate setting authority for the TSP when setting a rate of return, combined with the 0.25x DSC adder in the controlling RFP, clearly support a request for a 1.75x DSC ratio. The Order errs by completely ignoring the Commission's substantive rules when adopting a 1.25x DSC.86 Denton has established a clear policy and mandate for DME to meet a 1.50x DSC ratio, which is justification enough for the request.87 The controlling RFP supports DME's request, and a finding otherwise is erroneous. Furthermore, the record shows that a 1.75x DSC coverage is in line with other non-IOU TSPs' authorized DSC ratio.88 DME's requested 1.75x DSC ratio is reasonable and the Order should be reversed.

IV. POINT OF ERROR #3: REQUIRING INTERIM TCOS WITHIN 90 DAYS OF FINAL ORDER [CONCLUSION OF LAW 59; ORDERING PARAGRAPH 8] The Commission' s decision impermissibly requires DME to file an interim TCOS proceeding no later than 90 days after the Order.89 The Commission' s legal basis for imposing such a requirement is 16 Tex. Admin. Code § 25.247-a Commission substantive rule for which there is no enabling statutory authority. The Order also refers to the Commission' s authority under PURA § 35.004(c), but Texas courts have characterized the Commission' s power over MOUs under Chapter 35 as "largely an oversight role for the Commission with respect to wholesale transmission transactions."90 The Commission does not have explicit statutory authority to order a MOU to file a rate proceeding as it does in other utility contexts. For example, the Legislature has made it abundantly clear that the Commission has the authority under Chapter 36 to order a utility to file a rate proceeding. Specifically, PURA § 36.157(e) provides for "the ability of a regulatory authority to initiate a base rate proceeding at any time under this title."91 No such language exists in PURA Chapter 35. The language of Chapter 36 demonstrates that if the Legislature had intended to give the Commission power to order a MOU to file a rate proceeding

86 Order, CoL No. 11A Rebuttal Testimony of Jill A. Schuepbach, DME Ex. 16 at Bates 529-558, Attachment JAS-8 at pg. 500 of 568.

88 DME Ex. 8 at Bates 172.

89 Order at 13, Ordering Paragmph No. 8.

90 City Pub. Serv. Bd. of San Antonio, 53 S . W . 3d at 320 .

91 Tex. Util. Code § 36.157(e).

at any time, it would have explicitly included language to that effect in Chapter 35. Arbitrarily ordering a MOU to file an interim TCOS proceeding shortly after a lengthy comprehensive TCOS proceeding has no grounding in the express jurisdiction of the Commission over MOUs.

Finding of Fact No. 59 from the Commission' s Order reads, "[gliven the particular circumstances of this docket, it is in the public interest to require Denton to file an interim TCOS proceeding within 90 days of the final order in this docket."92 In addition to lacking any statutory authority for imposing this requirement on DME, the Commission provides no actual basis in the record for why the 90-day requirement is in the public interest. In addition to the Commission's lack of statutory authority, the failure to provide any evidentiary basis for imposing a burdensome, discriminatory requirement on DME is erroneous, and the Commission should modify the Order accordingly.

V. CONCLUSION & PRAYER DME respectfully requests that the Commission grant this Motion for Rehearing to reevaluate the sections of the Order referenced above and grant any further relief to which DME has shown itself entitled.

92 Order, FoF No 59.

Respectfully submitted, LLOYD GOSSELINK ROCHELLE & TOWNSEND, P.C.

816 Congress Avenue, Suite 1900 Austin, Texas 78701 (512) 322-5800 (512) 472-0532 (Fax)

4«zftr~--- --- JAMIE Il-k[AULDIN State Bar No. 24065694 [email protected] ROSLYN M. DUBBERSTEIN State Bar No. 24117520 [email protected] ATTORNEYS FOR THE CITY OF DENTON

CERTIFICATE OF SERVICE I certify that notice of the filing of this document was provided to all parties of record via electronic mail on November 3,2023, in accordance with the Order Suspending Rules, issued in Project No. 50664,

Ij- JAMIE Ijt[AULDIN

1060/64/8698402 19 Tab 3 Transmission Cost of Service Rate Filing Package for Non-Investor Owned Transmission Service Providers in the Electric Reliability Council of Texas, Project No. 21276, Tex. Pub. Util. Comm’n (OPUC Exhibit 15) (AR 206) PUBLIC UTILITY COMMISSION OF TEXAS Project No. 21276 Modification of Rate Filing Package for Transmission Rates

TRANSMISSION COST OF SERVICE RATE FILING PACKAGE FOR NON-INVESTOR OWNED TRANMISSION SERVICE PROVIDERS IN THE ELECTRIC RELIABILITY COUNCIL OF TEXAS (Non-IOU TCOS-RFP) Pursuant to §25.192

As Adopted in December 16, 1999 Open Meeting (with revisions to Schedule C-2 instructions (pages 15-16) and Schedule C-4 instructions (pages 17-18) as authorized by the Commission in October 6, 2022 Open Meeting)

OPUC Exhibit No. 15 TABLE OF CONTENTS GENERAL INSTRUCTIONS ....................................................................................................... 5 DEFINITION OF TERMS AND ACRONYMS ......................................................................... 10 SECTION I : HISTORIC YEAR DATA ..................................................................................... 11 Schedule A: Summary of Total Cost of Service by Function (See Attached Form) ............................................ 11 SCHEDULE B: RATE BASE .............................................................................................................. 12 Schedule B: Summary of Rate Base by Function (See Attached Form) .............................................................. 12 Schedule B-1: Original Cost of Plant ................................................................................................................. 12 Schedule B-2: General Plant Functionalization .................................................................................................. 12 Schedule B-3: Communication Equipment ........................................................................................................ 12 Schedule B-4: Unbundled Construction Work in Progress................................................................................. 12 Schedule B-5: Unbundled Accumulated Depreciation ....................................................................................... 13 Schedule B-6: Unbundled Plant Held for Future Use ......................................................................................... 13 Schedule B-7: Unbundled Accumulated Provision Balances ............................................................................. 13 Schedule B-8: Unbundled Materials and Supplies ............................................................................................. 13 Schedule B-9: Unbundled Cash Working Capital .............................................................................................. 13 Schedule B-10: Unbundled Prepayments ........................................................................................................... 14 Schedule B-11: Unbundled Other Rate Base Items ............................................................................................ 14 Schedule B-12: Unbundled Regulatory Assets (See Attached Form)................................................................. 14 SCHEDULE C: RATE OF RETURN, DEBT SERVICE COVERAGE, CASH FLOW, OR TIMES INTEREST EARNED RATIO ............................................................................................... 15 Schedule C-1: Rate of Return Method ................................................................................................................. 15 Schedule C-2: Debt Service Coverage Method: .................................................................................................. 15 Schedule C-3: Cash Flow Method ....................................................................................................................... 16 Schedule C-4: Times Interest Earned Method: .................................................................................................... 17 SCHEDULE D: OPERATION & MAINTENANCE EXPENSES ................................................... 18 Schedule D-1: O&M Expenses ............................................................................................................................ 18 Schedule D-2: A&G Expenses ............................................................................................................................ 18 Schedule D-3: Payroll Expense Distribution ....................................................................................................... 19 Schedule D-5: Summary of Exclusions from Reporting Period (See Attached Form) ........................................ 19 SCHEDULE E: OTHER ITEMS ......................................................................................................... 20 Schedule E-1: Depreciation Expense ................................................................................................................... 20 Schedule E-2: Taxes Other Than Federal Income Taxes ..................................................................................... 20 Schedule E-3: Federal Income ............................................................................................................................. 20 Schedule E-4: Other Expenses ............................................................................................................................. 20 Schedule E-5: Other Revenue Items (credit) ....................................................................................................... 21 Schedule E-6: Wheeling Revenue under Existing Contracts ............................................................................... 21 SCHEDULE F: FUNCTIONALIZATION FACTORS ..................................................................... 22 SECTION II: FORECAST YEAR DATA ................................................................................... 25 Schedule A(f): Summary of Transmission Cost of Service (See Attached Form) ............................................... 25 SCHEDULE B(f): RATE BASE .......................................................................................................... 26 Schedule B(f): Summary of Transmission Rate Base (See Attached Form) ...................................................... 26 Schedule B(f)-1: Original Cost of Transmission Plant ....................................................................................... 26 Schedule B(f)-2: General Plant Functionalized to Transmission ........................................................................ 26 Schedule B(f)-3: Communication Equipment in Transmission .......................................................................... 26 Schedule B(f)-4.: Unbundled Construction Work in Progress in Transmission ................................................. 27 Schedule B(f)-5: Unbundled Accumulated Depreciation in Transmission ......................................................... 27 Schedule B(f)-6: Unbundled Plant Held for Future Use in Transmission .......................................................... 27 Schedule B(f)-7: Unbundled Accumulated Provision Balances in Transmission ............................................... 27 Schedule B(f)-8: Materials and Supplies in Transmission .................................................................................. 27 Schedule B(f)-9: Cash Working Capital in Transmission................................................................................... 28 Schedule B(f)-10: Prepayments in Transmission................................................................................................ 28 Schedule B(f)-11: Other Rate Base Items in Transmission ................................................................................ 28 Schedule B(f)-12: Regulatory Assets (See Attached Form) ............................................................................... 28 SCHEDULE C(f): RATE OF RETURN, DEBT SERVICE COVERAGE, CASH FLOW, OR TIMES INTEREST EARNED RATIO ............................................................................................... 29 Schedule C(f)-1: Rate of Return Method::........................................................................................................... 29 Schedule C(f)-2: Debt Service Coverage Method: .............................................................................................. 29 Schedule C(f)-3: Cash Flow Method: .................................................................................................................. 29 Schedule C(f)-4: Times Interest Earned Method: ................................................................................................ 29 SCHEDULE D(f): OPERATION & MAINTENANCE EXPENSES ............................................... 30 Schedule D(f)-1: Transmission O&M Expenses ................................................................................................. 30 Schedule D(f)-2: A&G Expenses in Transmission .............................................................................................. 30 SCHEDULE E(f): OTHER ITEMS ..................................................................................................... 31 Schedule E(f)-1: Transmission Depreciation Expense ........................................................................................ 31 Schedule E(f)-2: Taxes Other Than Federal Income Taxes in Transmission ...................................................... 31 Schedule E(f)-3: Federal Income Taxes .............................................................................................................. 31 Schedule E(f)-4: Other Expenses in Transmission .............................................................................................. 31 Schedule E(f)-5: Other Revenue Items (credit) in Transmission ......................................................................... 32 SECTION III AFFILIATE DATA ............................................................................................. 33 General Instructions.............................................................................................................................. 33 Guiding Principles ................................................................................................................................. 33 SCHEDULE N: AFFILIATE DATA ................................................................................................... 34 Schedule N-1A: ................................................................................................................................................... 34 Schedule N-1B:.................................................................................................................................................... 34 Schedule N-2A: ................................................................................................................................................... 34 Schedule N-2B:.................................................................................................................................................... 34 Schedule N-3A: ................................................................................................................................................... 34 Schedule N-3B:.................................................................................................................................................... 34 Schedule N-4A: ................................................................................................................................................... 34 Schedule N-4B:.................................................................................................................................................... 35 Schedule N-5A: ................................................................................................................................................... 35 Schedule N-5B:.................................................................................................................................................... 35 Schedule N-6A: ................................................................................................................................................... 35 Schedule N-6B:.................................................................................................................................................... 35 Schedule N-7A: ................................................................................................................................................... 35 Schedule N-7B:.................................................................................................................................................... 35 Schedule N-8: ...................................................................................................................................................... 35 Schedule N-9A: ................................................................................................................................................... 36 Schedule N-9B:.................................................................................................................................................... 36 Schedule N-10A: ................................................................................................................................................. 36 Schedule N-10B:.................................................................................................................................................. 36 Schedule N-11: .................................................................................................................................................... 36 Schedule N-12: .................................................................................................................................................... 36 SECTION IV FORMS ............................................................................................................. 3738 Schedule W: Confidentiality Schedule ............................................................................................ 3738

Sample Forms (Schedules : A, B, B-12, D-5, A(f), B(f), B(f)-12) ................................................... 3839

GENERAL INSTRUCTIONS

The following instructions are applicable to all schedules required in the Transmission Cost of Service Rate Filing Package (TCOS-RFP) for non-investor owned transmission service providers (TSP) in ERCOT, unless otherwise noted.

1. Unless otherwise indicated, the information required in this filing will be taken from the accounts and records prescribed in the Federal Energy Regulatory Commission (FERC) chart of accounts or the chart of accounts as prescribed by the municipal governing body.

All future references to “FERC” accounts in the TCOS RFP shall include the appropriate accounts of the municipal utility that are consistent with the FERC chart of accounts.

2. For the filing of the TCOS-FP, the following terms have the following meaning: a. Historic Year –Historic Year shall be the most recent fiscal year or calendar year.

For the TSPs filing its TCOS application by May 15, 2000, the Historic Year can be the twelve month period ended September 30, 1999. b. Forecast Year –Forecast Year shall be the twelve-month period ended December 31, 2002 or the fiscal year ending in 2002.

A TSP may use a 2002 forecasted test year only if it files its TCOS application by May 15, 2000 and only if it agrees to extend the effective date to January 1, 2002.

3. For the filing of the TCOS-RFP, the information reported shall be based on the Historic Year. The TSP shall use this Historic Year as the basis from which to forecast its transmission cost of service and billing determinants for the Forecast Year. All rate base items for the Forecast Year shall be reflected at their Forecast Year-end amounts. For the Forecast Year, expense items such as depreciation expense, operations and maintenance expense, taxes and return shall be based on forecasted amounts. Detailed supporting documentation shall be provided for all forecast adjustments.

4. For the Historic Year, costs shall be unbundled into the following three functions: a. Generation (GEN) b. Transmission (TRAN) c. Distribution (DIST) All references in these instructions to “the three functions” shall mean the three functions described in this paragraph (General Instruction No. 4) and the term “functionalize” shall mean the separation of costs into three functions. Of these functions, only the transmission will be projected for the Forecast Year.

5. A river authority, and one or more of its wholesale electric customers, may elect to file a combined transmission cost of service for the river authority and customer transmission cost of service requirements, that are not otherwise recoverable through transmission lease agreements with the river authorities allowed by PURA §35.007(b). The river authority shall file information in sufficient detail to allow the commission to evaluate the reasonableness and prudence of the each customer’s transmission cost of service.

6. A river authority shall be required to provide supplemental information and meet filing requirements in accordance with rules and procedures established by the PUC for securitization of stranded costs for river authorities at such time as such rules and procedures go into effect.

7. Schedule referencing: Schedules shall be referenced by schedule number and name as indicated in each instruction and shall identify the witness sponsoring the schedule.

Schedules, which are not applicable, shall be so designated and include an explanation of why it is not applicable.

8. Schedule format: Schedules which require information by FERC account shall be in accordance with the following instructions: Column (1): information as reported on the TSP’s financial statements Column (2): the adjustment necessary to remove non-regulated or non-electric amount from column (1) and items prohibited by statute or commission rule Column (3): the electric information only (col.(1)-col.(2)+col.(3)) Column (4): the electric amount(s) transferred from one FERC account to another pursuant to General Instruction No. 9(b) Column (5): Column (4) + Column (5) Column (6): Allocation of the total in column (6) to Texas Column (7): Allocation of column (6) to GEN function.

Column (8): Allocation of column (6) to TRAN function.

Column (9): Allocation of column (6) to DIST function.

Note 1: The TSP shall provide workpapers which detail the amounts transferred from one FERC account to another pursuant to General Instruction No. 9(b).

Supporting calculations and the basis for each transferred item shall also be included in these workpapers.

Note 2: The TSP shall provide workpapers, which detail the allocations of column (6) to columns (7) through (9). These workpapers shall contain all supporting calculations and the basis for such allocations.

Note 3: Utilities shall provide workpapers which detail the affiliated items included and support the allocation methods used to derive the amounts included.

Note 4: These schedules attempt to provide a complete listing of accounts. However, if the TSP has accounts on its books not included in the schedule listing, those accounts should be added.

9. Reclassification & Transfers: (a) Reclassifications between accounts shall be allowed consistent with commission rule. Reclassifications shall be documented in the appropriate schedules and amounts placed in the appropriate columns as generation, transmission or distribution. Reclassified costs should not be transferred from one account to another and should not appear in column (4) referenced in General Instruction No. 8.

(b) Transfers shall only be used to make accounting adjustments in accordance with FERC accounting instructions.

10. Adjustments: Adjustments to historic period balances shall be made for the removal of items not allowed to be included in the TSPs cost of service by statute or Commission rule. Additionally, adjustments shall be made to the Historic Year to remove nonrecurring costs and normalize extraordinary expenditures. Workpapers detailing and explaining the adjustments made shall be provided.

11. Functionalization: Costs and rate base items shall be assigned to the three functions using the following three-step process and shall be consistent with PUCT Substantive Rule 25.192. No common costs will be assigned to regulated wholesale transmission function by default. If the TSP cannot meet its burden of proof, the costs in question will not be assigned to the wholesale transmission function. a. For each FERC account, costs and rate base items shall be directly assigned to functions to the extent possible, and all relevant workpapers provided. b. The TSP shall provide detailed workpapers documenting the nature of any costs or rate base items that cannot be directly assigned. For adequately documented items, the utility may derive an account-specific functionalization factor based on the directly assigned costs or appropriate cost-causation principles. The utility must justify the assignment of common costs to regulated functions, and must present evidence to support any such assignment. c. If adequately documented costs or rate base items remain for which direct assignment or account-specific functionalization cannot be identified, the appropriate functionalization factor prescribed in Schedule F may be used. These functionalization factors shall only be used as a last resort. If a utility deems a functionalization factor other than the factor prescribed in Schedule F, to be necessary, the utility shall provide a detailed justification for the chosen functionalization factor.

After the Commission adopts this form, TSPs shall make reasonable changes in their cost accounting and or cost tracking system to ensure that costs are assigned directly to the cost objects and allocated based on the cost causation principles to the users and ensure that future cost information for the wholesale transmission function is collected in compliance with the three-step process described above and §25.192 on a forward going basis.

12. Workpapers: Concurrently with the filing of copies of the TCOS-RFP pursuant to Procedural Rule 22.71, the TSP must also separately file with the Commission corresponding complete sets of workpapers used in the preparation of certain schedules, subject to the provisions of General Instruction No. 15 dealing with voluminous workpapers. The TSP shall also concurrently file copies of its entire direct case, including all testimony and exhibits pursuant to Procedural Rule 22.71. In addition one complete set of the same TCOS-RFP, testimony, exhibits and workpapers shall be delivered to the Office of Public Counsel on the date of filing. Upon request by any person moving to intervene (which request may be made prior to any anticipated rate filing), on the date of filing the TSP will furnish to such person one complete set of the same TCOS-RFP, testimony, exhibits and workpapers filed with the Commission. a. Workpaper referencing format: The workpaper reference shall always begin with the characters “WP/” followed by the schedule to which the workpaper refers.

Ascending numbers shall then reference specific workpapers. The resulting series of workpapers shall have a pyramid structure, with the top workpaper (the workpaper with the least complicated reference, for example WP/A-1) being the workpaper which directly reflects the amounts shown on a particular schedule (in this case, Schedule A-1). The next level down the pyramid (using the A-1 series, this would be WP/A-1/1) would contain information which explains a portion of the top workpaper (in this case, WP/A-1). Each successive level down the pyramid would explain something from the next higher level. b. Workpaper content: All assumptions, calculations, sources, and data supporting allocation or functionalization of the historic period expenses and/or balances as well as the forecasted year expenses and/or balances shall be included in the workpaper supporting each schedule. Supporting documentation for each forecast adjustment shall be included in sufficient detail to allow parties to replicate the adjustment. In addition, specific numbers which “tie” between the schedule and the workpaper must be referenced on both the workpaper and the schedule. c. Workpaper location: All workpapers not considered voluminous (See General Instruction No. 15, below) shall be organized and appear in the same order as the schedules they support.

13. Electronic files: To the maximum extent possible, the Non-IOU TCOS-RFP, testimony and schedules shall be also provided to all participants on diskette or CD-ROM format on the date of filing. Any numerical data provided electronically shall be in Microsoft Excel (preferred), Lotus Symphony, Lotus 1-2-3, or ASCII formats on MS-DOS formatted computer diskette or CD-ROM.

14. Confidentiality: If the TSP claims that requested information is confidential, a statement to that effect shall be included in the filing package in the schedule where the information is requested. All information requested in the schedule for which the TSP does not claim confidentiality shall be included in the filing package schedule. The TSP shall include as part of Schedule W a signed statement by its attorney that presents, for each schedule for which the TSP claims that the requested information is confidential, the claimed reasons that the information should be treated as confidential and that states that the attorney has reviewed the information sufficiently to state in good faith that the information is confidential.

Until a protective order is issued, the TSP shall provide ORA or a party granted intervenor status the information claimed to be confidential if the party agrees to be bound by the draft protective order contained in Schedule W as if it had been issued. Use of the draft protective order contained in Schedule W as a confidentiality agreement pending issuance of a protective order does not preclude issuance of a protective order that differs from the draft protective order contained in Schedule W.

15. Voluminous material: For any individual schedule or supporting workpaper that consists of 100 or more pages and is not available electronically, the company may designate such information as voluminous. All voluminous material shall be made available in a designated location in Austin on the date of filing. If the volume of the data meet the threshold for the “freight car doctrine” [eight (8) linear feet of document], the requested material shall be made available at its normal repository on the date of filing. The TSP shall provide a schedule detailing all normal repositories and cross- reference all TCOS-RFP schedules to the information contained in those repositories.

For the purpose of General Instruction No. 15, each subpart of each section is a separate schedule (e.g., Schedule A-1, B-1, C-1, etc., are all separate schedules). The TSP shall deliver a hard copy of all voluminous materials not subject to the “freight car doctrine” to both the Office of Regulatory Affairs/Legal Division and the Office of Public Utility Counsel on the day of filing the TCOS-RFP application.

16. Attached forms: Certain schedule titles are followed by “(see attached form).” Where such a notation appears, the format for the schedule is provided and is to be followed.

DEFINITION OF TERMS AND ACRONYMS A&G Administrative and General ADIT Accumulated Deferred Income Tax CWIP Construction Work In Progress DSC Debt Service Coverage EPHFU Electric Plant Held For Future Use ERCOT Electric Reliability Council of Texas FERC Federal Energy Regulatory Commission IOU Investor-Owned utility M&S Materials & Supplies O&M Operations & Maintenance ORA Office of Regulatory Affairs PUC/PUCT Public Utility Commission of Texas PURA Public Utility Regulatory Act ROR Rate of Return SAIDI System Average Interruption Duration Index SAIFI System Average Interruption Frequency Index SOAH State Office of Administrative Hearings TCOS Transmission Cost of Service TCOS-FP Transmission Cost of Service Filing Package TIER Times Interest Earned Ratio TSP Transmission Service Provider 4-CP Average of Four Coincident Peak

SECTION I : HISTORIC YEAR DATA Schedule A: Summary of Total Cost of Service by Function (See Attached Form) This schedule shall summarize the TSP’s overall cost of service functionalized for the Historic Year including but not limited to, non-fuel operations and maintenance expenses, eligible fuel and purchased power expenses (if applicable1), non-eligible fuel and purchased power expense (if applicable), depreciation expenses, federal income taxes if applicable, taxes other than income taxes, and the return or coverage developed from the supporting schedules described herein. For any expenses in eligible or non-eligible fuel and purchased power expenses that are not included in generation costs, the FERC account for this expense and an explanation of why this expense is not included in the Generation function shall be included. Presentation shall be such that amounts can be readily determined and all costs to be included in TCOS shall be referenced to the detailed schedules B through E and/or the appropriate workpapers, computations, and analyses. This schedule should also show the derivation of the new wholesale transmission rate calculated by dividing the total transmission revenue requirement by the most recent total system ERCOT 4-CP at the time of application.

1 Municipally Owned Utilities and TSPs without generation do not have to distinguish between eligible and ineligible fuel and purchased power costs. These entities shall report their total fuel cost and total purchased power cost.

SCHEDULE B: RATE BASE Schedule B: Summary of Rate Base by Function (See Attached Form) The schedule shall summarize the TSP’s overall rate base as of end of the Historic Year, separated into three functions. Presentation shall be such that amounts can be readily determined and all items included shall be referenced to the detailed schedules and/or the appropriate workpapers, computations, and analyses. Supporting information may include one-line diagrams (marked to identify transmission, distribution and common facilities) of all distribution substations for which the high side (transmission voltage related equipment) is included in transmission rate base, functionalization factors or other documentation necessary to support the separation of rate base items (including “common” facilities) into the three functions.

Schedule B-1: Original Cost of Plant This schedule shall summarize the amounts of plant by FERC accounts 301-388 of the Uniform System of Accounts as of the end of the Historic Year, functionalized pursuant to General Instruction No 11. Utilities may reclassify some amounts among functions, consistent with Commission’s Substantive Rule 25.192(b). Any reclassification of plant shall be made in accordance with General Instruction No. 9. This schedule shall tie to the book balances at the end of the Historic Year. Supporting workpapers that fully and clearly explain the functionalization of each account or subaccount shall be included in the workpaper section, and any functionalization factors shall be referenced to the appropriate factors in Schedule F.

Schedule B-2: General Plant Functionalization This schedule shall detail the amounts of general plant for the Historic Year by FERC accounts 389-399, functionalized pursuant to General Instruction No. 11. Supporting workpapers that fully and clearly explain the functionalization of each account or sub account shall be included in the workpaper section, and any functionalization factors shall be referenced to the appropriate factors in Schedule F.

Schedule B-3: Communication Equipment This schedule shall show the balance of communication equipment for the Historic year in FERC Account 397, or other account (specify) where such equipment is booked, functionalized pursuant to General Instruction No. 11. For the purposes of General Instruction No. 11, equipment located at substations, which provide multiple functions, shall be functionalized on the same basis as common plant at that substation. Supporting workpapers that fully and clearly explain the functionalization of each account or subaccount shall be included in the workpaper section, and any functionalization factors shall be referenced to the appropriate factors in Schedule F.

Schedule B-4: Unbundled Construction Work in Progress This schedule shall show the amount of Construction Work in Progress (CWIP) directly for the Historic Year, functionalized pursuant to General Instruction No. 11. Supporting workpapers that fully and clearly explain the functionalization of each account or subaccount shall be included in the workpaper section, and any functionalization factors shall be referenced to the appropriate factors in Schedule F.

Schedule B-5: Unbundled Accumulated Depreciation This schedule shall include the accumulated provisions for depreciation detailed by primary account classification (e.g., 350-359, 360-373, 389, etc.) as of the end of the Historic Year, functionalized pursuant to General Instruction No. 11. A description of the methods and procedures followed in booking depreciation shall be included in this schedule. Supporting workpapers that fully and clearly explain the functionalization of each account or subaccount shall be included in the workpaper section, and any functionalization factors shall be referenced to the appropriate factors in Schedule F. All depreciation rates and methodologies shall be included by primary account classification.

Schedule B-6: Unbundled Plant Held for Future Use This schedule shall show the amount of Electric Plant Held for Future Use (EPHFU) as of the end of the Historic Year functionalized pursuant to General Instruction No. 11. Supporting workpapers that fully and clearly explain the functionalization of each account or subaccount shall be included in the workpaper section, and any functionalization factors shall be referenced to the appropriate factors in Schedule F.

Schedule B-7: Unbundled Accumulated Provision Balances This schedule shall show the ending balance (Historic Year) of each accumulated provision account (i.e., injuries and damages, property insurance, etc.) functionalized pursuant to General Instruction No. 11. Supporting workpapers that fully and clearly explain the functionalization of each account or subaccount shall be included in the workpaper section, and any functionalization factors shall be referenced to the appropriate factors in Schedule F.

Schedule B-8: Unbundled Materials and Supplies This schedule shall show the total amount of Materials and Supplies (M&S) as of the end of the Historic Year functionalized pursuant to General Instruction No. 11. Supporting workpapers that fully and clearly explain the functionalization of each account or subaccount shall be included in the workpaper section, and any functionalization factors shall be referenced to the appropriate factors in Schedule F.

Schedule B-9: Unbundled Cash Working Capital This schedule shall show the amount of Cash Working Capital included in each component of the unbundled rate base as of the end of the Historic Year, functionalized on the same basis as the underlying expense, and consistent with General Instruction No. 11. The amount to be included will be in accordance with P.U.C Subst. R. 25.231(c)(2)(B)(iii). Municipal utilities,cooperatives, and river authorities shall be allowed to use the one-eighth method to calculate cash working capital allowance. Supporting workpapers that fully and clearly explain the functionalization of each account or subaccount shall be included in the workpaper section and any functionalization factors shall be referenced to the appropriate factors in Schedule F.

Schedule B-10: Unbundled Prepayments This schedule shall show the amount of Prepayments as of the end of the Historic Year, functionalized on the same basis as the underlying expense, and consistent with General Instruction No. 11. Supporting workpapers that fully and clearly explain the functionalization of each account or subaccount shall be included in the workpaper section and any functionalization factors shall be referenced to the appropriate factors in Schedule F.

Schedule B-11: Unbundled Other Rate Base Items This schedule shall detail all other rate base items for the Historic Year not included in the previous categories, functionalized pursuant to General Instruction No. 11. Supporting workpapers that fully and clearly explain the functionalization of each account or subaccount shall be included in the workpaper section and any functionalization factors shall be referenced to the appropriate factors in Schedule F. Supporting workpapers showing the derivation of the amounts shall also be included.

Schedule B-12: Unbundled Regulatory Assets (See Attached Form) The TSP shall provide the total amount of regulatory assets detailed on asset-by-asset basis for the Historic Year, functionalized pursuant to the General Instruction No. 11. For each item that the TSP claims as regulatory asset, the TSP should identify with specificity the commission Order (including applicable pages) or other authority upon which it bases it claims. If the TSP relies upon an authority other than a commission Order as the basis of its claim, it should provide a copy of the document(s) it relies on. Supporting workpapers that fully and clearly explain the functionalization of each account or subaccount shall be included in the workpaper section and any functionalization factors shall be referenced to the appropriate factors in Schedule F.

SCHEDULE C: RATE OF RETURN, DEBT SERVICE COVERAGE, CASH FLOW, OR TIMES INTEREST EARNED RATIO The determination of final revenue requirements for a municipal utility, river authority, power agency, or electric cooperative may be based on any of the following methods at the election of the filing TSP.

Schedule C-1: Rate of Return Method The rate of return may be the TSP’s weighted average cost of capital based upon the TSP’s capitalization at the end of the Historic Year. A schedule showing the calculation shall be provided. The cost of debt capital and owner’s equity shall be the weighted average cost as of the end of the Historic Year. A cost of owner’s equity equal to the average yield for bonds of an entity with the TSP’s credit rating published in Moody’s Credit Perspective or similar publication during the most recent three months plus two percent shall be presumed reasonable.

The TSP shall justify the use of any other rate of return, and shall specify the special circumstances that warrant the use of a different rate of return. Supporting documentation shall be provided for the average bond yields used in the cost of equity calculation.

Description Of Schedules: A schedule showing the calculation of the TSP’s weighted average cost of capital shall be provided Schedule C-2: Debt Service Coverage (DSC) Method: A requested return may be based on the TSP’s debt service expense as of the end of the Historic Year and the debt service coverage levels stated in the TSP’s most recently issued bond and debt covenants. To the extent the utility can show that short-term debt has been utilized in a cost- effective manner as a reasonable alternative to long-term financing, its principal and interest and an additional coverage of 0.25 may be requested in calculating the return. The return for short- term debt shall not include the coverage that is specified in the bond and debt covenants unless the covenants include short-term debt service in the denominator of the DSC ratio that is used to calculate default on the debt. To the extent there are no minimum debt service coverage requirements in the TSP’s bond resolutions, the Board of Director’s policy, with respect to coverage, shall be considered. The TSP shall justify the use of the requested debt service coverage and specify the reasonable circumstances that support its use.

The Texas Municipal Power Agency or its successor in interest may, at its option, use the rate of return method for calculating its transmission cost of service. If the rate of return method is used, the return component for the transmission cost of service revenue requirement shall be sufficient to meet the transmission function's pro rata share of levelized debt service and debt service coverage ratio (1.50) and other annual debt obligations; provided, however, that the total levelized debt service may not exceed the total debt service under the current payment schedule.

Any additional revenue generated by the methodology described in this subsection shall be applied to reduce the agency's outstanding indebtedness.

An electric cooperative may, at its option, use the debt service coverage method for calculating its transmission cost of service. A requested return may be based on the debt service coverage levels stated in the cooperative’s most recent debt covenants. To the extent that short-term debt is included in the calculation of these debt service coverage level covenants, it may be included in the debt service coverage used to calculate the transmission cost of service. To the extent there are no minimum debt service coverage requirements in the cooperative’s debt covenants, the Board of Director’s policy, with respect to coverage, shall be considered. The cooperative shall justify the use of its requested debt service coverage and specify the reasonable circumstances that support its use.

Description of Schedules: a. For utilities using the debt service coverage method, a schedule showing the debt service requirement for each debt issue outstanding at the end of the fiscal year shall be provided, as well as relevant excerpts of the bond and debt covenants supporting the debt service coverage utilized. b. An additional schedule showing the calculation of return and rate of return on invested capital in total plant (rate base) shall be provided. Return is computed based on the amount of debt service requirements (net of capitalized interest) times the coverage ratio described above, less interest income and depreciation. Supporting fiscal or calendar year-end audited financial statements (if available) and any other documents necessary to support the TSP’s debt service requirement and other components in the return calculation, including the sources of interest income, shall be provided. In addition, the following financial ratios shall be provided, based on the requested debt service coverage ratio: revenues per kWh; and net income per revenue dollar. The percentage of revenues from generation and the percentage of revenues from distribution should be provided if unbundled, and if not unbundled, then generation and distribution revenues should be provided on a bundled basis. If the TSP has any unique characteristics, which might have a bearing on return, it should provide a narrative describing the characteristics.

Schedule C-3: Cash Flow Method A TSP may elect to use the cash flow method for determining its transmission revenue requirement based on the Historic Year. If the TSP elects to use the cash flow method, the Commission shall consider reasonable cash needs in to the following categories: A debt service (including principal and interest) for long- term and short-term debt; B funding of reserve requirements on both long-term and short-term debt as set forth in revenue bond and debt ordinances; C for municipal utilities, annual payments for transfers to the city’s general fund at rates established by the municipal utility’s governing authority, to the extent such amounts are not recovered through other elements of the TCOS.

D capital lease payments and/or finance lease payments; E annual payments to provide internally generated funds for construction, system improvements, and repair and replacement; Transfers to the general fund (which may have different names in different municipal utility systems), debt service, and funding of reserve requirements shall be functionalized, subject to commission review, to the transmission function on a basis comparable to that used to allocate such costs to the other functions of the municipal utility.

Lease payments and capital expenditures shall be included to the extent the can be directly assigned to the wholesale transmission function.

Transmission related costs other than the elements described above should be determined in accordance with the appropriate instructions contained in these rate-filing package.

Description of Schedules: For utilities using the Cash Flow Method, a schedule showing the costs to be included shall be provided together with supporting documentation in the form of bond and debt covenants, adopted policies of the governing authority, approved budgets and other documentation supporting the Cash Flow Component as may be reasonably required by the Commission.

Schedule C-4: Times Interest Earned Method: Generation and Transmission Cooperatives Generation and Transmission Cooperatives may request the use a rate of return based on the TSP’s interest expense requirement on long term debt outstanding as of the end of the Historic Year, and a reasonable net times-interest-earned ratio (Net TIER) coverage. The TSP shall justify the use of its requested rate of return and specify any special circumstances that warrant its use. Special circumstances for purposes of this subsection may include a showing of an equity ratio below 20 percent, or a showing that the proposed Net TIER is insufficient to meet the reasonable cash needs (particularly debt service and internal funds for transmission plant additions) of the TSP.

Description of Schedules: a) A schedule showing the interest expense requirement for each long-term debt issue outstanding at the end of the Historic Year shall be provided. b) An additional schedule showing the calculation of return and rate of return on invested capital in total plant (rate base) shall be provided. Return is computed based on the amount of interest expense requirement at the end of the year times the 1.20 times Net TIER, less non-operating margins, plus other interest expense and other deductions. Supporting year- end financial statements and any other documents necessary to support the debt outstanding at year-end and the calculation of return, including the sources of non-operating margins, shall be provided.

Electric Distribution Cooperatives An electric distribution cooperative may request the use a rate of return based on the TSP’s interest expense on long term debt outstanding at the end of the Historic Year and a modified times interest earned ratio excluding capital credits (modified TIER). The TSP shall justify the use of its requested rate of return and specify the reasonable circumstances that warrant its use.

Description of Schedules: a) A schedule showing the interest expense requirement for each debt issue outstanding at the end of Historic Year shall be provided. b) An additional schedule calculating return and rate of return on invested capital in total plant (rate base) shall be provided. Return is computed based on the amount of interest expense requirement at year end times the 2.0 times modified TIER, less non-operating income other than capital credits, plus other interest expense and other deductions. Supporting year-end financial statements and any other documents necessary to support the debt outstanding at year-end and the calculation of return, including the sources of non-operating income, shall be provided.

Municipal Utilities or River Authorities Municipal Utilities or River Authorities electing to use the TIER method will be considered on a case-by-case basis.

SCHEDULE D: OPERATION & MAINTENANCE EXPENSES Schedule D-1: O&M Expenses This schedule shall include the TSP’s overall operations and maintenance expenses according to FERC accounts 500-917 for the Historic Year, functionalized pursuant to General Instruction No. 11. The documentation shall itemize the wheeling expenses incurred for the old contracts on a contract by contract basis. Utilities may reclassify some amounts among functions, consistent with Commission’s Substantive Rule 25.192(b). Any reclassification of expenses shall be made in accordance with General Instruction No. 9. Supporting workpapers that fully and clearly explain the functionalization of each account or subaccount shall be included in the workpaper section, and any functionalization factors shall be referenced to the appropriate factors in Schedule F.

Schedule D-2: A&G Expenses This schedule shall show the annual expenses in FERC accounts 920-935 for the Historic Year, functionalized pursuant to General Instruction No. 11. Supporting workpapers that fully and clearly explain the functionalization of each account or subaccount shall be included in the workpaper section, and any functionalization factors shall be referenced to the appropriate factors in Schedule F.

Schedule D-3: Payroll Expense Distribution This schedule shall present the payroll expense for the Historic Year by FERC primary account functionalized pursuant to General Instruction No. 11. For the purpose of General Instruction No. 11, Payroll Expenses shall be functionalized using the same factors as the respective accounts in the O&M schedules. For accounts, which are functionalized using a composite factor, the respective composite factors shall be developed based on Payroll information only.

Supporting workpapers that fully and clearly explain the functionalization of each account or subaccount shall be included in the workpaper section, and any functionalization factors shall be referenced to the appropriate factors in Schedule F.

Schedule D-5: Summary of Exclusions from Reporting Period (See Attached Form) This schedule shall present a summary of all reporting period expenditures for items not allowed to be included in the TSP’s cost of service by statute or commission rule.

SCHEDULE E: OTHER ITEMS Schedule E-1: Depreciation Expense This schedule shall show the TSP’s overall unbundled depreciation expense for the Historic Year for the TSP’s plants and shall be based on Commission approved depreciation rates or an updated depreciation study. If a TSP does not have Commission approved depreciation rates, the TSP shall provide the basis for the depreciation rates used and explain the process by which the rates were established. Documentation supporting the approval of the depreciation rates used shall be provided. Plant depreciation rates and depreciation expense shall be shown by FERC Account, functionalized pursuant to General Instruction No. 11. All adjustments appearing on this schedule shall be referenced to detailed workpapers, computations, and analyses.

Presentation shall be such that amounts can be readily determined and all costs to be included in each function shall be referenced to the detailed schedules and/or the appropriate workpapers, computations and analyses. Supporting workpapers that fully and clearly explain the functionalization of each account or subaccount shall be included in the workpaper section, and any functionalization factors shall be referenced to the appropriate factors in Schedule F.

Schedule E-2: Taxes Other Than Federal Income Taxes This schedule shall show the amount of other taxes, excluding federal income taxes, assessed on or paid for by the TSP for the Historic Year, functionalized pursuant to General Instruction No. 11. Supporting workpapers that fully and clearly explain the functionalization of each account or subaccount shall be included in the workpaper section, and any functionalization factors shall be referenced to the appropriate factors in Schedule F. To the extent that PURA identifies the functionally separated business entities of the TSP that are responsible for payment of specific revenue related taxes, these taxes will be directly assigned to these entities in accordance with the statute.

Schedule E-3: Federal Income Tax Federal Income Taxes shall be calculated using the return method for the Historic Year, functionalized pursuant to General Instruction 11. Supporting explanations and calculations shall be referenced to this schedule, and if not found elsewhere in the TCOS-RFP, shall be provided as workpapers to this schedule. Supporting workpapers that fully and clearly explain the functionalization of each account or subaccount shall be included in the workpaper section, and any functionalization factors shall be referenced to the appropriate factors in Schedule F.

Schedule E-4: Other Expenses This schedule shall show all items not classified elsewhere, functionalized on the same basis as the underlying expense and consistent with General Instruction No. 11. All items shall be identified on an item by item basis and supporting workpapers shall be provided. Supporting workpapers that fully and clearly explain the functionalization of each account or subaccount shall be included in the workpaper section, and any functionalization factors shall be referenced to the appropriate factors in Schedule F.

Schedule E-5: Other Revenue Items (credit) This schedule shall show all other revenue credits functionalized on the same basis as the underlying assets or activities and consistent with General Instruction No. 11. Wheeling revenues shall not be credited to Transmission function. Revenues from transmission of electric energy out of ERCOT over DC ties that is not recovered through rates for annual planned transmission service and revenue from monthly, weekly, and daily planned transmission service, however, shall be credited to Transmission. Supporting documentation shall be provided. The portion of the revenue credits functionalized to transmission function shall be deducted from the TSP’s total cost of service for transmission.

Schedule E-6: Wheeling Revenue under Existing Contracts This schedule shall detail the amount of wheeling revenues received under existing contracts on contract by contract basis.

SCHEDULE F: FUNCTIONALIZATION FACTORS 1. Provide a listing of functionalization factors and associated data, which shall include the following information for every factor, used to assign costs to a function: a. A narrative description of the functionalization factor if code designation is used. b. The relative (decimal representations of percentages) amounts constituting the functionalization factors. c. The absolute amounts constituting the factors. That is the data used as numerators and divisors in calculating the functionalization factors in b. above.

2. Provide workpapers and a narrative explanation to support the calculation of each functionalization factor listed in 1 above. To the extent that data provided elsewhere in this filing package are employed in directly developing the functionalization factors, workpapers shall be referenced directly to this data.

3. For direct assignment (General Instruction No. 11(a)) and account-specific assignment (General Instruction No. 11(b)) of costs, provide a narrative description of the justification for such assignment.

The following table lists factors, which may be used to functionalize costs pursuant to General Instruction No. 11 (c). For FERC accounts, which do not appear in this table, it is assumed that all costs will be functionalized pursuant to General Instruction Nos. 11(a) and 11(b).

This table is for reference and summary purposes only. Specific instructions given elsewhere in this rate-filing package control over any summary information presented in this table.

FERC Acct. TITLE SUBACCOUNT ALLOCATOR 301 Organization Revenue-Related TOTREV Items 301 Organization Plant-Related Items PLTSVC-NX 302 Franchise and Consents Revenue-Related TOTREV Items 302 Franchise and Consents Plant-Related Items PLTSVC-NX 303 Misc. Intangible Plant Revenue-Related TOTREV Items 303 Misc. Intangible Plant Plant-Related Items PLTSVC-NX 310-346 Generation Plant GEN (re-classify GEN/TRAN per 25.192 (b)) 350-359 Transmission Plant TRAN (re-classify TRAN/GEN or TRAN/DIST per 25.192 (b)) 360-373 Distribution Plant DIST (re-classify DIST/TRAN per 25.192(b)) 389 Land and Land Rights SQFT 390 Structures and Improvements SQFT 391 Office Furniture and Equipment SQFT 392 Transportation MILE Equipment 393 Stores Equipment PLTXGNL-N 394 Tools, Shop and Garage PLTXGNL-N Equipment 395 Laboratory Equipment PLTXGNL-N 396 Power Operated PLTXGNL-N Equipment 397 Communication Schedule B-5 Equipment 398 Misc. Equipment PLTXGNL-N 500-554 GEN O&M GEN 555 Purchased Power Wholesale GEN/TRAN based on supplier info 555 Purchased Power Cogenerator GEN 555 Purchased Power Economy Energy GEN (TRAN for losses) 556 System Control and Load Dispatching GEN/TRAN - direct assignment 557 Other Expenses GEN 560-564, Transmission O&M TRAN 566-574 565 Wheeling Expenses DIST (ERCOT) 580-598 Distribution O&M DIST 901 Supervision DIST 902 Meter Reading Expense DIST 903.E Customer Records and Collection Expenses DIST Collection Expenses 903.R Customer Records and Customer Records DIST Collection Expenses 905 Misc. Customer Account Exp. DIST 907-917 Customer Service & DIST Information,Sales 920 A&G Salaries PAYXAG 921 Office Supplies PAYXAG 922 Admin. Expenses Transferred PAYXAG 923 Outside Services TOMXFP 924 Property Insurance PLTSVC-N Expense 925 Injuries and Damages PAYXAG 926 Pensions and Benefits PAYXAG 927 Franchise Requirements DIST 928 Regulatory Expenses TOTREV (PUC assessment DIST)

930 Misc. General Expense Plant-related PLTSVC-N 930 Misc. General Expense Personnel-related PAYXAG 931 Rents PAYXAG 935 Maint. Of General Plant GNLPLT-N

Where a one or more of the three functions is listed in the Functionalization Factor column, the costs in that FERC account shall be assigned exclusively to the function(s) listed. The remaining functionalization factors in the above table are defined as follows: C902_3 Composite allocator, comprised of FERC accounts 902 and 903 PAYROLL Total Payroll PAYXAG Payroll, excluding Administrative and General Salaries and excluding Contract Labor PAYXAGIC Payroll excluding Administrative and General Salaries and including Contract Labor PLTXGNL-N Net Plant, excluding General Plant PLTSVC-N Net Plant in Service PLTSVC-NX Net Plant in Service, excluding Intangible Plant SQFT Building Square Footage allocator (Assume Human Resources (HR) occupies one tenth of the total office space, therefore one tenth of total expense and rate base items for which square feet is an appropriate cost driver such as furniture, heating etc. will be allocated to the HR cost center, later HR costs will be allocated based on payroll or number of employees ( appropriate cost drivers for HR functions) to the user of the HR services.)

TOMXFP Total Operations and Maintenance Expenses, excluding Fuel and Purchased Power TOTREV Total Revenue TRB Total Rate Base MILE Miles driven on the transportation equipment

SECTION II: FORECAST YEAR DATA

Schedule A(f): Summary of Transmission Cost of Service (See Attached Form) This schedule shall provide the TSP’s Forecast Year unbundled cost of service for the transmission function. It shall begin with the Historic Year cost of service for this function as reported on Schedule A-1. An additional column shall present the forecast adjustments to the Historic Year which are necessary to reach the Forecast Year. All adjustments appearing on this schedule shall be referenced to detailed workpapers, computations, and analyses. Presentation shall be such that amounts can be readily determined and all costs to be included in each function shall be referenced to the detailed schedules B(f) through E(f) and/or the appropriate workpapers, computations and analyses.

SCHEDULE B(f): RATE BASE Schedule B(f): Summary of Transmission Rate Base (See Attached Form) This schedule shall provide the TSP’s forecasted transmission rate base. It shall begin with the Historic Year rate base as reported on Schedule B for the transmission function. An additional column shall present the forecast adjustments to the Historic Year, which are necessary to reach the Forecast Year. Only plant in service projected to be in service at December 31, 2002 shall be allowed. All adjustments appearing on this schedule shall be referenced to detailed workpapers, computations, and analyses. Presentation shall be such that amounts can be readily determined and all costs to be included in each function shall be referenced to the detailed schedules B(f)-1 and B(f)-12 and/or the appropriate workpapers, computations and analyses.

Schedule B(f)-1: Original Cost of Transmission Plant This schedule shall provide, by FERC account, the TSP’s estimated plant balances as of the end of the Forecast Year for the transmission function. It shall begin with the corresponding Historic Year-end balances presented on Schedule B-1. An additional column shall present forecast adjustments to the historic balances necessary to reach the plant balances expected to be in service at the end of the Forecast Year. Only plant in service projected to be in service at the end of the Forecast Year shall be allowed. All adjustments appearing on this schedule shall be referenced to detailed workpapers, computations, and analyses. Presentation shall be such that amounts can be readily determined and all costs to be included in each function shall be referenced to the detailed schedules and/or the appropriate workpapers, computations and analyses.

Schedule B(f)-2: General Plant Functionalized to Transmission This schedule shall detail the amounts of general plant for the Forecast Year functionalized to transmission by FERC accounts 389-399. It shall begin with the corresponding Historic Year- end balances presented on Schedule B-2. An additional column shall present forecast adjustments to the historic balances necessary to reach the plant balances expected to be in service at the end of the Forecast Year. Supporting workpapers that fully and clearly explain the forecast adjustments to each account shall be included in the workpaper section.

Schedule B(f)-3: Communication Equipment in Transmission This schedule shall show the balance of communication equipment for the Forecast Year in FERC Account 397, or other account (specify) where such equipment is booked as reported on Schedules B(f)-1 and B(f)-2 and as functionalized to transmission. It shall begin with the corresponding Historic Year-end balances presented on Schedule B-3. An additional column shall present forecast adjustments to the historic balances necessary to reach the plant balances expected to be in service at the end of the Forecast Year. Supporting workpapers that fully and clearly explain the forecast adjustments to each account shall be included in the workpaper section.

Schedule B(f)-4.: Unbundled Construction Work in Progress in Transmission This schedule shall detail the amounts of construction work in progress for the Forecast Year functionalized to transmission. It shall begin with the corresponding Historic Year-end balances presented on Schedule B-4. An additional column shall present forecast adjustments to the historic balances necessary to reach the plant balances expected to be in service at the end of the Forecast Year. Supporting workpapers that fully and clearly explain the forecast adjustments to each account shall be included in the workpaper section.

Schedule B(f)-5: Unbundled Accumulated Depreciation in Transmission This schedule shall detail the accumulated provisions for depreciation by primary account classification (e.g., 350-359, 360-373, 389, etc.) for the Forecast Year that is functionalized to transmission. It shall begin with the corresponding Historic Year-end balances presented on Schedule B-5. An additional column shall present forecast adjustments to the historic balances necessary to reach the account balances expected at the end of the Forecast Year. Supporting workpapers that fully and clearly explain the forecast adjustments to each account shall be included in the workpaper section.

Schedule B(f)-6: Unbundled Plant Held for Future Use in Transmission This schedule shall show the amount of Electric Plant Held for Future Use (EPHFU) as of the end of the Forecast Year and as functionalized to transmission. It shall begin with the corresponding Historic Year-end balances presented on Schedule B-6. Additional columns shall present forecast adjustments to the historic balances necessary to reach the plant balances expected to be in service at the end of the Forecast Year. Supporting workpapers that fully and clearly explain the forecast adjustments to each account shall be included in the workpaper section.

Schedule B(f)-7: Unbundled Accumulated Provision Balances in Transmission This schedule shall show the ending balance (Forecast Year) of each accumulated provision account (i.e., injuries and damages, property insurance, etc.) as functionalized to transmission. It shall begin with the corresponding Historic Year-end balances presented on Schedule B-7. An additional column shall present forecast adjustments to the historic balances necessary to reach the account balances expected at the end of the Forecast Year. Supporting workpapers that fully and clearly explain the forecast adjustments to the total amounts shall be included in the workpaper section.

Schedule B(f)-8: Materials and Supplies in Transmission This schedule shall show the total amount of Materials and Supplies (M&S) as of the end of the Forecast Year and as functionalized to transmission. It shall begin with the corresponding Historic Year-end balances presented on Schedule B-8. An additional column shall present forecast adjustments to the historic balances necessary to reach the account balances expected to be in service at the end of the Forecast Year. Supporting workpapers that fully and clearly explain the forecast adjustments to the total amount shall be included in the workpaper section.

Schedule B(f)-9: Cash Working Capital in Transmission This schedule shall show the total amount of Cash Working Capital included in transmission rate base as of the end of the Forecast Year. It shall begin with the corresponding Historic Year-end balances presented on Schedule B-9. An additional column shall present forecast adjustments to the historic balances necessary to reach the balances expected at the end of the Forecast Year.

The amount to be included will be in accordance with PUC Substantive Rule 25.231(c)(2)(B)(iii). Supporting workpapers that fully and clearly explain the forecast adjustments to the total shall be included in the workpaper section.

Schedule B(f)-10: Prepayments in Transmission This schedule shall show the amount of Prepayments as of the end of the Forecast Year and as functionalized to transmission. It shall begin with the corresponding Historic Year-end balances presented on Schedule B-10. An additional column shall present forecast adjustments to the historic balances necessary to reach the account balances expected at the end of the Forecast Year. Supporting workpapers that fully and clearly explain the forecast adjustments to the total shall be included in the workpaper section.

Schedule B(f)-11: Other Rate Base Items in Transmission This schedule shall detail all other rate base items for the Forecast Year not included in the previous categories that are functionalized to transmission. It shall begin with the corresponding Historic Year-end balances presented on Schedule B-11. An additional column shall present forecast adjustments to the historic balances necessary to reach the plant balances expected to be in service at the end of the Forecast Year. Supporting workpapers shall be included showing the derivation of the amounts included.

Schedule B(f)-12: Regulatory Assets (See Attached Form) The TSP shall provide the total amount of regulatory assets detail on an asset-by-asset basis for the Forecast Year as functionalized to the transmission function. It shall begin with the corresponding Historic Year-end balances presented on Schedule B-12. An additional column shall present forecast adjustments to the historic balances necessary to reach the asset balances expected at the end of the Forecast Year. Supporting workpapers that fully and clearly explain the forecast adjustments to the total shall be included in the workpaper section.

SCHEDULE C(f): RATE OF RETURN, DEBT SERVICE COVERAGE, CASH FLOW, OR TIMES INTEREST EARNED RATIO Schedule C(f)-1: Rate of Return Method:: For utilities electing to make a transmission cost of service filing using a Forecast Year, a forecast showing the calculation of the TSP’s weighted average cost of capital shall be provided.

Schedule C(f)-2: Debt Service Coverage Method: For utilities required or electing to make a transmission cost of service filing on a Forecast Year, a forecast debt service coverage shall be used and supported with an appropriate schedule.

Schedule C(f)-3: Cash Flow Method: For utilities required or electing to make a transmission cost of service filing on a Forecast Year, a forecast cash flow shall be used and supported with an appropriate schedule.

Schedule C(f)-4: Times Interest Earned Method: For utilities required or electing to make a transmission cost of service filing on a Forecast Year, a forecast times interest earned shall be used and supported with an appropriate schedule.

SCHEDULE D(f): OPERATION & MAINTENANCE EXPENSES Schedule D(f)-1: Transmission O&M Expenses This schedule shall include the TSP’s overall operations and maintenance expenses according to FERC accounts 500 – 917 for the Forecast Year as functionalized to transmission. It shall begin with the corresponding Historic Year-end balances presented on Schedule D-1. An additional column shall present forecast adjustments to the historic balances necessary to reach the Forecast Year expenses. Supporting workpapers that fully and clearly explain the forecast adjustments to the total shall be included in the workpaper section. Presentation shall be such that amounts can be readily determined and all costs to be included in each function shall be referenced to the detailed schedules and/or the appropriate workpapers, computations, and analyses.

Schedule D(f)-2: A&G Expenses in Transmission This schedule shall show the annual expenses in FERC accounts 920-935 for the Forecast Year and as functionalized to transmission. It shall begin with the corresponding Historic Year-end balances presented on Schedule D-3.1. An additional column shall present forecast adjustments to the historic expenses necessary to reach the Forecast Year expenses. Supporting workpapers that fully and clearly explain the forecast adjustments to the total amounts shall be included in the workpaper section.

SCHEDULE E(f): OTHER ITEMS Schedule E(f)-1: Transmission Depreciation Expense This schedule shall show the TSP’s overall depreciation expense for plants functionalized to transmission for the Forecast Year and shall be based on Commission-approved depreciation rates. If a TSP does not have Commission approved depreciation rates, the TSP shall provide the basis for the depreciation rates used and explain the process by which the rates were established.

Documentation supporting the approval of the depreciation rates used shall be provided. Plant depreciation rates and functionally unbundled depreciation expense shall be shown by FERC Account. To calculate the unbundled depreciation expense for the Forecast Year, the TSP shall begin with the Historic Year expense for transmission function. An additional column shall present the forecast adjustments to the Historic Year which are necessary to reach the Forecast Year. Only plant in service projected to be in service at December 31, 2002 shall be allowed.

All adjustments appearing on this schedule shall be referenced to detailed workpapers, computations, and analyses. Presentation shall be such that amounts can be readily determined and all costs to be included in each function shall be referenced to the detailed schedules and/or the appropriate workpapers, computations and analyses.

Schedule E(f)-2: Taxes Other Than Federal Income Taxes in Transmission This schedule shall show the amount of other taxes, excluding federal income taxes, for the Forecast Year functionalized to transmission. It shall begin with the corresponding Historic Year-end balances presented on Schedule E(f)-2. An additional column shall present forecast adjustments to the historic expenses necessary to reach the Forecast Year expenses.

Schedule E(f)-3: Federal Income Taxes Federal Income Taxes will be calculated using the return method for the Forecast Year.

Supporting explanations and calculations shall be referenced to this schedule, and if not found elsewhere in the TCOS-RFP, shall be provided as workpapers to this schedule. It shall begin with the corresponding Historic Year expenses presented on the corresponding Historic Year schedule. Additional columns shall present forecast adjustments to the historic expenses necessary to reach the Forecast Year expenses.

Schedule E(f)-4: Other Expenses in Transmission This schedule shall show all items not classified elsewhere and functionalized to transmission.

All items shall be identified on an item by item basis and supporting workpapers shall be provided. It shall begin with the corresponding Historic Year-end balances presented on Schedule E-4. An additional column shall present forecast adjustments to the historic expenses necessary to reach the Forecast year expenses.

Schedule E(f)-5: Other Revenue Items (credit) in Transmission Other revenue credits shall be directly assigned or itemized and functionalized in this schedule.

Supporting documentation shall be provided. It shall begin with the corresponding Historic Year- end balances presented on Schedule E-5. Additional columns shall present forecast adjustments to the historic expenses necessary to reach the Forecast Year revenues. Wheeling revenues shall not be credited to Transmission function. TSP’s share of the total ERCOT wide revenues (based on the ERCOT wide ISO forecast) from transmission of electric energy out of ERCOT over DC ties and revenue from monthly, weekly, and daily planned transmission service, that is not recovered through rates for annual planned transmission service however, shall be credited to Transmission revenue requirement of the TSP.

SECTION III AFFILIATE DATA General Instructions 1. The affiliate filing requirements apply to TSPs in ERCOT having affiliates that have provided services or property the value of which is included in one of the three functions.

2. The definition of transmission costs for purposes of this filing shall be coordinated and consistent with the definition of these costs in Commission Substantive Rule 25.341.

Appropriate consideration should be given to the guidance provided by FERC through its account classification and functional descriptions.

3. For purposes of this filing, transmission costs shall include transmission–related, e.g., transmission–related administrative and general (A&G) costs in support of Texas activities.

4. The term “per book” is the Historic Year without pro-forma adjustments.

5. The term “net requested” amount for an item is the Historic Year with pro-forma adjustments to the Forecast Year and represents the revenue requirement on which the revised transmission rates are to be set.

Guiding Principles 1. To the extent that the affiliate standard prescribed by §36.058 of PURA is applicable in this filing, it should only be applied to the transmission function. However, in order to satisfy the requirements of §36.058, the Commission and other parties will be provided the affiliate costs charged to the three functions as well as to the other affiliates.

2. Transmission costs shall be presented in sufficient detail (e.g., transmission operations, transmission maintenance, FERC accounts 560 – 562, FERC accounts 568-574, or other logical groupings of services) to permit the Commission to conduct the review as required by PURA §36.058.

3. The following are examples of the types of evidence that may be presented to support the applicant’s burden of proof for the recovery of affiliate costs: a. historical cost trends; b. process improvements aimed at achieving efficiency; c. benchmark data. It is acknowledged that benchmark comparisons may not be available for all transmission costs. To the extent that certain relevant costs are not included in the benchmark data used for comparison purposes, other evidence may be provided to address those costs. d. outsourcing results; e. proof of customer benefit; f. a showing that services are not duplicated at the TSP; g. comparison of Historic Year costs to costs that would be expected if the TSP were a stand-alone company; cost control processes (e.g., budget, billing, audits); reviews by independent third parties; operational performance statistics; information regarding quality of management; service performance metrics; FTE statistics; and SAIDI/SAIFI data, FERC Form 1 data The items listed above are for illustrative purposes only; the TSP shall provide whatever information necessary to meet its burden of proof.

4. Transmission expenses will include an assignment/allocation of amounts (hereinafter referred to as “assigned expenses”) not recorded in transmission and distribution expense FERC accounts 560 – 574 (e.g., A&G FERC accounts 920 – 935). The expenses accumulated under accounts 920-935 shall be aggregated in classes, with sufficient detail provided to enable the Commission to evaluate whether the expenses are reasonable.

SCHEDULE N: AFFILIATE DATA Schedule N-1A: Schedule showing transmission affiliate expenses by FERC account grouped and subtotaled by class of items for the Historic Year.

Schedule N-1B: Schedule showing affiliate transmission expenses by FERC account grouped and subtotaled by class of items for the Forecast Year.

Schedule N-2A: Schedule showing transmission affiliate expenses listed by affiliate by FERC account on a per book basis; specific pro-forma adjustments; and on an adjusted basis for the Historic Year Schedule N-2B: Schedule showing transmission affiliate expenses listed by affiliate by FERC account on an adjusted basis for the Historic Year; specific pro-forma adjustments; and on an adjusted basis for the Forecast Year Schedule N-3A: Organization chart for the TSP system showing all regulated and non-regulated affiliates as of the end of the Historic Year.

Schedule N-3B: Organization chart for the TSP system showing all regulated and non-regulated affiliates as of the end of the Forecast Year.

Schedule N-4A: Description of types of services provided by other affiliates to the TSP for the Historic Year.

Identify specific services provided by each affiliate.

Schedule N-4B: Description of types of services provided by other affiliates to the TSP for the Forecast Year.

Identify specific services provided by each affiliate.

Schedule N-5A: Schedule showing transmission capital projects by affiliate. Amounts closed to total requested plant-in-service since the last base rate case or four years, whichever is shorter, unless ordered otherwise, and a discussion of the significant projects based on amount or project category.

Schedule N-5B: Schedule showing transmission capital projects by affiliate amounts closed to plant-in-service from the end of the Historic Year to the end of the Forecast Year, unless ordered otherwise, and a discussion of the significant projects based on amount or project category.

Schedule N-6A: Schedule showing adjustments to per book costs for the Historic Year including the description, purpose, and amount for each adjustment. This schedule must correlate with the Schedule N-2 listing pro-forma adjustments to Historic Year. For any adjustment where a difference exists between Schedule N-2 and this schedule reconciliation must be provided.

Schedule N-6B: Schedule showing adjustments to per book costs for the Historic Year transmission costs including the description, purpose, and amount for each adjustment. This schedule must correlate with the Schedule 2A listing pro-forma adjustments to the adjusted Historic Year. For any adjustment where a difference exists between Schedule N-2A and this schedule a reconciliation must be provided.

Schedule N-7A: For each class of affiliate charges in the Historic Year, this schedule will show the categories of services included in the affiliate transmission costs; the total amount in the Historic Year; a discussion of necessity and reasonableness of the services/costs; and a “no higher than” standard analysis.

Schedule N-7B: For each class of affiliate charges in the Forecast Year, this schedule will show the categories of services included in the affiliate transmission costs; the total amount in the Forecast Year; a discussion of necessity and reasonableness of the services/costs; and a “no higher than” standard analysis.

Schedule N-8: This schedule shall detail per book charges to other affiliate companies by FERC account. This schedule format should list the affiliate company providing the identified service.

Schedule N-9A: Schedule N-9A applies to each TSP having affiliates that have provided services or property the value of which is included in one of the three functions. This schedule shall consist of a description of the affiliate billing process, including the manner in which costs are recorded by project/activity code or work order and the process by which costs are allocated to each affiliate.

This schedule shall include allocation formulas and their derivations for the Historic Year.

Schedule N-9B: Schedule N-9A applies to each TSP having affiliates that have provided services or property the value of which is included in one of the three functions. This schedule shall consist of a description of the affiliate billing process, including the manner in which costs are recorded by project/activity code or work order and the process by which costs are allocated to each affiliate.

This schedule shall include allocation formulas and their derivations for the Forecast Year.

Schedule N-10A: This schedule shall describe controls that are in place during the Historic Year to ensure appropriate billing for affiliate services. These controls shall include (but not be limited to) controls related to internal audits, external reviews, frequency with which allocation formulas are updated and internal procedures for challenges to affiliate expenses billed (such as billing review committees and processes for correction of billing errors).

Schedule N-10B: This schedule shall describe controls that are in place during the Forecast Year to ensure appropriate billing for affiliate services. These controls shall include (but not be limited to) controls related to internal audits, external reviews, frequency with which allocation formulas are updated and internal procedures for challenges to affiliate expenses billed (such as billing review committees and processes for correction of billing errors).

Schedule N-11: Schedule showing billing methods used by affiliates to bill net requested transmission costs to the TSP.

Schedule N-12: This schedule shall show the amounts and percentages of each expense by function billed to the TSP and each affiliate for each billing method.

Workpapers shall be provided to show the calculation of the net requested affiliate amounts in the level of detail necessary for the Commission and other parties to duplicate and track the calculation of the costs Applicant has presented for recovery. These workpapers would include but not be limited to: a description of the manner in which the affiliate costs and schedules are presented; affiliate costs by witness, by class and by project/activity code or work order; project/activity or work order summaries; affiliate billings by FERC account and class; affiliate billings by class and project/activity code or work order; and affiliate billings by class, FERC account and by project/activity code or work order.

SECTION IV FORMS Schedule W: Confidentiality Schedule

Sample Forms (Schedules : A, B, B-12, D-5, A(f), B(f), B(f)-12)

Tab 4 16 Tex. Admin. Code § 25.192 § 25.192. Transmission Rates for Export from ERCOT, 16 TX ADC § 25.192

Texas Administrative Code Title 16. Economic Regulation Part 2. Public Utility Commission of Texas Chapter 25. Substantive Rules Applicable to Electric Service Providers Subchapter I. Transmission and Distribution Division 1. Open-Access Comparable Transmission Service for Electric Utilities in the Electric Reliability Council of Texas TAC § 25.192 § 25.192. Transmission Rates for Export from ERCOT Currentness

(a) Tariffs. Each transmission service provider (TSP) shall file a tariff for transmission service to establish its rates and other terms and conditions and shall apply its tariffs and rates on a non-discriminatory basis. The tariff shall apply to all distribution service providers (DSPs) and any entity scheduling the export of power from the Electric Reliability Council of Texas (ERCOT) region. The tariff shall not apply to any entity engaging in wholesale storage as described by §25.501(m) of this title (relating to Wholesale Market Design for the Electric Reliability Council of Texas) (storage entity).

(b) Charges for transmission service delivered within ERCOT. DSPs, excluding storage entities, shall incur transmission service charges pursuant to the tariffs of the TSP.

(1) A TSP's transmission rate shall be calculated as its commission-approved transmission cost of service divided by the average of ERCOT coincident peak demand for the months of June, July, August and September (4CP), excluding the portion of coincident peak demand attributable to wholesale storage load. A TSP's transmission rate shall remain in effect until the commission approves a new rate. The TSP's annual rate shall be converted to a monthly rate. The monthly transmission service charge to be paid by each DSP is the product of each TSP's monthly rate as specified in its tariff and the DSP's previous year's average of the 4CP demand that is coincident with the ERCOT 4CP.

(2) Payments for transmission services shall be consistent with commission orders, approved tariffs, and §25.202 of this title (relating to Commercial Terms for Transmission Service).

(c) Transmission cost of service. The transmission cost of service for each TSP shall be based on the expenses in Federal Energy Regulatory Commission (FERC) expense accounts 560-573 (or accounts with similar contents or amounts functionalized to the transmission function) plus the depreciation, federal income tax, and other associated taxes, and the commission-allowed rate of return based on FERC plant accounts 350-359 (or accounts with similar contents or amounts functionalized to the transmission function), less accumulated depreciation and accumulated deferred federal income taxes, as applicable.

(1) The following facilities are deemed to be transmission facilities:

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(A) power lines, substations, reactive devices, and associated facilities, operated at 60 kilovolts or above, including radial lines operated at or above 60 kilovolts, except the step-up transformers and a protective device associated with the interconnection from a generating station to the transmission network;

(B) substation facilities on the high side of the transformer, in a substation where power is transformed from a voltage higher than 60 kilovolts to a voltage lower than 60 kilovolts;

(C) the portion of the direct-current interconnections with areas outside of the ERCOT region (DC ties) that are owned by a TSP in the ERCOT region, including those portions of the DC tie that operate at a voltage lower than kilovolts; and

(D) capacitors and other reactive devices that are operated at a voltage below 60 kilovolts, if they are located in a distribution substation, the load at the substation has a power factor in excess of 0.95 as measured or calculated at the distribution voltage level without the reactive devices, and the reactive devices are controlled by an operator or automatically switched in response to transmission voltage.

(E) As used in subparagraphs (A)-(D) of this paragraph, reactive devices do not include generating facilities.

(2) For municipally owned utilities, river authorities, and electric cooperatives, the commission may permit the use of the cash flow method or other reasonable alternative methods of determining the annual transmission revenue requirement, including the return element of the revenue requirement, consistent with the rate actions of the rate-setting authority for a municipally owned utility.

(3) For municipally owned utilities, river authorities, and electric cooperatives, the return may be determined based on the TSP's actual debt service and a reasonable coverage ratio. In determining a reasonable coverage ratio, the commission will consider the coverage ratios required in the TSP's bond indentures or ordinances and the most recent rate action of the rate setting authority for the TSP.

(4) A municipally owned utility that is required to apply for a certificate of public convenience and necessity to construct, install, or extend a transmission facility within ERCOT pursuant to §25.101 of this title (relating to Certification Criteria) is entitled to recover, through the utility's wholesale transmission rate, reasonable payments made to a taxing entity in lieu of ad valorem taxes on that transmission facility, provided that:

(A) The utility enters into a written agreement with the governing body of the taxing entity related to the payments;

(B) The amount paid is the same as the amount the utility would have to pay to the taxing entity on that transmission facility if the facility were subject to ad valorem taxation;

(C) The governing body of the taxing entity is not the governing body of the utility; and

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(D) The utility provides the commission with a copy of the written agreement and any other information that the commission considers necessary in relation to the agreement.

(5) The commission may adopt rate-filing requirements that provide additional details concerning the costs that may be included in the transmission costs and how such costs should be reported in a proceeding to establish transmission rates.

(d) Billing units. No later than December 1 of each year, ERCOT shall determine and file with the commission the current year's average 4CP demand for each DSP, or the DSP's agent for transmission service billing purposes, as appropriate, excluding the portion of coincident peak demand attributable to wholesale storage load. This demand shall be used to bill transmission service for the next year. The ERCOT average 4CP demand shall be the sum of the coincident peak of all of the ERCOT DSPs, excluding the portion of coincident peak demand attributable to wholesale storage load, for the four intervals coincident with ERCOT system peak for the months of June, July, August, and September, divided by four. As used in this section, a DSP's average 4CP demand is determined from the total demand, coincident with the ERCOT 4CP, of all customers connected to a DSP, including load served at transmission voltage, but excluding the load of wholesale storage entities. The measurement of the coincident peak shall be in accordance with commission-approved ERCOT protocols.

(e) Transmission rates for exports from ERCOT. A transmission service charge for exports of power from ERCOT must be assessed to transmission service customers for transmission service within the boundaries of the ERCOT region, in accordance with this section and the ERCOT protocols.

(1) A transmission service customer must be assessed a transmission service charge for the use of the ERCOT transmission system in exporting power from ERCOT based on scheduled exports and the rates established under subsections (c) and (d) of this section. The intervals must consist of one hour.

(2) The hourly transmission rate for exports from ERCOT will be the TSP's annual rate established under subsections (c) and (d) of this section divided by 8760.

(3) The entity scheduling the export of power over a DC tie is solely responsible to the TSP for payment of transmission service charges under this subsection.

(4) Beginning with the January 2023 reporting month, ERCOT must file a public report with the commission stating the total amount of energy imported and the total amount of energy exported over each DC tie for the calendar month. The report must also include the total amount of energy exported from the ERCOT region during the reporting month and each of the preceding 11 calendar months, reported by scheduling entity. Each report must be filed within 45 days of the end of the reporting month.

(f) Transmission revenue. Revenue from the transmission of electric energy out of the ERCOT region over the DC ties that is recovered under subsection (e) of this section shall be credited to all transmission service customers as a reduction in the transmission cost of service for TSPs that receive the revenue.

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(g) Revision of transmission rates. Each TSP in the ERCOT region shall periodically revise its transmission service rates to reflect changes in the cost of providing such services. Any request for a change in transmission rates shall comply with the filing requirements established by the commission under this section.

(h) Interim Update of Transmission rates.

(1) Frequency. Each TSP in the ERCOT region may apply to update its transmission rates on an interim basis not more than once per calendar year to reflect changes in its invested capital. Upon the effective date of an amendment to §25.193 pursuant to an order in Project Number 37909, Rulemaking Proceeding to Amend P.U.C. Subst. R. 25.193, Relating to Distribution Service Provider Transmission Cost Recovery factors (TCRF), that allows a distribution service provider to recover, through its transmission cost recovery factor, all transmission costs charged to the distribution service provider by TSPs, each TSP in the ERCOT region may apply to update its transmission rates on an interim basis not more than twice per calendar year to reflect changes in its invested capital. If the TSP elects to update its transmission rates, the new rates shall reflect the addition and retirement of transmission facilities and include appropriate depreciation, federal income tax and other associated taxes, and the commission authorized rate of return on such facilities as well as changes in loads. If the TSP does not have a commission-authorized rate of return, an appropriate rate of return shall be used.

(2) Reconciliation. An update of transmission rates under paragraph (1) of this subsection shall be subject to reconciliation at the next complete review of the TSP's transmission cost of service, at which time the commission shall review the costs of the interim transmission plant additions to determine if they were reasonable and necessary. Any amounts resulting from an update that are found to have been unreasonable or unnecessary, plus the corresponding return and taxes, shall be refunded with carrying costs determined as follows: for the time period beginning with the date on which over-recovery is determined to have begun to the effective date of the TSP's rates set in that complete review of the TSP's transmission cost of service, carrying costs shall be calculated using the same rate of return that was applied to the transmission investments included in the update. For the time period beginning with the effective date of the TSP's rates set in that complete review of the TSP's transmission cost of service, carrying costs shall be calculated using the TSP's rate of return authorized in that complete review.

(3) Future consideration of effect on TSP's financial risk and rate of return. For a TSP that has increased its rates pursuant to paragraph (1) of this subsection, the commission may, in setting rates in the next complete review of the TSP's transmission cost of service, expressly consider the effects of reduced regulatory lag resulting from the interim updates to the TSP's rates and the concomitant impact on the TSP's financial risk and rate of return.

(4) Commission processing of application. The commission shall process an application filed pursuant to paragraph (1) of this subsection in the following manner.

(A) Notice and intervention deadline. The applicant shall provide notice of its application to all parties in the applicant's last complete review of the applicant's transmission cost of service and all of the distribution service providers listed in the last docket in which the commission set the annual transmission service charges for the Electric Reliability Council of Texas. The intervention deadline shall be 21 days from the date service of notice is completed.

(B) Sufficiency of application. A motion to find an application materially deficient shall be filed no later than 21 days after an application is filed. The motion shall be served on the applicant by hand delivery, facsimile transmission,

© 2025 Thomson Reuters. No claim to original U.S. Government Works. 4 § 25.192. Transmission Rates for Export from ERCOT, 16 TX ADC § 25.192 or overnight courier delivery, or by e-mail if agreed to by the applicant or ordered by the presiding officer. The motion shall specify the nature of the deficiency and the relevant portions of the application, and cite the particular requirement with which the application is alleged not to comply. The applicant's response to a motion to find an application materially deficient shall be filed no later than five working days after such motion is received. If within ten working days after the deadline for filing a motion to find an application materially deficient, the presiding officer has not filed a written order concluding that material deficiencies exist in the application, the application is deemed sufficient.

(C) Review of application. A proceeding initiated pursuant to paragraph (1) of this subsection is eligible for disposition pursuant to §22.35(b)(1) of this title (relating to Informal Disposition). If the requirements of §22.35 of this title are met, the presiding officer shall issue a notice of approval within 60 days of the date a materially sufficient application is filed unless good cause exists to extend this deadline or the presiding officer determines that the proceeding should be considered by the commission.

(5) Filing Schedule. The commission may prescribe a schedule for providers of transmission services to file proceedings to revise the rates for such services.

(6) DSP's right to pass through changes in wholesale rates. A DSP may expeditiously pass through to its customers changes in wholesale transmission rates approved by the commission, pursuant to §25.193 of this title (relating to Distribution Service Provider Transmission Cost Recovery Factors (TCRF)).

(7) Reporting requirements. TSPs shall file reports that will permit the commission to monitor their transmission costs and revenues, in accordance with any filing requirements and schedules prescribed by the commission.

Credits Source: The provisions of this §25.192 adopted to be effective April 13, 1999, 24 TexReg 2874; amended to be effective September 30, 1999, 24 TexReg 8162; amended to be effective December 29, 1999, 24 TexReg 11722; amended to be effective June 20, 2001, 26 TexReg 4440; amended to be effective August 25, 2010, 35 TexReg 7195; amended to be effective April 18, 2012, 37 TexReg 2613; amended to be effective July 5, 2016, 41 TexReg 4805; amended to be effective December 20, 2022, 47 TexReg 8267.

Current through 50 Tex.Reg. No. 460, dated January 10, 2025, as effective on or before January 24, 2025. Some sections may be more current. See credits for details.

© 2025 Thomson Reuters. No claim to original U.S. Government Works. 5 Tab 5 16 Tex. Admin. Code § 22.80 § 22.80. Commission Prescribed Forms, 16 TX ADC § 22.80

Texas Administrative Code Title 16. Economic Regulation Part 2. Public Utility Commission of Texas Chapter 22. Procedural Rules Subchapter E. Pleadings and Other Documents TAC § 22.80 § 22.80. Commission Prescribed Forms Currentness

The commission may require that certain reports and applications be submitted on standard forms. The commission filing clerk shall maintain a complete index to and set of all commission forms. All documents that are the subject of an official form shall contain all matters designated in the official form and shall conform substantially to the official form. Prior to the implementation of any new form or significant change to an existing form, the change or new form shall be referenced in the “In Addition” section of the Texas Register for public comment. For good cause, new forms or significant changes to existing forms may be implemented without publication on an interim basis for a period not to exceed 180 days.

Credits Source: The provisions of this § 22.80 adopted to be effective November 1, 1993, 18 TexReg 6641; amended to be effective September 8, 1995, 20 TexReg 6627; amended to be effective September 23, 1999, 24 TexReg 7401.

Current through 50 Tex.Reg. No. 460, dated January 10, 2025, as effective on or before January 24, 2025. Some sections may be more current. See credits for details.

16 TAC § 22.80, 16 TX ADC § 22.80 End of Document © 2025 Thomson Reuters. No claim to original U.S. Government Works.

© 2025 Thomson Reuters. No claim to original U.S. Government Works. 1 Automated Certificate of eService This automated certificate of service was created by the efiling system.

The filer served this document via email generated by the efiling system on the date and to the persons listed below. The rules governing certificates of service have not changed. Filers must still provide a certificate of service that complies with all applicable rules.

David Laurent on behalf of Jordan Pratt Bar No. 24140277 [email protected] Envelope ID: 100837990 Filing Code Description: Brief Requesting Oral Argument Filing Description: Brief of Appellant Public Utility Commission of Texas Status as of 5/14/2025 3:35 PM CST Associated Case Party: Texas Industrial Energy Consumers Name BarNumber Email TimestampSubmitted Status Katherine Coleman 24059596 [email protected] 5/14/2025 3:17:02 PM SENT Michael McMillin [email protected] 5/14/2025 3:17:02 PM SENT John Hubbard [email protected] 5/14/2025 3:17:02 PM SENT

Associated Case Party: City of Denton Name BarNumber Email TimestampSubmitted Status Jamie Mauldin 24065694 [email protected] 5/14/2025 3:17:02 PM SENT Gabrielle Smith 24093172 [email protected] 5/14/2025 3:17:02 PM SENT Jose E.de la Fuente [email protected] 5/14/2025 3:17:02 PM SENT Amy Hoffee [email protected] 5/14/2025 3:17:02 PM SENT Marcella Lunn [email protected] 5/14/2025 3:17:02 PM SENT Roslyn Warner [email protected] 5/14/2025 3:17:02 PM SENT Devin Alexander [email protected] 5/14/2025 3:17:02 PM SENT

Case Contacts Name BarNumber Email TimestampSubmitted Status David Laurent [email protected] 5/14/2025 3:17:02 PM SENT Colton Halter [email protected] 5/14/2025 3:17:02 PM SENT

Associated Case Party: Public Utility Commission of Texas Name BarNumber Email TimestampSubmitted Status Automated Certificate of eService This automated certificate of service was created by the efiling system.

The filer served this document via email generated by the efiling system on the date and to the persons listed below. The rules governing certificates of service have not changed. Filers must still provide a certificate of service that complies with all applicable rules.

David Laurent on behalf of Jordan Pratt Bar No. 24140277 [email protected] Envelope ID: 100837990 Filing Code Description: Brief Requesting Oral Argument Filing Description: Brief of Appellant Public Utility Commission of Texas Status as of 5/14/2025 3:35 PM CST Associated Case Party: Public Utility Commission of Texas Name BarNumber Email TimestampSubmitted Status John RHulme [email protected] 5/14/2025 3:17:02 PM SENT Jordan Pratt [email protected] 5/14/2025 3:17:02 PM SENT

Associated Case Party: Office of Public Utility Counsel Name BarNumber Email TimestampSubmitted Status Chris Ekoh [email protected] 5/14/2025 3:17:02 PM SENT Justin Swearingen [email protected] 5/14/2025 3:17:02 PM SENT Christiana Segura 24143396 [email protected] 5/14/2025 3:17:02 PM SENT Sharbel Sfeir [email protected] 5/14/2025 3:17:02 PM SENT