Capital Power Corporation v. FERC

• Court: Court of Appeals for the D.C. Circuit
• Decided: September 26, 2025
• Docket: 23-1134
• Status: Published

Opinion

United States Court of Appeals FOR THE DISTRICT OF COLUMBIA CIRCUIT

Argued October 1, 2024 Decided September 26, 2025

No. 23-1134

CAPITAL POWER CORPORATION, ET AL., PETITIONERS

v.

FEDERAL ENERGY REGULATORY COMMISSION, RESPONDENT

AMERICAN CLEAN POWER ASSOCIATION, ET AL., INTERVENORS

Consolidated with 23-1135, 23-1136, 23-1231, 23-1233, 23-1234

On Petitions for Review of Orders of the Federal Energy Regulatory Commission

James E. Tysse argued the cause for petitioners. With him on the joint briefs were Michael R. Engleman, Robert C. Fallon, Christina R. Switzer, Stephen J. Hug, Benjamin N. Reiter, Zach ZhenHe Tan, Bruce A. Grabow, and Jennifer Brough. 2 Ben Norris, Melissa Alfano, Elizabeth W. Whittle, Gabriel Tabak, Michael J. Rustum, and David M. DeSalle were on the brief for intervenors in support of petitioners. Neil H. Koslowe entered an appearance.

Beth G. Pacella, Deputy Solicitor, Federal Energy Regulatory Commission, argued the cause for respondent. With her on the brief were Matthew R. Christiansen, General Counsel at the time the brief was filed, and Robert H. Solomon, Solicitor.

Wendy B. Warren argued the cause for intervenors in support of respondent. With her on the joint brief were James K. Mitchell, Wendy N. Reed, and Abraham F. Johns III.

Before: MILLETT, KATSAS, and WALKER, Circuit Judges.

Opinion for the Court filed by Circuit Judge KATSAS.

KATSAS, Circuit Judge: When a power plant generates electricity, it emits two kinds of power: active or “real” power, which produces usable energy, and reactive power, which helps stabilize voltage levels across the grid. For over a decade, the Midcontinent Independent System Operator treated real and reactive power as distinct services for which generators were separately compensated. Generators received market-based prices from wholesale customers for real power, and cost-based compensation from transmission owners for reactive power. This changed in 2022, when MISO amended its tariff to end separate compensation for reactive power. But when the Federal Energy Regulatory Commission approved this amendment and gave it immediate effect, the agency failed to fully consider the generators’ short-term reliance interests. We therefore grant the petitions for review, set aside FERC’s orders, and remand the matter for further proceedings. 3 I

A

The provision of electric power involves three major functions. Generators produce electricity, transmission owners move it to local markets, and distributors deliver it to end users. Detroit Edison Co. v. FERC, 334 F.3d 48, 49 (D.C. Cir. 2003). Historically, vertically integrated monopolies performed all three functions. Morgan Stanley Cap. Grp. Inc. v. Pub. Util. Dist. No. 1, 554 U.S. 527, 535 (2008). Consequently, state and federal regulators played a role in setting generation, transmission, and distribution prices. See id. at 531; Transmission Access Pol’y Study Grp. v. FERC, 225 F.3d 667, 681 (D.C. Cir. 2000). Regulators aimed to set prices at levels that enabled utilities to recover their costs plus a reasonable rate of return, which is known as “cost-based” pricing. See, e.g., Morgan Stanley, 554 U.S. at 532, 550.

The Federal Energy Regulatory Commission regulates prices for the interstate transmission and wholesale sale of electricity. 16 U.S.C. § 824(b)(1); Morgan Stanley, 554 U.S. at 531–32. Regulated utilities file their rates with FERC under section 205 of the Federal Power Act, which requires the rates to be “just and reasonable” and prohibits “any undue preference or advantage.” 16 U.S.C. § 824d(a)–(b).

In the late 1990s, FERC required vertically integrated utilities to unbundle generation and transmission services and sell them separately. See Promoting Wholesale Competition Through Open Access Non-Discriminatory Transmission Services by Public Utilities, 61 Fed. Reg. 21,540 (May 10, 1996) (Order No. 888). In particular, FERC required transmission owners to offer their services to all generators on nondiscriminatory terms. See id. at 21,570–73. FERC also prescribed standard rules for independent generators’ use of 4 transmission facilities. See Standardization of Generator Interconnection Agreements & Procs., 104 FERC ¶ 61,103 (2003) (Order No. 2003).

As independent and transmission-owned generators began to compete, the sale of wholesale power moved toward market prices that generators negotiated with their customers. Morgan Stanley, 554 U.S. at 536–37. In contrast, transmission utilities, which enjoy natural monopolies due to high capital costs and entry barriers, still had to price transmission services at cost. See id. at 532–36.

At the same time, increases in supply and improved transmission technology allowed generators to sell power over longer distances. These longer distances brought additional transaction costs: Generators faced multiple transmission utilities along the route, each with its own tariffs, prices, and terms of service. See Morgan Stanley, 554 U.S. at 535–37. To reduce these transaction costs, transmission owners formed regional “independent system operators” working under a common tariff. Id. at 536–37. In the midwestern United States, this entity is the Midcontinent Independent System Operator, or MISO.

B

While the wholesale electric market structure has changed, its essential output—alternating-current (AC) electricity—has not. Solar Energy Indus. Ass’n v. FERC, No. 21-1126, 2025 WL 2599488, at *1, *4 (D.C. Cir. Sep. 9, 2025). When a generator emits AC electricity, the resulting output has two components: active or “real” power, and reactive power. Dynegy Midwest Generation, Inc. v. FERC, 633 F.3d 1122, 1124 (D.C. Cir. 2011). Consumers can use real power for things like running a motor or lighting a home. Id. Reactive power, in contrast, serves a different purpose. It helps maintain 5 a stable voltage across the electric grid, which ensures that real power may be reliably transmitted. Id.

When integrated utilities began selling transmission and generation services separately, FERC authorized them to treat reactive-power production as an ancillary transmission cost. Order No. 888, 61 Fed. Reg. at 21,581–82, 21,586–88. Thus, when billing customers for transmission services, integrated transmission utilities could include charges for some of the costs incurred by their own generators. E.g., Midwest Indep. Transmission Sys. Operator, Inc., 109 FERC ¶ 61,005, PP 6, 41 (2004).

On the generator side, FERC set default compensation rules for reactive power. In Order 2003, FERC required generators to calibrate their equipment so that their reactive- power capacity fell within a standard ratio known as the “deadband.” See Order No. 2003, 104 FERC ¶ 61,103, P 542; see also Standardization of Small Generator Interconnection Agreements & Procs., 113 FERC ¶ 61,195, PP 34–38 (2005). Because a standard reactive-power ratio was required for grid reliability, FERC concluded that generators should not be separately compensated for it. 104 FERC ¶ 61,103, P 546. Only reactive-power generation above what is ordinarily necessary—that is, reactive power outside the deadband— would be compensated. Id. Nonetheless, FERC left the door open for independent service operators like MISO to propose regional variances to this rule. Id. P 548.

A generator requested rehearing on the ground that FERC had created a disparity between independent and transmission- affiliated generators. Order 888 permitted transmission owners to be compensated for their own generators’ costs of producing reactive power. See Standardization of Generator Interconnection Agreements & Procs., 106 FERC ¶ 61,220, 6 P 411 (2004) (Order No. 2003-A). Yet Order No. 2003 prevented independent generators from receiving compensation for reactive power. In effect, integrated facilities were paid for deadband-level reactive power, while independent generators were not.

To remedy this imbalance, FERC added a caveat: If transmission owners collected revenue for their own generators’ reactive-power production, they would also need to compensate independent generators for reactive power. Order No. 2003-A, 106 FERC ¶ 61,220, P 416. This rule became known as the “comparability standard.”

In 2004, FERC applied this standard to MISO after concluding that its tariff had a means for collecting reactive- power charges for transmission-owner-affiliated sources, but not for independent generators. 109 FERC ¶ 61,005, P 39. Accordingly, FERC ordered MISO to amend its tariff to provide cost-based compensation for all generators’ reactive power, including independent generators. Id. P 40. To receive such compensation, generators would file their own cost-based reactive-power rates with FERC under section 205. Id. P 41.

Thus, as the wholesale electric market moved toward market-based rates in the mid-2000s, generators in MISO separately received regulated, cost-based rates for their reactive power. This led to a peculiar arrangement in which generators received two revenue streams for the same power production: Wholesale electricity customers would purchase the real component of generators’ power, often at market prices, while transmission owners would purchase the reactive component of that power according to a filed, cost-based rate. 7 C

In 2022, MISO initiated a section 205 filing to amend its tariff. Citing the comparability standard, MISO sought to (1) eliminate reactive-power charges from its transmission rate and (2) end reactive-power compensation for independent generators. Midcontinent Indep. Sys. Operator, Inc., 182 FERC ¶ 61,033 (2023), modified on reh’g, 184 FERC ¶ 61,022 (2023). Thus, under the amendments, neither transmission owners nor independent generators would receive any revenue for deadband-level reactive power. These proposed changes would take effect immediately. Id.

Many generators protested. They argued that eliminating reactive-power compensation would upset their investment- backed reliance interests. Despite these objections, FERC approved MISO’s proposal. 182 FERC ¶ 61,033 (2023), modified on reh’g, 184 FERC ¶ 61,022 (2023).

Several generators and industry groups petitioned for review in this Court, and several more intervened on their behalf. In the meantime, FERC issued a separate order eliminating reactive-power compensation nationwide. See Compensation for Reactive Power Within the Standard Power Factor Range, 189 FERC ¶ 61,034 (2024) (Order No. 904), reh’g denied, 191 FERC ¶ 61,188 (2025), petition for review filed, Vistra Corp. v. FERC, No. 25-60055 (5th Cir. Feb. 10, 2025). Despite that order, the dispute here remains live because both orders are still under review. When a litigant’s injury-in-fact stems from two independently sufficient causes, it may separately challenge both of them, even though success in only one proceeding might not fully redress its injury. See Khodara Env’t, Inc. v. Blakey, 376 F.3d 187, 194–95 (3d Cir. 2004) (Alito, J.). Although granting the petitions here would not restore reactive-power compensation in MISO, it would 8 remove one barrier to such compensation, which suffices to establish the redressability element of Article III standing. See id.

II

This Court reviews FERC orders under the Administrative Procedure Act. Entergy Ark., LLC v. FERC, 109 F.4th 583, 590 (D.C. Cir. 2024). We must therefore set aside the orders here if they were arbitrary and capricious. 5 U.S.C. § 706(2)(A). Under that standard, we consider whether FERC “examine[d] the relevant data and articulate[d] a satisfactory explanation for its action including a rational connection between the facts found and the choice made.” See Entergy Ark., 109 F.4th at 590 (cleaned up). As part of this explanation, FERC must “assess whether there were reliance interests” on the part of regulated entities. MediNatura, Inc. v. FDA, 998 F.3d 931, 940–41 (D.C. Cir. 2021) (cleaned up). And if FERC approves an amendment despite such reliance interests, “it must provide a reasoned explanation” for doing so. Id. (cleaned up).

Applying these standards here, we hold that FERC did not adequately consider the generators’ reliance interests. In the proceedings below, the generators explained that they had incurred significant debt and contractual obligations relying on MISO’s longstanding practice of allowing generators to recover cost-based compensation for reactive power. In approving MISO’s proposal to eliminate that compensation, FERC failed to explain why these financial concerns were unjustified, entitled to no weight, or outweighed by other considerations. See DHS v. Regents of the Univ. of Cal., 591 U.S. 1, 31–32 (2020). FERC’s failure to explain itself adequately, independent of the orders’ substantive validity, warrants vacatur and remand here. 9 A

We begin by considering whether we have statutory jurisdiction to decide this case. The statute providing for judicial review of FERC orders requires petitioners to seek review within sixty days of the relevant order. See 16 U.S.C. § 825l(b). Our circuit treats this limit as jurisdictional. Pac. Gas & Elec. Co. v. FERC, 533 F.3d 820, 825 (D.C. Cir. 2008). Our caselaw has suggested that this time limit prevents a petitioner from questioning the logic or holding of past FERC precedents. See, e.g., S. Co. Servs. v. FERC, 416 F.3d 39, 44– 46 (D.C. Cir. 2005); Ga. Indus. Grp. v. FERC, 137 F.3d 1358, 1363–64 (D.C. Cir. 1998). But see City of Batavia v. FERC, 672 F.2d 64, 72 n.15 (D.C. Cir. 1982) (noting parties may raise previously litigated issues when they are “inextricably linked to a subsequent agency opinion on another aspect of the same case”). In other words, once sixty days pass, courts lose jurisdiction to consider the validity of a previous FERC holding—even when it is applied in future proceedings involving different parties.

FERC has invoked this rule, commonly known as the “collateral-attack doctrine.” See, e.g., 182 FERC ¶ 61,033, P 53. Specifically, FERC contends that the challenges hinge on revisiting decisions made long ago in Order No. 2003. But that overstates what the petitioners seek. They could succeed regardless of Order No. 2003’s validity because their challenge depends on whether FERC failed to consider MISO-specific reliance interests when accepting the tariff amendments and immediately cutting off a source of generators’ revenue. Those challenges concern the specific reasoning FERC employed in its orders below—something that was clearly not at issue in the early 2000s orders adopting the comparability principle. The doctrine does not bar our review of FERC’s specific consideration of reliance interests in this case. 10 B

Section 205 of the Federal Power Act requires that all regulated rates be “just and reasonable.” 16 U.S.C. § 824d(a). Under this standard, utilities must be able to recover costs, service their debt, and compete with comparably risky enterprises for investors. Morgan Stanley, 554 U.S. at 532; Emera Me. v. FERC, 854 F.3d 9, 20 (D.C. Cir. 2017). When assessing whether a rate is just and reasonable, courts consider “the total effect of the rate order” on “the financial integrity of the enterprise.” Jersey Cent. Power & Light Co. v. FERC, 810 F.2d 1168, 1176 (D.C. Cir. 1987) (en banc) (cleaned up).

As discussed above, MISO’s tariff amendment immediately eliminated reactive-power charges from its transmission rates and ended cost-based compensation for generators’ production of reactive power. In other words, the MISO tariff now treats deadband-range reactive power as incidental to generation and transmission. Reactive power is neither purchased nor sold as a discrete service.

The generators argue that FERC failed to adequately consider the impact of this change on their short-term financial health. Specifically, they contend that immediately ending cost-based reactive-power compensation will strain them financially, given their investment-backed reliance on this longstanding revenue stream.1 As noted above, MISO has been

1 FERC claims the generators failed to invoke reliance interests in their requests for rehearing, thereby forfeiting this issue for judicial review. See 16 U.S.C. § 825l(b). The administrative record shows otherwise. On rehearing, the generators argued that FERC “failed to consider … the reasonable investment-backed expectations of generators” and “fail[ed] to grapple with [their] reliance interests.” J.A. 515–16. And in denying rehearing, FERC acknowledged—and 11 compensating generators for deadband-level reactive-power production since the mid-2000s. And since then, MISO and its transmission owners have paid around 400 generators for reactive power. By one estimate, this compensation totaled over $200 million annually. See 182 FERC ¶ 61,033, P 3 (Danly, Comm’r, dissenting). The generators claim to have relied on the availability of this revenue stream when entering loans and negotiating long-term power-purchase agreements with wholesale customers. Consequently, the generators argue, the overnight elimination of reactive-power compensation will jeopardize their ability to service debt and render their current wholesale contracts unprofitable. This, in turn, will hurt the generators’ bottom lines in the short term, undermining their ability to attract capital.

FERC failed to adequately explain why these reliance interests were either inconsequential or outweighed by countervailing considerations. FERC gave five reasons for rejecting these arguments. None of them responds to the concern that immediately eliminating reactive-power compensation would cause the generators material financial harm in the short term.

First, FERC contends the generators failed to prove that they actually relied on reactive-power compensation when entering loans and other contracts. See 184 FERC ¶ 61,022, P 34. But MISO—not the generators—bore the burden of proving that it was reasonable to implement its amendments overnight. Ala. Power Co. v. FERC, 993 F.2d 1557, 1571 (D.C. Cir. 1993). Of course, if MISO had made a prima facie showing of reasonableness, then the generators would have had to support their reliance claims with rebuttal evidence. Evergy

promptly rejected—the generators’ “reliance argument[s].” 184 FERC ¶ 61,022, P 33. 12 Kan. Cent., Inc. v. FERC, 77 F.4th 1050, 1056 (D.C. Cir. 2023). But here, MISO never carried its initial burden of showing that it would be reasonable to end compensation for reactive power immediately, despite existing contracts and investment decisions predicated on its availability. This is not to say that these reliance interests must carry the day, but MISO at least should have addressed them, explaining why they were either insubstantial or overcome by other considerations.

Second, FERC doubts that it was even possible for generators to rely on reactive-power revenue when entering power-purchase agreements. It notes that generators entered those agreements “long before” they knew what their reactive- power-compensation rate would be. 184 FERC ¶ 61,022, P 34. But the generators do not claim to have relied on any precise compensation rate in negotiating their deals. Rather, they claim to have made contractual commitments assuming that, at a minimum, “the most conservative, lowest Commission- approved rate in the market” would be paid for reactive power. J.A. 128. Put differently, while generators could not reasonably expect any specific reactive-power rate, they nonetheless expected some cost-based compensation for it. The impossibility of knowing their precise rates ahead of time is beside the point.

Third, FERC claims that the comparability standard made it unreasonable for generators to rely on continued compensation for reactive power. According to FERC, its reactive-power precedents had established a clear rule: Independent generators may expect deadband-level reactive- power compensation if and only if transmission-owned utilities also received such compensation. 184 FERC ¶ 61,022, PP 26– 28, 33. And since MISO’s amendments prohibit compensation for both independent and affiliated generators, they comport with Order No. 2003-A’s comparability standard. Thus, 13 FERC’s approval of the amendments is consistent with what generators reasonably should have expected. Id. P 33.

In support of this stance, FERC points to eight orders, issued between 2005 and 2022, in which it applied the comparability principle to bar compensation for reactive power. See 184 FERC ¶ 61,022, P 27 n.84. FERC asserts that these decisions put generators on notice that their right to reactive-power compensation was contingent upon the comparability standard. Id. P 33. If transmission-owned utilities stopped receiving compensation, so would independent generators. FERC further explains that its precedent delineated only limited exceptions to the no- compensation rule for reactive power. And an industry’s longstanding receipt of such compensation has never been one of them. Id. P 32. FERC concludes that these decisions made clear that compensation for reactive power would not be available in perpetuity, making it unreasonable for generators to assume otherwise.

This argument does not respond to the generators’ specific objection, which focuses on giving the amendments immediate effect. The generators repeatedly expressed concern about the “abrupt” nature of the changes. See J.A. 71, 166, 169, 239, 279, 508, 516. This makes sense given the extent of the generators’ contractual obligations to creditors and wholesale power customers. Yet FERC never considered a more gradual elimination of reactive-power compensation, despite having solicited comments on that very question later on. See Compensation for Reactive Power Within the Standard Power Factor Range, 89 Fed. Reg. 21,454, 21,466 (proposed Mar. 28, 2024). Nor did FERC explain why immediate elimination is reasonable despite the generators’ long-term power obligations and accompanying investments. Put differently, although 14 compensation cannot be guaranteed forever, that does not suggest it could reasonably be eliminated overnight.

Fourth, FERC argues that the generators’ reliance interests are insignificant because the marginal costs of producing deadband-level reactive power are small. See 184 FERC ¶ 61,022, P 34. But the harm to the generators stems from the loss of all reactive-power revenue. And as explained above, there is reason to think that such revenues have been significant.

Fifth, FERC argues that if the generators’ margins become too tight without reactive-power compensation, they can compensate by increasing their market-based revenue. 184 FERC ¶ 61,022, PP 40, 42. FERC suggests two mechanisms for this: renegotiating prices in existing power-purchase agreements, or increasing their asking price in new market offers.

Neither possibility adequately addresses the generators’ short-term financial concerns. FERC itself acknowledges that generators “may not be successful” in renegotiating existing contracts, Resp. Br. at 42, which seems likely because many of their customers are affiliates of vertically integrated utilities that have monopsony power in the market for wholesale power. And as for price increases in future contracts, that possibility does little to address the generators’ concerns that their immediate debt and power-sale obligations will force them to operate at a loss—and inflict financial harm on generators stuck in long-term contracts at current prices. See, e.g., Wisconsin v. FERC, 104 F.3d 462, 467 (D.C. Cir. 1997) (noting a ten-year-long power purchase agreement).

To be sure, the generators may be able to negotiate new wholesale contracts with high enough margins to offset any short-term losses. But FERC did not attempt to explain why 15 eliminating reactive-power compensation overnight is nonetheless reasonable despite these short-term losses. In sum, the possibility of the generators recovering higher returns in future contracts does not directly address their immediate reliance concerns.

* * * *

All told, FERC failed to reasonably explain why the generators’ short-term financial concerns were unfounded, immaterial, or outweighed by countervailing policy concerns. And it entirely failed to consider whether a phase-in period was warranted for these significant tariff changes. Because FERC failed to consider important aspects of the problem before it, the orders at issue were arbitrary.

III

A few final points are worth noting. First, we do not address the substantive validity of MISO’s proposal under section 205. Instead, we hold only that FERC did not adequately explain its decision to allow immediate implementation. We do not foreclose the agency from giving a more thorough explanation in support of MISO’s amendments on remand.

Second, our decision does not trigger reinstatement of the pre-amendment MISO tariff—even while the remanded proceeding is pending. As noted above, FERC has entered a separate order ending reactive-power compensation nationwide, which is presently under review in the Fifth Circuit. So, while we vacate the order approving MISO’s amendments, reactive-power compensation will remain unavailable in MISO. Moreover, our conclusion that FERC inadequately considered the generators’ reliance interests in the order under review has no bearing on whether FERC 16 adequately considered reliance interests in its separate, nationwide order. That order—which includes a 60-day phase- in period, see Compensation for Reactive Power Within the Standard Power Factor Range, 191 FERC ¶ 61,118, P 177— is not before us, and this opinion has no bearing on its procedural or substantive validity.

IV

We hold that FERC acted arbitrarily by giving MISO’s proposed tariff amendments immediate effect without adequately considering the generators’ asserted short-term reliance interests. Accordingly, we grant the petitions for review, set aside FERC’s orders, and remand this matter for further proceedings.

So ordered.