MAINE SUPREME JUDICIAL COURT Reporter of Decisions Decision: 2025 ME 64 Docket: PUC-24-322 Argued: March 5, 2025 Decided: July 15, 2025 Panel: STANFILL, C.J., and MEAD, HORTON, LAWRENCE, and DOUGLAS, JJ.

SNAKEROOT SOLAR, LLC v. PUBLIC UTILITIES COMMISSION

DOUGLAS, J.

[¶1] Snakeroot Solar, LLC, appeals from an order of the Public Utilities Commission denying its petition for a good-cause exemption under 35-A M.R.S.

§ 3209-A(7) (2025) from the statute’s December 31, 2024, deadline—the date by which certain electric generating facilities must have “reach[ed] commercial operation” in order to participate in Maine’s net energy billing program.

Without the exemption, Snakeroot’s proposed photovoltaic generating facility in Pittsfield would be ineligible for net energy billing. Snakeroot contends that the Commission erred in its interpretation of the statute’s good-cause exemption; the Commission’s findings are unsupported by the record evidence; and its denial of the exemption constituted an abuse of discretion. We affirm the Commission’s order.

I. BACKGROUND A. The Net Energy Billing Program [¶2] Since the 1980s, Maine’s net energy billing1 (NEB) program has promoted alternative energy sources by allowing customers to offset their electric bills using the output from renewable power generators such as home-installed solar panels. In 2019, the Legislature significantly expanded the NEB program to permit utility customers with an interest in an electric generating facility with a capacity of up to five megawatts using certain “renewable fuel or technology,” see 35-A M.R.S. § 3210(2)(B-3) (2025), to participate in the program. P.L. 2019, ch. 478, §§ A-3, A-4 (effective Sept. 19, 2019) (codified as amended at 35-A M.R.S. §§ 3209-A, 3209-B (2025)) (“2019 NEB Act”).2 [¶3] The 2019 NEB Act prompted a sharp spike in the development of Maine solar projects with generating capacities between two and five

1“Net energy billing” is defined as “a billing and metering practice under which a customer is billed on the basis of the difference between the kilowatt-hours delivered by a transmission and distribution utility to the customer over a billing period and the kilowatt-hours delivered by the customer to the transmission and distribution utility over the billing period, taking into account accumulated unused kilowatt-hour credits from the previous billing period.” 35-A M.R.S.

§ 3209-A(1)(C) (2025).

2 In addition to amending certain provisions in 35-A M.R.S. § 3209-A, the 2019 NEB Act enacted a new section, codified at 35-A M.R.S. § 3209-B (2025), directed at “commercial and institutional customers.” The provisions of section 3209-B are not at issue here. megawatts seeking to interconnect to the electrical grid, with the result of substantially increasing utilities’ stranded costs.3 This so-called “solar gold rush” thus gave rise to concerns that, absent intervention, rates would increase sharply. Legis. Rec. H-750 (1st Spec. Sess. 2021); see also infra n.4.

Consequently, in 2021 the Legislature amended the 2019 NEB Act to curb development and contain the projected impact on electricity rates.4 See P.L.

2021, ch. 390, § 1 (effective Oct. 18, 2021) (codified as amended at 35-A M.R.S.

§ 3209-A(7)) (“2021 Amendment”).5 [¶4] The 2021 Amendment set a total statewide target of 750 megawatts of generating capacity for development of commercially operational distributed generation resources6 participating in the NEB program. Id. The

3 “Stranded costs” are defined as “a utility’s legitimate, verifiable and unmitigable costs made unrecoverable as a result of the restructuring of the electric industry.” 35-A M.R.S. § 3208(1) (2025).

Stranded costs are spread out among ratepayers by the Commission in the process of rate-setting.

The Commission has determined that NEB costs should generally be treated like other stranded costs.

Pub. Utils. Comm'n, Investigation of Rate Treatment of NEB Program Costs, No. 2021-360, Order at 8-10 (Me. P.U.C. Mar. 11, 2022). See generally Indus. Energy Consumer Grp. v. Pub. Utils. Comm'n, 2024 ME 60, 320 A.3d 437, for a more detailed discussion of stranded costs.

4 Legis. Rec. H-750-51 (1st Spec. Sess. 2021); Legis. Rec. S-1051-52 (1st Spec. Sess. 2021); see infra ¶¶ 31-32.

5 The statute was amended again in 2023, but the later amendments have no impact on this appeal. See P.L. 2023, ch. 230, § 1 (effective Oct. 25, 2023) (codified as amended at 35-A M.R.S.

§ 3209-A(8)); P.L. 2023, ch. 411, § 2 (effective Oct. 25, 2023) (codified at 35-A M.R.S. § 3209-A(9)).

6 A “distributed generation resource” refers to “an electric generating facility that uses a renewable fuel or technology . . . and is located in the service territory of a transmission and distribution utility.” 35-A M.R.S. § 3209-A(1)(B). legislation established milestones with mandatory deadlines applicable to projects with a generating capacity of between two and five megawatts, including those under development at the time. See 35 M.R.S.

§ 3209-A(7)(A)-(E). A project was required to meet each milestone to participate in the NEB program. See id.7 The final milestone in section 3209-A(7)(E)—and the one that prompted Snakeroot’s petition for a good-cause exemption—provides as follows: E. In order for a distributed generation resource to be used for net energy billing, the following must be met on or before December 31, 2024: (1) The proposed distributed generation resource must reach commercial operation by the date specified in the net energy billing agreement or by the date specified with an allowable modification to that agreement.8 Id. § 3209-A(7)(E)(1). The 2021 Amendment also included a provision allowing a developer of a distributed generation resource that could not meet one or more of the milestones to petition the Commission “for a good-cause

7 The milestones in the 2021 Amendment set deadlines for, among other things, executing an interconnection agreement; commencing the interconnection study process; certifying that all applicable permit applications had been submitted to and accepted by the Department of Environmental Protection and certifying receipt of all necessary nonministerial permits from local authorities; and reaching full commercial operation. See 35-A M.R.S. § 3209-A(7)(A)-(E). The parties agree that Snakeroot Solar has met all milestone deadlines except the final one, which required that it reach commercial operation by December 31, 2024. Id. § 3209-A(7)(E).

8 Snakeroot’s NEB agreement does not alter the statutory deadline of December 31, 2024. exemption due to external delays outside of the entity’s control.” Id. § 3209-A(7).

B. Overview of the Interconnection Process [¶5] To initiate development of a distributed generation resource to be used for net energy billing under the 2019 NEB Act, as amended by the 2021 Amendment, a project developer and the transmission and distribution (T&D) utility9 in whose service territory the proposed project is located enter into two agreements: (i) an interconnection agreement, which governs the connection of the resource to the utility’s system and its ongoing operation thereafter, 65-407 C.M.R. ch. 324, § 2(EE) (effective Nov. 20, 2023); 35-A M.R.S.

§ 3209-A(7)(A)(1), and (ii) an NEB agreement, which governs credits for excess energy exported to the grid, see 35-A M.R.S. § 3209-A(7)(A)(2).

[¶6] A proposed project undergoes a complex review process overseen by the T&D utility to assess the impact of its interconnection on the electrical grid. See 65-407 C.M.R. ch. 324, § 1. Because the grid is regional, the interconnection process is subject to oversight in certain instances by ISO New England, an independent, federally regulated organization formed to

9A “Transmission and Distribution Utility” or “T&D utility” is the entity that owns, controls, operates, or manages an electric transmission and distribution plant for compensation within the State. 65-407 C.M.R. ch. 324, § 2(MMM) (effective Nov. 20, 2023). “coordinate, control, and monitor the operation of a regional bulk electric power system . . . to ensure the safety and reliability of the system.”

TransCanada Power Mktg. Ltd. v. Fed. Energy Regul. Comm’n, 811 F.3d 1, 5 (D.C. Cir. 2015); see also Emera Me. v. Fed. Energy Regul. Comm’n, 854 F.3d 662, 666 (D.C. Cir. 2017); NextEra Energy Res., LLC v. Me. Pub. Utils. Comm’n, 2020 ME 34, ¶ 37 n.17, 227 A.3d 1117. ISO New England also administers a separate “queue” of projects seeking interconnection to a transmission system within the jurisdiction of the Federal Energy Regulatory Commission (FERC).10 See NextEra Energy Res., LLC, 2020 ME 34, ¶ 37 n.18, 227 A.3d 1117; see also infra n.12.

[¶7] Each interconnection agreement requires that a proposed project undertake and complete a transmission study. The transmission study, which is administered by the T&D utility, 65-407 C.M.R. ch. 324, § 14(J), assesses potential impacts that the proposed generating facility may have on the reliability, stability, and performance of the electrical grid and overall power system. Id. Projects are categorized by level based on their size, complexity,

10 Projects subject to FERC jurisdiction are typically larger generators interconnecting to high-voltage transmission lines managed by the regional ISO (such as ISO New England) or selling power at wholesale in interstate commerce. See 16 U.S.C.A. § 824(b)(1) (Westlaw through Pub. L. No. 119-18) (granting FERC authority over transmission of electric energy in interstate commerce and the sale of electric energy wholesale in interstate commerce, while expressly excluding jurisdiction over facilities used for generation of electric energy distributed only locally). and potential impact of their generating systems. See id. §§ 1, 2(JJ)–(MM). The interconnection process varies in complexity depending on the level of the project. See id. [¶8] Certain distributed generation projects with a capacity of greater than one megawatt that will impact the regional transmission system require approval under Section I.3.9 of ISO New England’s Transmission, Markets, and Services Tariff (“Section I.3.9 approval”).11 Additionally, Section I.3.9. approval may be required where multiple projects with a combined generating capacity of twenty megawatts or more propose to interconnect in a defined local area.

When this occurs, ISO New England requires a transmission study for all the projects with a capacity greater than one megawatt in that area be conducted as a formal group analysis known as a “cluster study,” rather than as individual, sequential studies. A cluster study offers a more comprehensive, expeditious review by grouping projects in a defined area based on the projects’ maturity and proximity. Each proposed project seeking interconnection must submit its

11 Section I.3.9 approval is a separate review process that applies to projects with a capacity greater than one megawatt that will have a cumulative impact on the regional power system. As part of its responsibility to ensure grid stability, ISO New England sets parameters for the study in Section I.3.9. Section I.3.9 approval means that ISO New England has determined that the proposed interconnection will not have a significant adverse effect on the reliability of the regional electric grid. study “in such form, manner and detail as the ISO may prescribe.” ISO New England Transmission, Markets, and Services Tariff, Section I.3.9.

[¶9] The duration and complexity of the cluster study process varies considerably depending on a number of factors, including, for example, the number of projects seeking to interconnect, their respective generation capacities, the locus of their connection to the grid, and the overall condition of the grid. Projects involved in a cluster study may encounter additional complications, including a phenomenon known in the industry as “freefalling.”12 When this happens, a cluster study may have to be restarted or adjusted in order to account for the impacts of a FERC-level generator’s interconnection, and this delays the final review and approval of studies of

12 Interconnection requests are placed in order in a queue. See 65-407 C.M.R. ch. 324, § 14(D). A project like Snakeroot’s that is seeking to connect locally to a T&D utility’s distribution system is considered a “distribution-level” project and is placed in a “distribution queue.” Larger projects that connect to the high-voltage transmission system managed by ISO New England are placed in a separate, FERC-jurisdictional queue. ISO New England reviews and studies the interconnection requests in the order that they appear in its queue. Distribution-level projects, by contrast, are studied separately and, while subject to ISO New England review, are not formally part of ISO New England’s queue. “Freefalling” refers to a pause or delay in the cluster study process of distribution- level projects caused by ISO New England’s prioritization of higher-queued “transmission-level” projects. The Commission described “freefalling” this way: Projects participating in a cluster study are not formally a part of the ISO-NE queue because they are distribution level projects. Because of this status, cluster study projects are subject to ‘freefall’ from ISO-NE, meaning that if an interconnecting generator in ISO-NE’s FERC queue impacts the same transmission area as the projects in the cluster study, the cluster study is put on hold while ISO-NE first studies the interconnecting generator in its queue. other distribution-level projects. These and other complications inherent in the process affect the time needed to finalize the study and secure approval.

[¶10] Once a cluster study is successfully completed, formal Section I.3.9 approval is issued by ISO New England.13 An approved study may identify modifications or upgrades that are necessary to the electrical grid in order to accommodate interconnection. The administering T&D utility determines what, if any, equipment and construction are necessary to implement the upgrades; establishes a construction schedule for the work required; and invoices the developer to cover the associated costs.

[¶11] Between completion of the cluster study and full payment for distribution upgrades, projects seeking interconnection at the time Snakeroot’s project was under review were still at risk of additional delays due to a second phenomenon known in the industry as “leapfrogging.”14 A “leapfrogged”

13 Once ISO New England is satisfied with the study, it presents the proposal to a technical committee of the New England Power Pool (NEPOOL) that advises on the design and oversight of reliability standards for the New England power grid. If the committee finds no adverse impact, ISO New England issues a final Section I.3.9 approval.

14 “Leapfrogging” refers to a practice that was permitted under the Commission’s rules in effect during the relevant time period here. The rules allowed smaller projects to proceed with interconnection ahead of earlier-queued, larger projects that had not yet paid their full distribution upgrade costs. A “leapfrogged” project was bumped to a lower queue position and potentially subject to a revised transmission study to assess the impact of the newly elevated project’s interconnection.

The Commission has amended its rules to eliminate this requirement. Pub. Utils. Comm., Amendments to Small Generator Interconnection Procedures (Chapter 324), No. 2023-00103, Order Adopting Rule and Statement of Factual and Policy Basis at 11 (Me. P.U.C. Nov. 3, 2023). project typically had to undergo a re-study to account for the effect of the “leapfrogging” project’s interconnection on the power grid. Once the revised study was approved, the “leapfrogged” project’s interconnection agreement was amended and the utility issued a final invoice for the portion of any necessary upgrades. A project cannot be connected to the grid and thus “reach commercial operation” until the invoice has been paid in full, all upgrades are successfully completed, and the project is approved by the T&D utility to operate. See 65-407 C.M.R. ch. 324, § 14(T)–(V).

C. Snakeroot’s Proposed Project [¶12] In May 2020, Snakeroot submitted an application to the Commission to construct and interconnect a 4.98-megawatt photovoltaic generating facility in Pittsfield, a location in Central Maine Power Company’s (CMP) service territory. Snakeroot Solar’s application had first position in the queue at the time. Snakeroot executed an interconnection agreement on September 18, 2020, and three days later, on September 21, 2020, entered into a net energy billing agreement with CMP. Snakeroot obtained other required permits in April 2021 from the Maine Department of Environmental Protection and in July 2021 from the Town of Pittsfield.

[¶13] As proposed, Snakeroot’s project required ISO New England approval of a transmission study that would be administered by CMP. Prior to Snakeroot’s application, CMP already had begun utilizing cluster studies rather than individual transmission studies when multiple projects were seeking interconnection in a defined area. CMP published a transmission study schedule for the Belfast-Detroit-Guilford area, which included Pittsfield, that would eventually become known as “Cluster 06.” Multiple projects were seeking to interconnect in this area; the number fluctuated over the course of the study, but at one point approximately twenty-five projects in Cluster 06 were proposing to interconnect.

[¶14] On August 4, 2020, CMP held a webinar for solar developers that highlighted certain study areas, including the Belfast-Detroit-Guilford area, Cluster 06. CMP provided an overview of the study process and an estimated “study timeline,” explaining its responsibility for ensuring reliability of the electricity system, and ISO New England’s role in approving the study.

[¶15] In early 2021, CMP set a closure date of February 1, 2021, for Cluster 06, and estimated March 2022 as the date for Section I.3.9 approval.

The Cluster 06 study commenced June 9, 2021; it received Section I.3.9 approval just over two years later, on August 31, 2023.

[¶16] A number of factors extended the time required to complete the Cluster 06 study beyond CMP’s initial estimate of March 2022. There were “complex mitigation issues,” issues with the computer models (known as Power System Computer Aided Design, or PSCAD, models) used to study the impact of integrating new generation capacity into the power grid under certain conditions, and issues with the results of stability studies. Problems with the computer models were identified in March 2022 and continued through summer 2022, with additional issues arising after CMP submitted a draft of the impact study to ISO New England in September 2022. The Cluster timeline was affected by “freefalling,” see supra n.12. The withdrawal of a FERC-level generator, which impacted the study’s baseline assumptions, delayed receipt of models from two other FERC-level generators necessary for revising the Cluster 06 study. CMP was not able to restart the study until March 2023, upon receiving this information. Then two projects withdrew from Cluster 06 and another project downsized, requiring further revisions to the Cluster 06 PSCAD analysis.

[¶17] CMP divided Cluster 06 into two areas, the “Belfast” area and the “Guilford/Detroit” area, to allow the latter to move forward with analysis through summer 2023. The “Guilford/Detroit” area of Cluster 06, which included Snakeroot’s project, ultimately received Section I.3.9 approval on August 31, 2023.15 [¶18] It was also only after Snakeroot’s project received Section I.3.9 approval in August 2023 that CMP could finalize upgrade designs, procure equipment, and schedule the construction work to install the upgrades. At that point, CMP estimated that it would take an additional twenty-four to thirty months to complete the upgrades, although it acknowledged that equipment procurement and construction could take more or less time. The construction schedule accounted for an estimated seventy-two-to-eighty-week period to obtain equipment necessary for the upgrades based on estimates from CMP’s vendors at the time. CMP also needed to account for the time to engineer and construct the interconnection upgrades.

[¶19] Snakeroot had paid twenty-five percent of its interconnection upgrade costs to CMP but had not paid the remainder of the costs required for distribution upgrades nor been invoiced for necessary transmission upgrades.

Construction of its generating facility in Pittsfield was only partially complete.

And, without accounting for CMP’s estimated time to make required system

15 Cluster 06 projects were then also affected by “leapfrogging,” see supra n.14, which would necessitate that they be re-queued and re-studied at the distribution level. Following a re-study, interconnection agreements would need to be updated, and the projects would receive an invoice for the final amount due for upgrades. upgrades, Snakeroot projected its facility would not achieve mechanical completion until just a couple of months prior to the December 31, 2024, deadline. When CMP’s estimate for procuring the equipment and completing the upgrades was factored in, the predicted time to reach commercial operation stretched well into 2025.

D. Snakeroot Solar’s Petition for Good-Cause Exemption [¶20] On September 8, 2023, Snakeroot filed a petition for a good-cause exemption pursuant to 35-A M.R.S. § 3209-A(7), seeking relief from the December 31, 2024, deadline and requesting that the Commission set “an alternative deadline for operation aligned with the schedule for CMP to complete the upgrades” for its project.16 The petition asserted that the exemption was justified because of delays resulting from the cluster study process and from CMP’s estimated timeline for completing necessary grid upgrades. The Office of the Public Advocate (“OPA”) filed a motion to intervene pursuant to 35-A M.R.S. § 1702(2) (2025) and 65-407 C.M.R. ch. 110, § 8(B), which was granted on October 4, 2023.

Snakeroot was one of six projects in Cluster 06 seeking a good-cause exemption under 35-A M.R.S. § 3209-A(7), (9). The Commission denied all six petitions; only Snakeroot has appealed the Commission’s denial.

[¶21] A technical conference was held on October 19, 2023, to gather information, facilitate discussion, and receive testimony. Representatives of Snakeroot and CMP offered testimony at the October 19 conference and provided supplemental information on November 3 as requested. On December 13, 2023, the Commission issued a procedural order communicating that the record was complete.

[¶22] Following submission of briefs by the parties and responses to data requests, an examiners’ report was issued on April 22, 2024, recommending that Snakeroot’s petition be denied. Snakeroot filed exceptions to the examiners’ report. The OPA filed a letter in support of the report. On June 24, 2024, the Commission issued an order denying all Cluster 06 petitioners’ requests for a good-cause exemption under 35-A M.R.S.

§ 3209-A(7), including Snakeroot’s.

[¶23] The Commission’s order made findings of fact specific to Snakeroot and each of the other petitioners. The Commission found that the use of cluster studies had become routine in Maine; CMP’s administration of the studies is subject to ISO New England’s guidance and oversight; ISO New England’s approval process does not have deadlines or anticipated timelines; and the time it took for completion of the Cluster 06 study was slightly longer, but not materially longer, than the average time that other cluster studies have taken.

The Commission further found that the events contributing to the delays associated with the approval of the cluster study were inherently part of the interconnection process and that CMP’s estimated timeframes for the upgrade construction schedule were based on equipment procurement lead times that were consistent with then-current industry standards.

[¶24] Based on its findings, the Commission concluded that the events alleged by Snakeroot as the basis for its request for a good-cause exemption did not constitute “external delays outside of [Snakeroot’s] control” within the meaning of the statute, and that regardless of delays in the cluster study process, Snakeroot had not demonstrated that it could have reasonably expected to meet the December 31, 2024, commercial operation deadline given the long lead times for equipment procurement. Accordingly, the Commission denied Snakeroot’s petition.

[¶25] Snakeroot timely appealed. See 35-A M.R.S. § 1320(1)-(4) (2025); M.R. App. P. 2B(c)(1); M.R. App. P. 22.

II. DISCUSSION A. Interpretation of the Good-Cause Exemption [¶26] “When reviewing an agency’s interpretation of a statute that is both administered by the agency and within the agency’s expertise, we apply a two-part inquiry.” Cent. Me. Power Co. v. Pub. Utils. Comm’n, 2014 ME 56, ¶ 18, 90 A.3d 451 (quotation marks omitted). First, we determine de novo whether the statute is ambiguous, meaning whether it is “reasonably susceptible of different interpretations.” Off. of the Pub. Advoc. v. Pub. Utils. Comm’n, 2023 ME 77, ¶ 9, 306 A.3d 633 (quotation marks omitted). Next, if the statute is unambiguous, we construe its plain terms; if it is ambiguous, we determine whether the agency’s construction is reasonable. Id. [¶27] The good-cause exemption in 35-A M.R.S. § 3209-A(7) provides as follows: An entity proposing the development of a distributed generation resource that does not meet one or more of the requirements of this subsection may petition the commission for a good-cause exemption due to external delays outside of the entity’s control, which the commission may grant if it finds that, without the external delays, the entity could reasonably have been expected to meet the requirements. (Emphasis added.) The phrase “requirements of this subsection” refers to the development milestones in 35-A M.R.S. § 3209-A(7)(A)-(E). An entity seeking an exemption from the milestones must therefore establish that there were “external delays outside of [its] control” and but for the “external delays” it could “reasonably have been expected to meet the requirements.” See id. § 3209-A(7).

[¶28] Snakeroot contends that the “plain language” of the good-cause exemption in section 3209-A(7) is unambiguous. It argues that the Commission erred in construing the statute because the delays it experienced—specifically, the protracted duration of the cluster study process and the lengthy period of time estimated to complete grid upgrades—are precisely the kind of “external delays” that the Legislature intended to encompass within the statute’s good-cause exemption as a safe harbor for developers unable to meet the statute’s development milestones. These events, Snakeroot maintains, were outside of its control, prevented its project from reaching commercial operation by December 31, 2024, and therefore fell within the scope of section 3209-A(7)’s exemption.

[¶29] The Commission also contends that the “plain meaning” of section 3209-A(7)’s language is clear, but it interprets the statute more narrowly. The Commission construes “external delays” to mean events that are “external” to, or outside of, the interconnection process—a process that is typically “long, complicated, . . . and subject to frequent interruptions.” See Naples Roosevelt Trail Solar 1, LLC, Petition for Good-Cause Exemption Pursuant to 35-A M.R.S.

§ 3209-A, No. 2021-215, Order at 13 (Me. P.U.C. Mar. 2, 2022) (acknowledging in interpreting the good-cause exemption for the first time that “the interconnection process is complicated and can easily become protracted and difficult when issues arise”). Thus, the Commission does not consider a transmission (or cluster) study conducted in accordance with prevailing guidelines and practices to constitute a “delay” within the meaning of the statute. Nor does it view the time required by the utility to make post-approval grid upgrades to be a “delay” that is “external” to the interconnection process, absent any extraordinary circumstances.

[¶30] In light of these conflicting interpretations, it is apparent that section 3209-A(7)’s language is “reasonably susceptible of different interpretations.” Off. of the Pub. Advoc., 2023 ME 77, ¶ 9, 306 A.3d 633 (quotation marks omitted). We therefore determine that the statute is ambiguous; accordingly, we afford “great deference” to the Commission’s interpretation and will uphold its interpretation “unless the statute plainly compels a contrary result.” Cent. Me. Power Co., 2014 ME 56, ¶ 18, 90 A.3d 451 (quotation marks omitted); see also Off. of the Pub. Advoc., 2023 ME 77, ¶ 9, 306 20 A.3d 633 (reiterating that deference is afforded to the Commission’s interpretation of the statutes it administers “in recognition of [its] greater expertise in matters of relevant concern and greater experience administering and interpreting those particular statutes” (alteration and quotation marks omitted)).

[¶31] We conclude that the Commission’s interpretation is reasonable in light of the overarching purpose of the 2021 Amendment to the 2019 NEB Act.

As referenced above, see supra ¶¶ 3-4, the impetus behind the Legislature’s adoption of the statutory milestones in 35-A M.R.S. § 3209-A(7) was clear—to set an overall target of 750 megawatts for development of distributed generation resources participating in the NEB program and thus limit the number of projects that become operational, principally out of concern about the potential impact on electricity rates.17 See Legis. Rec. H-750-51 (1st Spec.

Sess. 2021); Legis. Rec. S-1051 (1st Spec. Sess. 2021). There was particular concern about the impact that significant rate increases would have on the

In 2021, approximately 1500 megawatts of distributed generation resources were enrolled or seeking enrollment in the NEB program. Legis. Rec. H-750 (1st Spec. Sess. 2021). According to a Commission estimate, if all 1500 megawatts of distributed generation became operational, rates could increase by thirty-one percent and cost ratepayers approximately $230.08 million per year. Id. At the time of its decision in this matter, the Commission found that the capacity of operational and pending NEB projects was already more than 1,100 megawatts. elderly, individuals on fixed incomes, and other individuals who are especially vulnerable to increased costs. Legis. Rec. H-750-51 (1st Spec. Sess. 2021).

[¶32] The Legislature fully appreciated that imposing mandatory milestones could adversely affect some developers who, like Snakeroot, already had invested in projects that were underway and could find it difficult to meet all milestones. See Legis. Rec. S-1051-52 (1st Spec. Sess. 2021). Nonetheless, this was a calculated risk that the Legislature weighed against the perceived necessity to protect ratepayers from rapidly escalating electricity rates, as was recognized by the chair of the Energy, Utilities and Technology Committee that reviewed the 2021 legislation imposing the milestones: This was a very difficult issue we had to deal with. Let me explain what this bill does. We passed solar power last session. It actually was sponsored by the Republican Floor Leader in this Legislature and we got an overwhelming response for it and we began to get concerned about what impact it would have on rates. So we put together this subcommittee and we tried to, I never like to do this because investors have already invested in developing these solar projects, but we tried to determine a cut-off point at which it would only allow projects that had completed that cut-off point to go ahead under the old rate system. We did a cut-off point. It was a little bit higher than what I had wanted but that’s part of compromise.

Id. [¶33] The Commission’s interpretation of the exemption is consistent with, and effectuates, the Legislature’s intent to curtail eligibility for participation in the NEB program, even for projects then underway.

[¶34] Further, contrary to Snakeroot’s contention, there is no entitlement to an exemption under section 3209-A(7). The language of the statute is discretionary; it provides that the Commission “may grant” an exemption for good cause. 35-A M.R.S. § 3209-A(7); see Friedman v. Bd. of Env’t Prot., 2008 ME 156, ¶¶ 14, 16, 956 A.2d 97 (noting that “the use of . . . the word ‘may’ indicates authorization or permission to act,” signaling that the decision “lies in the agency’s sole discretion” (quotation marks omitted)).

[¶35] The Commission’s interpretation of section 3209-A(7) reflects that “the interconnection process is complicated and can easily become protracted” and correctly concludes that such impacts on timing “do[ ] not represent a ‘delay’” within the meaning of section 3209-A(7). See Naples Roosevelt Trail Solar 1, LLC, Petition for Good-Cause Exemption Pursuant to 35-A M.R.S.

§ 3209-A, No. 2021-215, Order at 13 (Me. P.U.C. Mar. 2, 2022). The interpretation urged by Snakeroot, on the other hand, potentially opens the door wide to any project experiencing the vicissitudes of the normal interconnection process. Given the clear legislative purpose animating the 2021 Amendment and the broad discretion vested in the Commission to administer the process, we conclude that the Commission’s interpretation of section 3209-A(7) is reasonable and consonant with the Legislature’s intent.

B. Sufficiency of the Evidence; Abuse of Discretion [¶36] Snakeroot contends that even accepting the Commission’s interpretation of section 3209-A(7), its findings are unsupported by the record evidence. Specifically, Snakeroot maintains that the evidence does not support the Commission’s findings that the Cluster 06 study was a routine part of a typical interconnection process or that the time it took to gain Section I.3.9 approval was within, or “slightly slower” than, the average time for such transmission studies. Moreover, Snakeroot contends that the Commission abused its discretion by arbitrarily denying its petition while granting other petitions based on similar facts.

[¶37] In reviewing an agency decision, “[t]he issue before us is not whether we would have reached the same conclusion as the agency, but whether the record contains competent and substantial evidence that supports the result reached.” CWCO, Inc. v. Superintendent of Ins., 1997 ME 226, ¶ 6, 703 A.2d 1258 (quotation marks omitted); see Me. Coal. to Stop Smart Meters v. Me. Pub. Utils. Comm’n, 2023 ME 8, ¶ 7, 288 A.3d 1195 (“We will sustain findings of fact issued by the Commission unless they are not supported by substantial evidence in the record.” (quotation marks and alteration omitted)). Our review “does not involve any weighing of the merits of evidence; instead, we will vacate an agency’s factual findings only if there is no competent evidence in the record to support the findings . . . even if the record contains inconsistent evidence or evidence contrary to the result reached by the agency.” Ouellette v. Saco River Corridor Comm’n, 2022 ME 42, ¶ 20, 278 A.3d 1183 (citation and quotation marks omitted).

[¶38] Snakeroot’s interconnection process undeniably took far longer than initially anticipated. However, the record supports the Commission’s findings that the prolonged Cluster 06 study process and the extended upgrade construction schedule—the two principal reasons cited by Snakeroot as the cause of its inability to meet the December 31, 2024, commercial operation deadline—were inherent in, not external to, and well within the bounds of the complicated regulatory process in this area. See supra ¶¶ 16-18, 23. There is also competent record evidence to support the Commission’s finding that the average length of cluster studies conducted by CMP in Maine is approximately two years, and that Cluster 06 took two to three months longer than the two-year average.18 Even if, as Snakeroot contends, the Commission’s

Although Snakeroot challenges the Commission’s methodology for computing the average duration of a cluster study, we find both its approach and its conclusion to be reasonable and supported by the record. The Commission based its calculation on the length of time it took to complete all cluster studies in CMP’s territory to date, and determined: The shortest amount of time it took CMP to complete a cluster study was 217 calendar days (or 0.59 years) [and] [t]he longest it took to complete a cluster study was 1025 calculations are erroneous and completion of the Cluster 06 study took up to one year longer than the average transmission study, the estimated additional time of twenty-four to thirty months to complete the construction of the grid upgrades clearly foretold that Snakeroot’s project would be unable to reach commercial operation until well beyond the statutory deadline of December 31, 2024.

[¶39] Moreover, the Commission found that the time utilities need to make post-approval grid upgrades is also part of the interconnection process and generally “do[es] not constitute an external delay but for which the projects could have been expected to meet the commercial operation deadline.” In Snakeroot’s case, the Commission found no evidence that the schedule presented by CMP amounted to a “delay.” This finding is also supported by the record. A CMP representative testified that the company’s estimate was based largely on equipment procurement lead times provided to the company by its vendors, and those lead times were not atypical or abnormal in the industry at

calendar days (or 2.81 years). The mean average time for CMP to complete a cluster study is just over two years, or 2.03 years.

Snakeroot, on the other hand, looked at a more limited sample, namely Clusters 01–05 and 16 that were being studied around the time of, and ahead of, Cluster 06 to determine an average study duration of 1.44 years (seventeen months). that time. CMP also clarified that its timeline constituted a baseline estimate and that the construction could take more or less time.

[¶40] Finally, we conclude that the Commission did not abuse its discretion in denying Snakeroot’s petition for a good-cause exemption. Mindful of our deferential standard of review, we have held that the “Commission’s ruling will stand unless it is irrational; is unsupported by the record evidence; or violates a statutory mandate, reading any ambiguity in statutory language as the Commission reasonably resolves.” Indust. Energy Consumer Grp. v. Me. Pub.

Utils. Comm’n, 2024 ME 60, ¶ 33, 320 A.3d 437.

[¶41] We have already determined that the Commission’s order does not violate its statutory mandate and is supported by the record evidence.

Snakeroot’s contention that the Commission acted arbitrarily is also without merit. In support of this contention, Snakeroot cites an exemption granted to another solar developer where the Commission found that the utility’s delayed equipment procurement constituted an “external delay” within the meaning of section 3209-A(7). See Pembroke Solar LLC, Petition for Good-Cause Exemption Pursuant to 35-A M.R.S. § 3209-A, No. 2023-304, Order (Me. P.U.C. June 20, 2024). Snakeroot argues that this demonstrates the “lack of any clear definition of what does or does not constitute an external delay” and therefore makes the Commission’s denial here “arbitrary and capricious.”

[¶42] On the contrary, Pembroke’s circumstances at the time it petitioned for a good-cause exemption were markedly different than Snakeroot’s. Pembroke experienced an eleventh-hour, unanticipated change in the utility’s equipment procurement schedule that occurred after (i) the cluster study had been finally approved in September 2022, (ii) the developer had been invoiced for, and paid, the full amount due for its interconnection and grid upgrades, (iii) construction of its generating facility was well underway, and (iv) all equipment necessary for the upgrades had been ordered. Id. at 4-6. The estimated thirty-four-week lead time for procuring equipment put Pembroke on track to reach commercial operation by April 24, 2024, well before the statutory deadline. Id at 5. However, when the lead time for equipment unexpectedly increased from thirty-four to eighty-one weeks, the estimated commercial operation date was pushed beyond December 31, 2024. Id. [¶43] Snakeroot’s project, by contrast, was in a very different posture when its exemption petition was submitted in September 2023. The Cluster 06 study had just been approved as of August 31, 2023. There remained fewer than sixteen months for the project to reach commercial operation before the December 31, 2024, statutory deadline. There was still a likelihood that a revised study would be needed due to leapfrogging. Snakeroot’s Pittsfield facility had not been constructed. CMP had not invoiced Snakeroot for the costs of upgrades. And CMP’s estimated twenty-four-to-thirty-month timeline for procuring equipment necessary to make the upgrades reflected current industry lead times. Combined, these factors put the project considerably beyond the mandatory statutory deadline to “reach commercial operation.”

The entry is: The Commission’s order denying the petition for a good-cause exemption is affirmed.

Jonathan M. Dunitz, Esq. (orally), and Hans C. Eysenbach, Esq., Verrill Dana, LLP, Portland, for appellant Snakeroot Solar, LLC Daya J. Taylor, Esq. (orally), and Elizabeth J. Wyman, Esq., Maine Public Utilities Commission, Augusta, for appellee Maine Public Utilities Commission William S. Harwood, Esq., Richard P. Hevey, Esq., and Brian T. Marshall, Esq. (orally), Office of the Public Advocate, Augusta, for appellee Office of the Public Advocate Anthony W. Buxton, Esq., R. Benjamin Borowski, Esq., and Joseph G. Donahue, Esq., Preti, Flaherty, Beliveau & Pachios, LLP, Augusta, for amicus curiae Industrial Energy Consumer Group

Public Utilities Commission docket number 2023-00236 FOR CLERK REFERENCE ONLY