Constellation Mystic Power v. FERC, No. 20-1343 (D.C. Cir. 2022)

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Justia Opinion Summary

Constellation Mystic Power, LLC (Mystic)—a subsidiary of Exelon Generation Company, LLC (ExGen), which itself is a subsidiary of Exelon Corporation (Exelon)—announced its intention to retire the Mystic Generating Station (Mystic Station). ISO New England entered into a cost-of-service agreement with Mystic and ExGen to keep two of Mystic Station’s generating units, referred to as Mystic 8 and 9, in service between June 2022 and May 2024. The parties filed the proposed agreement (Mystic Agreement) with the Federal Energy Regulatory Commission (Commission or FERC). The Commission ultimately approved the terms of the Mystic Agreement.
 
At issue are Commission orders related to its approval of the Mystic Agreement. Two groups of petitioners sought review: Mystic and a group of New England state regulators (State Petitioners). The DC Circuit dismissed Mystic’s petition for review in part and denied it in part; the court granted the State Petitioners’ petitions. The court held that the Commission’s application of the original cost test to determine Mystic 8 and 9’s rate base was not arbitrary and capricious. The court dismissed Mystic’s objection to the Commission’s selection of capital structure as moot in light of the Commission’s May 2022 Order. The court further concluded that the Commission properly included historical rate base components in the true-up mechanism but also find that the Commission failed to respond to the State Petitioners’ request for clarification.

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United States Court of Appeals FOR THE DISTRICT OF COLUMBIA CIRCUIT Argued May 5, 2022 Decided August 23, 2022 No. 20-1343 CONSTELLATION MYSTIC POWER, LLC, PETITIONER v. FEDERAL ENERGY REGULATORY COMMISSION, RESPONDENT BRAINTREE ELECTRIC LIGHT DEPARTMENT, ET AL., INTERVENORS Consolidated with 20-1361, 20-1362, 20-1365, 20-1368, 21-1067, 21-1070 On Petitions for Review of Orders of the Federal Energy Regulatory Commission Matthew A. Fitzgerald argued the cause for petitioner Constellation Mystic Power, LLC. With him on the briefs were Noel H. Symons and Katlyn A. Farrell. Jeffrey A. Schwarz argued that cause for State petitioners. With him on the briefs were Seth A. Hollander, Assistant 2 Attorney General - Special Litigation, Office of the Attorney General for the State of Connecticut, Scott H. Strauss, Amber L. Martin Stone, Kirsten S. P. Rigney, Robert Snook, Assistant Attorney General - Environment, Office of the Attorney General for the State of Connecticut, Andrew Minikowski and Julie Datres, Staff Attorneys, Ashley M. Bond, Maura Healy, Attorney General, Office of the Attorney General for the Commonwealth of Massachusetts, Christina Belew, Assistant Attorney General, Jason Marshall, and Phyllis G. Kimmel. Scott H. Strauss, Jeffrey A. Schwarz, Amber L. Martin Stone, and John P. Coyle were on the briefs for intervenors Braintree Electric Light Department, et al. in support of State petitioners. Robert M. Kennedy and Carol J. Banta, Senior Attorneys, Federal Energy Regulatory Commission, argued the causes for respondent. With them on the brief were Matthew R. Christiansen, General Counsel, and Robert H. Solomon, Solicitor. John P. Coyle argued the cause for intervenors Braintree Electric Light Department, et al. in support of respondent. With him on the brief were Scott H. Strauss, Jeffrey A. Schwarz, and Amber L. Martin Stone. Michael J. Thompson, Ryan J. Collins, and Maria Gulluni were on the brief for intervenor ISO New England, Inc. in support of respondent. Before: SRINIVASAN, Chief Judge, HENDERSON and RAO, Circuit Judges. Opinion for the Court filed PER CURIAM. 3 PER CURIAM: In March 2018, Constellation Mystic Power, LLC (Mystic)—a subsidiary of Exelon Generation Company, LLC (ExGen), which itself is a subsidiary of Exelon Corporation (Exelon)1—announced its intention to retire the Mystic Generating Station (Mystic Station), a natural gas-fired generator serving the greater Boston metropolitan area, after the facility’s existing capacity obligations expired in May 2022. The region’s independent system operator, ISO New England, concluded that Mystic Station’s loss would exacerbate anticipated stresses on the region’s electricity network during winter months and increase the risk of rolling blackouts. ISO New England also found that Mystic Station’s retirement risked the closure of its sole fuel source, the Everett Marine Terminal (Everett)—a liquified natural gas (LNG) import and regasification facility currently owned and operated by an ExGen subsidiary—adding to the risk of blackouts in the region. In light of these findings, ISO New England entered into a cost-of-service agreement with Mystic and ExGen to keep two of Mystic Station’s generating units, referred to as Mystic 8 and 9, in service between June 2022 and May 2024. The parties filed the proposed agreement (Mystic Agreement) with the Federal Energy Regulatory Commission (Commission or FERC). The Commission ultimately approved the terms of the Mystic Agreement, albeit with significant modifications. 1 In February 2022, after the petitions for review here had been filed, Exelon consummated a spinoff transaction that placed ExGen—which was renamed Constellation Energy Generation, LLC—and Mystic under the corporate parentage of Constellation Energy Corporation. Despite this transaction, we will refer to Mystic’s parents as ExGen and Exelon, as the parties have done, unless context dictates otherwise. 4 At issue are six Commission orders related to its approval of the Mystic Agreement. See Constellation Mystic Power, LLC, 164 FERC ¶ 61,022 (July 13, 2018) (July 2018 Order); Constellation Mystic Power, LLC, 165 FERC ¶ 61,267 (Dec. 20, 2018) (December 2018 Order); Constellation Mystic Power, LLC, 172 FERC ¶ 61,043 (July 17, 2020) (First July 2020 Rehearing Order); Constellation Mystic Power, LLC, 172 FERC ¶ 61,044 (July 17, 2020) (Second July 2020 Rehearing Order); Constellation Mystic Power, LLC, 172 FERC ¶ 61,045 (July 17, 2020) (Compliance Order); Constellation Mystic Power, LLC, 173 FERC ¶ 61,261 (Dec. 21, 2020) (December 2020 Rehearing Order). Two groups of petitioners now seek review of those orders: Mystic and a group of New England state regulators (State Petitioners).2 As detailed infra, we dismiss Mystic’s petition for review in part and deny it in part; we grant the State Petitioners’ petitions. I. BACKGROUND A. Statutory Background Section 201(b) of the Federal Power Act (FPA) grants the Commission jurisdiction of the transmission and wholesale sale of electric energy in interstate commerce. 16 U.S.C. § 824(b); see New York v. FERC, 535 U.S. 1, 6–7 (2002). The FPA provides that “[a]ll rates for or in connection with jurisdictional sales and transmission service are subject to review by FERC to ensure that the rates are just and reasonable 2 The State Petitioners include the Connecticut Public Utilities Regulatory Authority, the Connecticut Department of Energy and Environmental Protection, the Connecticut Office of Consumer Counsel (collectively, Connecticut Parties), the Attorney General of the Commonwealth of Massachusetts (Massachusetts AG) and the New England States Committee on Electricity, Inc. (States Committee). 5 and not unduly discriminatory or preferential.” New England Power Generators Ass’n v. FERC (NEPGA), 881 F.3d 202, 205 (D.C. Cir. 2018)); see 16 U.S.C. §§ 824d(a), (e), 824e(a). Section 205 requires that all public utilities “file with the Commission . . . all rates and charges for any transmission or sale subject to the jurisdiction of the Commission,” 16 U.S.C. § 824d(c), with the utility bearing the burden to show that its proposed rate is lawful, id. § 824d(e). See NEPGA, 881 F.3d at 205. If the Commission determines that a rate is “unjust, unreasonable, unduly discriminatory or preferential,” it must set aside the rate and replace it with one that is just and reasonable. 16 U.S.C. § 824e(a)–(b). A negatively affected party may challenge a Commission-approved rate by filing a complaint with the Agency, and it carries the burden of demonstrating that the rate is unjust or unreasonable. See id. § 824e(a)–(b). The reasonableness of a rate is assessed in light of the FPA’s goals of promoting reliable service at reasonable rates and developing plentiful energy supplies. See Consol. Edison Co. v. FERC, 510 F.3d 333, 342 (D.C. Cir. 2007); see also NAACP v. FPC, 425 U.S. 662, 669–70 (1976). B. The New England Electricity Market ISO New England is the independent system operator3 that operates the transmission facilities and administers the wholesale electricity markets across six states—Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island and Vermont. The wholesale markets facilitate the sale of 3 Independent system operators result from the unbundling of transmission and generation services—which were historically handled by a single, vertically integrated utility—and serve to coordinate, control and monitor the electricity transmission facilities owned by its member utilities in order to ensure nondiscriminatory access to all electricity generators. See Midwest Indep. Transmission Sys. Operator, Inc. v. FERC, 388 F.3d 903, 906 (D.C. Cir. 2004). 6 electricity by generators to electric utilities and electricity traders before its eventual sale to end-use consumers. The rates charged by ISO New England for access to its transmission system and the rules governing the wholesale markets under its purview are set out in a grid-wide tariff. In addition to ensuring adequate supply to meet presentday electricity demands, ISO New England must also ensure sufficient supplies to meet future needs. This is accomplished via a forward-capacity market, in which load serving entities— i.e., the utilities delivering electricity to end users—purchase capacity, which “is not electricity itself but the ability to produce it when necessary,” from generators. Pub. Citizen, Inc. v. FERC, 839 F.3d 1165, 1167–68 (D.C. Cir. 2016) (quoting Conn. Dep’t of Pub. Util. Control v. FERC, 569 F.3d 477, 479 (D.C. Cir. 2009)). The forward-capacity market is conducted via an auction held three years in advance of a particular capacity commitment period. Generators submit bids reflecting the lowest price they will accept before exiting the market. During the “descending clock” auction, the capacity price is steadily lowered, causing bidding generators to exit. Once the amount of capacity offered reaches ISO New England’s projected capacity requirement for the commitment period, the auction stops, and those generators remaining in the market are paid the clearing price, regardless of their initial bids. See generally id. (explaining forward-capacity auction). Once a generator participates in a forward-capacity auction, it is automatically re-entered into every subsequent auction unless it affirmatively seeks to remove its capacity from the market for that commitment period or permanently, with the latter option constituting “retirement.” If a generator seeks to retire from the market, it must submit a Retirement DeList Bid eleven months before the auction corresponding to the period for which it intends to retire, which signals the 7 generator’s intent to exit the market if the clearing price falls below its bid price and gives ISO New England an opportunity to determine if the generator’s proposed retirement presents a service risk to the region. If ISO New England so concludes, it may ask the generator to remain in operation; if the generator accepts, it can then elect to receive either its initial bid price or a cost-of-service rate. C. Mystic 8 and 9 Mystic 8 and 9 are combined-cycle natural gas-fired generating units with a combined summer capacity of about 1,400 megawatts.4 The two units run on revaporized LNG imported via marine terminal, making them unique among other natural gas-fired units in the region, which run on vapor natural gas imported through regional pipelines. Following the restructuring of the Massachusetts energy market in the 1990s, Mystic Station was acquired from the Boston Edison Company by Sithe Energies, Inc. in 1999. Sithe shortly thereafter began construction of Mystic 8 and 9, with the two units beginning commercial operation as merchant generators in 2003; according to Mystic, the two units were constructed at a cost of just under $1 billion. In 2002, ExGen acquired Sithe but subsequently ran into financial troubles in connection with the construction of Mystic 8 and 9. In May 2004, ExGen reached a settlement with its lenders, transferring Mystic Station to a special purpose entity owned by a consortium of lenders in exchange for the cancellation of debts. 4 Mystic units 1 through 6 have been decommissioned, and the other units still in operation, Mystic 7 and Mystic Jet, are subject to Retirement De-List Bids but have not been designated as units necessary to meet reliability needs. None of these units is at issue here. 8 According to Mystic, as a result of this transaction, Mystic 8 and 9 were valued at approximately $547 million. In 2010, after the special purpose entity declared bankruptcy, subsidiaries of Constellation Energy Group, Inc. purchased Mystic Station, as well as a separate natural gasfired facility unrelated to the proceedings at issue, for $1.1 billion. In 2012, Constellation Energy Group merged with Exelon. According to Mystic, as part of the merger, Mystic 8 and 9 were independently appraised at $925 million. As a result of the merger, Mystic, which traces its parentage through ExGen to Exelon, became the owner of Mystic 8 and 9. D. The Everett Marine Terminal Everett, located on a property near Mystic Station, is Mystic 8 and 9’s sole source of revaporized LNG, making the two units “the only natural gas-fired units in the United States that are directly connected to an LNG import regasification facility.” Joint Appendix (J.A.) 7. Everett, the longestoperating LNG import terminal in the United States, has a storage capacity of 3.4 billion cubic feet and connects to, aside from Mystic 8 and 9, two outbound interstate pipeline facilities and a local gas company’s distribution facility. When the Commission proceedings began, Everett was owned by Distrigas of Massachusetts, LLC, a subsidiary of Engie Gas & LNG Holdings LLC, although Exelon was already in the process of purchasing the Everett facility. According to William Berg, an Exelon executive, the company determined that acquisition of Everett “was the best and most reliable option for Mystic to meet its existing capacity supply obligations through May 2022 without significant risk of nonperformance.” J.A. 197. In late 2018, while the Commission’s proceedings were ongoing, Exelon finalized its purchase of 9 Everett, which is now owned by Constellation LNG, LLC, another subsidiary of ExGen. E. The Mystic Agreement In 2018, Mystic concluded that Mystic Station was no longer economically viable, notified ISO New England of its intent to retire when its existing capacity supply obligations expired in May 2022 and submitted the required Retirement De-List Bid. Following Mystic’s announcement, ISO New England analyzed the impact of Mystic 8 and 9’s retirements on the region’s fuel security during the winter months, when natural gas-fired power plants have difficulties obtaining the necessary fuel through the region’s limited pipeline network due to priority demands for heating. See Belmont Mun. Light Dep’t v. FERC, 38 F.4th 173, 180–81 (D.C. Cir. 2022) (discussing ISO New England’s fuel security analysis). ISO New England concluded that the loss of Mystic 8 and 9, given their unique reliance on imported LNG rather than vapor natural gas distributed through regional pipelines, would likely result in multiple days of “load shedding”—i.e., rolling blackouts—during the 2022 through 2024 capacity commitment periods. ISO New England further determined that Mystic 8 and 9’s retirements could affect the financial viability of Everett, whose retirement could further exacerbate the length and severity of load shedding events. In light of these findings, ISO New England sought to retain Mystic 8 and 9 for two years beyond their planned retirements. In May 2018, Mystic, acting pursuant to section 205 of the FPA, filed with the Commission an agreement, the Mystic Agreement, among itself, Exelon and ISO New England that would provide Mystic cost-of-service compensation for the continued operation of Mystic 8 and 9 from June 1, 2022, until May 31, 2024. We go into greater 10 detail infra as to several of the cost inputs comprising Mystic’s cost-of-service rate under the agreement but, in simplified terms, the rate is derived from four primary cost inputs: (1) a return on Mystic 8 and 9’s “rate base,” meaning the value of the facilities used to provide service to ratepayers less depreciation; (2) operation and maintenance expenses; (3) depreciation expenses; and (4) taxes. As part of its filing, Mystic attached a separate agreement between Mystic and Everett, referred to as the Everett Agreement. Per the Everett Agreement, over which the Commission disclaims jurisdiction, see Second July 2020 Rehearing Order, at ¶ 43; FERC Br. 53, Mystic agreed to pay Everett a cost-based rate for the fuel used by Mystic 8 and 9 alongside a monthly charge (Fuel Supply Charge) covering 100 per cent of Everett’s fixed operating and maintenance costs as well as a return on investment tied to Everett’s rate base. As originally proposed, the Fuel Supply Charge would be offset by 50 per cent of the profits Everett earned on third-party sales over the course of the Everett Agreement. F. The Commission Proceedings This brings us to the Commission orders underlying this litigation. For clarity, rather than take the orders chronologically, we break up the orders according to the five disputed components of the Commission-approved Mystic Agreement. Mystic’s Rate Base: Under cost-of-service ratemaking principles, the starting point to calculate a generator’s return on capital is the generating facility’s rate base, or the value of the assets used to serve ratepayers. See NEPCO Mun. Rate Comm. v. FERC, 668 F.2d 1327, 1335 (D.C. Cir. 1981). Mystic initially proposed to set Mystic 8 and 9’s rate base according to the $925 million valuation it made in connection with the 2012 11 Constellation Energy Group-Exelon merger, before adding post-acquisition capital expenditures and subtracting depreciation. In its December 2018 Order, however, the Commission rejected Mystic’s approach as inconsistent with the Commission’s “original cost test,” which provides that a utility “may only earn a return on (and recovery of) the lesser of the net original cost of plant or, when plant assets change hands in arms-length transactions, the purchase price of the plant,” id. at ¶ 63; see infra Part III (explaining original cost test), and directed Mystic to reduce its valuation of Mystic 8 and 9 to account for past sales of the units at prices lower than the 2012 valuation, see id. at ¶¶ 63–66. On rehearing, the Commission rejected Mystic’s claim that the original cost test, as applied by the Commission, was inappropriate to calculate its return on Mystic 8 and 9’s rate base, see generally Second July 2020 Rehearing Order, at ¶¶ 105–111, and on compliance, rejected Mystic’s proposed rate base calculation for failing to account for the 2004 $547 million transfer in lieu of foreclosure, see Compliance Order, at ¶ 45. Mystic’s Capital Structure: Alongside its rate base, a generator’s return on capital under a cost-of-service model is derived from its overall rate of return, which is dependent upon its capital structure—i.e., the relative amounts of debt and equity. See NEPCO, 668 F.2d at 1335. Mystic initially proposed using the capital structure of its immediate parent, ExGen: 67.28 per cent equity and 32.72 per cent debt. See December 2018 Order, at ¶ 35. The Commission rejected this proposal, finding the proposed structure too equity-heavy relative to the industry, see id. at ¶¶ 48–51, and instead directed Mystic to use the capital structure of ExGen’s parent, Exelon, which was 52.4 per cent debt and 47.6 per cent equity, id. at ¶ 52. After Mystic sought rehearing, the Commission 12 reaffirmed its determination, again citing the anomalous nature of ExGen’s capital structure relative to the industry. See Second July 2020 Rehearing Order, at ¶¶ 132–34. After the petitions for review had been filed but before oral argument, the Commission issued an additional order that, although not subject to review in this proceeding, is nevertheless relevant. In February 2022, Exelon consummated a spinoff transaction that placed ExGen and Mystic under the corporate parentage of Constellation Energy Corporation. See Constellation Mystic Power, LLC, 179 FERC ¶ 61,081, at ¶ 6 (May 2, 2022) (May 2022 Order). As a result, Mystic amended the Mystic Agreement to reflect the changes in corporate structure and, as relevant here, argued that Exelon’s capital structure was no longer relevant—as Exelon no longer had any relationship with Mystic—and again requested to use ExGen’s capital structure. Id. at ¶ 9. The Commission “agree[d] with Mystic that it would be inappropriate to continue basing its capital structure and cost of debt on those of Exelon Corporation,” id. at ¶ 25, but further explained that Mystic had not yet shown ExGen’s capital structure to be just and reasonable, id. at ¶ 24. The Commission accordingly set a hearing to determine the appropriate capital structure. Id. at ¶¶ 24–25. Everett’s Costs: The Commission rejected Mystic’s proposal to recover 100 per cent of Everett’s fixed operating and maintenance costs via the Fuel Supply Charge, instead adopting its Trial Staff’s proposal that would allocate 91 per cent of Everett’s costs—the historical ratio of Everett’s vapor sales, as opposed to its LNG sales, to its total sales—and the Staff’s related revenue crediting mechanism, whereby Everett would retain up to 50 per cent of the margin on third-party forward sales, meaning those made at least three months in 13 advance.5 See December 2018 Order, at ¶¶ 133–35. The Commission also rejected Mystic’s proposal to include the Everett acquisition cost as part of Everett’s rate base, which is used to calculate the return-on-investment component of the Fuel Supply Charge. See id. at ¶¶ 148–49. On rehearing, the Commission rejected Mystic’s arguments regarding the exclusion of Everett’s acquisition cost from its rate base. See Second July 2020 Rehearing Order, at ¶¶ 113, 118–20. Further, the Commission rejected arguments by the Massachusetts AG, one of the State Petitioners, that the Commission lacked jurisdiction to review and approve the inclusion of Everett’s fixed operating costs as a component of Mystic’s proposed cost-of-service rate, asserting that “[t]he Fuel Supply Charge is a component of Mystic’s cost-of-service rate and, as a result, is subject to Commission review and approval.” First July 2020 Rehearing Order, at ¶¶ 16–18, 26– 31. Despite comments from several State Petitioners objecting to the Commission’s allocation of Everett-related costs, see Second July 2020 Rehearing Order, at ¶¶ 57–60, 62, the Commission reaffirmed the appropriateness of its 91 per cent allocation, see id. at ¶¶ 64–65. In response to comments noting that vapor sales are made to parties other than Mystic, the Commission reasoned that those sales nevertheless benefit Mystic “by helping to manage Everett’s tank.” Id. at ¶ 64. But the Commission did decide to eliminate revenue crediting, finding that “proper cost allocation based on cost-causation principles obviate[d] the need” for the revenue crediting and Under the revenue crediting mechanism, “the first 10 million MMBtus are credited 90 percent to Mystic (i.e., back to ratepayers) and 10 percent to Constellation LNG, revenue from the next 30 million MMBtus are credited 80 percent to Mystic and 20 percent to Constellation LNG, and so on until all deliveries above 60 million MMBtus are credited 50/50 as initially proposed by Mystic.” December 2018 Order, at ¶ 134. 5 14 questioning its own jurisdiction to approve an incentive mechanism that “focuses directly on Everett’s conduct rather than Mystic’s.” Id. at ¶ 66. The Connecticut Parties, a subset of the State Petitioners, sought rehearing on the elimination of revenue crediting, arguing that “unless or until Mystic’s share of Everett costs is reduced to correspond to its use of the facilities,” the Commission should “restore the crediting mechanism.” J.A. 1664. The Commission denied their request. On this issue, then-Commissioner (now Chairman) Glick dissented from all of the orders at issue, asserting that the Commission overstepped its jurisdictional boundaries by reviewing and approving recovery of Everett-related costs that, in his view, bore little relationship to Mystic’s jurisdictional rate. See, e.g., December 2018 Order (Glick, C., dissenting); First July 2020 Rehearing Order (Glick, C., dissenting). True-Up Mechanism: Recognizing that many of the components of Mystic’s cost-of-service rate were based, at least in part, on Mystic’s projections of future costs, the Commission directed Mystic to include a “true-up” mechanism in the Mystic Agreement, which would allow parties to reconcile cost projections with actual expenditures via surcharges and refunds as necessary. See July 2018 Order, at ¶ 20. Mystic initially proposed a true-up mechanism that would have applied only to specific subsets of rate inputs, see December 2018 Order, at ¶ 165, but the Commission rejected this approach, instead “direct[ing] that the true-up mechanism apply to the entire [Mystic] Agreement, with the exception of the [return on equity],” id. at ¶ 177. The Commission emphasized that the true-up process included Mystic’s revenues. Id. at ¶ 179. The Commission also noted that the reasonableness of tank congestion charges passed along to ratepayers “is more appropriately reviewed during the true-up process,” id. at ¶ 164, but later determined that review of tank 15 congestion charges was “no longer required” given its elimination of the revenue crediting mechanism, see Second July 2020 Rehearing Order, at ¶ 73. Mystic sought rehearing on the breadth of the true-up mechanism as it applied to pre-2018 costs related to Mystic 8 and 9 that, in Mystic’s view, had already been fully litigated. See Second July 2020 Rehearing Order, at ¶ 79. The Commission denied rehearing, finding that those historic numbers had not yet been fully litigated and were thus appropriately “subject to true-up.” Id. at ¶ 86. Mystic also objected to the inclusion of revenues as part of the true-up process. Id. at ¶ 80. The Commission agreed with this argument and “set aside” its earlier requirement that Mystic “true-up revenues.” Id. at ¶ 88. The States Committee, another of the State Petitioners, sought clarification, or rehearing in the alternative, as to whether interested parties could still challenge the calculation of revenue credits despite the Commission’s decision to omit revenues from the true-up process. See J.A. 1716. As they see it, the Commission acknowledged their request, see December 2020 Rehearing Order, at ¶ 25, but failed to address it adequately. See infra Part VI.B.1. With regard to the tank congestion charges, the States Committee also sought rehearing, arguing that if the costs of third-party sales are being passed on to ratepayers, ratepayers should have some mechanism to review and challenge the reasonableness of those sales, see J.A. 1712–13, arguments that the Commission addressed in its final rehearing order, see December 2020 Rehearing Order, at ¶¶ 26–28. Clawback Provision: In its December 2018 Order, the Commission determined that the Mystic Agreement was not just and reasonable without a “clawback” provision—which 16 would require Mystic to reimburse ratepayers for certain capital and repair expenditures made over the course of the Mystic Agreement if Mystic 8 and 9 were to re-enter the New England energy market after the Agreement expires. See December 2018 Order, at ¶ 208. In essence, a clawback provision disincentivizes a generating facility from switching between cost-of-service and market-based rates so that ratepayers finance investments during the term of a cost-ofservice agreement that benefit the facility beyond the term of the agreement. Id.; see also Midcontinent Indep. Sys. Operator, Inc., 161 FERC ¶ 61,059, at ¶ 55 (2017). The Commission accordingly directed Mystic to revise the Mystic Agreement to include a clawback provision. See December 2018 Order, at ¶ 208. The States Committee sought clarification as to whether the required clawback provision would apply to consumerfunded investments and repairs in connection with both Mystic 8 and 9 and Everett. See J.A. 1374. On compliance, Mystic proposed a clawback provision applicable to certain repairs and capital expenditures made by Mystic. See J.A. 1506 (proposed clawback language); Compliance Order, at ¶ 16. The States Committee and Connecticut Parties protested the omission of Everett expenditures from Mystic’s proposed clawback provision, pointing to the affiliate relationship between Mystic and Everett. See J.A. 1509–11 (States Committee); J.A. 1512–15 (Connecticut Parties). The Commission ultimately approved Mystic’s proposed clawback provision. See Compliance Order, at ¶ 25. In the Second July 2020 Rehearing Order, the Commission rejected the request that the provision encompass Everett’s costs, noting that neither Everett nor the Everett Agreement falls within the Commission’s jurisdiction and concluding that it “lack[ed] jurisdiction to require a clawback, true-up, and/or refund of 17 Everett’s costs.” See Second July 2020 Rehearing Order, at ¶ 43. The Commission further explained that, if Mystic 8 and 9 retired while Everett remained in service, the Mystic Agreement would terminate, leaving “no rate within the jurisdiction of the Commission through which to order a refund.” Id. In the Compliance Order, the Commission denied the States Committee’s and Connecticut Parties’ related protests, referring back to the Second July 2020 Rehearing Order. See Compliance Order, at ¶ 28. The Commission also denied the Connecticut Parties’ subsequent request for rehearing for the same reasons it outlined in the July 2020 orders. See December 2020 Rehearing Order, at ¶ 39. G. Petitions for Review Mystic and the State Petitioners petitioned for review of the various Commission orders modifying and ultimately approving the Mystic Agreement. Mystic objects to the Commission’s application of the original cost test in determining Mystic 8 and 9’s rate base; the selection of Exelon’s capital structure instead of ExGen’s; the exclusion of Everett’s acquisition cost from the Fuel Supply Charge calculation; and the inclusion of Mystic 8 and 9’s rate base components as part of the true-up process. The State Petitioners, for their part, object to the Commission’s exercise of jurisdiction of and allocation of Everett’s costs as part of the Fuel Supply Charge; the exclusion of Everett’s costs from the clawback provision; the failure to address the request to allow revenue credit calculations to be reviewed during the true-up process; the confusion over who can review the reasonableness of tank congestion charges during that process; and the failure 18 to address the incentives created by the Mystic Agreement’s treatment of delayed capital projects. We dismiss Mystic’s petition for review in part and deny it in part, and we grant the State Petitioners’ petitions. The opinion proceeds as follows: In Part III, we hold that the Commission’s application of the original cost test to determine Mystic 8 and 9’s rate base was not arbitrary and capricious. In Part IV, we dismiss Mystic’s objection to the Commission’s selection of capital structure as moot in light of the Commission’s May 2022 Order. In Part V, we find that the Commission acted arbitrarily and capriciously in allocating Everett’s operating costs but otherwise acted lawfully in excluding Everett’s acquisition cost from the Fuel Supply Charge calculation. In Part VI, we conclude that the Commission properly included historical rate base components in the true-up mechanism but also find that the Commission failed to respond to the State Petitioners’ request for clarification as to whether interested parties may challenge the calculation of Mystic’s revenue credits and that the December 2020 Rehearing Order created confusion over who can review the tank congestion charges during the true-up process. Finally, in Part VII, we hold that the Commission’s jurisdictional rationale for excluding costs related to Everett from the clawback process does not constitute reasoned decisionmaking and that the Commission failed to address related arguments raised by the State Petitioners. II. STANDARD OF REVIEW We begin by setting forth the standard of review common to all of the objections brought by the petitioners. This Court will set aside a Commission order found to be “arbitrary, capricious, an abuse of discretion, or otherwise not in accordance with law.” 5 U.S.C. § 706(2)(A); see Del. Div. of 19 Pub. Advoc. v. FERC, 3 F.4th 461, 465 (D.C. Cir. 2021). Our role is not to ascertain “whether a regulatory decision is the best one possible or even whether it is better than the alternatives.” FERC v. Elec. Power Supply Ass’n (EPSA), 577 U.S. 260, 292 (2016). It is instead limited to ensuring the Commission can demonstrate that its decision is supported by substantial evidence in the record, see Emera Me. v. FERC, 854 F.3d 9, 22 (D.C. Cir. 2017); see also 16 U.S.C. § 825l(b), and “articulate[s] a satisfactory explanation for its action including a rational connection between the facts found and the choice made,” Del. Div. of Pub. Advoc., 3 F.4th at 465 (quoting Motor Vehicle Mfrs. Ass’n of U.S., Inc. v. State Farm Mut. Auto. Ins. Co., 463 U.S. 29, 43 (1983)). Regarding ratemaking, the Commission is required to ensure that electricity rates are “just and reasonable.” 16 U.S.C. §§ 824d(a), 824e(a). “The statutory requirement that rates be ‘just and reasonable’ is obviously incapable of precise judicial definition,” and we accordingly grant the Commission “great deference . . . in its rate decisions.” Morgan Stanley Cap. Grp. Inc. v. Pub. Util. Dist. No. 1 of Snohomish Cnty., Wash., 554 U.S. 527, 532 (2008); see also EPSA, 577 U.S. at 295 (“The Commission, not this or any other court, regulates electricity rates.”). But deference does not mean carte blanche, and the Commission must at all times demonstrate the markers of “principled and reasoned decision[making] supported by the evidentiary record.” Emera Me., 854 F.3d at 22 (quoting S. Cal. Edison Co. v. FERC, 717 F.3d 177, 181 (D.C. Cir. 2013)). III. MYSTIC 8 AND 9’S RATE BASE Mystic first contends that the Commission erred by applying the original cost test to calculate the rate base for Mystic 8 and 9. 20 When calculating a cost-of-service rate for a facility devoted to public use, a generator must first establish what return it is permitted to recover on its capital. That is determined in part by the rate base, which represents a utility’s total investment in the facility. See FEDERAL ENERGY REGULATORY COMMISSION, COST-OF-SERVICE RATES MANUAL 8 (1999). We have explained that the Commission “may adopt any method of valuation for rate base purposes so long as the end result of the rate order cannot be said to be unjust or unreasonable.” NEPCO, 668 F.2d at 1333 (cleaned up). To calculate the rate base, the Commission applies a set of accounting principles collectively known as the “original cost test.” The test begins with the “original cost” of a facility, such as the cost of construction, “to the person first devoting it to public service.” 18 C.F.R. pt. 101(23). The next step is calculating how much the facility has depreciated over time. The difference between the original cost and accumulated depreciation represents the facility’s depreciated original cost, or net book value. Net book value is a primary input for calculating the facility’s rate base. COST-OF-SERVICE RATES MANUAL, supra, at 8–9. Under the original cost test, the net book value may adjust after a facility is sold. If the sale price is below the net book value, that price becomes the new net book value, and the rate base will be lowered. Locust Ridge Gas Co., 29 FERC ¶ 61,052, at 61,114 (1984). If the sale price is higher than the net book value, the net book value (and thus the rate base) generally remains unchanged.6 In short, under the original cost 6 The Commission treats the amount of the purchase price above net book value as an “acquisition premium,” which does not increase the net book value or the rate base. Mo. Pub. Serv. Comm’n v. FERC, 783 F.3d 310, 313 (D.C. Cir. 2015). A utility paying a sale 21 test, the rate base decreases after a sale below net book value, yet generally cannot increase after a sale above net book value. Mystic’s parent company valued Mystic 8 and 9 as part of a merger in 2012 at around $925 million, and Mystic claims this “sale” price should determine its rate base. The Commission rejected that approach as inconsistent with the original cost test because, considering the units’ full purchase history, the rate base was in fact much lower. The Commission recognized that Mystic 8 and 9 were “first devoted to public service” in 2003 after being constructed for just under $1 billion. See December 2018 Order, at ¶ 64. When the units were transferred in 2004 for approximately $547 million in lieu of foreclosure, that “sale” price fell below the units’ net book value. See Second July 2020 Rehearing Order, at ¶ 112. The net book value thus reset to $547 million, and under the original cost test, could not be increased to account for later sale prices above that amount, such as the $925 million merger valuation in 2012. See December 2018 Order, at ¶ 64; see also Second July 2020 Rehearing Order, at ¶ 105; Compliance Order, at ¶ 45. The Commission explained that the $547 million “sale” capped the units’ net book value, determining Mystic’s rate base going forward. See Second July 2020 Rehearing Order, at ¶ 112. This conclusion followed from a straightforward application of the original cost test as articulated in the Commission’s precedents. price above the seller’s net book value may be able to incorporate some of the acquisition premium into its rate base if it can “prove that benefits, equal to the excess acquisition costs and measurable in dollars, were conferred on its ratepayers.” Locust Ridge Gas Co., 29 FERC at 61,114; see also Mo. Pub. Serv. Comm’n, 783 F.3d at 313 (describing the Commission’s “two-part benefits exception test”). Mystic does not claim this exception applies. 22 Mystic maintains it was arbitrary and capricious to apply the original cost test to the circumstances here. Mystic first contends that using the original cost test was arbitrary because Mystic 8 and 9 previously functioned as merchant generators. According to Mystic, the original cost test should not apply to merchant generators that have converted to cost-of-service facilities because the economic calculus of selling a merchant generator differs from the calculus of selling a cost-of-service facility. While cost-of-service facilities are bought and sold with the original cost test in mind, Mystic claims merchant generators like Mystic 8 and 9 are bought and sold based on fair market value, which often does not track original cost. As the Commission explained, however, Mystic’s request for a merchant-generator exception to the original cost test is inconsistent with Commission precedent. For instance, the Commission has required a facility that previously operated as a merchant generator to apply original cost principles and explained that those principles apply to all cost-of-service facilities, “regardless of the rate treatment afforded the facilities” in the past. PacifiCorp, 124 FERC ¶ 61,046, at ¶¶ 7, 10–11, 28–31 (2008). Likewise, the Commission in another decision concluded that the original cost test was “consistent” with past practice and “appropriate” for facilities converting from merchant generators to cost-of-service facilities, a situation almost identical to the facts presented here. PSEG Power Conn., LLC, 110 FERC ¶ 61,020, at ¶¶ 27, 30–31 (2005). The Commission reasonably relied on its consistent precedent when applying the original cost test to Mystic 8 and 9, even though those facilities were once merchant generators. See December 2018 Order, at ¶ 65. Furthermore, the Commission explained why Mystic’s argument rests on a mistaken assumption. Mystic presses for the Commission to create an exemption to the original cost test 23 for facilities that previously charged market-based rates because, it claims, original cost accounting principles are not considered during the sale of a merchant generator. But charging market rates as a merchant generator and using original cost accounting are not “mutually exclusive.” Id. at ¶ 66; Second July 2020 Rehearing Order, at ¶ 106. Instead, a facility could be a merchant generator and use original cost accounting principles, which would be taken into account during a sale. Given this possible overlap, it was reasonable for the Commission to decline making an exception to the original cost test for a facility that previously operated as a merchant generator. Mystic next argues it was unreasonable for FERC to apply the original cost test in this context because such an application would not serve the policy interests protected by the test. The original cost test was developed in part to prevent utilities from artificially inflating a facility’s purchase price, which would then increase the facility’s rate base and allow the utility to charge higher rates to the public. Mo. Pub. Serv. Comm’n v. FERC, 783 F.3d 310, 313 (D.C. Cir. 2015). Mystic argues that as a merchant generator it had no incentive to inflate the $925 million valuation in 2012, and therefore there was no need to apply the original cost test. But the Commission set the original cost test as an across-the-board rule, not a calculation that applies only when certain policy concerns are present. See Second July 2020 Rehearing Order, at ¶ 105. Even when “[t]here is no allegation” that a utility “attempted to artificially inflate its rate base when it acquired” a facility, “the purpose of the [Commission]’s original cost accounting rules is to obviate the need for such allegations.” Mont. Power Co. v. FERC, 599 F.2d 295, 300 (9th Cir. 1979). Instead, these “rules provide an objective method of valuation without the need for independent assessment of the fair market value of individual acquisitions.” Id.; see also, e.g., PacifiCorp, 124 FERC at ¶¶ 11, 28–31 24 (applying the original cost test despite a utility arguing the “the policy concern” behind the original cost test “does not apply”). Mystic next argues it was arbitrary and capricious to apply the original cost test to merchant generators that convert to cost-of-service facilities because the fair market value of a merchant generator facility may rise or fall based on market forces, but the original cost test captures only the downward swings. This discrepancy, however, is the necessary and expected outcome of the original cost test. In an effort to protect ratepayers, the test was designed to ratchet down a facility’s net book value based on a facility’s lower sale price but prohibit ratcheting up the value based on a higher sale price. See Locust Ridge Gas Co., 29 FERC at 61,114. That design choice protects ratepayers from higher rates due to changes in ownership that do not increase the value of services provided. Id. A general rule “may produce unfortunate results in individual cases”; however, the possibility of such disparities does not “preclude the [Commission] from” adopting an objective and generally applicable accounting method. Mont. Power Co., 599 F.2d at 300. The Commission chose original cost accounting principles in part to “avoid the difficulties of more subjective methods of property valuation,” id., and we find that it applied that objective test here. Furthermore, the Commission declined to create an exception to its objective test because doing so would lead to unequal treatment between similarly situated electricity generators. The Commission determined it was unfair to allow a utility’s return to depend on its past accounting method, especially when a non-original cost method is not indicative of a facility’s actual cost and when actual cost is what lies at the heart of cost-of-service rates. See Second July 2020 Rehearing Order, at ¶ 107. 25 Mystic also maintains that Mystic 8 and 9 never would have been transferred in lieu of foreclosure in 2004 if the facilities had been charging cost-of-service rates, and therefore the 2004 valuation was an improper and unreliable input for calculating the rate base. The Commission reasonably rejected this argument, explaining that charging cost-of-service rates does not insulate facilities from financial distress or fire sales. Mystic’s assertions that the 2004 transfer would not have occurred were therefore speculative. See id. at ¶ 106. It was not unreasonable for the Commission to bypass such conjecture and instead rely on its objective test and the units’ actual purchase history. Because the Commission’s decision to apply original cost principles to Mystic 8 and 9 accorded with its precedent and was supported by reasoned explanation, Mystic’s petition cannot succeed on this ground. IV. MYSTIC’S CAPITAL STRUCTURE We next take up Mystic’s challenge to the capital structure adopted by the Commission for ratemaking purposes. Because the Commission’s subsequent order has mooted Mystic’s challenge, we dismiss the petition on this issue.7 A case becomes moot if intervening events mean the court’s “decision will neither presently affect the parties’ rights nor have a more-than-speculative chance of affecting them in the future.” Clarke v. United States, 915 F.2d 699, 701 (D.C. Cir. 1990) (quotation marks and citation omitted). While no party contends that has happened here, we “have an 7 On August 12, 2022, Mystic notified the court it had reached a settlement in principle with the Commission on this issue. Because we find the issue moot, that settlement in principle has no bearing on our analysis. 26 ‘independent obligation’ to ensure that appeals before us are not moot.” Planned Parenthood of Wis., Inc. v. Azar, 942 F.3d 512, 516 (D.C. Cir. 2019) (citation omitted). In the orders under review, the Commission adopted Exelon’s capital structure for ratemaking purposes. Mystic challenges that decision as arbitrary and capricious, contending that the Commission instead should have imputed the capital structure of Mystic’s immediate parent, ExGen. But after the petitions for review were filed in this case, the Commission revised its initial decision on this issue in response to intervening developments. On February 1, 2022, Exelon and a newly created holding company, Constellation Energy Corporation, consummated a spin-off transaction. May 2022 Order, at ¶¶ 6–7; supra Part I.F, at 12. As a result of that transaction, Mystic is no longer affiliated with or owned by Exelon. May 2022 Order, at ¶¶ 6–7. In light of that development, the Commission determined that “it would be inappropriate to continue basing [Mystic’s] capital structure and cost of debt on those of Exelon Corporation.” Id. at ¶ 25. The Commission therefore set aside its prior decision to use Exelon’s capital structure and set the matter for a new hearing. Id. at ¶¶ 25–26. The Commission, however, lacked jurisdiction to modify or vacate an order under judicial review without obtaining leave of the court. See 16 U.S.C. § 825l(b). The Commission thus sought the requisite leave to issue the May 2022 Order “[t]o the extent [it] constitutes a modification or vacatur of the capital structure ruling in the initial orders.” FERC Mot. for Leave 4. We granted the Commission’s motion. See Order Granting Mot. for Leave. Now that it has been issued with our authorization, the May 2022 Order effectively vacated the capital structure 27 rulings in the orders now under review. Mystic suggests that it nonetheless remains unclear whether the May 2022 Order, while vacating the decision to use Exelon’s capital structure as the basis for Mystic’s ratemaking, also vacated the decision not to use ExGen’s structure. Mystic, that is, seeks reassurance that the Commission remains free to base Mystic’s rate on ExGen’s structure. The May 2022 Order is clear on that issue: the entirety of the capital structure rulings have been vacated, including the Commission’s rejection of ExGen’s structure for ratemaking purposes. The order states that “Mystic’s proposal to use the capital structure of its immediate corporate parent . . . has not been shown to be just and reasonable and . . . the record would benefit from further information.” May 2022 Order, at ¶ 24. Although the Commission noted that Mystic’s proposed capital structure was more “equity-rich” than structures previously accepted, the Commission simply proceeded to set the capital structure issue for hearing without qualification. Id. at ¶¶ 25–26. And in oral argument before us, the Commission confirmed that the option to use ExGen’s structure remains open to the Commission in the new proceedings. Recording of Oral Arg. 29:03–29:51. The May 2022 Order thus fully vacated the capital structure rulings under review. Because the portion of the orders subject to Mystic’s challenge to the Commission’s capital structure decision has been vacated, we conclude that the challenge is moot. As we have previously explained, a “case is plainly moot” when “[t]he challenged orders of the Federal Energy Regulatory Commission were superseded by a subsequent FERC order, and while the challenged orders were in effect petitioners suffered no injury this court can redress.” Freeport-McMoRan Oil & Gas Co. v. FERC, 962 F.2d 45, 46 (D.C. Cir. 1992). In an analogous context, we noted that a court “can do nothing to 28 affect [a party’s] rights relative to . . . now-withdrawn” regulations, and we described challenges to such regulations as “classically moot.” Friends of Animals v. Bernhardt, 961 F.3d 1197, 1203 (D.C. Cir. 2020) (quoting Akiachak Native Cmty. v. U.S. Dep’t of the Interior, 827 F.3d 100, 106 (D.C. Cir. 2016)). Here, we can grant Mystic no effective relief to redress an action that has already been vacated by the Commission itself. And Mystic suffered no injury from the Commission’s nowvacated ruling because a rate based on Exelon’s capital structure never took effect. If the Commission ultimately sets a capital structure in the new proceedings to which Mystic objects, Mystic may file a new petition for review to challenge that decision. We dismiss the petition on this issue as moot. V. RECOVERY OF EVERETT’S COSTS In the initially filed Mystic Agreement, Mystic proposed recovery of Mystic 8 and 9’s fuel costs through a cost-ofservice rate charged by Everett. See July 2018 Order, at ¶¶ 21– 22; see also J.A. 19–20. This rate would have included Mystic 8 and 9’s variable fuel costs as well as a monthly Fuel Supply Charge encompassing all of Everett’s operating costs and a return on investment calculated from Everett’s rate base. See July 2018 Order, at ¶ 22. The Fuel Supply Charge was to be offset by 50 per cent of the profits Everett earned on third-party sales over the course of the Agreement. Id. The Commission declined to approve recovery of the proposed Fuel Supply Charge, instead adopting, then modifying, an approach proposed by its Trial Staff. First, the Commission reduced the recovery of Everett’s operating costs to only those attributable to Everett’s sale of vapor natural 29 gas—91 per cent of Everett’s total operating costs. See December 2018 Order, at ¶ 133. Second, regarding the returnon-investment component of the Fuel Supply Charge, the Commission excluded the purchase price ExGen paid to acquire Everett from Everett’s rate base, finding that costcausation principles did not support its inclusion. See id. at ¶¶ 148–49. Third, the Commission adopted a sliding-scale revenue-crediting mechanism for Everett’s third-party sales that ultimately required greater revenue crediting than Mystic initially proposed, see id. at ¶¶ 134–35, but later eliminated revenue crediting, citing a lack of necessity in light of its allocation of Everett’s costs and jurisdictional concerns, see Second July 2020 Rehearing Order, at ¶ 66. The State Petitioners bring two challenges, arguing that (1) the Commission lacked jurisdiction to regulate the rates charged by Everett and (2) the Commission’s decision to allocate 91 per cent of Everett’s operating costs to Mystic (and ultimately to ratepayers) was arbitrary and capricious. Mystic asserts that the Commission erred in excluding Everett’s purchase price from Everett’s rate base, arguing that the decision deviates from precedent and violates well-established ratemaking principles. As detailed infra, we conclude that the Commission did not exceed its statutory authority in reviewing and ordering recovery of Everett’s costs as part of Mystic’s cost-of-service rate. On the merits, we accept the State Petitioners’ challenges but reject Mystic’s. A. State Petitioners’ Arguments 1. At the threshold, the State Petitioners raise an objection to the Commission’s jurisdiction with respect to Everett’s costs 30 and the Fuel Supply Charge. The Commission maintains that “[w]hether individual components of a cost-of-service rate, including fuel-related costs, are recoverable turns on whether they are just and reasonable, not whether the Commission has regulatory authority over all aspects of those rate components.” July 2018 Order, at ¶ 37; see FERC Br. 52–54. The State Petitioners contend, however, that the Commission’s jurisdiction of Mystic’s cost-of-service rate and incorporated Fuel Supply Charge “does not provide a jurisdictional basis for burdening New England ratepayers with Everett costs that are not fairly attributable to Mystic’s use of that facility.” State Pet’rs Br. 29. We reject their argument. Section 205 of the FPA delineates the Commission’s role to ensure that “rates and charges made, demanded, or received by any public utility for or in connection with” interstate wholesale electric sales as well as the “rules and regulations affecting or pertaining to such rates or charges” are just and reasonable and not unduly discriminatory or preferential. 16 U.S.C. § 824d(a)–(b). Section 206 similarly instructs the Commission to affirmatively remediate any “rate [or] charge” or “any rule, regulation, practice, or contract affecting such rate [or] charge” found to be “unjust [or] unreasonable.” Id. § 824e(a). The State Petitioners do not seriously dispute that Mystic’s cost-of-service rate plainly falls within the ambit of the Commission’s authority under section 205, see State Pet’rs Br. 28–29 (“There is no dispute . . . that the Commission can review Mystic’s costs before permitting their inclusion in a jurisdictional rate.”), nor does the Commission claim authority over the rate Everett charges Mystic for its fuel, as outlined in the non-jurisdictional Everett Agreement, see FERC Br. 53; see also First July 2020 Rehearing Order, at ¶ 26; Second July 2020 Rehearing Order, at ¶ 24. 31 The State Petitioners instead focus on the particular inputs of Mystic’s jurisdictional rate, arguing that the Commission lacks authority to permit recovery of Everett-related costs “not fairly attributable to Mystic’s use of that facility.” See State Pet’rs Br. 29. They principally rely on the United States Supreme Court’s decision in FERC v. Electric Power Supply Ass’n, 577 U.S. 260 (2016), which held that the Commission’s authority under sections 205 and 206 to regulate rules and regulations “affecting” jurisdictional rates is limited to “rules or practices that ‘directly affect the [wholesale] rate.’” Id. at 278 (emphasis in original) (quoting Cal. Indep. Sys. Operator Corp. v. FERC, 372 F.3d 395, 403 (2004)). As the State Petitioners see it, the Commission cannot approve rate inputs that lack a sufficiently direct effect on wholesale rates, thereby proposing a sort of threshold inquiry applicable to rate inputs. See State Pet’rs Br. 28–29. But EPSA’s jurisdictional holding has little salience here. EPSA involved a Commission rule, Order No. 745, governing how energy market operators compensate suppliers of demandresponse resources (i.e., those that alter a consumer’s energy consumption). See 577 U.S. at 272–75; see generally Demand Response Compensation in Organized Wholesale Energy Markets, 76 Fed. Reg. 16,658 (Mar. 24, 2011). Accordingly, the Commission relied upon, and the Supreme Court interpreted, its jurisdiction of rules and regulations “affecting” wholesale rates. EPSA, 577 U.S. at 277–79; see also 16 U.S.C. §§ 824d(a), 824e(a). It was precisely because of the expansive meaning of “affecting,” which the Supreme Court observed “could extend FERC’s power to some surprising places,” that the Court found the need to limit its scope to those “rules or practices that ‘directly affect the wholesale rate.’” EPSA, 577 U.S. at 277–78 (alteration accepted) (quoting Cal. Indep. Sys. Operator, 372 F.3d at 403). 32 Unlike EPSA, this case does not involve rules affecting wholesale rates, but rather a wholesale rate itself—Mystic’s proposed cost-of-service rate—which is not similarly qualified by “affecting” language. Granted, section 205 references “rates and charges . . . for or in connection with the transmission or sale of electric energy subject to the jurisdiction of the Commission,” 16 U.S.C. § 824d(a) (emphasis added), and the Supreme Court in EPSA noted that phrases such as “affecting” and “in connection with” could “assum[e] near-infinite breadth” if unconstrained, see 577 U.S. at 278 (citing N.Y. State Conf. of Blue Cross & Blue Shield Plans v. Travelers Ins. Co., 514 U.S. 645, 655 (1995), and Maracich v. Spears, 570 U.S. 48, 59–60 (2013)). But Mystic’s proposed rate is plainly “for,” not merely “in connection with,” the transmission or sale of electricity, see J.A. 1 (“The Agreement provides cost-ofservice compensation to Mystic for continued operation of . . . Mystic 8 and 9 . . . .”), and the State Petitioners have not given us reason to think otherwise. Thus, there is little question of the Commission’s jurisdiction of Mystic’s rate pursuant to section 205 of the FPA. Moreover, as to individual rate inputs, our case law affirms that the reasonableness of an input is not a jurisdictional issue. The Commission maintains, and the State Petitioners do not appear to contest, that “[c]ost-of-service rates routinely include costs that are outside the Commission’s regulatory authority, such as fuel supplies, labor costs, and taxes.” FERC Br. 53; see also First July 2020 Rehearing Order, at ¶¶ 28, 30. Our precedent indicates that the key constraint on the Commission’s authority to order recovery of such cost inputs is the just-and-reasonable standard and cost-causation principles, not a threshold jurisdictional issue. For example, in BP West Coast Products, LLC v. FERC, 374 F.3d 1263 (D.C. Cir. 2004) (per curiam), the Commission determined, and we affirmed, that it would have been inequitable for a pipeline to 33 recover certain civil litigation costs that “lack[] the requisite nexus to the provision of . . . service.” Id. at 1294–95; see also id. at 1296–97 (“The salient criterion . . . for the recovery of legal expenditures by regulated entities is whether the underlying activity being defended in the litigation serves the interests of ratepayers.”). Similarly, in Grand Council of Crees (of Quebec) v. FERC, 198 F.3d 950 (D.C. Cir. 2000), we determined that environmental costs associated with developing and operating a generating facility whose rates were subject to Commission jurisdiction under sections 205 and 206 of the FPA could be deemed recoverable—subject, of course, to “the Commission’s normal rate calculation”—even though the Commission refused to consider the underlying environmental issues in section 205 proceedings. Id. at 957. In our view, the State Petitioners’ argument boils down to a question of cost attribution and allocation, see State Pet’rs Br. 29 (“[T]he [Mystic] Agreement does not provide a jurisdictional basis for burdening New England ratepayers with Everett costs that are not fairly attributable to Mystic’s use of that facility.” (emphases added)), which sounds in justness and reasonableness, not jurisdiction. See Old Dominion Elec. Coop. v. FERC, 898 F.3d 1254, 1255 (D.C. Cir. 2018) (“For decades, the Commission and the courts have understood [the FPA’s just-and-reasonable] requirement to incorporate a costcausation principle.” (internal quotation marks omitted)). The cost of fuel purchased from Everett is plainly an input into Mystic’s cost of service. See, e.g., Delmarva Power & Light Co., 24 FERC ¶ 61,199, at 61,460 (1983) (concluding disposal costs of spent nuclear fuel were “an appropriate cost-of-service item”); Pub. Serv. Co. of N.H., 6 FERC ¶ 61,299, at 61,714–15 (1979) (considering effect of coal supply contract on utility’s fuel expenses). The State Petitioners do not appear to dispute the Commission’s reasonable conclusion that “third-party suppliers can and do recover [operating] costs through their 34 sales because their business would not be sustainable if they did not.” First July 2020 Rehearing Order, at ¶ 30. Thus, to the extent the State Petitioners contest whether particular Everett operating costs are properly recoverable under cost-of-service ratemaking, that is a matter of cost causation. See infra Part V.A.2. At bottom, the State Petitioners have not given us reason to doubt the Commission’s statutory authority to review and order recovery of discrete portions of Everett’s costs. We therefore reject their jurisdictional argument and move to the issue of justness and reasonableness, where we find their arguments more persuasive. 2. The State Petitioners contend that the Commission’s decision to allocate 91 per cent of Everett’s operating costs— or, put another way, all operating costs associated with Everett’s vapor gas sales—to Mystic (and, by extension, ratepayers) runs counter to longstanding cost-causation principles and is therefore arbitrary and capricious. We agree. Cost-causation principles “require[] that ‘all approved rates reflect to some degree the costs actually caused by the customer who must pay them.’” Black Oak Energy, LLC v. FERC, 725 F.3d 230, 237 (D.C. Cir. 2013) (quoting E. Ky. Power Coop., Inc. v. FERC, 489 F.3d 1299, 1303 (D.C. Cir. 2007)). The Commission accordingly set out to allocate Everett’s operating costs pursuant to cost-causation principles. See December 2018 Order, at ¶ 133 (“[P]rinciples of fairness and cost causation require that New England ratepayers and those third-party customers should share [Everett’s] costs.”). Although we are generally “obliged to defer to [the Commission’s] technical ratemaking expertise,” deference is warranted only “[s]o long as its decision is reached by reasoned 35 decisionmaking and supported by substantial evidence.” Ala. Power Co. v. FERC, 993 F.2d 1557, 1560 (D.C. Cir. 1993); see also Del. Div. of Pub. Advoc., 3 F.4th at 465. Here, the Commission failed to meet its required burden for two reasons. First, the Commission failed to provide an adequate rationale for allocating all of Everett’s vapor-related operating costs to Mystic, despite the Commission’s express acknowledgment, based on record evidence, that at least some portion of Everett’s vapor sales is attributable to customers other than Mystic. See Second July 2020 Rehearing Order, at ¶ 64 (“We acknowledge that some vapor sales are made to third parties . . . .”); FERC Br. 63 (acknowledging same); see also J.A. 1253 (Connecticut Parties contending that “[e]ven when Mystic is operating at full capacity . . . , Everett is able to supply the Algonquin and Tennessee Gas pipelines an additional 465,000 MMBtu/day or more—nearly double the quantity consumed by Mystic”). On its face, then, allocating all vapor-related operating costs to Mystic appears to run contrary to rational cost causation. See Pa. Elec. Co. v. FERC, 11 F.3d 207, 211 (D.C. Cir. 1993) (“Utility customers should normally be charged rates that fairly track the costs for which they are responsible.”). The only rationale the Commission cites in support of its allocation is that Everett’s third-party vapor sales “benefit Mystic by helping to manage Everett’s tank,” a benefit the Commission describes as “not trivial.” Second July 2020 Rehearing Order, at ¶ 64; see also December 2018 Order, at ¶¶ 155–56 (explaining Everett’s tank management practices). The Commission repeats this rationale before us, albeit without much additional elaboration. See FERC Br. 63. It makes no attempt, however, to explain how these tank-management benefits are sufficient to entirely offset Mystic’s apparent subsidization of vapor-related operating costs attributable to 36 third parties. Further, as both the State Petitioners and dissenting Commissioner Glick point out, any purported tankmanagement benefits “work[] both ways,” as all customers who purchase vapor gas stored in Everett’s tanks necessarily promote tank management by allowing the unloading and regasification of additional LNG. See State Pet’rs Br. 26 (quoting J.A. 1253); Second July 2020 Rehearing Order (Glick, C., dissenting), at ¶ 8 n.19 (“What is never explained, however, is why third parties do not also benefit from ‘tank management’ or why the Commission can so confidently conclude that all tank-related benefits go to and ought to be paid for by electricity customers.”). Ignoring such reciprocity of benefit runs contrary to the Commission’s mandate to ensure “burden is matched with benefit,” Old Dominion Elec. Coop., 898 F.3d at 1255 (quoting BNP Paribas Energy Trading GP v. FERC, 743 F.3d 264, 268 (D.C. Cir. 2014)), and ignores party (as well as Commissioner) comments highlighting the flaw in its reasoning, see Pub. Serv. Comm’n of Ky. v. FERC, 397 F.3d 1004, 1008 (D.C. Cir. 2005) (“The Commission must . . . respond meaningfully to the arguments raised before it.”). Second, and relatedly, the Commission failed to justify the continuing validity of the 91 per cent cost allocation after eliminating the revenue crediting mechanism for Everett’s third-party sales. As noted previously, the Commission eliminated the sliding-scale revenue-crediting mechanism it had approved as part of its December 2018 Order, citing concerns that regulating Everett’s third-party sales may exceed its jurisdiction. See Second July 2020 Rehearing Order, at ¶ 66. Regardless of any perceived jurisdictional hurdles—on which we do not opine—the Commission failed to grapple with the cost-causation implications stemming from the elimination of revenue crediting. Despite allocating all of Everett’s vaporrelated operating costs, the Commission expressly observed that Mystic is not the sole source causing Everett to incur those 37 costs, see id. at ¶ 64; see also FERC Br. 63, meaning that revenue crediting served as the sole means of offsetting payment of operating costs not reasonably attributable to Mystic, see December 2018 Order, at ¶ 134 (revenue crediting “allocates costs to third-party customers that do not benefit Mystic 8 and 9 at all”). In fact, in initially approving revenue crediting, the Commission explicitly noted the consequences of over-allocating costs while simultaneously eliminating crediting: “If costs are included but related revenue credits are excluded, then the resulting rate results in double recovery.” December 2018 Order, at ¶ 134 n.303; see also Minn. Mun. Power Agency, 68 FERC ¶ 61,060, at 61,205 n.3 (1994) (“If the utility excludes a firm customer from the cost allocation and simply credits the firm service revenues to the cost-of-service, other customers will subsidize the transaction if the revenues credited are less than the cost responsibility that should be allocated to that service.”). Yet in subsequent orders, the Commission failed to address these over-allocation concerns, a failure that does not evince reasoned decisionmaking. To make matters worse, the Connecticut Parties, in their rehearing petition from the Second July 2020 Rehearing Order, pointed out the problem of eliminating revenue crediting without a corresponding adjustment to the initial cost allocation. See J.A. 1664 (“[The Second July 2020 Rehearing Order] wrongly set aside the December 2018 Order’s approval of a revenue-crediting mechanism necessitated by assigning Mystic a share of Everett costs far exceeding Mystic’s use of Everett facilities.”). Yet the Commission’s response was cursory at best, as it simply referred back to “the July 2020 Orders,” December 2020 Rehearing Order, at ¶ 39 & n.94 (citing Second July 2020 Rehearing Order, at ¶ 66), relying specifically on the similarly conclusionary statement that its “proper cost allocation based on cost-causation principles obviate[d] the need for . . . revenue crediting,” Second July 38 2020 Rehearing Order, at ¶ 66. As the preceding analysis makes clear, the Commission’s reliance on its purported achievement of “proper cost allocation” was unwarranted. This is not to say that revenue crediting was necessary to achieve a reasonable cost allocation. Rather, we find that its elimination materially altered the existing cost-allocation calculation, yet the Commission made no effort to address the implications of elimination aside from citations to costcausation principles and sketchy assertions. In short, the Commission has failed to adequately justify its decision to allocate all of Everett’s vapor-related operating costs to Mystic (and, ultimately, ratepayers). We therefore grant the State Petitioners’ petitions on this issue. B. Mystic’s Arguments Mystic’s principal objection with respect to the recovery of Everett’s costs involves the Commission’s exclusion of the Everett purchase price from Everett’s rate base, which is used to calculate the return-on-investment component of the Fuel Supply Charge. As Mystic sees it, “[t]he Commission’s decision contradicts fundamental ratemaking principles and deviated from precedent without a principled rationale.” Mystic Br. 50. Mystic’s arguments on this issue are unpersuasive. In declining to include Everett’s acquisition price as part of Everett’s rate base, the Commission again relied on costcausation principles. See December 2018 Order, at ¶¶ 148–49; Second July 2020 Rehearing Order, at ¶¶ 113, 118–20. As already noted, cost causation is premised upon the notion that “all approved rates reflect to some degree the costs actually caused by the customer who must pay them.” Black Oak Energy, 725 F.3d at 237 (quoting E. Ky. Power, 489 F.3d at 39 1303). In determining whether to include Everett’s acquisition price in the rate base calculation, the Commission relied in large part on William Berg, an Exelon executive, who testified that ExGen acquired Everett to satisfy pre-existing capacity obligations arising before the Mystic Agreement was set to take effect: “ExGen determined that acquisition of Everett was the best and most reliable option for Mystic to meet its existing capacity supply obligations through May 2022 without significant risk of non-performance.” J.A. 197 (emphasis added); see also December 2018 Order, at ¶ 148; Second July 2020 Rehearing Order, at ¶ 118. The Commission therefore concluded that “the beneficiary of the purchase of Everett was ExGen,” not ratepayers, and the cost of that acquisition “should properly be recovered in the period prior to the [Mystic] Agreement (i.e., the period for which the purchase was initially made).” December 2018 Order, at ¶ 149; see also Second 2020 Rehearing Order, at ¶ 118 (“Exelon was aware that, absent the Commission’s acceptance of the Mystic Agreement, Exelon would have had to absorb the cost of its purchase of Everett during the terms of its existing Capacity Supply Obligations.”). Mystic’s primary reply is that no precedent “suggest[s] that the subjective intent of the purchaser matters, or provides a reason to cut out the investment in the facility from a cost-ofservice rate.” Mystic Br. 52. But the Commission focused on cost causation, not subjective intent. The Commission pointed to the Berg testimony to support its conclusion that ExGen’s acquisition of Everett was for the company’s—not ratepayers’—benefit. Mystic wants the Commission to ignore record evidence that goes directly to the question of cost causation—matching burden with benefit. See Old Dominion Elec. Coop., 898 F.3d at 1255. In fact, Mystic does not point to or provide any contrary evidence indicating that ExGen’s acquisition of Everett—as opposed to simply its continued 40 operation—provides ratepayers a benefit that would warrant the proposed burden. Mystic also argues that “a return on and of the investment made in purchasing a facility is part of the costs sunk to provide service to ratepayers and is recoverable in cost of service,” Mystic Br. 51, meaning that the Commission needed to articulate a “principled rationale” for departing from that established methodology, id. at 54 (quoting Williston Basin Interstate Pipeline Co. v. FERC, 165 F.3d 54, 65 (D.C. Cir. 1999)). But in highlighting this supposed departure, Mystic confuses the matter by characterizing Everett—not Mystic 8 and 9—as the facility providing service to ratepayers. To the extent that Everett contributes to Mystic 8 and 9’s provision of service, the Commission permitted recovery of “incremental capital expenditures” and the percentage of “Everett’s fixed operating costs . . . attributable to serving Mystic 8 and 9,” Second July 2020 Rehearing Order, at ¶ 118, a permissible outcome provided that the Commission hews more faithfully to cost-causation principles, see supra Part V.A.2. Mystic has not otherwise given a reason to find that its parent’s acquisition of Everett is providing service to ratepayers. For this reason, the two Commission decisions that Mystic cites in support are inapposite, as they involve sunk costs for cost-of-service facilities that were directly providing electric service to customers, not those facilities’ fuel suppliers. See PSEG Power, 110 FERC at ¶¶ 1, 30 (cost-based rates for generating plants); Mirant Kendall, LLC, 109 FERC ¶ 61,227, at ¶¶ 1, 6 (2004) (same). In sum, we conclude that Mystic has not provided a sufficient basis to conclude that the Commission’s exclusion of Everett’s acquisition cost from Mystic’s cost-of-service rate was arbitrary and capricious and we therefore deny its petition on the issue. 41 VI. TRUE-UP MECHANISM A. Mystic’s Arguments Mystic challenges the scope of the “true-up” mechanism approved by the Commission. Cost-of-service rates are designed to pass along only those costs actually incurred by a utility. But with any cost-of-service rate, there is “inherent difficulty in projecting costs in advance.” December 2018 Order, at ¶ 175 (cleaned up). A true-up mechanism allows ratepayers to seek an adjustment if the costs charged do not match the costs incurred. See id. at ¶ 179. Mystic proposed a true-up mechanism that would allow interested parties to challenge only a subset of its costs. Id. at ¶¶ 165, 178. The Commission rejected that proposal as unduly narrow and decided that “the true-up mechanism [shall] apply to the entire Agreement,” with one exception not relevant here. Id. at ¶ 177. Mystic argues that the true-up is over-broad because it would allow interested parties to relitigate the pre-2018 costs that inform Mystic 8 and 9’s rate base. According to Mystic, the Commission had already approved these historic costs as just and reasonable when it accepted Mystic’s filings.8 The Commission, however, has not yet determined whether the pre-2018 costs are just and reasonable. It reiterated throughout the proceedings that it “decline[d] to make findings” on Mystic’s historic costs, instead requiring Mystic to “adequately support” its historic costs “in the true-up The Commission and Intervenors argue Mystic’s challenge is not ripe because the Commission has not determined the justness and reasonableness of Mystic’s historic costs. But Mystic does not challenge the Commission’s determination on the merits. Instead, it challenges the scope of the true-up mechanism, an issue properly before us because the Commission decided it below. See Second July 2020 Rehearing Order, at ¶ 86. 8 42 process.” Compliance Order, at ¶ 47; see also December 2018 Order, at ¶ 64; Second July 2020 Rehearing Order, at ¶ 86. When the Commission later accepted Mystic’s filings, it again specified that it had made no determination about whether those rates should be approved as just and reasonable: “acceptance . . . shall not be construed as constituting approval of the referenced filing or of any rate” in the filing. Acceptance of Compliance Filing, Constellation Mystic Power, LLC, Dkt. No. ER18-1639-009 (July 29, 2021). Mystic’s concern that the true-up mechanism will lead to relitigation of its historic costs is thus unfounded because those costs have not been evaluated in the first instance. We therefore deny Mystic’s petition on this issue. B. State Petitioners’ Arguments 1. The State Petitioners allege that the Commission unreasonably failed to address the States Committee’s request for clarification about revenue credits. When an agency “d[oes] not respond to . . . arguments” that “do not appear frivolous on their face and could affect the [agency]’s ultimate disposition,” we remand for agency consideration. Frizelle v. Slater, 111 F.3d 172, 177 (D.C. Cir. 1997). We do so because the “failure to respond meaningfully to objections raised by a party renders [the Commission’s] decision arbitrary and capricious.” PSEG Energy Res. & Trade LLC v. FERC, 665 F.3d 203, 208 (D.C. Cir. 2011) (cleaned up). The Commission determined that Mystic’s revenues would not be subject to true-up because the Mystic Agreement already contained a mechanism to “credit revenues Mystic earns against its annual fixed revenue requirement.” Second 43 July 2020 Rehearing Order, at ¶ 88. The States Committee sought clarification or rehearing of this finding, inquiring whether interested parties could challenge the calculation of these revenue credits during the true-up process. See December 2020 Rehearing Order, at ¶ 25. The Commission does not claim that the States Committee’s request was frivolous or irrelevant; instead, the Commission maintains it responded to this request, pointing to a single paragraph. That paragraph, however, addresses a different issue, Everett’s tank congestion charges, and explains that “these costs may be reviewed in the true-up process.” Id. at ¶ 27 (emphasis added). In context, “these costs” refer to Everett’s tank congestion charges, not the States Committee’s request regarding the calculation of revenue credits. The Commission assures us that revenue discrepancies can be addressed during true-up proceedings. See FERC Br. 82. But the agency’s “explanation to this court cannot substitute for reasoned decisionmaking at the agency level.” Williams Gas Processing-Gulf Coast Co. v. FERC, 475 F.3d 319, 329 (D.C. Cir. 2006) (cleaned up). The failure to respond to the States Committee’s request was arbitrary and capricious. We thus grant the petition on this issue and remand for the Commission to consider the States Committee’s request in the first instance. 2. The State Petitioners also argue that the Commission’s December 2020 Rehearing Order introduced an apparent contradiction that requires remand for further clarification. We agree. Ordinarily, “we will uphold an agency decision where the agency’s path may be reasonably discerned, even if the decision is of less than ideal clarity.” Epsilon Elecs., Inc. v. U.S. Dep’t of Treasury, 857 F.3d 913, 924 (D.C. Cir. 2017) (cleaned 44 up). But when an agency “fail[s] to provide an intelligible explanation” for its decision, it has “fail[ed] to engage in reasoned decisionmaking” and we remand for further explanation. FPL Energy Marcus Hook, L.P. v. FERC, 430 F.3d 441, 448 (D.C. Cir. 2005). An order with apparent contradictions as to a dispositive issue is not reasoned decisionmaking and requires remand for clarification. The Commission initially stated that Mystic need not file its general methodology for calculating tank congestion charges and that the reasonableness of those charges would be “reviewed during the true-up process.” December 2018 Order, at ¶ 164. In a subsequent decision, however, the Commission decided these costs no longer needed to be reviewed during the true-up process. Second July 2020 Rehearing Order, at ¶ 73. The States Committee sought clarification and rehearing to ensure that ratepayers could still challenge tank congestion costs, and in its last rehearing order, the Commission again changed course, granting the States Committee’s request and allowing such charges to be “reviewed in the true-up process.” December 2020 Rehearing Order, at ¶ 27. Immediately after this statement in the same order, however, the Commission explained that only ISO New England could “audit and ensure that the tank congestion charge is properly calculated.” Id. at ¶ 28. ISO New England does not represent ratepayers, but rather manages the grid. On its face, the Commission’s reasoning appears incongruous: it agreed with the States Committee that ratepayers could review tank congestion charges during trueup, yet limited review to only ISO New England. To resolve the inconsistency, we remand for clarification. See FPL Energy Marcus Hook, 430 F.3d at 448. 45 VII. CLAWBACK PROVISION A. Everett’s Costs We turn next to the State Petitioners’ challenge to the clawback mechanism in the Mystic Agreement. The State Petitioners contend that the Commission arbitrarily and capriciously excluded Everett’s costs from the clawback mechanism. We agree and accordingly grant the petition on this issue. The Commission’s cost-of-service ratemaking typically allows for the recovery of capital expenditures over the life of a facility. Clawback mechanisms address the unfairness that results if a generator switches from charging cost-of-service rates to charging market rates. In that event, customers under the cost-of-service regime cover capital expenditures and repair expenses that benefit a facility for years after the costof-service agreement ends. See December 2018 Order, at ¶ 210. The Commission has explained that it would be unfair to permit owners to recover capital expenditures and repair expenses “that provide significant benefits beyond the term of the . . . Agreement from . . . customers.” Midcontinent, 161 FERC at ¶ 55. Under the Mystic Agreement’s clawback mechanism, the costs of certain repair and capital expenditures attributable to Mystic 8 and/or 9 are refunded to ratepayers if the units return to the market after termination of the Agreement. See Compliance Order, at ¶ 25; J.A. 1506. The clawback mechanism, however, does not impose the same refund obligation as to Everett’s repair and capital expenditure costs. And the Commission rejected the States Committee’s and Connecticut Parties’ request that the clawback provision include Everett’s costs. See supra Part I.F, at 16–17. 46 In declining to include Everett’s costs in the clawback, the Commission reasoned that it “lack[ed] jurisdiction to require a clawback, true-up, and/or refund of Everett’s costs” because “the Everett Agreement is not on file with the Commission and . . . Everett is not a jurisdictional entity” (i.e., Everett is not subject to the Commission’s jurisdiction in relevant respects). Second July 2020 Rehearing Order, at ¶ 43. If the Mystic Agreement terminated but Everett remained in service, the Commission explained, “there would be no rate within the jurisdiction of the Commission through which to order a refund.” Id. The Commission rested entirely on that reasoning in rejecting subsequent requests for rehearing on this issue. See Compliance Order, at ¶ 28; December 2020 Rehearing Order, at ¶ 39. We conclude that the Commission arbitrarily and capriciously excluded Everett’s costs from the clawback. The Commission supported its decision solely by reference to its lack of jurisdiction over Everett. But in the same proceeding, the Commission also held that it could include Everett’s costs in Mystic’s rate notwithstanding its lack of jurisdiction over Everett. The Commission determined that “there is no bar to the Commission’s exercising jurisdiction to allow Mystic’s recovery of 100 percent of Everett’s fixed costs.” December 2018 Order, at ¶ 133. It reasoned that Everett’s fixed operating costs are “a component of Mystic’s cost-of-service rate and, as a result, [are] subject to Commission review and approval.” Second July 2020 Rehearing Order, at ¶ 22. We find the Commission’s reasoning, without further explanation, to be internally inconsistent. The Commission acknowledges, and we agree, that it has jurisdiction to include Everett’s costs in Mystic’s rate in accordance with cost causation principles. See supra Part V.A.1. The Commission cannot in the same breath contend that it lacks jurisdiction to 47 refund a portion of those same costs to ratepayers. To be sure, the Commission does not claim authority over Everett itself or over the Everett Agreement. FERC Br. 53. But as we have already explained, that lack of jurisdiction did not prevent the Commission from including Everett’s costs in Mystic’s rate. See supra Part V.A.1. Lack of jurisdiction over Everett thus cannot prevent the Commission from ordering Mystic to refund a portion of those costs to ratepayers. The rest of the Commission’s reasoning does not resolve the seeming inconsistency. The Commission reasoned that if the clawback mechanism included Everett’s costs, the clawback “would not apply to payments that Mystic received under a jurisdictional rate, but rather would apply to payments that Everett received under the non-jurisdictional Everett Agreement.” Second July 2020 Rehearing Order, at ¶ 43. But the fuel supply costs paid by Mystic to Everett are also “received under the non-jurisdictional Everett Agreement,” id., and the Commission saw fit to include 91 per cent of those costs in Mystic’s rate. Although we have determined that this allocation was arbitrary and capricious, see supra Part V.A.2, we have also concluded that the error in allocation was not a jurisdictional one, see supra Part V.A.1. The Commission further reasoned that it could not include Everett’s costs in the clawback because, once the Mystic Agreement terminates, “there would be no rate within the jurisdiction of the Commission through which to order a refund.” Second July 2020 Rehearing Order, at ¶ 43. That objection is also unpersuasive. Even as applied only to Mystic, the clawback contemplates a refund that will take place after expiration of the Agreement. The Mystic Agreement requires Mystic to make a true-up filing, reconciling estimated and actual costs, by April 1, 2025, after the expiration of the Agreement. The Agreement thus already requires Mystic to 48 engage in settlement of funds without a jurisdictional rate through which to order the refund. The Commission provides no reason that the same sort of settlement could not be used to refund Everett’s costs. We express no view on whether the Commission may come up with alternative reasons to exclude Everett’s costs from the clawback. But the reason the Commission did provide—its lack of jurisdiction over Everett—does not hold up to scrutiny. We accordingly conclude that the Commission’s “failure to provide an intelligible explanation . . . amounts to a failure to engage in reasoned decisionmaking,” FPL Energy Marcus Hook, 430 F.3d at 448, rendering its decision arbitrary and capricious. We grant the State Petitioners’ petition on this issue and vacate the clawback portions of the challenged orders. B. Capital Projects We next consider one additional argument related to the clawback provision. The State Petitioners contend that the Commission failed to address their argument that the Mystic Agreement will induce Mystic to delay capital projects into the term of the agreement. We agree and thus grant the petition on that issue. Recall that during the term of the cost-of-service agreement, Mystic will recover certain repair and capital expenditure costs from ratepayers. As previously discussed, the Mystic Agreement includes a clawback mechanism to refund ratepayers for such costs if Mystic stays in service past the term of the Agreement. In the December 2018 Order, the Commission also ordered Mystic to contractually agree not to “delay[] [capital expenditure] projects until the term of the Agreement that it would otherwise have undertaken sooner 49 with the purpose of recovering excessive costs from ratepayers under the Agreement.” December 2018 Order, at ¶ 174. In its Second July 2020 Rehearing Order, however, the Commission revised its decision. Rather than obligate Mystic to demonstrate that it had not delayed capital expenditure projects into the term of the Agreement, the Commission merely required Mystic to identify whether it had delayed any such projects and its reasons for doing so. Second July 2020 Rehearing Order, at ¶ 7. Seeking rehearing, the States Committee argued that the revised Agreement would permit Mystic to recover costs for capital projects that should have been completed before expiration of the Mystic Agreement. The States Committee pointed out that Mystic would have the incentive to delay those projects because it could recover the full cost of projects expensed during the term of the Agreement. To be sure, if Mystic stays in service past the term of the Agreement, those costs would be refunded through the clawback. But if Mystic retires from the market at the end of the Agreement, ratepayers will have covered the entire costs of delayed projects— potentially creating perverse incentives. The State Petitioners contend that while the Commission recited the States Committee’s argument in the December 2020 Order, the Commission entirely failed to respond to that argument. State Pet’rs Br. 43–44; see December 2020 Rehearing Order, at ¶ 32. The Commission counters that it did respond to the States Committee’s argument in the December 2020 Order. FERC Br. 80. But the portion of the order cited by the Commission mentions neither the challenged delay provision nor the incentives created by that provision. December 2020 Rehearing Order, at ¶¶ 30–31, 33. The Commission thus entirely failed to address the States Committee’s argument. And the Commission’s “‘failure to respond meaningfully’ to objections raised by a party renders its decision arbitrary and capricious.” 50 PSEG Energy Res. & Trade LLC, 665 F.3d at 208 (citation omitted). Accordingly, we grant the State Petitioners’ petition on this issue and vacate the portion of the orders under review relating to the challenged delay provision. VIII. CONCLUSION For the foregoing reasons, we dismiss Mystic’s petition for review in part and deny it in part, and we grant the State Petitioners’ petitions for review. So ordered.
Primary Holding
The DC Circuit dismissed Mystic’s petition for review of the Federal Energy Regulatory Commission (Commission) orders in part and denied it in part; the court further granted the State Petitioners’ petitions.

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