Industrial Energy Consumer Group v. Public Utilities Commission

2024 ME 60

Opinion

MAINE SUPREME JUDICIAL COURT Reporter of Decisions Decision: 2024 ME 60 Docket: PUC-23-388 Argued May 8, 2024 Decided: August 8, 2024 Revised: September 17, 2024

Panel: STANFILL, C.J., and MEAD, HORTON, CONNORS, LAWRENCE, and DOUGLAS, JJ.

INDUSTRIAL ENERGY CONSUMER GROUP v.

PUBLIC UTILITIES COMMISSION et al.

LAWRENCE, J.

[¶1] Industrial Energy Consumer Group (IECG) appeals from an order of the Public Utilities Commission that determined that the costs related to ongoing power supply obligations and state energy programs should be recovered volumetrically from and within all ratepayer classes, except that one category of such costs should be recovered intra-class using a fixed customer charge. Although IECG is not precise as to the contours of the rate allocation and design that it would prefer, it asserts that the order is preempted by the Federal Power Act (FPA), 16 U.S.C.A. §§ 791a-828c. (Westlaw through Pub. L. No. 118-66), and it raises various arguments on the merits that collectively contend that the allocation and design are insufficiently founded in cost- causation principles and violate state statutes.

[¶2] In response, the Office of the Public Advocate argues that IECG’s appeal is untimely and should be dismissed. The Commission argues that dismissal is warranted because the appeal is an improper collateral attack on a prior rate order. Both the Public Advocate and the Commission argue that if we reach the merits, we should find that the order is rational and supported and should be affirmed.

[¶3] We (1) conclude that the appeal is timely and is not barred by collateral estoppel, (2) do not address the preemption argument, and (3) reject IECG’s arguments on the merits given our deferential standard of review. We therefore affirm the order.

I. BACKGROUND

A. The Electricity Market and Recovery of “Stranded” Costs

[¶4] To orient the reader, we provide a brief history and overview of the structure of Maine’s electricity market.

1. Traditional Rate Methodology

[¶5] Prior to 2000, electricity was generally supplied by vertically integrated utilities that both generated electricity and transported it to retail consumers. See L.D. 1804, Summary (118th Legis. 1997); An Act to Restructure the State’s Electric Industry (Restructuring Act), P.L. 1997, ch. 316, § 3

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(effective Sep. 19, 1997) (codified as amended at 35-A M.R.S. ch. 32 (2024)). Under traditional ratemaking principles, the Commission typically determined the reasonableness of rates by calculating the revenue a utility is entitled to receive based on (i) the utility’s total cost of providing its service to its customers and (ii) an appropriate return on the utility’s investment. See Mech. Falls Water Co. v. Pub. Utils. Comm'n, 381 A.2d 1080, 1095 (Me. 1977); James C. Bonbright, Principles of Public Utility Rates, at 66-71 (1961), https://www.raponline.org/wp-content/uploads/2023/09/powellgo ldstein-bonbright-principlesofpublicutilityrates-1960-10-10.pdf (last visited July 30, 2024) [https://perma.cc/4HN3-G7CE]. After calculating the total amount of revenue that a utility is permitted to earn, the Commission then allocated that revenue among the ratepayer classes (including industrial, commercial, and residential), and identified the type of charge to be used to produce that revenue—for example through an “energy” charge, which is volumetric and measured by kilowatt hour (kWh) usage, or through a “customer” charge, which is typically fixed. See generally Cent. Me. Power Co. v. Pub. Utils. Comm'n, 416 A.2d 1240, 1242-45 (Me. 1980) (describing a study that classified costs by demand, energy, and customer components); Bonbright, supra, at 337-38.

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2. Recovery of “Stranded” Costs

[¶6] Changes in the electricity market have created costs that do not comfortably fall within a utility’s traditional costs of service. For the purposes of this appeal, these costs can be divided into three categories: pre-restructuring, post-restructuring, and net energy billing costs. While only the costs in the first category meet the statutory definition of a “stranded cost,” see 35-A M.R.S. § 3208(1) (2024), the Commission sometimes uses this term to refer to all three categories.

a. Pre‐restructuring Costs

[¶7] Starting in 1997, the Legislature ordered Maine electric utilities to divest their generation assets and contracts and engage only in the transmission and distribution (T&D) of electricity. See P.L. 1997, ch. 316, § 3; Competitive Energy Servs. LLC v. Pub. Utils. Comm'n, 2003 ME 12, ¶ 2, 818 A.2d 1039. As a result of the Legislature’s directive, the now-T&D utilities were left with generation assets and contracts that they could no longer use or sell wholesale at market prices. See P.L. 1997, ch. 316, § 3. In response, the Legislature enacted statutes and the Commission promulgated regulations and issued orders explaining how such pre-restructuring costs would be recovered in the utilities’ rates. See id.

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[¶8] Generally speaking, the guidelines for determining the amount of pre-restructuring costs that the utilities were entitled to recover are provided in 35-A M.R.S. 3208(5), which mandates that the Commission provide a T&D utility “a reasonable opportunity to recover stranded costs through [its] rates.” No statute explicitly addresses how to allocate these costs among rate classes or how to design the rates within a class, except that section 3208(7) provides that the Commission “may not shift cost recovery among customer classes in a manner inconsistent with existing law, as applicable.” See also 35-A M.R.S. § 3209(1) (2024) (“The design of rate recovery for the collection of [T&D] costs, stranded costs and other costs recovered pursuant to this chapter must be consistent with existing law, as applicable.”).

b. Post‐restructuring Costs

[¶9] The Legislature has also enacted statutes to promote certain types of electricity generation. See, e.g., An Act to Establish the Community-based Renewable Energy Pilot Program, P.L. 2009, ch. 329, § A-4 (effective Sept. 12, 2009) (codified as amended at 35-A M.R.S. §§ 3601-3610 (2024)); 35- A M.R.S. §§ 3210-C, -G (2024). As with pre-restructuring costs, the Legislature and the Commission have addressed how T&D utilities may recover costs incurred as a result of these statutes.

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[¶10] In a 2011 order, the Commission decided that electric utilities were entitled to recover these costs and that the costs would be treated the same as pre-restructuring costs. Pub. Utils. Comm’n, Investigation into Recovery of Expenses and Disposition of Resources from Long-Term Contracts by Maine’s T&D Utilities, No. 2011-222, Order (Me. P.U.C. Oct. 26, 2011) (“Although it is clear that costs under these contracts are not ‘stranded costs’ as defined by statute, for cost recovery purposes we see no reason to treat them differently than [pre-restructuring] stranded costs . . . .).

c. Net Energy Billing Costs

[¶11] Finally, the Legislature recently expanded net energy billing1 (NEB) programs to promote the use of certain types of generation, such as solar and other distributed generation. See An Act to Promote Solar Energy Projects and Distributed Generation Resources in Maine, P.L. 2019, ch. 478, §§ A-3,-4 (effective Sept. 19, 2019) (codified as amended at 35-A M.R.S. §§ 3209-A, 3209-B (2024)). There are two NEB programs: the kWh credit program, see 35- A M.R.S. § 3209-A, and the tariff rate program, see 35-A M.R.S. 3209-B. Section 3209-A(1)(C) provides that kWh credit program participants are billed based

1 Net energy billing is a “renewable energy incentive program that is intended to encourage electricity generation from renewable resources.” Conservation L. Found. v. Pub. Utils. Comm’n, 2018 ME 120, ¶ 2, 192 A.3d 596.

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on the difference per billing period between the kWh delivered by the utility to the customer and the kWh delivered by the customer to the utility, accounting for “accumulated unused [kWh] credits from the previous billing period.” Section 3209-B(5) provides the rate of the financial credit to tariff rate program participants, which is dependent on the date that construction began on the customer’s distributed generation project.2

[¶12] In an order dated March 11, 2022, the Commission, employing reasoning similar to that reflected by its 2011 order, concluded that NEB costs should generally be treated like the other two categories of 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).

[¶13] Relevant for our purposes, the Commission noted in the March 2022 order that legislative history reflected “an overall purpose of separating [out] the recovery of costs that are not related to the provision of T&D services.” Id. at 10. Accordingly, the Commission noted that since the inception of the

2 If construction began on the project before September 1, 2022, the “old” method of calculating

the rate of the financial credit applies. See 35-A M.R.S. § 3209-B(5)(A) (2024). Under the old method, the tariff rate equals the sum of the standard-offer service rate applicable to the customer and seventy-five percent of the effective transmission and distribution rate for the smallest commercial class of the utility. See id. If construction began on the project on or after September 1, 2022, the “new” method applies. See id. § 3209-B(5)(A-1). The new method provides a rate that was set in 2022 by reference to 2020 rates and increases by 2.25 percent per year thereafter. See id.

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mechanism to recover stranded costs, it “has appropriately acted to consider recovery of costs resulting from State energy policies that are unrelated to the costs and operation of providing T&D service separate[ly] from the traditional ratemaking process related to the provision of regulated T&D service.” Id. at 10-11 (“[T]raditionally established utility rate design principles apply to the costs and the appropriate cost recovery related [to] the provision of regulated T&D service. These traditional rate design principles have less relevance when allocating the cost of State energy policies. The costs at issue for the NEB programs flow directly from State energy policies and are fundamentally different from the cost of providing T&D service.”).

[¶14] In short, the Commission concluded, building on its previous decisions, that it could not apply traditional ratemaking principles, in which the cost imposed by members of a particular class of ratepayers is used to determine the rates of providing T&D service, to public policy costs like those incurred from NEB programs. Id. at 10-11.

[¶15] In the March 2022 order, the Commission also rejected an argument made by IECG that public policy intended to mitigate climate change—like NEB programs—largely benefits residential and not commercial or industrial customers. Id. at 11. Concluding that all ratepayers benefit from

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state policies on climate change, the Commission stated that “basic rate design and equity principles would dictate that all ratepayers pay some portion of these costs.” Id. In further support of its conclusion that all classes of customers should pay the costs of both NEB programs, the Commission noted that the Legislature has explicitly exempted certain commercial and industrial customers connected to the grid at the transmission and sub-transmission level from some costs of state energy programs and that therefore, by inference, excluding customers from NEB program cost allocation in the absence of a Legislative exemption was not appropriate. Id. at 11 n.2.

[¶16] Finally, the Commission stated that it would open a rate design proceeding to determine rates, both inter- and intra-class, for T&D utilities to recover costs incurred from the NEB programs and, more generally, costs “driven by public policy programs that are unrelated to the cost of providing distribution service.” Id. at 13; see infra n.3. B. The Challenged Order

[¶17] The order challenged on appeal is the product of the rate design proceeding called for in the March 2022 order. See id. at 13. In the order appealed from, the Commission repeats points it made in the March 2022 order: for cost-recovery purposes, the three stranded cost categories outlined

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above should be treated similarly; all rate classes should pay for these costs; and costs arising out of energy-related public policy programs are “not informed by the kind of cost-of-service studies and methods that are typically the focus of electric utility rate design.” To address the inter-class allocation of post-restructuring and NEB costs, the Commission reasoned that because most of the policy objectives of the legislation creating these costs do not benefit any one class, the costs should be allocated to each class according to that class’s overall kWh load share.3 Additionally, the Commission concluded that pre- and post-restructuring stranded costs should be recovered within each class based on kWh usage. By contrast, the Commission concluded that NEB costs should be recovered within each class through a fixed customer charge—a charge that does not change based on kWh usage.

[¶18] The Commission explained that it decided to allow recovery of NEB costs within each class through a fixed customer charge instead of through a charge based on kWh load share because the latter would result in some NEB program participants paying nothing for the cost of NEB programs, which the

3 As to the inter-class allocation of pre-restructuring costs, the Commission concluded that such

costs should continue to be recovered volumetrically. The Commission noted that the proceeding did not explore this issue and thus it did not have a record upon which to assess a change in pre- restructuring cost allocation.

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Commission concluded would be unfair because everyone benefits from climate change mitigation policies. C. Procedural History

[¶19] The following procedural history “is drawn from the administrative record and the Commission’s order.” Off. of the Pub. Advoc. v. Pub. Utils. Comm'n, 2023 ME 77, ¶ 2, 306 A.3d 633.

[¶20] The Commission issued a notice of investigation opening the docket for this rate design proceeding in June 2022. Over the next nine months, the matter proceeded through intervention by interested parties, data requests and responses, a technical conference, testimony, and briefing. The hearing examiners issued a report with their recommendations in January 2023, some parties filed exceptions to the report in February 2023, and the Commission issued the challenged order on April 21, 2023. Thereafter, the following occurred:

 May 2, 2023: As a follow-up to the challenged order, the Commission issued a procedural order requesting that the participating utilities provide additional information, including “stranded cost rates and bill impact analyses by rate class reflecting all NEB-related stranded costs recovered through a fixed charge.”

 May 11, 2023: IECG timely filed a petition for reconsideration.

 May 24, 2023: The Commission issued a procedural order tolling the reconsideration period until further notice.

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 July 1, 2023: Central Maine Power’s proposed rate schedule, which included the treatment of NEB costs approved by the order, was stamp-approved by the Commission and went into effect.

 July 14, 2023: IECG withdrew its May 11 petition for reconsideration.

 July 18, 20, and 27, 2023: Multiple customers filed petitions to intervene and reconsider the order.

 July 25 and 27, 2023: IECG objected to the late-filed petitions to intervene.

 July 26, 2023: The Commission issued a procedural order stating, “[T]o the extent that there are any procedural deadlines pending (e.g., filing comments on the [customers’] requests for reconsideration), the Hearing Examiners stay such deadlines until further notice.”

 September 12, 2023: The Commission opened a new investigation of stranded cost rate design, Pub. Utils. Comm’n, Continuing Investigation into Stranded Cost Rate Design, No. 2023-230, Notice of Investigation (Me. P.U.C. Sept. 12, 2023), and granted the late-filing parties’ petitions in that proceeding. The notice of investigation limited the scope of the new investigation to “examining the impact of the [intra-class] fixed charge on customers, clarifying the definition of ‘rate class,’ as requested by Versant, and examining the possibility of a fixed charge for recovery of non-NEB stranded costs.” Id. at 3. The Commission noted that it would continue to investigate beyond the scope of the identified issues if “necessary and appropriate.” Id. The issues identified in the September 12 notice of investigation did not include inter-class allocation of NEB costs. See id.

[¶21] On October 3, 2023, IECG appealed the April 21, 2023, order.

See 35-A M.R.S. § 1320(1), (5) (2024); M.R. App. P. 2B(c)(1), 22.

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II. DISCUSSION

A. The appeal is timely.

[¶22] The Public Advocate argues that IECG’s appeal is untimely because, although IECG’s filing of a timely petition for reconsideration tolled the time to appeal, see M.R. App. P. 2B(c)(1), (2)(E), the twenty-one-day clock to appeal reset when IECG withdrew its petition on July 14, 2023. In response, IECG argues that the Commission proceedings were not final, and therefore not subject to the twenty-one-day deadline, until September 12, 2023, because the Commission had issued procedural orders staying procedural deadlines “until further notice,” and the exact posture of the proceedings was uncertain until the Commission opened the new docket and made clear that it considered the proceedings to be final. The Commission takes no position on the timeliness issue.

[¶23] A decision of the Commission is final when it “fully decides and disposes of the whole cause leaving no further questions for the future consideration and judgment of the [Commission].” Mech. Falls Water Co., 381 A.2d at 1087 (quotation marks omitted); see also Cent. Me. Power Co. v. Pub. Utils. Comm’n, 408 A.2d 681, 683 (Me. 1979) (noting that whether a decision of the Commission is final is a case-specific inquiry).

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[¶24] IECG’s initial position after it withdrew its petition for reconsideration—despite the apparent inconsistency with its decision to wait until the Commission opened a new docket to file its appeal—was that the Commission should reject the customers’ petitions as untimely. But the Commission tolled the reconsideration period in May 2023, see 65-407 C.M.R. ch. 110, § 11(D) (effective Nov. 26, 2012), and in its July 26, 2023, procedural order, instead of rejecting the customers’ petitions as untimely, stayed “any procedural deadlines pending,” stating that the Commission was “currently considering all procedural options.” We conclude that this language effectively established that the Commission’s proceedings were not final until the Commission opened a new docket, indicating that no further action would be taken in the instant matter. Because IECG filed its notice of appeal within twenty-one days of the opening of the new docket, its appeal to us is timely. See 35-A M.R.S. § 1320(1); M.R. App. P. 2B(c)(1). B. The appeal is not barred by res judicata.

[¶25] The Commission argues that IECG’s arguments are an improper attempt to appeal the March 2022 order and that the doctrine of administrative res judicata immunizes its prior order from collateral attack. Cf. City of Lewiston v. Verrinder, 2022 ME 29, ¶ 8, 275 A.3d 327.

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[¶26] It is true that IECG raises arguments that it unsuccessfully raised in February 2022, see Pub. Utils. Comm’n, Investigation of Rate Treatment of NEB Program Costs, No. 2021-360, IECG/CES Exceptions to Examiners’ Report (Me. P.U.C. Feb. 23, 2022), and that it did not appeal the March 2022 order. But the Commission’s argument fails because, as IECG notes, ratemaking is a legislative, not adjudicatory, function of the Commission, and is, therefore, not subject to principles of res judicata. See New England Tel. & Tel. Co. v. Pub. Utils. Comm’n, 390 A.2d 8, 23, 48, 53 n.34, 55 (Me. 1978); Sw. Bell Tel. Co. v. Ark. Pub. Servs. Comm’n, 593 S.W.2d 434, 445 (Ark. 1980); Cent. W. Va. Refuse, Inc. v. Pub. Serv. Comm’n, 438 S.E.2d 596, 600 (W. Va. 1993).

[¶27] Moreover, in the March 2022 order, the Commission expressly stated that further consideration of stranded cost rate design would take place in a future docket.4 Pub. Utils. Comm'n, Investigation of Rate Treatment of NEB Program Costs, No. 2021-360, Order, at 13 (Me. P.U.C. Mar. 11, 2022).

4 The Commission stated,

The Commission concurs with [] IECG . . . that a thorough review of stranded cost rate design is overdue and should be a priority. This is especially the case given the substantial costs of the NEB programs that will increasingly flow through stranded costs. However, the Commission notes [] acknowledging that a rate design proceeding is appropriate does not mean, as suggested by IECG[], that current existing rate design structures lack a legal or evidentiary basis. The Commission noted in its January 6th Order Denying Appeal that the utilities “have existing rate design structures in place for either outcome – recovery of NEB costs through either distribution or as stranded costs.” Thus, the Commission found that it was unnecessary to conduct a full rate design proceeding to make the initial decision of

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C. IECG’s preemption claim is not properly before us.

[¶28] IECG argues that the order is preempted by the FPA. IECG concedes that it did not raise its preemption argument before the Commission but asserts that because the argument relates to the Commission’s jurisdiction, the argument may be raised at any time. IECG also argues that we should address the preemption claim in the interests of justice and judicial economy.

[¶29] We have been consistently clear that “[i]ssues not raised at the administrative level are deemed unpreserved for appellate review.” Forest Ecology Network v. Land Use Regul. Comm’n, 2012 ME 36, ¶ 24, 39 A.3d 74; see Mazariegos–Paiz v. Holder, 734 F.3d 57, 62 (1st Cir. 2013) (“Were the court free to delve into the merits of issues not presented to the agency, it would effectively usurp the agency’s function.”). Even constitutional issues must be raised before an agency to be ripe for appeal. Oronoka Rest., Inc. v. Me. State Liquor Comm’n, 532 A.2d 1043, 1045 n.2 (Me. 1987).

whether NEB costs belong in stranded costs or distribution rates. Nevertheless, the Commission will shortly initiate a holistic review of stranded cost rate design matters.

This proceeding will address not only the kWh Credit program and Tariff Rate program, but other costs driven by public policy programs that are unrelated to the cost of providing distribution service.

Pub. Utils. Comm’n, Investigation of Rate Treatment of NEB Program Costs, No. 2021-360, Order at 13 (Me. P.U.C. Mar. 11, 2022).

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[¶30] The issue as to whether rates imposed to recover NEB costs are preempted under the FPA is complex, and, to date, this question has been only minimally addressed by federal (and state) authorities. See Hughes v. Talen Energy Marketing, LLC, 578 U.S. 150, 166 (2016); MidAmerican Energy Co., 94 F.E.R.C. ¶ 61,340 (2001); Sun Edison LLC, 129 F.E.R.C. ¶ 61,146 (2009); Steven Ferrey, Tightening the Legal ‘Net’: The Constitution’s Supremacy Clause Straddle of the Power Divide, 10 Mich. J. Env’t & Admin. L. 415, 431 (2021); Conor T. Burns, Sale or No Sale: Is It Time to Turn Back the Meter on State Net Metering Policies?, 17 Fla. St. Univ. Bus. Rev. 149, 158-59 (2018); Giovanni S. Saarman González, Evolving Jurisdiction Under the Federal Power Act: Promoting Clean Energy Policy, 63 UCLA L. Rev. 1422, 1447 (2016).

[¶31] As such, and sensitive to issues of primary jurisdiction, see Ashburnham Mun. Light Plant v. Me. Yankee Atomic Power Co., 1998 ME 270, ¶ 8, 721 A.2d 651, at a minimum, a fully developed administrative record and comprehensive ruling by the Commission would be needed before we ventured

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into this area.5 We therefore conclude that the argument has not been sufficiently developed for our review.6

D. The order is rational and sufficiently supported under our deferential standard of review.

[¶32] IECG’s remaining arguments go to the merits of the Commission’s decision. Although IECG has launched a broadside attack on the order, it has remained noticeably silent as to what sort of inter-class allocation or intra-class rate design it would deem to pass legal muster. We read IECG’s position as essentially arguing that the inter-class allocation and intra-class rate design are not sufficiently cost-causation based. IECG references traditional ratemaking principles to argue that NEB costs are tied to the cost of T&D service and require a cost-of-service study to identify a proper rate allocation and design that pinpoints cost causation within and between rate classes, and it challenges

5 We note that federal courts have deemed preemption claims jurisdictional and not waivable when they involve a choice of forum versus a choice of law. See, e.g., Fryer v. A.S.A.P. Fire & Safety Corp., 658 F.3d 85, 90 (1st Cir. 2011). IECG is not arguing that the Commission lacks jurisdiction, in other words is the wrong forum, to set, allocate, or design rates. Instead, IECG is essentially claiming that under the FPA, the Commission cannot set the price paid for power generated by participants in NEB programs at a rate higher than the wholesale market rate.

6 Further, IECG states that it “does not seek to invalidate the Maine NEB program.” But it appears

to be arguing that an above-market price for the NEB participants’ generation cannot be recovered in rates, which does seem contrary to the statutory scheme and could raise constitutional confiscation concerns. IECG’s lack of specificity as to the scope of its argument contributes to our incapacity to address the argument as presented to us on appeal. See French v. Merrill, 15 F.4th 116, 133 (1st Cir. 2021) (“It is not enough merely to mention a possible argument in the most skeletal way, leaving the court to do counsel’s work, create the ossature for the argument, and put flesh on its bones.” (alteration and quotation marks omitted)).

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the Commission’s rationale that because everyone benefits from climate change policies, a fixed customer charge makes sense. It also argues that the Commission’s insufficient consideration of cost imposition and benefits violates various statutory provisions.

[¶33] In considering IECG’s arguments, we must be sensitive to our deferential standard of review, particularly with regard to the Commission’s “expert judgment in choosing among various ratemaking techniques or methodologies.” Off. of the Pub. Advoc., 2023 ME 77, ¶ 8, 306 A.3d 633 (quotation marks omitted). 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. See NextEra Energy Res., LLC v. Me. Pub. Utils. Comm’n, 2020 ME 34, ¶¶ 37-38, 227 A.3d 117 (“The Commission’s decision will not be disturbed if it results from a reasonable exercise of discretion and is supported by substantial evidence in the record.” (quotation marks omitted)); Off. of the Pub. Advoc. v. Pub. Utils. Comm’n, 2024 ME 11, ¶¶ 12-13, 314 A.3d 116.

[¶34] The primary flaw in IECG’s argument is its assertion that the Commission must treat NEB costs like a component of the cost of delivering transmission and distribution services. As noted above, in both the March 2022

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order and the order on appeal, the Commission explained that stranded costs are incurred not from the utilities’ provision of T&D services, but from the Legislature’s creation of energy programs and the determination that the cost of those programs should be recovered through rates.

[¶35] The conclusion that NEB costs are not a component of traditional T&D service is rational. NEB costs are not part of the cost of transporting electricity over the electricity grid. IECG has not indicated with any specificity what a cost-of-service study would measure or achieve. Similarly, given that NEB costs are not incurred through T&D service, it is unclear what sort of evidence is lacking in the record to support the Commission’s ruling. For example, IECG has not explained why the Commission’s reasoning that everyone benefits from climate change policies is wrong or how rate classes or customers within a rate class differentially create the costs or reap the benefits of the legislated policies. Given that IECG provides no study of its own to show how costs and benefits are distributed between and within rate classes, or that the Commission’s choices to allocate NEB costs inter-class by load share and intra-class through a fixed charge violate any fundamental ratemaking principle, the Commission’s choices fall within its broad discretion given the

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record presented.7 See Me. Water Co. v. Pub. Utils. Comm'n, 482 A.2d 443, 456- 57 (Me. 1984) (“[I]n addition to recovery of the utility's total revenue requirement, the primary objectives of a sound rate design [include] . . . ‘the fair-cost-apportionment objective, which invokes the principle that the burden of meeting total revenue requirements must be distributed fairly among the beneficiaries of the service’ . . . .”) (quoting Bonbright, supra, at 292); Cent. Me. Power Co., 405 A.2d at 189-91 (discussing the breadth of the Commission’s discretion in classifying costs that are basically unallocable under the usual standards); Cent. Me. Power Co. v. Pub. Utils. Comm’n, 382 A.2d 302, 327-28 (Me. 1978) (“We know of no persuasive authority, however, . . . establishing a per se rule that all utility rates must be based solely on cost factors . . . . The concept of a ‘just and reasonable’ rate does not signify a particular single rate as the only lawful rate but rather encompasses a range within which rates may be deemed just and reasonable both in terms of revenue level and rate design. It is within the sound discretion of the Commission to fix the exact level and design within that range.”).

7 In any event, record evidence, including testimony and the parties’ briefs, supports the position

that the NEB programs have environmental benefits, that all ratepayers benefit from state policies on climate change, and that there is no reason to deviate from how other policy costs are allocated.

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[¶36] This leaves IECG’s argument that the Commission’s cost allocation and rate design violate state statutes. For the reasons brieϐly explained below as to each statute IECG raises, we disagree.

 The Restructuring Act, 35-A M.R.S. §§ 3208(5), (6), 3209(1): Section 3208(6) provides that the Commission must use estimates of stranded costs as the basis for stranded-costs charges to be imposed by the utilities in rates when retail access begins. See also id. § 3208(5).

Section 3209(1) provides that rate design to recover T&D costs, stranded costs, and other costs recoverable pursuant to the Restructuring Act must be consistent with existing law “as applicable.”

This language does not preclude the Commission’s choice of allocation and design for NEB costs. “Stranded costs” as used in these sections do not include NEB costs; they include only pre-restructuring costs.

See 35-A M.R.S. § 3208(1), (3). Hence, sections 3208(5) and 3209(1)

are unrelated to the recovery of NEB costs. If there were a connection, that section 3209(1) lists stranded costs separately from T&D costs suggests that stranded costs should not be treated as a component of T&D costs.

 The Electric Rate Reform Act, 35-A M.R.S. §§ 3152, 3154 (2024)

(ERRA): ERRA includes a declaration that improvements in T&D rate design and related regulatory programs have the potential to reduce the cost of electric utility service to consumers, to encourage energy conservation and efficient use of existing facilities, and to minimize the need for expensive new electric transmission capacity. Id. § 3152(1).

Therefore, the purpose of the ERRA is to “[r]equire the Commission to relate [T&D] rates more closely to the costs of providing [T&D]

service.” Id. § 3152(1)(A). Section 3154 addresses the development of T&D rate design proposals and related programs to implement energy conservation and efficiency and other goals. As noted above, the Commission could reasonably conclude that NEB costs are not related to the costs of providing T&D service. Moreover, IECG has not explained how allocating costs among ratepayer classes by load share

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and applying a fixed customer charge within each class undermines these statutory goals.

 Incentive ratemaking, 35-A M.R.S. § 3195(1) (2024): This statutory provision provides that the Commission may establish reasonable rate-adjustment mechanisms to promote efficient T&D operations and least-cost planning,8 and provides a non-exhaustive list of potential rate-adjustment mechanisms, none of which pertain to stranded costs.

The order on appeal does not involve a rate-adjustment mechanism.

How NEB costs are collected is unrelated to this statutory scheme of rate design based upon performance criteria, and IECG has not explained how the order’s allocation and design undermines least-

cost planning.

 35-A M.R.S. § 3210-C(2)(A): IECG cites this provision for the proposition that the Legislature has directed that renewable generation resources be used “primarily for their capacity value, not their energy value.” Section 3210-C relates to the adequacy of resources required to meet peak demand and ensure reliability within a regional energy system. See L.D. 2041, Summary (122nd Legis.

2006). The statute reflects the Legislature’s desire to prioritize renewable generation and demand response techniques to meet these regional resource requirements. The statute is unrelated to how NEB costs are recovered inter- or intra-class except to the extent that it reflects a state policy, consistent with the NEB programs, to promote the use of renewable energy.

8Least-cost planning is “a planning process that can be used by utilities in forecasting needs, assessing uncertainties, and hedging risks. . . . [It] is a strategy whose goal is to provide reliable electrical services at the lowest overall cost with a mix of supply-side and demand-side resources [and with] a flexible system that helps utilities and regulators to respond to uncertainties and to cope with risks.” 1 National Association of Regulatory Utility Commissioners, Least‐Cost Utility Planning Handbook for Public Utility Commissioners 6 (1988), https://etapublications .lbl.gov/sites/default/files/least_cost_utility_handbook_vol_1.pdf (last visited July 30, 2024) [https://perma.cc/T4L9-BWUY ].

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[¶37] Further, to the extent that IECG is arguing as a general matter that rate allocation and design cannot be based on the concept that everyone benefits from climate change policies, the Legislature expressly requires the Commission to consider policies to reduce greenhouse gas emissions. To the extent that IECG is arguing that the order ignores Commission precedent, the contrary is true: the order is the logical continuation of the Commission’s treatment of other stranded costs since 1997.

III. CONCLUSION

[¶38] The Commission’s approach to allocation and rate design regarding NEB costs is simple. A more sophisticated allocation or design might also have been justiϐied and adopted within the Commission’s broad discretion. Given that the Commission has ordered the further collection of data showing rate impacts and has ordered party input, the Commission may very well in the future reϐine its approach to NEB cost recovery. But for the purposes of our review, the Commission’s current allocation and design are sufϐicient to avoid being disturbed by this Court.

The entry is:

Judgment affirmed.

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Anthony W. Buxton, Esq. (orally), and Joseph G. Donahue, Esq., Preti Flaherty Beliveau & Pachios, LLP, Augusta, for appellant Industrial Energy Consumer Group

Leslie Raber, Esq. (orally), and Jordan McColman, Esq., Maine Public Utilities Commission, Augusta, for appellee Maine Public Utilities Commission William S. Harwood, Esq., and Andrew Landry, Esq. (orally), Office of the Public Advocate, Augusta, for intervenor Office of the Public Advocate

Public Utilities Commission docket number 2022-00160 FOR CLERK REFERENCE ONLY