Capital Power Corporation v. Federal Energy Regulatory Commission

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.

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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.

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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

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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

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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,

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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.

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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

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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.

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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.

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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

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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.

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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,

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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

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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

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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

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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.

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