The opinion
United States Court of Appeals
FOR THE DISTRICT OF COLUMBIA CIRCUIT
Argued September 26, 2025 Decided July 31, 2026
No. 23-1282
ADVANCED ENERGY UNITED, ET AL.,
PETITIONERS
v.
FEDERAL ENERGY REGULATORY COMMISSION,
RESPONDENT
CONSUMERS ENERGY COMPANY, ET AL.,
INTERVENORS
Consolidated with 23-1284, 23-1289, 23-1297, 23-1299,
23-1305, 23-1310, 23-1312, 23-1313, 23-1320, 23-1327,
23-1330, 23-1346, 24-1093, 24-1106, 24-1112, 24-1136,
24-1137, 24-1139, 24-1140, 24-1141
On Petitions for Review of Orders
of the Federal Energy Regulatory Commission
John Lee Shepherd Jr. and Elbert Lin argued the causes
for Transmission Provider Petitioners. With them on the briefs
were Catherine P. McCarthy, Joshua Kirstein, Paul A. Colbert,
2
Blake Grow, Sara Weinberg, Lisa B. Luftig, Christopher D.
Supino, Ilia Levitine, Ted Murphy, Andrew W. Tunnell, Wendy
N. Reed, Matthew J. Binette, Abraham F. Johns, III, Lyle D.
Larson, Abigail C. Fox, Robert V. Eckenrod, Christopher R.
Jones, Antonia M. Douglas, Adrienne Thompson, Wendy B.
Warren, David S. Berman, Elizabeth P. Trinkle, and Priyanka
Vashisht. Ryan J. Collins, Kevin M. Leroy, Jason Tompkins,
Misha Tseytlin, and Susan J. LoFrumento, entered
appearances.
Melissa Alfano argued the causes for Association
Petitioners. With her on the briefs were Ben Norris, Gabriel
Tabak, Jeremy McDiarmid, Nicholas M. Gladd, and Kelsey C.
Catina.
Robert H. Solomon, Solicitor, Federal Energy Regulatory
Commission, argued the cause for respondent. With him on
the brief were David L. Morenoff, Acting General Counsel, and
Susanna Y. Chu and J. Houston Shaner, Attorneys.
Alexander L. Tom argued the cause for intervenors. With
him on the brief were Christine A. Powell, Ada Statler, Nick
Lawton, Linnet Davis-Stermitz, John Moore, Caroline Reiser,
Gregory E. Wannier, Justin Vickers, Adam Kurland, Ben
Norris, Melissa Alfano, Gabriel Tabak, and Jeremy
McDiarmid. Danielle Fidler entered an appearance.
Before: MILLETT, WALKER, and CHILDS, Circuit Judges.
Opinion for the Court filed PER CURIAM.
PER CURIAM: The on-ramps to our nation’s power grid are
in the middle of a decades-long traffic jam. At the end of 2023,
roughly 2,600 gigawatts of proposed generating and storage
capacity were stuck in interconnection queues, waiting years
3
for the completion of the studies needed before they can
connect to the transmission system. Solar, wind, and energy
storage accounted for about 95 percent of that capacity.1 That
0F
backlog represents more than twice the country’s installed
generation capacity, which stood at roughly 1,200 gigawatts in
2023. 2 The Federal Energy Regulatory Commission (“FERC”)
1F
concluded that the existing process could not keep up with the
“unprecedented” volume of interconnection requests and that
the resulting delays were producing unjust and unreasonable
conditions in wholesale markets.
Order 2023 is FERC’s attempt to clear that traffic. Acting
under its remedial authority, FERC directed every transmission
provider under its jurisdiction to overhaul how it processes
interconnection requests—moving from a serial, project-by-
project model to clustered studies, requiring substantial
deposits, imposing withdrawal fines, setting firm study
deadlines, and backing those deadlines with automatic late
fees.
Those reforms drew fire from several directions.
Transmission providers and system operators argue that FERC
exceeded its authority under the Federal Power Act, violated
due process, and ran afoul of the Administrative Procedure Act
by layering “strict-liability penalties” on top of already-revised
tariffs. Clean-energy developers challenge the rule from the
opposite flank, attacking what they see as an arbitrary safe
harbor that shields transmission providers from penalties when
1
Joseph Rand et al., Queued Up: 2024 Edition, Characteristics
of Power Plants Seeking Transmission Interconnection As of the End
of 2023, Lawrence Berkeley Nat’l Lab’y, 14 (Apr. 2024),
https://perma.cc/Y6KF-KX55.
2
Electricity explained, U.S. Energy Info. Admin. (July 16,
2024), https://perma.cc/RFE7-LE2A.
4
their cost estimates prove wildly wrong. FERC and supporting
intervenors defend the rule as a measured response to a
systemic breakdown in the interconnection process.
These petitions ask whether FERC lawfully adopted that
nationwide interconnection regime and whether FERC
reasonably explained how the rule balances the interests of
transmission providers, interconnection customers, and
ultimate consumers.
We conclude that FERC acted within its authority and
reasonably explained its order. Accordingly, we deny the
petitions.
I. Background
A
Under the Federal Power Act, FERC regulates the
transmission of electric energy in interstate commerce and
wholesale sales of that energy. See 16 U.S.C. § 824(b)(1). The
Act requires that “all rates and charges” for those services, and
the rules and practices that affect them, remain “just and
reasonable” and not unduly discriminatory or preferential. Id.
§§ 824d(a), 824e(a). That mandate extends to the terms on
which new generators connect to the transmission grid because
interconnection procedures and costs directly affect wholesale
rates and competition. See Improvements to Generator
Interconnection Procedures and Agreements, Order
Addressing Arguments Raised on Rehearing, Setting Aside
Prior Order, in Part, and Granting Clarification, Order No.
2023-A, 186 FERC ¶ 61,199, at P 315 (2024) (“Order 2023-
A”) (“queue backlogs are causing unjust and unreasonable
rates and . . . must, therefore, be remedied pursuant to our
statutory mandate”).
5
Before a new generating facility can inject power into the
grid, the transmission provider must complete technical studies
to determine whether the system can safely accommodate the
new resource and what network upgrades would be needed.
Those studies often involve not only the transmission owner
whose facilities the project will connect to, but also
neighboring “affected systems” that may be affected when the
new resource comes online. Improvements to Generator
Interconnection Procedures and Agreements, Order No. 2023,
184 FERC ¶ 61,054, at P 13 n.22 (2023) (“Order 2023”).
Under FERC’s standard interconnection procedures, the
generator enters the queue, posts deposits, undergoes
successive studies, and eventually receives an interconnection
agreement that identifies any required upgrades and assigns
their costs.
Over the last decade, that process has strained under the
volume of new projects. FERC found that the combined
capacity of projects sitting in interconnection queues across the
country was nearly equal to the entire existing United States
generation fleet. Order 2023 at P 30. 3 It noted, too, that more
2F
than seventy percent of the interconnection requests submitted
between 2000 and 2017 were eventually withdrawn. Id. at
P 49. FERC explained that late-stage withdrawals were
increasing and could require transmission providers to redo
studies, raising costs and further delaying projects behind them
in the queue. Id.
FERC concluded that these backlogs, delays, and repeated
restudies were hampering the timely development of new
generation and “stifl[ing] competition” in wholesale markets,
3
And now surpasses it. See notes 1 & 2, supra, and
accompanying text.
6
producing unjust and unreasonable conditions under the
Federal Power Act. Order 2023 at PP 37, 44. Order 2023 is
FERC’s response to those findings.
B
1
Federal Power Act—Section 205. The Federal Power
Act sets out two major avenues through which FERC can
regulate rates and related aspects of our energy grid: Sections
205 and 206. Section 205 governs utility-initiated changes to
rates and practices. As relevant here, it provides:
All rates and charges made, demanded, or received by
any public utility for or in connection with the
transmission or sale of electric energy subject to the
jurisdiction of the Commission, and all rules and
regulations affecting or pertaining to such rates or
charges shall be just and reasonable, and any such rate
or charge that is not just and reasonable is hereby
declared to be unlawful.
16 U.S.C. § 824d(a). Under Section 205, a utility files
proposed tariff changes, and FERC may reject them only if the
utility fails to show they are just and reasonable.
Federal Power Act—Section 206. Section 206 gives
FERC remedial authority to replace existing rates or practices
that have become unlawful. It is the “related but distinct” tool
that allows FERC to act on its own initiative or on complaint.
Emera Maine v. FERC, 854 F.3d 9, 21 (D.C. Cir. 2017)
(quoting FirstEnergy Serv. Co. v. FERC, 758 F.3d 346, 348
(D.C. Cir. 2014)). The statute provides, in relevant part:
7
Whenever the Commission, after a hearing held upon
its own motion or upon complaint, shall find that any
rate, charge, or classification, demanded, observed,
charged, or collected by any public utility for any
transmission or sale subject to the jurisdiction of the
Commission, or that any rule, regulation, practice, or
contract affecting such rate, charge, or classification
is unjust, unreasonable, unduly discriminatory or
preferential, the Commission shall determine the just
and reasonable rate, charge, classification, rule,
regulation, practice, or contract to be thereafter
observed and in force, and shall fix the same by order.
16 U.S.C. § 824e(a) (emphasis added). In a Section 206
proceeding, FERC bears the burden to show that existing rates
or practices are unlawful and then to identify a replacement that
is itself just and reasonable and not unduly discriminatory.
Emera Maine, 854 F.3d at 21, 24–25.
Administrative Procedure Act. Judicial review is
governed by 5 U.S.C. § 706. As relevant here, the reviewing
court must “hold unlawful and set aside agency action,
findings, and conclusions found to be . . . arbitrary, capricious,
an abuse of discretion, or otherwise not in accordance with
law” or “unsupported by substantial evidence.” 5 U.S.C.
§ 706(2)(A), (E).
The parties agree that Order 2023 is subject to those
standards.
2
Order 888: open-access transmission. Until the mid-
1990s, vertically integrated utilities controlled generation,
transmission, and distribution within their territories and could
8
use their transmission facilities to favor their own generation.
See NextEra Energy Res., LLC v. FERC, 118 F.4th 361, 365
(D.C. Cir. 2024). In 1996, FERC issued Order 888, which
required transmission owners to offer non-discriminatory
open-access transmission service under a standard tariff and to
“unbundl[e]” transmission from generation. Id. at 365–66.
This court largely upheld that regime, and the Supreme Court
confirmed FERC’s authority to impose open-access
requirements on interstate transmission. See Transmission
Access Pol’y Study Grp. v. FERC, 225 F.3d 667, 681 (D.C. Cir.
2000), aff’d sub nom. New York v. FERC, 535 U.S. 1, 16–24
(2002).
Order 2000: regional transmission organizations.
FERC then turned to who operates the power grid. In Order
2000, FERC encouraged utilities to place operational control
of transmission facilities in regional transmission organizations
and independent system operators—entities that manage the
grid over multi-state regions and administer competitive
markets. Regional Transmission Organizations, Order No.
2000, 65 Fed. Reg. 810, 811 (Jan. 6, 2000). FERC and this
court understood that regional operators could reduce
opportunities for discriminatory transmission practices and
improve coordination across the network. See id.; Pub. Util.
Dist. No. 1 of Snohomish Cnty. v. FERC, 272 F.3d 607, 611
(D.C. Cir. 2001).
Order 2003: standardized interconnection procedures.
In 2003, FERC addressed how new generators connect to the
grid. Order 2003 required all public utilities that own, control,
or operate interstate transmission facilities to adopt standard
Large Generator Interconnection Procedures and a standard
Large Generator Interconnection Agreement for facilities
larger than 20 megawatts. See Standardization of Generator
9
Interconnection Agreements & Procedures, Order No. 2003,
104 FERC ¶ 61,103, at PP 1–2 (2003) (“Order 2003”).
Order 2003 adopted a serial “first-come, first-served”
approach. Transmission providers studied each new request
individually in the order received. Generators entered the
queue with a modest refundable deposit and proceeded through
successive feasibility, system-impact, and facilities studies.
See Order 2003 at PP 34–38. Transmission providers were
obligated only to use “reasonable efforts” to complete those
studies within target timeframes. Id., pro forma Large
Generator Interconnection Procedures §§ 1, 6.3, 7.4, 8.3. They
effectively set their own schedules under that flexible standard.
As markets evolved, FERC observed that the serial,
reasonable-efforts model was contributing to delays and
backlogs. In technical conferences and later rulemakings,
FERC identified surges in new generation development,
especially from smaller renewable projects, and noted that
many interconnection requests were speculative entries that
would eventually withdraw—often late in the process—forcing
restudies and increasing uncertainty for projects deeper in the
queue. Interconnection Queuing Practices, Order on
Technical Conference, 122 FERC ¶ 61,252, at P 18 (2008);
Reform of Generator Interconnection Procedures and
Agreements, Order No. 845, 163 FERC ¶ 61,043, at P 24 &
n.21 (2018).
FERC adopted incremental reforms, see, e.g., Order 845,
but it ultimately concluded that piecemeal adjustments did not
solve the core problems with queue management, study
timelines, and cost certainty. See Order 2023 at PP 17–19.
10
3
Advance notice and proposed rule. In July 2021, FERC
issued an Advance Notice of Proposed Rulemaking that
flagged potential reforms to transmission planning, cost
allocation, and generator interconnection. Building for the
Future Through Electric Regional Transmission Planning and
Cost Allocation and Generator Interconnection, Advance
Notice of Proposed Rulemaking, 176 FERC ¶ 61,024 (2021).
After receiving extensive comments, FERC split those topics
into separate dockets and, in June 2022, issued a notice of
proposed rulemaking focused on generator interconnection
reforms. Improvements to Generator Interconnection
Procedures and Agreements, Notice of Proposed Rulemaking,
179 FERC ¶ 61,194 (2022) (“NPRM”).
Commenters—including transmission providers, system
operators, state regulators, consumer advocates, and
environmental groups—largely agreed that queue backlogs and
cost uncertainty warranted significant changes to the existing
interconnection regime. See Order 2023 at P 30.
Order 2023’s core reforms. In July 2023, FERC issued
Order 2023. Based on the rulemaking record, FERC found that
its existing pro forma interconnection procedures and
agreements were “insufficient” to ensure that customers can
interconnect in a “reliable, efficient, transparent, and timely
manner” and that, without reform, existing backlogs and delays
would continue to hinder new generation and undermine just
and reasonable rates. Order 2023 at PP 37, 44.
Acting under Section 206, FERC directed jurisdictional
transmission providers—that is, those that are governed by
FERC—to make a series of nationwide changes.
11
First, Order 2023 replaces the serial, first-come, first-
served model with a “first-ready, first-served” cluster-study
process. Transmission providers must study groups of
interconnection requests together in defined cluster windows,
rather than one by one, to improve efficiency and better
allocate network upgrade costs. Order 2023 at PP 177–83.
Next, the rule requires interconnection customers to post
substantial study deposits at the outset of the process, calibrated
to project size and stage, to ensure that only commercially
ready projects enter and stay in the queue. Order 2023 at
PP 502–07.
The order then adopts a tiered schedule of withdrawal fines
that increase as a project advances through the interconnection
stages, while allowing limited opportunities for fine-free
withdrawal when specified conditions are met. Order 2023 at
PP 780–813.
With the cluster study process and deposit system in place,
the order establishes firm deadlines for transmission providers
to complete cluster studies. It includes a 150-day deadline for
the main cluster study and eliminates the “reasonable efforts”
standard. Order 2023 at PP 324–31, 962. If a transmission
provider misses a study deadline, the rule requires it to pay late
fees to interconnection customers, subject to certain limits. Id.
at PP 962–1007. To protect against undue exposure to fees and
account for unusual circumstances, Order 2023 caps annual
late-fee amounts and creates an appeals process under which
transmission providers can seek relief from late fees in
specified situations. Id. at PP 981–89.
Finally, the order standardizes how affected-system
transmission providers study and allocate costs for impacts on
their systems, and adopts Energy Resource Interconnection
12
Service (“energy service”) as the default standard for such
studies. Order 2023 at PP 1110–80, 1276–93.
FERC received thirty-two timely rehearing and
clarification requests challenging various aspects of these
reforms. See Order 2023-A at P 5.
Order 2023-A. In March 2024, FERC issued Order 2023-
A, addressing those rehearing arguments. As relevant here,
FERC reaffirmed its findings that existing interconnection
procedures and agreements had become unjust and
unreasonable, declined to abandon the late-fee framework for
study delays, and defended the chosen thresholds for fine-free
withdrawal as part of a broader effort to balance cost certainty
against the need to deter speculative queue entries. Order
2023-A at PP 35, 280–303, 413–15.
C
The petitions challenge three portions of the rule: (1) the
fines on interconnection customers for withdrawing from the
queue, (2) the firm deadlines for interconnection studies,
backed by late fees on transmission providers, and (3) the
requirement that all affected-system studies use Energy Service
Modeling.
Challenges to the Thresholds for Withdrawal Fees
Clean Energy Petitioners challenge Order 2023’s rule that
allows an interconnection customer to withdraw without a fine
between the final cluster study and the individual facilities
study stages only if the customer’s assigned network upgrade
costs increase by 100 percent or more over earlier estimates.
13
They argue that allowing host-system cost estimates to
double before a customer may withdraw without a fine is
arbitrary and capricious and results in unjust and unreasonable
rates. Specifically, they argue that the 100-percent threshold
for fine-free withdrawal is unsupported by the record,
inconsistent with FERC’s own findings that cost uncertainty is
a major barrier to project financing, and, as a result, at odds
with FERC’s obligation under Section 206 to ensure just and
reasonable practices. They contend that the same problems
undermine FERC’s decision not to adopt any fine-free-
withdrawal threshold for cost estimates from affected-system
studies.
FERC defends the 100-percent threshold as a reasonable
exercise of its ratemaking discretion: It says the threshold
discourages speculative queue entries and late withdrawals
while still providing an escape hatch in cases of severe cost
shocks. FERC likewise defends its decision not to create a
withdrawal threshold for affected-system studies as a judgment
call needed to balance the interests of various customers in the
queue.
Challenges to the Study-Delay Incentive Scheme
Transmission providers and system operators focus on the
other side of the balance. They contend that Order 2023’s
financial incentive scheme for missed study deadlines exceeds
FERC’s remedial authority under Section 206, violates due
process, and is arbitrary and capricious.
To start, they argue that Order 2023 effectively punishes
them for delays without any finding that they caused those
delays or acted unreasonably, and that the rule leaves key
questions about cost recovery—especially for regional system
operators that lack shareholders—unresolved.
14
FERC, in response, characterizes the late fees as part of its
Section 206 remedy for unjust and unreasonable
interconnection practices, not as punitive sanctions, and points
to the late-fee caps and appeals process as safeguards that
mitigate the risk of unfair liability.
Next, these petitioners argue that the scheme is arbitrary
and capricious on a variety of grounds. They maintain, for
instance, that FERC failed to grapple with evidence that delays
often stem from factors outside the transmission providers’
control, including interconnection customer behavior, third-
party studies, and regional reliability requirements, and that
FERC did not meaningfully respond to their rehearing
arguments on that point.
FERC responds that the late fees, coupled with the appeals
process, reflect a reasonable balance between encouraging
timely performance and recognizing exceptional
circumstances. FERC stated that it needed a uniform,
enforceable mechanism to ensure timely completion of studies
in light of nationwide backlogs and the failure of the
“reasonable efforts” standard. Order 2023-A at PP 1–3.
Challenges to the Energy Service Modeling Requirements
Finally, a subgroup of transmission providers argues that
FERC acted arbitrarily and capriciously in requiring energy
service modeling for all affected-system studies. The
transmission providers complain that the requirement prevents
affected systems from fully assessing the scope of the
customer’s impact on their system if the host transmission
system ultimately provides the customer a higher level of
service, known as Network Resource Interconnection Service
(“firm service”).
15
FERC responds that it chose the energy service standard
to promote consistency and transparency, reduce late queue
withdrawals, and ensure that interconnection customers are not
charged for a service they do not receive or for significant
upgrades on a system they may never use.
All of the petitioners’ arguments fail.
II. Standing
A
FERC argues that the Clean Energy Petitioners lack
associational standing because they “have failed to
demonstrate that any of their members have suffered ‘imminent
or concrete’ harm as a result” of those orders. FERC Br. 88
(quoting Indus. Energy Consumers of Am. v. FERC, 125 F.4th
1156, 1161 (D.C. Cir. 2025)). FERC adds that the Clean
Energy Petitioners’ opening brief did not “identify members
who have suffered the requisite harm.” Id. at 86–87 (citing
Chamber of Com. v. EPA, 642 F.3d 192, 199 (D.C. Cir. 2011)).
And it faults them for failing to submit “member affidavits with
their opening brief.” Id. at 86 (citation modified). We consider
whether the Clean Energy Petitioners have carried their burden
on the record before us.
Standing is “a constitutional prerequisite to the exercise of
our jurisdiction.” Healthy Gulf v. Dep’t of the Interior, 152
F.4th 180, 189 (D.C. Cir. 2025) (citing Spokeo, Inc. v. Robins,
578 U.S. 330, 338 (2016)). Once an organization establishes
that one member has standing, it need go no further, because
when the standing of additional members or organizations
“makes no difference to the merits of the case,” “the standing
of one member of one of the organizations bringing suit
16
suffices.” Ctr. for Biological Diversity v. EPA, 56 F.4th 55, 66
(D.C. Cir. 2022) (citation modified). An organization, under
our standing doctrine, “can assert standing in one of two ways”:
“on its own behalf, as an organization,” or “on behalf of its
members, as associational standing.” Elec. Priv. Info. Ctr. v.
Dep’t of Com., 928 F.3d 95, 100 (D.C. Cir. 2019) (citation
modified). The Clean Energy Petitioners invoke the latter. To
establish associational standing, they must show that “(1) at
least one of their members would have standing to sue in their
own right, (2) the interests the members seek to protect are
germane to their organizations’ purposes, and (3) neither the
claim asserted, nor the relief requested requires the members to
participate individually in the lawsuit.” Healthy Gulf, 152
F.4th at 189 (citation modified). The Clean Energy Petitioners
satisfy each requirement.
1
Before an organization may invoke associational standing,
it must first establish that at least one of its members would
have Article III standing in its own right. See Sierra Club v.
FERC, 827 F.3d 59, 65 (D.C. Cir. 2016). That showing
requires an injury “fairly traceable” to the challenged action
and “likely”—not “merely speculatively”—redressable “by a
favorable decision.” See Friends of the Earth, Inc. v. Laidlaw
Env’t Servs. (TOC), Inc., 528 U.S. 167, 180–81 (2000) (citation
modified). The association must make that showing with
“substantial probability.” Sierra Club v. EPA, 292 F.3d 895,
898–99 (D.C. Cir. 2002).
When the Clean Energy Petitioners filed their opening
brief, Circuit Rule 28(a)(7) required evidence of standing only
when standing was not “apparent” from the administrative
record. D.C. Cir. R. 28(a)(7) (2024); see SSM Litig. Grp. v.
17
EPA, 150 F.4th 593, 596 (D.C. Cir. 2025) (applying the version
of Rule 28(a)(7) in effect when the opening brief was filed). 4 3F
Here, the administrative record shows that these
petitioners have standing. The Clean Energy Petitioners’
corporate disclosure statements and administrative comments
establish that their members participate in the interconnection
queue as customers and so face the withdrawal fines imposed
by the challenged orders. See J.A. 1021 (Pine Gate
Renewables, a member of Solar Energy Industries Association
(“SEIA”) and American Clean Power Association that operates
clean-energy generation projects, describing its continuing role
as an interconnection customer); id. at 1489 (Order 2023
identifying solar projects as among the fastest-growing sources
of energy generation); see also Clean Energy Petitioners Br., at
iii (corporate disclosures stating that “SEIA represents the
entire solar industry, including installers, project developers,
manufacturers, contractors, financiers and non-profits”). And
Pine Gate Renewables explained that the “voluntary
withdrawal of an interconnection customer from the queue or
an interconnection customer’s removal from the queue . . .
often trigger a restudy of the entire cluster regardless of the
minimal effect of the change on most of the previous study
results.” J.A. 1027. “[T]here is ordinarily little question that a
regulated individual or entity has standing to challenge an
allegedly illegal statute or rule under which it is regulated.”
Bonacci v. TSA, 909 F.3d 1155, 1159 (D.C. Cir. 2018) (citation
modified).
4
In August 2025, the court revised Circuit Rule 28(a)(7) to
require every petitioner to “include arguments and cite evidence
establishing by a ‘substantial probability’ the claim of standing” in
its opening brief. D.C. Cir. R. 28(a)(7).
18
What’s more, while Clean Energy Petitioners did not
submit a declaration with their opening brief, they did submit
one with their reply brief, “in an abundance of caution.” Decl.
of Brett White, Senior Vice President of Regulatory and
Government Affairs at Pine Gate Renewables (Attach. A to
Clean Energy Petitioners Reply Br.). That timing poses no
problem. Although it is disfavored, we have allowed
“petitioners to support their standing in their reply brief [and]
in affidavits submitted along with the reply brief.” Am. Libr.
Ass’n v. FCC, 401 F.3d 489, 494 (D.C. Cir. 2005).
White explains in his declaration how Order 2023 affects
several Pine Gate Renewables projects. Pine Gate Renewables
“has 3.5 GWs of solar and energy storage assets under contract,
under construction, or in operation in the Southeast, the
Electric Reliability Council of Texas . . . region, the PJM
Interconnection, LLC . . . region, Oregon, and Rhode Island,”
representing “over seven billion dollars in completed
transactions.” White Decl. ¶ 8. White further declares that
Pine Gate Renewables “is currently developing projects in
several FERC-jurisdictional markets that will be subject to the
requirements of Order 2023, including the rules governing cost
increases and withdrawal fines at the facilities study and
affected systems study phases of the interconnection process.”
Id. That is enough to show injury-in-fact because Pine Gate
Renewables develops projects in markets governed by Order
2023, and those projects face the very withdrawal-fine rules
challenged here, and their attendant financial consequences.
See Bonacci, 909 F.3d at 1159.
With injury-in-fact established, we turn next to causation
and redressability. Causation asks whether it is “substantially
probable that the challenged acts of the defendant, not of some
absent third party, will cause the particularized injury of the
plaintiff.” Orangeburg v. FERC, 862 F.3d 1071, 1080 (D.C.
19
Cir. 2017) (citation modified). Redressability requires an
injury “capable of resolution and likely to be redressed by
judicial decision.” W. Coal Traffic League v. Surface Transp.
Bd., 998 F.3d 945, 950 (D.C. Cir. 2021) (citation modified).
The Clean Energy Petitioners satisfy both requirements.
Their members face a substantial risk of injuries because
FERC has subjected them to the withdrawal fines in Order
2023, and they challenge those fines as “arbitrary and
capricious and unsupported by substantial evidence, in
violation of the Administrative Procedure Act, 5 U.S.C.
§§ 706(2)(A), (E), and [as] result[ing] in unjust and
unreasonable rates to Petitioners’ member companies.” Clean
Energy Petitioners Br. 14. That injury is fairly traceable to
FERC because the challenged orders create the policy Pine
Gate Renewables says will govern its projects. And Clean
Energy Petitioners’ injury is redressable by a favorable ruling.
Cf. Ctr. for Energy & Econ. Dev. v. EPA, 398 F.3d 653, 657
(D.C. Cir. 2005) (“[T]he redressability requirement may be
satisfied by vacating the challenged rule and giving the
aggrieved party the opportunity to participate in a new
rulemaking the results of which might be more favorable to it.”
(citation modified)).
The Clean Energy Petitioners therefore have shown that at
least one of their members would have standing to sue,
satisfying the first element of associational standing.
2
Likewise, the Clean Energy Petitioners have shown that
the interests of their members are germane to their purpose,
satisfying the second element of associational standing. That
element ensures that “the association’s litigators will
themselves have a stake in the resolution of the dispute, and
20
thus be in a position to serve as the defendant’s natural
adversary.” United Food & Com. Workers Union Loc. 751 v.
Brown Grp., Inc., 517 U.S. 544, 555–56 (1996); see also Ctr.
for Sustainable Econ. v. Jewell, 779 F.3d 588, 597 (D.C. Cir.
2015) (similar).
Here, in its corporate disclosure, the American Clean
Power Association (one of the Clean Energy Petitioners)
maintains that the organization “represents over 100 member
companies and has a mission to achieve 100% clean power and
transportation electrification across the United States.” Clean
Energy Petitioners Br., at i. Additionally, the SEIA’s “member
companies develop, manufacture, finance and build solar
projects both domestically and abroad.” Id. at iii. This case
sits comfortably within those missions. The Clean Energy
Petitioners challenge interconnection rules that burden clean-
energy development by exposing their members, in their view,
to unlawful withdrawal fines. The connection between the suit
and the organization’s purpose is therefore not strained but
direct. The interests these petitioners seek to protect are
therefore “germane to [their] purpose.” Ctr. for Biological
Diversity, 56 F.4th at 66 (citation modified).
3
The Clean Energy Petitioners also satisfy the third element
of associational standing. “Member participation is not
required where a suit raises a pure question of law and neither
the claims pursued, nor the relief sought require the
consideration of the individual circumstances of any aggrieved
member of the organization.” Healthy Gulf, 152 F.4th at 191
(citation modified).
Here, the Clean Energy Petitioners’ challenges against
Order 2023 concern pure questions of law. See Marshall Cnty.
21
Health Care Auth. v. Shalala, 988 F.2d 1221, 1226 (D.C. Cir.
1993) (“[W]hen an agency action is challenged[] . . . [t]he
entire case on review is a question of law, and only a question
of law.”). And purely legal challenges, like this one, do not
“depend[] on individualized evidence from their members,” or
any individualized remedies. Healthy Gulf, 152 F.4th at 191.
For these reasons, the Clean Energy Petitioners satisfy all
three elements of associational standing.
B
Staying with standing, we also consider whether the
respondent-intervenors—the Clean Energy Advocates—have
associational standing to advocate in support of Order 2023’s
study-delay fees. Neither set of petitioners argues against their
standing. Article III, however, does not depend on party
presentation since we must assure ourselves of our jurisdiction,
“sua sponte if necessary.” Flytenow, Inc. v. FAA, 808 F.3d
882, 888 (D.C. Cir. 2015). We therefore address the issue and
hold that the Clean Energy Advocates have standing.
An intervenor has a “sufficient injury in fact where,” for
example, “[it] benefits from agency action, the action is then
challenged in court, and an unfavorable decision would remove
[its] benefits.” Crossroads Grassroots Pol’y Strategies v. FEC,
788 F.3d 312, 317 (D.C. Cir. 2015). This rule even applies
when the challenged agency action benefits the intervenor only
“tangentially” or “indirectly.” Id. at 318. What matters is the
practical effect. In those circumstances, the only question is
whether another party “seeks relief, which, if granted, would
injure the prospective intervenor.” Id. (citation modified).
The Clean Energy Advocates satisfy that standard. They
say their members benefit from the challenged orders because
22
they address widespread interconnection queue delays. And
those delays, in their view, cause higher energy bills and slow
the integration of cheaper, cleaner energy, including wind,
solar, and battery storage. On their telling, vacating the study-
delay incentive scheme in Order 2023 would undo those
improvements and likely increase electricity costs for their
members.
The record bears out that point. The Environmental
Defense Fund, one of the Clean Energy Advocates, has
318,225 members in forty-seven states where most or all
customers are served by Regional Transmission Organizations
or electric utilities subject to Order 2023. Those members use
electricity in markets affected by the challenged orders.
Vacating the rule’s study-delay incentive scheme would likely
expose them to higher electricity costs caused by renewed
interconnection delays. See Goodman v. Pub. Serv. Comm’n,
467 F.2d 375, 378 (D.C. Cir. 1972) (holding that consumers
have standing to challenge or defend agency action that affects
the prices they pay for electricity). Thus, by showing that their
members would benefit if the challenged orders remain in
place, the Clean Energy Advocates have shown that at least one
member would be injured if we set aside Order 2023. These
same facts also establish causation and redressability. See
Healthy Gulf, 152 F.4th at 191. 54F
5
The Clean Energy Advocates advance a fallback argument.
Because they intervened in support of FERC, the respondent here,
they say they do not invoke our jurisdiction in their own right, and
so need not establish standing for themselves. We need not resolve
that question because the Clean Energy Advocates have Article III
standing regardless. See United States v. Waksberg, 112 F.3d 1225,
1227 (D.C. Cir. 1997) (explaining that courts “should not decide a
constitutional issue unless it is necessary to do so”).
23
Turning to the second and third elements of associational
standing, we hold that the Clean Energy Advocates satisfy
them as well. Their members’ interests are germane to the
organizations’ purposes—helping move the country toward a
clean, affordable, and reliable electric grid. This suit fits that
purpose. The Clean Energy Advocates seek to defend the
study-delay incentive scheme because, in their view, it reduces
interconnection delays and lowers the costs of bringing clean
energy onto the electric grid. Nor is individual member
participation required considering that the Clean Energy
Advocates’ challenges raise purely legal issues and seek
common relief. See Marshall Cnty. Health Care Auth., 988
F.2d at 1226. Given that point, they seek relief that does not
“depend[] on individualized evidence from their members.”
Healthy Gulf, 152 F.4th at 191. For those reasons, the Clean
Energy Advocates have satisfied the latter two elements of
associational standing. 65F
*****
With Article III standing established, we turn to the merits.
III. Challenges to the Thresholds for Withdrawal Fees
The Clean Energy Petitioners argue that (1) the threshold
for fine-free withdrawal from a host transmission system is
arbitrary and capricious; (2) FERC arbitrarily declined to adopt
a comparable threshold for withdrawals based on affected-
systems upgrade costs; and (3) the fine-free withdrawal
6
The Transmission Petitioners plainly have Article III standing.
Order 2023 regulates them directly, compelling compliance filings,
requiring a cluster-study interconnection process, and imposing new
study deadlines backed by fines. See Bonacci, 909 F.3d at 1159;
Transmission Petitioners Br. 18.
24
thresholds depart from precedent without adequate
explanation. We address these arguments in turn.
A
We start with whether FERC reasonably set the threshold
for avoiding withdrawal fines at the facilities-study stage. The
Clean Energy Petitioners challenge the third and final
exemption from those fines. That exemption provides that an
interconnection customer will not incur withdrawal fines when,
by the time it receives its individual facilities study, its
estimated network-upgrade costs have increased by more than
100 percent from the last cluster study. The Clean Energy
Petitioners say that threshold is too high—so high, in fact, that
it frustrates Order 2023’s stated goal of giving interconnection
customers better cost certainty. They also contend, for much
the same reason, that the 100-percent threshold is not “just and
reasonable.” Clean Energy Petitioners Br. 19. We disagree.
An agency must “give adequate reasons for its decisions.”
Montrois v. United States, 916 F.3d 1056, 1067 (D.C. Cir.
2019) (quoting Encino Motorcars, LLC v. Navarro, 579 U.S.
211, 221 (2016)). That requirement “is meant to ensure that
agencies offer genuine justifications for important decisions,
reasons that can be scrutinized by courts and the interested
public.” Dep’t of Com. v. New York, 588 U.S. 752, 785 (2019).
It is satisfied when the agency’s explanation is “clear enough
that its path may reasonably be discerned.” Montrois, 916 F.3d
at 1067. So while the agency sometimes need only offer a
“brief statement,” it must still “explain why it chose to do what
it did.” Tourus Records, Inc. v. DEA, 259 F.3d 731, 737 (D.C.
Cir. 2001) (quoting Henry J. Friendly, Chenery Revisited:
Reflections on Reversal and Remand of Administrative Orders,
1969 Duke L.J. 199, 222).
25
In determining whether an agency’s final rule is arbitrary
and capricious, “we may consider only the regulatory rationale
actually offered by the agency during the development of the
regulation.” Grand Canyon Air Tour Coal. v. FAA, 154 F.3d
455, 469 (D.C. Cir. 1998). We do not “accept as evidence of
reasoned decisionmaking a post hoc rationalization for agency
action.” City of Kansas City v. Dep’t of Hous. & Urb. Dev.,
923 F.2d 188, 194 (D.C. Cir. 1991).
Considering those principles, we address whether FERC’s
decision to set the fine-free withdrawal threshold at a 100-
percent cost increase was arbitrary and capricious. FERC
found, and no party disputes, that withdrawal fines are “needed
to remedy the issues regarding speculative interconnection
requests,” and the “harms to the function of the interconnection
queue that occur when” nonviable projects withdraw. Order
2023 at P 781. FERC further explained that fines discourage
speculative requests by “encourag[ing] interconnection
customers to ensure that their proposed generating facilities are
likely commercially viable when they” enter the queue. Id.
That explanation is reasonable. A project that enters the queue
without a realistic path to completion can consume study
resources, distort cost estimates, and shift the resulting burdens
to others.
FERC also found that withdrawals become more harmful
the later they occur. Order 2023 at P 781. “[L]ate-stage
withdrawals,” after all, “cause the greatest disruption to
interconnection queue processing via restudies and delays.” Id.
at P 790. And the problem is not only delay. A withdrawal
“after the facilities study” can shift network-upgrade costs onto
the customers that remain in the queue. Id. at P 808. In support
of that position, FERC, “[b]y way of example,” explained how
one late withdrawal could reallocate $9 million in costs to other
26
interconnection customers, even after crediting those
customers a proportional amount of the withdrawal fine. Id.
In response to those findings, FERC adopted a graduated
structure. It set “the thresholds for [fine]-free withdrawal . . .
higher at later stages of the interconnection study process,”
including the facilities-study stage, “given the greater harms of
late-stage withdrawals and the importance of incentivizing
earlier withdrawal of non-viable interconnection requests.”
Order 2023-A at P 232; see also Order 2023 at P 792. That
structure followed FERC’s straightforward premise that the
later the withdrawal, the greater the disruption; and the greater
the disruption, the stronger the incentive needed to avoid it.
The Clean Energy Petitioners do not dispute that premise.
They acknowledge that a higher exemption threshold is
appropriate at the facilities-study stage; they just would have
set it at some lower percentage. See Order 2023-A at P 223
(“Clean Energy Associations submit that the Commission
should lower this threshold to a 50% cost increase post-study
for a [fine]-free withdrawal.”). They make the same point by
citing other project developers that preferred lower thresholds,
including at the facilities study stage. Hence, these petitioners
dispute not the rationale of a graduated fine structure but rather
FERC’s decision to draw the line at a 100-percent withdrawal
threshold instead of some lower percentage.
FERC, however, did not pick the 100-percent withdrawal
threshold out of thin air. In its Notice of Proposed Rulemaking,
FERC supported its proposed thresholds by pointing to prior
orders applying to individual transmission providers that had
adopted the same 25-percent and 100-percent fine-free
withdrawal thresholds. NPRM at P 139 n.209 (citing
PacifiCorp, 171 FERC ¶ 61,112 (2020); Pub. Serv. Co. of
Colo., 169 FERC ¶ 61,182 (2019); Tri-State Generation &
27
Transmission Ass’n, 174 FERC ¶ 61,021 (2021)); see also id.
at P 139 n.210 (citing PacifiCorp, 171 FERC ¶ 61,112, at
P 112). Those real-world examples give FERC three concrete
models of successful implementation of the 100-percent fine-
free withdrawal threshold. And FERC did not stand alone
considering that at least one commenter supported the 100-
percent threshold. See Order 2023 at P 743 (citing Comments
of the National Rural Electric Coop. Association at 30 (Oct. 13,
2022)).
The Clean Energy Petitioners counter that FERC’s
reliance on its precedent and the Notice of Proposed
Rulemaking is merely the “post hoc salvage operations of
counsel” that “cannot overcome the inadequacy of the
Commission’s explanation.” Clean Energy Petitioners Reply
Br. 9 (quoting KeySpan-Ravenswood, LLC v. FERC, 348 F.3d
1053, 1059 (D.C. Cir. 2003)). But they misread KeySpan.
In KeySpan, FERC’s counsel defended its order with a
rationale that FERC had never adopted. 348 F.3d at 1059. The
order contained only a “cryptic statement” about consistency.
Id. It did not explain that the twelve-month outage-rate
measure was justified because the same twelve-month period
governed another party’s sales, thereby offsetting any price-cap
effect. Id. That rationale first appeared in litigation. So we
treated it for what it was: the “post hoc salvage operations of
counsel.” Id. But this case differs from that one.
FERC does not urge us to accept a new rationale invented
by counsel after the fact. FERC cited the relevant precedent in
the Notice of Proposed Rulemaking, received comments
addressing the relevant thresholds, and then adopted the same
basic approach in the final rule. Its reliance on that precedent
therefore does not invoke new, independent reasons. It instead
elaborates on reasoning already present in the record, providing
28
an “amplified articulation.” Concert Inv., LLC v. Small Bus.
Admin., 100 F.4th 215, 220 (D.C. Cir. 2024). More, FERC’s
reliance on the relevant precedent occurred “during the
development of the regulation,” which we may consider.
Grand Canyon Air, 154 F.3d at 469.
For those reasons, we hold that FERC’s decision to set the
fine-free withdrawal threshold at a 100-percent cost increase
was not arbitrary and capricious.
B
The Clean Energy Petitioners also argue that FERC acted
arbitrarily and capriciously in declining to set a fine-free
withdrawal option related to non-jurisdictional affected-system
studies. We reject that argument too.
Generally, “FERC enjoys broad discretion to invoke its
expertise in balancing competing interests and drawing
administrative lines.” Minisink Residents for Env’t Pres. &
Safety v. FERC, 762 F.3d 97, 111 (D.C. Cir. 2014) (citation
modified). That discretion matters here because FERC’s job is
not to maximize one interest at the expense of all others. It
must “balance competing equities against the backdrop of the
public interest.” Colum. Gas Transmission Corp. v. FERC, 750
F.2d 105, 112 (D.C. Cir. 1984). Those equities often include
“practical challenges” and “divergent interests.” New England
Power Generators Ass’n v. FERC, 881 F.3d 202, 210 (D.C.
Cir. 2018). So when FERC draws a line in an area committed
to its technical judgment, we do not ask whether we would have
drawn the same one. See FERC v. Elec. Power Supply Ass’n,
577 U.S. 260, 292 (2016), as revised (Jan. 28, 2016) (“[W]e
may not substitute our own judgment for that of the
Commission.”). And we defer to its “reasonable balancing of
divergent considerations on a matter within [its] expertise.”
29
Xcel Energy Servs. Inc. v. FERC, 41 F.4th 548, 562 (D.C. Cir.
2022) (citation modified).
To that end, FERC reasonably balanced the interests of the
queue as a whole against the interests of the smaller group of
customers awaiting affected-system studies. No party disputes
that an interconnection customer may receive an affected-
system study at different points in the interconnection
process—anywhere from the cluster-study stage through
execution of the generator interconnection agreement. Timing
matters because network-upgrade costs identified in an
affected-system study received before the individual facilities
study stage count toward the 25-percent and 100-percent fine-
free withdrawal thresholds. See Order 2023-A at P 503. The
rule thus reduces the likelihood that an affected-system study
will expose a customer to withdrawal fines.
FERC tried to increase the chance that the existing
exemptions would capture affected-system upgrade costs. It
adopted reforms to “ensure that the affected system study
process moves along expediently, providing clarity, cost
certainty, and increased transparency throughout the study
process.” Order 2023 at P 1110. Those reforms also reduced
the risks that affected-system studies pose to interconnection
customers more generally. For example, FERC standardized
the methods used to conduct affected-system studies. And by
requiring energy-service modeling for those studies, FERC
found that “affected system network upgrade costs will likely
be lower” for customers in the queue. Id. at P 1279.
FERC, however, could not guarantee the timing of every
affected-system study. Some potentially affected neighboring
transmission providers conduct those studies, and not all of
them fall within FERC’s jurisdiction. And even for affected
systems within FERC’s jurisdiction, FERC “recognize[d] that
30
an affected system impact may not be identified until a [cluster]
restudy occurs.” Order 2023 at P 1119. So some affected-
system study reports may arrive after the facilities-study stage,
even though “other interconnection customers in the same
cluster who are not awaiting affected system studies” must
already execute their own generator interconnection
agreements. Order 2023-A at P 502. FERC further found that
even the possibility of that scenario creates uncertainty for the
remaining customers. See id. And that uncertainty, if left
unchecked, could produce “cascading withdrawals and
restudies.” Id.
That was of course the tradeoff. A fine exemption for
customers awaiting late affected-system studies “would give
greater weight to [the] cost certainty of a few interconnection
customers who are awaiting affected system study results than
to the many interconnection customers who did not impact an
affected system and had to finalize their” interconnection
agreements. Order 2023 at P 502. FERC chose the broader
interest of the interconnection queue. It found it “more
important for all interconnection customers in a cluster to have
greater certainty . . . than for one or [a] few interconnection
customers in a cluster to have cost estimate certainty inclusive
of affected system study results.” Id. That is a decision about
how to allocate risk in a congested queue. It is also the kind of
decision FERC is best positioned to make. See Vistra Corp. v.
FERC, 80 F.4th 302, 313 (D.C. Cir. 2023) (“As an expert in
energy regulation, the Commission has the technical
understanding necessary to carry out its congressionally
delegated duties.” (citation modified)).
Order 2023 also includes safeguards when the affected
system falls within FERC’s jurisdiction. Interconnection
customers, for example, need not sign Large Generator
Interconnection Agreements before receiving an affected-
31
system study. See Order 2023 at P 1123 (mandating that a host
transmission provider “at the interconnection customer’s
request, delay the deadline” for executing the agreement until
thirty days after receipt of the affected-system study). And at
oral argument, FERC confirmed that many non-jurisdictional
affected systems will voluntarily sign on to the same rules as
this order “because they also get the advantages of
nondiscriminatory open access transmission tariff[s].” Oral
Arg. Tr. 138:20–22. As a result, most interconnection
customers will be able to add affected-system upgrade costs to
their host-transmission-facility costs and thereby qualify for a
fine-free withdrawal. And in those rare cases, FERC could
reasonably require a withdrawing customer to pay a 20-percent
fine, particularly because the fine helps offset costs stomached
by the other members of the cluster.
The Clean Energy Petitioners respond with several
critiques of FERC’s balancing. None succeeds.
They first argue that FERC policy forbids penalizing
customers that cannot avoid the fine. See Clean Energy
Petitioners Br. 7, 21–22 (citing, e.g., El Paso Nat. Gas Co., 125
FERC ¶ 61,309, at P 105 (2008)). But they forfeited that
argument. The Clean Energy Petitioners’ rehearing application
raised it, if at all, only by implication—through one brief
citation parenthetical tucked into a footnote. That is not
enough to preserve a claim. See Ctr. for Biological Diversity
v. FERC, 67 F.4th 1176, 1184–85 (D.C. Cir. 2023) (explaining
that one “see, e.g.,” citation cannot exhaust a claim).
The Clean Energy Petitioners say next that FERC ignored
“record evidence” showing that affected-system studies can
drive large increases in upgrade costs. Clean Energy
Petitioners Br. 23. Not so. FERC understood the problem and
directly addressed it. Indeed, the existing exemptions already
32
account for affected-system-study costs through the facilities-
study stage. And as explained above, FERC adopted reforms
to reduce the risk that affected-system studies would surprise
interconnection customers with higher upgrade costs. FERC,
nevertheless, declined to create a separate late-stage exemption
because that exemption would favor the “cost certainty of a few
interconnection customers . . . awaiting affected system
stud[ies]” over greater certainty for “the many interconnection
customers who did not impact an affected system and had to
finalize their” agreement. Order 2023-A at P 502. Therefore,
FERC did not ignore the record; it weighed the evidence
differently than these petitioners preferred. See Level the
Playing Field v. FEC, 961 F.3d 462, 465 (D.C. Cir. 2020)
(“[T]hat plaintiffs may disagree with the Commission’s
weighing of the evidence presented to it is not enough for the
courts to overturn the Commission’s decisions as arbitrary,
capricious, or contrary to law.” (citation modified)).
The Clean Energy Petitioners also dispute how much the
energy-service standard will reduce upgrade-cost increases
from affected-system studies. But that objection misses the
point. FERC did not represent that the energy-service standard
would eliminate those increases. FERC merely determined
that “affected systems network upgrade costs will likely be
lower” under that standard, and that interconnection customers
“assigned” those network upgrades will be “less likely to
withdraw at a later stage.” Order 2023 at P 1279 (emphasis
added).
We defer to that sort of predictive judgment. FERC may
“base its findings on basic economic theory, including relying
on generic factual predictions,” so long as it “explains and
applies the relevant economic principles in a reasonable
manner.” Xcel Energy Servs., 41 F.4th at 560–61 (citation
modified). FERC did so here. After considering comments on
33
both sides, FERC reasonably made the energy-service standard
the default. The network-service standard “will likely” require
“more network upgrades to accommodate the interconnection
of a generating facility[,]” driving costs beyond what the
requested service demands. Order 2023 at PP 1256, 1279. By
tying upgrades to the service provided, FERC also sought to
“help prevent the cascading restudies” and queue withdrawals
that had burdened the interconnection process. Id. at P 1279;
see also Section V, infra. That saves money for affected
customers and those remaining in the queue.
And tellingly, neither set of petitioners seriously disputes
that the energy-service standard benefits interconnection
customers. The Clean Energy Petitioners describe projects
facing large affected-system study cost increases as “unlucky,”
Clean Energy Petitioners Br. 25, suggesting that such outcomes
will not be the norm. The Transmission Petitioners go further,
calling it “obvious” that the energy-service standard “will
result in lower cost assignments to generators.” Transmission
Petitioners Br. 84.
The Clean Energy Petitioners next argue that FERC
wrongly assumed that “allowing [fine]-free withdrawal . . .
would result in more withdrawals . . . than if interconnection
customers faced a withdrawal [fine].” Clean Energy
Petitioners Br. 28. But FERC made a simple economic
determination that fines make late withdrawal less attractive,
and so they “incentivize[]” customers “to withdraw non-viable
interconnection requests earlier in the process.” Order 2023 at
PP 786–87. And as discussed above, FERC may rely on “basic
economic theory” to make “generic factual predictions.” Xcel
Energy Servs., 41 F.4th at 561 (citation modified).
Clean Energy Petitioners also argue that denying penalty-
free withdrawal could “adversely incentivize affected system
34
transmission providers to delay” a study and thereby sabotage
interconnection customers. Clean Energy Petitioners Br. 31–
32. But Petitioners did not raise that argument on rehearing.
See J.A. 3113–17. We therefore lack jurisdiction to consider
it. See Citadel FNGE Ltd. v. FERC, 77 F.4th 842, 861 (D.C.
Cir. 2023).
Finally, the Clean Energy Petitioners say that withdrawal
fines will not prevent every customer awaiting an affected-
system study from withdrawing. Some affected-system
studies, they say, will reveal upgrade costs so high that
customers will withdraw anyway—even after other customers
in the queue have executed interconnection agreements. That
may be true. But it does not make the rule unreasonable. FERC
never claimed that fines would prevent every late-stage
withdrawal. It expected only that the fines would reduce some
late withdrawals and soften the harm from others. And when
withdrawals do occur, the fines collected can help cover costs
imposed on the customers left behind. See Order 2023 at
PP 798–799. FERC reasoned that better cost certainty “for all
interconnection customers” mattered more than fuller
protection for the few customers still awaiting affected-system-
study results. Order 2023-A at P 502. That tradeoff falls
comfortably within FERC’s expertise. “Such a reasonable
balancing of divergent considerations on a matter within the
Commission’s expertise merits deference.” Xcel Energy
Servs., 41 F.4th at 562.
We therefore hold that FERC’s decision declining to
create a separate fine-free withdrawal option for late-arriving
affected-system studies was not arbitrary and capricious.
35
C
Trying another route, the Clean Energy Petitioners
contend that FERC offered no reasonable explanation for
departing from prior precedent and policy. Their argument
rests mainly on several FERC orders involving the regulation
of individual Regional Transmission Organizations—the
Midcontinent Independent System Operator (“MISO”) and
Southwest Power Pool, Inc. (“Southwest”). Those orders,
these petitioners say, establish that an interconnection customer
must be exempt from fines whenever it “faces significant and
unanticipated cost increases.” Clean Energy Petitioners Br. 32.
But whatever force that argument might have, it comes too late.
The Clean Energy Petitioners did not preserve it, and we
therefore do not reach it.
Our jurisdiction to review a FERC order is “strictly limited
by the specific arguments a petitioner makes in its application
for rehearing.” Citadel FNGE, 77 F.4th at 861 (citation
modified); see also 16 U.S.C. § 825l(b). A petitioner does not
satisfy that requirement by “merely refer[ring] to an argument
generally” or “simply allud[ing] to the argument in a single
statement.” Citadel FNGE, 77 F.4th at 861. Nor may a
petitioner raise an argument “indirectly” or “implicitly” and
expect us to decide it. Ameren Servs. Co. v. FERC, 893 F.3d
786, 793 (D.C. Cir. 2018) (citation modified). And when the
objection is that the order conflicts with precedent, the
petitioner must identify the specific authorities FERC allegedly
disregarded. See City of Port Isabel v. FERC, 111 F.4th 1198,
1217–18 (D.C. Cir. 2024) (holding that a petitioner failed to
raise noncompliance with a specific regulation on rehearing).
The Clean Energy Petitioners failed to clearly raise this
argument in their rehearing request. Their rehearing
application cited no MISO or Southwest orders with which the
36
challenged orders supposedly conflict. Indeed, they did not
argue on rehearing that the exemption thresholds conflicted
with any precedent, much less the particular precedent they
now invoke. See Citadel FNGE, 77 F.4th at 861–62
(explaining that a petitioner must specifically raise an argument
in its rehearing request to exhaust a claim).
To be sure, we may hear an argument not raised in a
petitioner’s application for rehearing if “there is reasonable
ground” for the petitioner’s “failure” to raise the argument.
16 U.S.C. § 825l(b). But we reserve that exception for an
“extraordinary situation, such as when a Commission practice
is admitted or adjudged to be unlawful.” New England Power
Generators Ass’n v. FERC, 879 F.3d 1192, 1199 (D.C. Cir.
2018) (citation modified). We have also reserved that
exception when new evidence first arises after the rehearing
request. See Wabash Valley Power Ass’n v. FERC, 268 F.3d
1105, 1114 (D.C. Cir. 2001) (considering a claim that was not
raised below because it was based on a report issued several
months after the rehearing request).
This case presents no such circumstance. The Clean
Energy Petitioners failed to make this argument in their petition
for rehearing. FERC issued the MISO and Southwest orders
before the Clean Energy Petitioners filed their petition for
rehearing. Because the Clean Energy Petitioners had the
opportunity to raise these claims before FERC but failed to do
so, the “reasonable ground” exception in 16 U.S.C. § 825l(b)
does not apply.
We therefore lack jurisdiction to consider the Clean
Energy Petitioners’ argument concerning the MISO and
Southwest orders. See Consol. Edison Co. of N.Y. v. FERC, 45
F.4th 265, 289 (D.C. Cir. 2022) (per curiam) (“Under 16
U.S.C. § 825l(b), no objection to an order of the Commission
37
shall be considered by the court unless such objection shall
have been urged before the Commission in the application for
rehearing.” (citation modified)); United Power, Inc. v. FERC,
49 F.4th 554, 559 (D.C. Cir. 2022) (“We therefore have no
jurisdiction over an objection the petitioner fails to raise with
specificity.”).
For all these reasons, we deny the Clean Energy
Petitioners’ petition in full.
IV. Interconnection Study Incentive System
Transmission Petitioners take aim at Order 2023’s
incentive system for the timely completion of interconnection
studies. Order 2023 replaced the prior reasonable-efforts
standard for evaluating interconnection-study delays, which
had proven ineffectual, with a new, uniform fee schedule that
enforces firm deadlines by “reduc[ing] what transmission
providers can charge [customers] for interconnection studies
that fail to meet . . . performance standards.” Order 2023-A at
P 358.
Transmission Petitioners raise four challenges to the new
incentive system. First, they contend that the scheme exceeds
FERC’s statutory authority. Second, they argue that the fees
violate the Takings and Due Process Clauses of the Fifth
Amendment. Third, they insist that FERC lacked substantial
evidence to abandon the reasonable-efforts standard and
impose a uniform, industry-wide incentive system. Finally,
they claim that FERC failed to respond adequately to concerns
that the rule would unduly discriminate against certain classes
of transmission providers. None of these challenges succeeds.
38
A
The reasonable-efforts standard for undertaking timely
interconnection studies first emerged in FERC Order 2003.
That order established deadlines for each interconnection-
study phase: 45 calendar days for the Interconnection
Feasibility Study, 60 calendar days for the Interconnection
System Impact Study, and 90–180 calendar days for the
Interconnection Facilities Study. Order 2003 at P 36. FERC
charged transmission providers with exerting “[r]easonable
[e]fforts” to meet those deadlines, and it then defined
“[r]easonable [e]fforts” as “actions that are timely and
consistent with Good Utility Practice and are substantially
equivalent to those a Party would use to protect its own
interests.” Id. at PP 67, 69. Order 2003, however, imposed “no
explicit consequences . . . for transmission providers that
fail[ed] to meet their study deadlines.” Order 2023 at P 872.
In the 2010s, interconnection delays began to accumulate,
causing “longer development timelines[] and increased
uncertainty regarding the cost and timing of interconnecting to
the transmission system.” Order 2023 at P 37 (citation
modified). Those problems inhibited energy developers’
ability to get their power on the transmission system in an
economically timely manner. See NPRM at P 19. Concerned
that a sluggish interconnection process could generate “higher
costs to customers, more uncertainty in the process, and less
competition in the [wholesale] market” for electricity, FERC
began to identify and address the key drivers of delay. Reform
of Generator Interconnection Procedures and Agreements, 163
FERC ¶ 61,043, at P 37. During the rulemaking for Order 845,
an early interconnection reform in 2018, several commenters
urged FERC to implement a firm deadline for interconnection
studies. See id. at P 315. While, at that time, FERC did not
believe that the record supported abandoning the reasonable-
39
efforts standard, FERC instituted study-delay reporting
requirements to “encourage timely processing of
interconnection studies” and to “help inform” whether “any
future action should be considered.” Id. at P 323.
Five years later, FERC reviewed the collected data and
concluded that “[d]elays in the interconnection study process
are an important contributor to interconnection queue backlogs
nationwide.” Order 2023 at P 40. In formulating a
comprehensive remedial plan to tackle these backlogs, FERC
adopted measures that both discourage interconnection
customers from withdrawing from the interconnection queue,
see Section III, supra, and incentivize transmission providers
to reduce their study delays.
Specifically, Order 2023 adjusts the study deadlines to
accommodate the new cluster-study regime. Transmission
providers have 150 days to complete the initial cluster study,
plus 150 days to conduct any necessary restudy. Order 2023-
A at P 317. The Order gives those deadlines bite by imposing
late fees for delayed studies: $1,000 per business day for
delayed cluster studies; $2,000 per business day for delayed
cluster restudies; $2,000 per business day for delayed affected-
system studies; and $2,500 per business day for delayed
facilities studies. Id. at P 454.
FERC explained that the escalating fee structure “reflects
the progressively greater harm to interconnection customers of
delayed studies at those later stages[,]” Order 2023 at P 977, as
well as the reduced burden on transmission providers to
conduct studies at later stages, when the volume of
interconnection requests commonly will be lower, see id. at
P 978. When studies run late, transmission providers must
distribute those late fees “to interconnection customers in the
relevant study on a pro rata per interconnection request basis to
40
offset” what they paid for the study to be done on the prescribed
timeline. Id. at P 963.
Order 2023 also provides a variety of safeguards to ensure
that the scheme will not unduly burden transmission providers.
First, a given transmission provider is not subject to fees until
the third study cycle after FERC approves that provider’s Order
2023 compliance filing. Order 2023 at P 980. Second, Order
2023 gives transmission providers an automatic grace period of
ten business days after each study deadline, id. at P 981, which
can be extended to thirty days upon the approval of all
interconnection customers in the study, id. at P 982. Third,
total fees per study are capped at 100 percent of the initial study
deposit paid by customers. Id. at P 984. “By tying the study
delay penalty cap to the study deposits,” FERC explained, the
Order “ensure[s] that the maximum penalty bears a relationship
to the costs of the study that was late.” Id.
Finally, transmission providers can challenge any fees
they believe were unreasonably incurred before FERC, which
may grant relief if it finds “good cause.” Order 2023 at P 987.
In evaluating whether “good cause” exists, FERC “may
consider, among other factors:”
(1) extenuating circumstances outside the
transmission provider’s control, such as delays in
affected system study results;
(2) efforts of the transmission provider to mitigate
delays; and
(3) the extent to which the transmission provider has
proposed process enhancements either in the
stakeholder process or at the Commission to
prevent future delays.
41
Id. (citation modified). Evidence that an interconnection
customer generated the delay supplies “a potentially
compelling basis” to find good cause. Id. at P 993.
B
The Transmission Petitioners argue that the study-delay
fees are civil penalties under Kokesh v. SEC, 581 U.S. 455
(2017), and that FERC could impose such penalties only under
Federal Power Act Section 316A, 16 U.S.C. § 825o-1. The
Transmission Petitioners also argue that the late fees are a
confiscatory taking and that the framework for imposing them
violates due-process principles.
We disagree. FERC acted under Section 206, which
authorizes it to revise unjust or unreasonable rules, practices,
or rates and to replace them with just and reasonable ones. The
study-delay fees function as part of that ratemaking remedy,
and the framework provides adequate process for transmission
providers to appeal the late fees. Challenges to the procedures
to be provided in a particular appeal are unripe, as is the takings
claim.
1
In Order 2023-A, FERC describes the study-delay fees as
part of its “regulation of the interaction between
[interconnection] parties,” designed “to serve a compensatory
function.” P 308. The interconnection customer prepays
deposits to fund the transmission provider’s study work. When
a study is completed after the required deadline, the customer
receives a refund of part or all of that deposit. Id. at P 358
(explaining that the late fee “reduces what transmission
providers can charge for interconnection studies that fail to
42
meet the performance standards set forth in Order No. 2023”);
id. at P 389 (providing transmission providers an opportunity
for full cost recovery when they meet “relevant standards of
performance” and avoid contributing to interconnection queue
backlogs that “result[] in unjust and unreasonable rates to
customers”). That refund compensates the customer for the
diminished value of a late study. In turn, the transmission
provider must absorb some of the economic consequence of the
delay. Id. at P 358. Framed this way, the mechanism operates
as a performance-based adjustment to the terms under which
the study is provided. See id. FERC has therefore permissibly
determined under its Section 206 authority that transmission
providers’ compensation for conducting a study is justly and
reasonably decreased when that study is delayed.
The study-delay refund is not a civil penalty. It differs in
kind from the sanction addressed in Kokesh. There, the
Supreme Court’s analysis rested on three features: the
monetary remedy was imposed for violations of public law; it
was imposed for punitive purposes; and the proceeds were paid
to the government. Kokesh, 581 U.S. at 463–65. Regardless
of whether this fee is imposed for punitive purposes—an issue
the parties dispute—the other two features are absent here. The
study-delay refunds go only to the customers who provided the
deposits, and the rule identifies no violation of the Federal
Power Act, no breach of a tariff obligation, and no enforcement
consequence. Order 2023 at P 990 (payment to interconnection
customers); Order 2023-A at P 308 (fees not imposed for
public-law violations). The mechanism thus reallocates study
costs between transmission providers and interconnection
customers; it does not impose a fine payable to the
Government. That the refunds may influence providers’
incentives does not convert what is otherwise a compensatory
43
adjustment into a “civil penalty” that FERC can impose only
under Section 316A.
Nor does the framework’s failure to match refund amounts
to individualized delay costs transform the refund into a civil
penalty. On this record, the cost of study delays to the
interconnection customers waiting in the queue likely exceeds
the deposit-based refunds Order 2023 affords. See Order 2023
at P 976 & n.1900 (citing Comments of Pine Gate Renewables,
LLC at 39–40 (Oct. 13, 2022); Comments of Cypress Creek
Renewables, LLC at 24 (Oct. 13, 2022)). In other words, there
is reason to think that fees calculated based on the actual cost
of delay would be even greater than they are. Rather than
accounting for the exact cost of delay, the refund framework
“effectively adjusts what transmission providers can charge”
given the diminished value of a late study. Order 2023-A at
P 289. FERC reasonably chose a uniform, administrable
method that likely undercharges transmission providers and
undercompensates interconnection customers relative to actual
delay-related harms. Indeed, FERC rejected arguments for fee
amounts that more closely approximate actual study-delay
costs and for higher uniform late fees as “overly punitive.”
Order 2023 at P 976.
Because the study-delay refunds compensate
interconnection customers for the reduced value of untimely
studies, direct all payments to the affected parties rather than
the government, and operate within the terms of the tariffed
service, they are not civil penalties. They fall within FERC’s
authority under Section 206 to establish just and reasonable
practices governing the provision of interconnection studies. 7 6F
7
The transmission providers also contend that FERC exceeded
its Section 206 authority because it failed to demonstrate that study-
44
2
Petitioners argue that the study-delay fees are confiscatory
because the rule may require a transmission provider to refund
study deposits even when the provider has already incurred the
costs of completing the study. That argument is premature.
Under the Federal Power Act and the governing constitutional
standard, a limit on a utility’s rates is confiscatory if it is “so
unjust as to destroy the value of the property for all the
purposes for which it was acquired” and thereby “practically
deprives the owner of property without due process of law.”
Duquesne Light Co. v. Barasch, 488 U.S. 299, 307–08 (1989)
(quoting Covington & Lexington Tpk. Rd. Co. v. Sandford, 164
U.S. 578, 597 (1896)). That standard does not require advance
assurance that a utility will recover each expense associated
with providing service, or that any particular cost will be
recoverable in all circumstances. To the contrary, the Supreme
Court has upheld rate orders that disallowed recovery of
substantial costs so long as the overall regulatory scheme
permitted the utility “to maintain its financial integrity.” Fed.
Power Comm’n v. Hope Nat. Gas Co., 320 U.S. 591, 605
(1944); see Jersey Cent. Power & Light Co. v. FERC, 810 F.2d
1168, 1175, 1178 (D.C. Cir. 1987) (en banc).
Petitioners have not shown that Order 2023 produces such
an end result. The penalties they fear have not yet been
imposed, and the rule provides multiple avenues for mitigating
or avoiding uncompensated costs. Order 2023 establishes a
delay fees will “directly affect” electric rates. Transmission
Petitioners Br. 54–56. But FERC’s jurisdiction extends to “both
wholesale rates and the panoply of rules and practices affecting
them.” FERC v. Elec. Power Supply Ass’n, 577 U.S. 260, 277–78
(2016). Because the study-delay fees regulate a critical part of the
interconnection process, they fall squarely within FERC’s
jurisdiction.
45
good-cause process through which a provider may seek waiver
of a late fee by showing that the delay was beyond its control.
See Order 2023-A at P 387 (explaining that providers may
argue on appeal that good cause exists, including on
confiscation grounds). The rule also permits tariff filings that
seek to recover specific late-fee costs or to establish a default
recovery structure. See id. at P 266. Nothing in the record
suggests that these procedures are illusory or incapable of
preventing the speculative confiscation.
A challenge framed in the abstract cannot substitute for the
concrete factual showing the Hope end-result test requires.
Petitioners speculate that providers will incur unrecoverable
costs when a study deadline is missed. But no such penalty has
yet been assessed, and the administrative process for seeking
waiver or recovery has not yet operated in any particular case,
so Petitioners have not shown that the overall effect of Order
2023 will deprive any transmission provider of a just and
reasonable opportunity to recover its costs or to maintain
financial integrity.
The claim is therefore unripe. FERC’s orders do not
require Petitioners to incur penalties before seeking relief. See
Order 2023 at P 987 (appeal filing stays obligation to pay late
fee). They simply require that challenges to the consequences
of a specific late fee await the factual context necessary to
apply the Hope standard.
3
Petitioners further argue that the study-delay mechanism
violates due process because penalties attach automatically
when a deadline is missed and because the relief process is not
defined with sufficient specificity. We disagree. FERC has
provided procedures adequate to the nature of the regulatory
46
scheme, and Petitioners’ concerns about how those procedures
might operate in future cases are premature.
The orders give transmission providers clear notice of the
circumstances that will trigger a refund obligation and set out
a sufficiently defined formula for calculating the amount owed.
After FERC issues a late-fee determination, providers may
seek relief through a good-cause showing, including on the
ground that the delay resulted from factors beyond their
control, and then through judicial review of the agency’s good-
cause determination. See Order 2023 at P 987 (outlining non-
exhaustive factors for consideration under the good-cause
standard); Order 2023-A at PP 359, 362 (providing process for
appeals, rehearing, and petition for judicial review). Order
2023-A further states that providers “will have the opportunity
to argue on appeal that there is good cause to grant relief,” and
specifically acknowledges that fairness considerations—
including constitutional limits—may be raised in that process.
P 387. These procedures provide the core constitutional
protection: an “opportunity to be heard at a meaningful time
and in a meaningful manner.” Mathews v. Eldridge, 424 U.S.
319, 333 (1976) (cleaned up).
Petitioners’ objections to the sufficiency of the good-cause
process are, at this stage, speculative. They identify no
instance in which a provider has been denied relief, no
application of the process that has produced an arbitrary result,
and no example showing that FERC would refuse to consider
circumstances that fairly excuse delay. Their challenge
therefore rests on predictions about how FERC might apply its
process in the future. Those concerns are unripe. Due process
requires fair notice of the conduct that triggers regulatory
consequences; it does not oblige an agency to catalogue in
advance every circumstance in which relief may be granted or
denied. See Sprint Corp. v. FCC, 151 F.4th 347, 367 (D.C. Cir.
47
2025) (rejecting a fair-notice challenge because agencies need
not “give advance warning of a statute’s every possible
application”). Where, as here, the validity of the procedure
turns on its future application rather than any defect in its facial
structure, judicial review can await a concrete dispute. Cf.,
e.g., Tennessee Gas Pipeline Co. v. FERC, 972 F.2d 376, 381
(D.C. Cir. 1992); Nat’l Ass’n of Regul. Util. Comm’rs v. FERC,
964 F.3d 1177, 1185–90 (D.C. Cir. 2020).
Nor does the timing of the good-cause process render it
facially unconstitutional. We discern no due process violation
where the regulatory scheme permits the transmission
providers to opt in to receiving process before any deprivation
is effected. See Order 2023 at P 987 (filing of appeal stays
obligation to pay fee); see, e.g., Statewide Bonding, Inc. v.
Dep’t of Homeland Sec., 980 F.3d 109, 118–19 (D.C. Cir.
2020) (no due process violation where an agency makes a
bond-breach determination but stays collection of the bond
until the end of the appeal process); cf. Myersville Citizens for
a Rural Cmty., Inc. v. FERC, 783 F.3d 1301, 1327 (D.C. Cir.
2015) (“The demands of due process do not require a hearing,
at the initial stage or at any particular point or at more than one
point in an administrative proceeding so long as the requisite
hearing is held before the final order becomes effective.”
(quoting Opp Cotton Mills, Inc. v. Adm’r of Wage & Hour Div.,
312 U.S. 126, 152–53 (1941))). 8 7F
In sum, the rule supplies clear notice of the obligations
imposed, establishes a mechanism for seeking individualized
relief, and preserves review to ensure fairness in particular
8
Transmission Petitioners argue that penalties may be assessed
only “after notice and opportunity for public hearing” under Section
316A(b) of the Federal Power Act. But because that provision
governs only civil penalties, it is inapposite here.
48
cases. Petitioners’ speculation about future applications of that
process does not establish a present due-process violation. The
study-delay framework is consistent with constitutional
requirements.
C
All but one of the Transmission Petitioners challenge
FERC’s imposition of a study-delay incentive system as
arbitrary and capricious. 98F
When, as here, FERC regulates under its Section 206
authority, 16 U.S.C. § 824e, it must make two findings: first,
that the existing practice or rule is unjust, unreasonable, or
unduly discriminatory; and second, that FERC’s replacement
scheme is just, reasonable, and not unduly discriminatory, id.
§ 824e(a); see Emera Maine, 854 F.3d at 24–25. FERC must
support both conclusions with substantial evidence. See Emera
Maine, 854 F.3d at 24–25 (“[S]ection 206 mandates a two-step
procedure that requires FERC to make an explicit finding that
the existing rate is unlawful before setting a new rate.”). To
satisfy that standard, FERC must supply “such relevant
evidence as a reasonable mind might accept as adequate to
support [each] conclusion.” Kentucky Mun. Energy Agency v.
FERC, 45 F.4th 162, 174 (D.C. Cir. 2022) (quoting South
Carolina Pub. Serv. Auth. v. FERC, 762 F.3d 41, 54 (D.C. Cir.
2014) (per curiam)); see also LSP Transmission Holdings II,
LLC v. FERC, 45 F.4th 979, 991 (D.C. Cir. 2022) (holding that
to survive arbitrary and capricious review, an agency must have
“examined the relevant considerations and articulated a
satisfactory explanation for its action, including a rational
connection between the facts found and the choice made”
9
Long Island Power Authority does not join this challenge.
49
(quoting Old Dominion Elec. Coop. v. FERC, 898 F.3d 1254,
1260 (D.C. Cir. 2018))).
Transmission Petitioners attack FERC’s reasoning at each
step. They assert that FERC’s decision to dispose of the
existing reasonable-efforts standard for study delays was
unsupported by substantial evidence. They also insist that
FERC acted arbitrarily and capriciously in replacing the
reasonable-efforts standard with firm deadlines and late fees,
especially when many transmission providers had already
implemented their own reforms.
These arguments fail. FERC reasonably determined a
need both for (1) departing from the reasonable-efforts
standard, and (2) imposing a fee system, with a safety valve for
needed exceptions, to promote timely study completion and
compensate customers for delays.
1
FERC marshaled substantial evidence to support its
finding that the reasonable-efforts regime was unjust and
unreasonable.
First, the data collected under Order 845 revealed
widespread interconnection-study delays. As FERC explained,
most transmission providers that completed studies in 2022
reported ongoing and delayed studies at the end of the year.
See Order 2023 at P 1012, app. B tbls. 2–5. In addition, 68
percent of the 2,179 interconnection studies completed in 2022
were late. See id. at P 1012.
Second, FERC connected these delays to a glaring flaw in
the existing regime: “[T]he reasonable efforts standard does
not provide an adequate incentive for transmission providers to
50
complete interconnection studies on time.” Order 2023 at
P 966; see id. at P 878 & n.1650 (citing more than two dozen
comments supporting the elimination of reasonable efforts and
imposition of late study fees).
FERC’s conclusion is rooted in the multiple comments
pointing out that the reasonable-efforts standard had proven
toothless. Over two decades, commenters explained, FERC
“ha[d] never concluded that a transmission provider has failed
to use Reasonable Efforts, even when the average processing
time for interconnection requests has nearly doubled.” Joint
Comments of the Affected Interconnection Customers to the
Commission’s Notice of Proposed Rulemaking on Generator
Interconnection Agreements and Procedures at 23 (Oct. 13,
2022) (emphasis added); see also Initial Comments of the New
Jersey Board of Public Utilities at 12 (Oct. 13, 2022) (“Despite
the near 1,900 interconnection studies delayed across the
country by the end of 2021, the Commission has never ruled
that a transmission provider has violated [the reasonable-
efforts] standard.”).
Similarly, a group of renewable-energy developers from
across the country explained that “many transmission providers
simply lack the incentive to timely process interconnection
studies, and independent [system operators] seem to have
different goals and interests than their interconnection
customers.” Joint Comments of the Affected Interconnection
Customers to the Commission’s Notice of Proposed
Rulemaking on Generator Interconnection Agreements and
Procedures at 23 (Oct. 13, 2022). The Electric Power Supply
Association, meanwhile, observed that “there have . . . been
vast failures by Transmission Providers to process
interconnection studies and provide necessary information to
prospective and existing interconnection customers in a timely
manner.” Initial Comments of the Electric Power Supply
51
Association at 10 (Oct. 13, 2022); see also J.A. 1248–49 (initial
comments of the American Clean Power Association and
RENEW Northeast) (“At present, there is no specific incentive
for delivering on-time and accurate studies, and late or
inaccurate studies bring few if any consequences.”).
FERC also relied on record evidence documenting an
asymmetry between the stringent demands placed on
interconnection customers and the feeble reasonable-efforts
standard for transmission providers. See Order 2023 at P 881
(“Some commenters point out that the . . . proposal resolves an
imbalance between interconnection customers, which are held
to strict deadlines, and transmission providers, which are
currently not required to meet study deadlines.”). As SEIA put
it, “[u]nder the current interconnection paradigm . . . only
interconnection customers bear the burden of compliance.”
J.A. 1312. While an interconnection customer could “lose[] its
queue position” and thus “much of the investment it made” for
failing to satisfy FERC requirements, transmission providers
did “not face any penalties” for “fail[ing] to meet a tariff
deadline.” Id.; see also Comments and Protest of the
Community Renewable Energy Association and Newsun
Energy LLC on Notice of Proposed Rulemaking at 83–84 (Oct.
13, 2022) (similar). Implementing a balanced set of reforms
that evenhandedly incentivizes timely conduct by both
customers and transmission providers, another commenter
explained, would “help bring certainty to the interconnection
process, turning the vicious cycle of delays, withdrawals, and
further delays into a virtuous one, in which projects have
certainty in timelines and financing, leading to more finalized
projects.” J.A. 1315 (comments of SEIA).
Third, faced with rampant study delays in transmission
systems nationwide, FERC reasonably found unjust and
unreasonable a system that, in practice, imposed no constraints
52
on the very entities responsible for running those studies. See
Order 2023-A at P 300 (“[U]nwarranted flexibility to the
detriment of timely study completion represents a defect in the
reasonable efforts standard in light of the record demonstrating
such backlogs: [I]t allows transmission providers too much
discretion to extend their own study deadlines.”).
Transmission Petitioners insist that FERC overstated the
severity of study delays. They point to a perceived
inconsistency in FERC’s data analysis. Specifically, FERC
excluded data from one system operator, Southwest, because
Southwest was transitioning to a new interconnection process
and so was “not clearly comparable to the other [system
operators].” Order 2023 at app. B tbl. 4 n.5. But, Petitioners
emphasize, FERC initially failed to exclude PJM, which also
was transitioning from a serial study process to a cluster study
process starting at “the end of 2020/beginning of 2021.” J.A.
3310 n.50 (PJM rehearing request); see Order 2023 at app. B
tbl. 4 (Order 2023 table including PJM data). That objection
does not hold up.
To be sure, PJM’s inclusion increased FERC’s first-round
estimate of the number of studies delayed at the end of 2022.
In Order 2023, FERC noted that “an additional 2,544 studies
were delayed (i.e., ongoing and past their deadline)” at the end
of 2022, and acknowledged that the “vast majority of these
studies (2,211) were in PJM[,]” Order 2023 at P 40 & n.116.
But FERC’s analysis ultimately did not depend on PJM’s
2021–2022 data. See Food & Water Watch v. FERC, 104 F.4th
336, 347 (D.C. Cir. 2024). For instance, the asserted error did
not disturb FERC’s findings that most non-system operator
transmission providers (i.e., “non-RTO/ISO” transmission
providers) had pending delayed studies at the end of 2022. See
Order 2023-A at P 292. As for the system operators, FERC
excluded PJM from its data analysis on rehearing and found
53
that its bottom-line conclusion remained the same. See id.
Even excluding both PJM and Southwest, FERC found that
three out of the four remaining system operators (i.e.,
“RTOs/ISOs”) had delayed studies at the end of 2022. Id.
Overall, then, the data continued to support FERC’s finding
that the study-delay problem extended well beyond “isolated
pockets” of the market. Associated Gas Distribs. v. FERC, 824
F.2d 981, 1019 (D.C. Cir. 1987); Order 2023-A at P 292.
Trying a different tack, Transmission Petitioners suggest
that Section 206 requires FERC to find that “a single
transmission provider’s interconnection process was unjust and
unreasonable,” in addition to finding a structural problem
nationwide. Transmission Petitioners Br. 49.
Not at all. “[T]he Commission ha[s] authority under
Section 206” to impose “generic remed[ies] for systemic”
problems. South Carolina, 762 F.3d at 49–50 (citation
modified). When it wields that power, FERC is “not required
to make specific findings that individual rates charged by
individual [market participants] [are] unlawful, or to offer
empirical proof for all the propositions upon which its order
depend[s], before promulgating a generic rule.” Transmission
Access Pol’y Study Grp. v. FERC, 225 F.3d 667, 688 (D.C. Cir.
2000) (per curiam); see also South Carolina, 762 F.3d at 67
(“[T]he Commission may rely on ‘generic’ or ‘general’
findings of a systemic problem to support imposition of an
industry-wide solution.” (alterations in original) (quoting
Interstate Nat. Gas Ass’n of Am. v. FERC, 285 F.3d 18, 37
(D.C. Cir. 2002))). Accordingly, in crafting Order 2023, FERC
appropriately relied on industry-wide trends in study delays in
concluding that the reasonable-efforts standard produces unjust
and unreasonable results.
54
2
Substantial evidence supports FERC’s second finding that
its new system of firm study deadlines backed by fines was just
and reasonable.
FERC found that putting the onus on transmission
providers to ensure the timeliness of their studies makes sense
because transmission providers “have the most complete
knowledge as to what actions to better ensure study timeliness
will be most effective as to their specific processes.” Order
2023-A at P 301. “As the entity that conducts the study,”
FERC explained, transmission providers “have control over
(among other things): the resources allocated to the study
process; the actual conduct of the study, e.g., the use of
advanced computing or other methods to improve efficiency;
coordination with interconnection customers and consultants;
and providing the conclusions of the study.” Id. at P 284.
Based on those findings, FERC reasonably adopted
financial incentives for timely compliance that would induce
transmission providers to act on the information they possess
and control, while refunding interconnection customers for
studies for which they had paid but did not receive on time. In
doing so, FERC avoided prescribing a top-down, wooden
approach to ensuring timeliness in favor of a system that left
individual transmission providers with “flexibility . . . as to
how they achieve those standards, along with appropriate
safeguards.” Order 2023-A at P 301.
At the same time, FERC acknowledged several ways in
which transmission providers might streamline studies, ranging
from “exploring administrative efficiencies and innovative
study approaches,” Order 2023 at P 967, to “hiring additional
personnel or investing in new software[,]” id. at P 975; see also
55
Order 2023-A at P 284 (“[T]ransmission providers have
significant authority to help ensure that other entities do not
unduly delay the results of the interconnection study, including
by deeming withdrawn the requests of interconnection
customers that fail to adhere to [FERC rules].”).
Commenters, too, pointed to potential levers, including
improved computing processes and “providing better
information to reduce the complexity of individual requests.”
Reply Comments of Public Interest Organizations at 4 (Dec.
15, 2022); see also id. at 3–4 (“[T]here are a number of process
and policy improvements available to transmission providers
who are regularly falling behind in their interconnection
studies, which are not yet implemented . . . . [A]ny claim that
an individual provider has done absolutely everything in its
power to improve the processing rate of interconnection
requests at this point almost certainly comes from a lack of
imagination.”); Comments of the Northwest & Intermountain
Power Producers Coalition at 14 (Sept. 14, 2022) (“Many
[Northwest and Intermountain Power Producers Coalition]
members believe that at least some of the problem is a result of
transmission providers failing . . . to dedicate sufficient
resources to complete studies on time. Eliminating the
reasonable efforts standard and imposing penalties for delays
will encourage transmission providers to complete their studies
on time.”); Comments of the Interwest Energy Alliance at 8
(Oct. 13, 2022) (“[I]mposing penalties for delays will
encourage this investment [in study resources] . . . and
potentially lead to more training for the expertise needed
among a shrinking pool of engineering experts.”).
FERC’s analysis was reasonable on the record before it.
“The idea that firms respond to financial incentives is . . .
hardly revolutionary . . . .” Connecticut Dep’t of Pub. Util.
Control v. FERC, 593 F.3d 30, 35 (D.C. Cir. 2010). The study-
56
delay incentive system operates on the core economic theory
that firms make decisions after rationally weighing costs and
benefits—and the intuitive corollary that late fees increase
transmission providers’ incentive to meet study deadlines. See,
e.g., Order 2023 at P 966 (“[W]e find that the elimination of
the reasonable efforts standard and the adoption of penalties for
late studies are needed to create an incentive for transmission
providers.”); id. at P 977 (“We find it appropriate that
transmission providers face study-delay penalties structured in
a similar manner to provide adequate incentives to complete
interconnection studies on time.”); Order 2023-A at P 289
(“This incentive will help ensure that transmission providers
exercise the control they have over the interconnection process
as to the timely conduct of those studies . . . .”); see also Xcel
Energy Servs. Inc., 41 F.4th at 561 (holding that an agency can
rely on “‘basic economic theory,’ including relying on ‘generic
factual predictions[,]’ as long as the agency ‘explain[s] and
applie[s] the relevant economic principles in a reasonable
manner’” (alteration in original) (quoting Sacramento Mun.
Util. Dist. v. FERC, 616 F.3d 520, 531 (D.C. Cir. 2010) (per
curiam))).
Transmission Petitioners throw out a variety of attacks on
the sufficiency of FERC’s analysis. The spaghetti does not
stick.
First, Transmission Petitioners fault FERC for failing to
prove that “transmission providers are at least partially
responsible for study delays.” Transmission Petitioners Br. 44.
To be sure, FERC acknowledged that forces outside
transmission providers’ control might contribute to study
delays. See Order 2023 at P 43 (“[T]ransmission providers
may face uncertainty regarding the size and makeup of the
interconnection queue and the commercial viability of the
project in the interconnection queue, creating inefficiencies in
57
the study process, increasing interconnection study costs, and
delayed study results.”).
That is precisely why Order 2023 contains multiple
reforms aimed at preventing other market participants, like
interconnection customers, from dragging out the
interconnection process. See Order 2023-A at P 287 (“Order
No. 2023 recognized that study delays are caused by a number
of factors, and adopted a comprehensive package of reforms
aimed at alleviating many of those factors from various
angles.”). Beyond that, it defies credulity to suggest that the
transmission providers—the entities that “control and are
responsible for the conduct of [interconnection] studies,” id. at
P 372—do not bear even partial responsibility for delays in
their own studies. In implementing the study-delay incentive
system, then, FERC reasonably shifted the burden to the party
with the most information about and control over the study
process. At the same time, FERC provided transmission
providers with an avenue for relief on a case-by-case basis if
delay is caused by circumstances beyond their control. See id.
at P 289.
Second, Transmission Petitioners contend that FERC did
not adequately respond to arguments that the incentive scheme
would generate perverse incentives for (1) transmission
providers to cut corners to meet study deadlines, and
(2) interconnection customers to prolong delays to receive a
payout.
FERC reasonably explained why neither concern
undercuts its determination that Order 2023 was just and
reasonable.
With respect to the incentives for transmission providers,
FERC disagreed that the new incentive system would reduce
58
study “accuracy” and “system reliability.” Order 2023 at
P 1007. The agency again pointed to various reasonable
administrative measures transmission providers could take to
avoid late fees, “such as hiring additional staff[] to efficiently
process interconnection queues without sacrificing accuracy,
flexibility, or reliability.” Id. And to the extent such measures
ultimately drive up the costs of studies, FERC explained, those
“costs will be passed on to interconnection customers,” who
“ultimately bear the costs of . . . studies.” Id. In addition,
Order 2023 provides “safeguards . . . that allow transmission
providers avenues of relief from the strict application of study
deadlines[,]” including an appeals process for transmission
providers that find themselves against a wall through no fault
of their own. Order 2023-A at P 375; see Order 2023 at P 979–
87 (describing safeguards including delayed implementation,
grace periods, a cap on fees at 100 percent of the initial study
deposits, and an appeals process). Transmission Petitioners
apparently agree that accuracy will not suffer because they
strenuously disavow any intent to “consciously sacrifice
reliability to avoid penalties.” Transmission Petitioners Br. 57.
FERC also assuaged transmission providers’ concerns
about interconnection customers’ incentives, explaining that
“the economic harms to the interconnection customer of
delayed study completion significantly outweigh any incentive
to delay the interconnection process.” Order 2023-A at P 373.
Further, any incentive to delay the process would be low-
powered because any delay fees would be divided among “all
the interconnection customers included in the relevant study
that did not withdraw.” Id.
Third, Transmission Petitioners insist that nationwide
rulemaking was unwarranted because the majority of
transmission providers had already shifted to a cluster-study
approach. But cluster studies are just one of the many
59
interlocking tools that Order 2023 adopts to streamline the
interconnection process. Incentivizing timely studies is
another. Imposing a tiered fee schedule for queue withdrawals
is one more still. So some transmission providers’ adoption of
piecemeal reforms does nothing to undermine FERC’s decision
to adopt a uniform and comprehensive scheme, the challenged
elements of which no transmission provider had previously
implemented. See Order 2023-A at P 380 (“The Commission
has found that adoption of a cluster study approach is such a
just and reasonable reform, but that additional reforms are also
necessary.”); see also South Carolina, 762 F.3d at 67
(upholding Section 206 rulemaking even when “some current
practices in some regions may have already been satisfying a
minimum set of requirements that must be met under the Final
Rule” (citation modified)). Nor does the industry-wide shift to
cluster studies alter FERC’s factual basis for imposing its
package of reforms since FERC found that even transmission
providers that use cluster studies “still often fail to meet
interconnection study deadlines.” NPRM at P 166. 10 9F
10
On the flip side, it is of no moment that FERC had recently
approved transmission rate schemes that did not include any study-
delay fees. Contra Transmission Petitioners Br. 51–52. When
FERC considers individual rate filings under Section 205, it must act
in “an essentially passive and reactive role[;] [it] may accept or reject
the proposal, but it may not suggest modifications that result in an
entirely different rate design than the utility’s original proposal or the
utility’s prior rate scheme.” Hecate Energy LLC v. FERC, 126 F.4th
660, 662 (D.C. Cir. 2025) (citation modified). As a result, FERC
lacked authority in those Section 205 proceedings to impose sua
sponte a novel incentive scheme. Instead, FERC formulated Order
2023 through a thoroughgoing Section 206 rulemaking, where it
could weigh the industry-wide implications of a shift away from the
prior reasonable-efforts standard, and elicit comments from a range
of industry participants on how to combat interconnection-study
delays most effectively.
60
Fourth, a subset of Transmission Petitioners complains
that Order 2023 unreasonably upends PJM’s recently adopted
reforms. 11 FERC explained, however, that PJM’s reforms
10F
were still in their “early stages,” so the “record d[id] not contain
any information regarding the effects of such reforms,
including whether PJM [was] meeting all study deadlines on
time.” Order 2023-A at P 40. Instead of creating a carveout,
FERC provided system operators like PJM the opportunity to
preserve just and reasonable reforms through “independent
entity variations.” Id. at P 453 n.884. To that point, FERC has
since allowed PJM to preserve the three-stage structure of its
cluster process. Order on Compliance, 192 FERC ¶ 61,077, at
P 66 (2025).
Fifth, a different group of Transmission Petitioners
contend that FERC was arbitrary and capricious in imposing
on system operators a uniform 150-day deadline for cluster
studies. 12 That argument has no purchase. FERC clarified that
1F
Order 2023 does “not preempt transmission providers from
proposing tariff-defined study deadlines that may differ from
the . . . 150-day schedule.” Order 2023-A at P 156. FERC has
practiced what it promised. When FERC approved PJM’s
three-stage cluster studies, it also sanctioned an individualized
study timeline: 120 days for phase I, 180 days for phase II, and
180 days for phase III. Order on Compliance, 192 FERC
¶ 61,077, at PP 67–68 (finding that “PJM’s cluster study
timeline is just and reasonable and not unduly discriminatory
11
The MISO Transmission Owners and PacifiCorp do not join
this portion of the brief.
12
Avangrid, Inc., New York State Electric & Gas Corp.,
Rochester Gas and Electric Corp., Long Island Power Authority, the
MISO Transmission Owners, and PacifiCorp do not join this
challenge.
61
or preferential and accomplishes the purposes” of Order 2023);
id. at P 211 n.415.
Of course, Order 2023 will not satisfy all transmission
providers (or interconnection customers) all the time. But
FERC has “considerable latitude in drawing th[ese] types of
lines.” LSP Transmission Holdings II, 45 F.4th at 993. Here,
FERC reasonably concluded, using “the most recent data set
available” when it issued Order 2023 in July 2023, that
transmission providers were generally able to “complete
system impact studies in an average of fewer than 150 days[,]”
even “for clusters containing significant numbers of
interconnection requests.” Order 2023-A at P 322. While it
acknowledged that some studies exceeded 150 days, FERC
explained that the timeline for those studies had been examined
under the lax reasonable-efforts regime, and that Order 2023
would incentivize providers to streamline their studies. See id.
Sixth, that same group of Transmission Petitioners accuses
FERC of “present[ing] a false dichotomy between subjecting
System Operators to, or ‘categorically exempt[ing]’ them from,
the strict liability penalty scheme.” Transmission Petitioners
Br. 74 (quoting Order 2023-A at P 400). But Transmission
Petitioners point to no comments or rehearing requests
proposing an alternative systemic reform. What few proposals
Transmission Petitioners did proffer were throwaways that
would perpetuate the very interconnection-delay problems
FERC sought to combat. See J.A. 3018 (New York
Independent System Operator (“NYISO”) rehearing request
suggesting allowing individual System Operators “to propose”
their own “alternative rules as independent entity variations,”
while sending FERC back to the drawing board to “updat[e]
and enhanc[e] its reporting requirements”); id. at 3084 (MISO
rehearing request insisting that, in its multi-phase study
process, “[i]t is the ultimate result that matters and there should
62
be no penalties for any delays of preliminary or revised studies
if the final study is delivered within a reasonable combined
timeline”).
Anyhow, even if these Transmission Petitioners had
proposed an alternative approach that would also address the
problem of late interconnection studies contributing to queue
backlogs and, ultimately, unjust and unreasonable rates, that
would say nothing about whether Order 2023’s chosen
deadline and penalty structure is itself just and reasonable. See
Entergy Arkansas, LLC v. FERC, 109 F.4th 583, 594 (D.C. Cir.
2024) (“FERC is not required to choose the best solution, only
a reasonable one.” (quoting Petal Gas Storage, LLC v. FERC,
596 F.3d 695, 703 (D.C. Cir. 2007))).
Nor did FERC ignore the variations among system
operators. While FERC set a new default in Order 2023, it has
allowed system operators to seek variations during the
compliance process upon an appropriate showing that Order
2023’s baseline will still be met. Order 2023-A at P 453 (“On
compliance, transmission providers can propose deviations
from the [Order 2023] requirements . . . and demonstrate how
those deviations meet the relevant standard.”); see also Order
on Compliance, 191 FERC ¶ 61,229, at P 181 (2025) (denying
MISO’s requested variation for late fees to trigger only at the
end of its three-phase study process).
*****
In sum, FERC calibrated its study-delay incentives to spur
transmission providers to act in a timely manner and to
compensate interconnection customers for the decreased value
of delayed studies, while not imposing excessive fees. It heard
from all interested parties and responded to their objections.
FERC confronted the “trade-off[s] inherent” in the study-delay
63
scheme and “determined that ‘the trade-off[s] w[ere] worth
it.’” Affirmed Energy, LLC v. FERC, 166 F.4th 1070, 1086
(D.C. Cir. 2026) (quoting Competitive Enter. Inst. v. Nat’l
Highway Traffic Safety Admin., 956 F.2d 321, 324 (D.C. Cir.
1992)). For all of those reasons, Transmission Petitioners’
arbitrary and capricious challenges fail.
D
Transmission Petitioners next argue that FERC failed to
adequately respond to comments raising concerns that the
study-delay incentive scheme would be unduly discriminatory
within the meaning of 16 U.S.C. § 824e(a). They are incorrect.
Under the Federal Power Act, a rate or practice is unduly
discriminatory when it treats “similarly situated” entities
differently “for no good reason.” Tenaska Clear Creek Wind,
LLC v. FERC, 108 F.4th 858, 868 (D.C. Cir. 2024) (quoting
Consol. Edison Co. of N.Y., Inc., 45 F.4th at 282). In contrast,
“[n]o undue discrimination exists where there is a ‘rational
basis for treating [two entities] differently’ and such
differential treatment is ‘based on relevant, significant facts
which are explained.’” BP Energy Co. v. FERC, 828 F.3d 959,
967 (D.C. Cir. 2016) (second alteration in original) (quoting
“Complex” Consol. Edison Co. of N.Y. v. FERC, 165 F.3d 992,
1012–13 (D.C. Cir. 1999) (per curiam)).
Transmission Petitioners lay out two theories of undue
discrimination. First, they argue that transmission providers in
regions with substantial renewable development will be more
likely to face study-delay fees due to higher volumes of
interconnection requests. Second, they argue that system
operators’ inability to pass costs on to shareholders unfairly
increases their costs of complying with Order 2023 compared
to traditional transmission providers. FERC adequately
64
considered and reasonably responded to both of those
concerns. 1312F
1
Transmission Petitioners worry that regions with large
numbers of renewable interconnection requests will be more
likely to face study-delay fees. See J.A. 3235 (PJM Rehearing
Request) (“Zones and regions with long queues will experience
a greater risk of incurring penalties than those that do not due
to factors that transmission owners cannot control.”). 14 13F
FERC acknowledged that concern and then explained why
it was premature:
[G]iven the structure of Order No. 2023—under
which we have imposed deadlines that should be
reasonably achievable, replaced the serial study
process with cluster studies, and afforded several
safeguards, including the appeals process—it is not
necessarily the case that some transmission providers
will be more likely to have to pay penalties than others
13
To the extent Transmission Petitioners claim that Order 2023
itself unreasonably causes undue discrimination, that claim is not yet
ripe for judicial resolution. The Order on its face does not exhibit
undue discrimination, and because the incentive scheme has not yet
taken effect, “no . . . discrimination ha[s] as yet been documented.”
Tennessee Gas Pipeline Co. v. FERC, 972 F.2d 376, 381 (D.C. Cir.
1992). Plus, FERC has “promised to address case-by-case such
complaints of discrimination as [parties] might later raise.” Id. So
the only question before us is whether the rulemaking record
discloses a procedural deficiency by FERC in addressing the asserted
risks of discrimination identified by the Transmission Petitioners.
14
Long Island Power Authority does not join this challenge.
65
based on the uneven distribution of interconnection
requests.
Order 2023-A at P 384 (citation modified).
FERC also provided several avenues for any over-
burdened parties to obtain relief, including the appeals process
and individual Section 205 filings. See Order 2023-A at P 384
(“[T]ransmission providers may propose variations from the
requirements of Order No. 2023, under the applicable standard,
which provides a further vehicle to ensure that the late study
deadline and penalty structure does not unduly burden certain
transmission providers as compared to others.”); id. at P 384
n.715 (“That the Commission can consider the individualized
factors in a particular case to determine whether to grant relief
from penalties is another avenue to ensure that undue
discrimination does not occur.”); id. at P 324 (“[T]o the extent
that transmission providers assert that factors allegedly outside
of their control may render it difficult or infeasible to meet the
interconnection study deadlines, this appeals process is the
avenue to raise those considerations in particular cases and
seek relief.”).
Our precedent confirms the point. In Transmission Access
Policy Study Group v. FERC, 225 F.3d 667 (D.C. Cir. 2000)
(per curiam), a variety of market participants leveled
challenges to FERC Order 888, which required transmission
providers to allow open and equal access to their services, id.
at 682–83. Before FERC promulgated the rule, vertically
integrated transmission owners in Georgia had invested heavily
in forming a transmission system and establishing reciprocal
open access. See id. at 689. One of those vertically integrated
entities, which operated both as a transmission provider and as
a customer utility, claimed that the rule unduly discriminated
against old customers of integrated transmission systems
66
because it gave new customers access to the system without
requiring any investment in the transmission system. See id.
This court rejected that argument. We explained that
FERC “recognized that its generic findings may have
exceptions, and thus that Order 888 may in individual
circumstances have a different result than that intended.”
Transmission Access, 225 F.3d at 689. But, as with Order
2023, market participants could “argue their particular
circumstances” and seek relief from FERC on a case-by-case
basis. Id. Order 888 “merely shift[ed] from a regulatory norm
in which a user of transmission services must demonstrate to
FERC an individualized need for open access to one in which
a provider of transmission services must present to FERC
individualized circumstances requiring relief from open
access.” Id.
So too here. Order 2023 simply shifts the default rule from
individual customers having to try to obtain relief from
transmission providers’ study delays to a background norm of
timeliness from which individual transmission providers can
seek individualized relief.
Transmission Petitioners try to distinguish Transmission
Access on the ground that FERC there relied on “extensive
commentary as well as its own experiences” to “conclude[]
that, as a general matter, transmission industry conditions were
conducive to discriminatory practices and anti-competitive
behavior, such that case-by-case adjudication could not
adequately address the problem,” and a nationwide rule was
needed. Transmission Petitioners Reply Br. 29 (second and
third alterations in original) (quoting Transmission Access, 225
F.3d at 688–89). So too here. In crafting Order 2023, FERC
came forth with substantial evidence showing that study delays
67
were a serious, recurring, and nationwide problem. See Section
IV.C, supra.
2
Lastly, some Transmission Petitioners argue that Order
2023 failed to address system operators’ restricted funding
opportunities. Unlike other transmission providers, system
operators are generally not-for-profit entities that cannot pass
the cost of late fees through to their shareholders. 1514F
FERC squarely addressed that concern. To start, FERC
provided a special exemption in Order 2023 to accommodate
system operators’ different funding structure. While Order
2023 generally prohibits transmission providers from
recovering study-delay fees through increased rates, see Order
2023 at P 992, the rule permits system operators to submit a
“[S]ection 205 filing to propose a default structure for
recovering study delay penalties and/or make individual
[Section] 205 filings to recover the costs of any specific study
delay penalties,” id. at P 994. 16
15F
FERC also pointed the system operators to several
additional safety valves. In particular, FERC found that system
operators could fund study-delay fees using administrative fees
collected from market participants. Order 2023 at P 998. In
15
Avangrid, Inc., New York State Electric & Gas Corp.,
Rochester Gas and Electric Corp., Long Island Power Authority, the
MISO Transmission Owners, and PacifiCorp do not join this
challenge.
16
FERC also explained that system operators like NYISO that
might require majority stakeholder approval for such filings could
alternatively file a complaint under Section 206 to unilaterally alter
their tariffs. See Order 2023-A at P 464.
68
addition, FERC noted that Order 2023 assigns study-delay fees
to the party that conducts the study. See id. at P 995. That is,
when a transmission-owning member of a system operator
performs a study, that member—not the system operator—is
responsible for paying any study-delay fees. See id. This
assignment rule, FERC explained, “aligns the incentive created
by the study delay penalty with the entity most in control of the
study timeline.” Id.
Finally, FERC concluded that any lingering disparate
impact would not be undue given the costs to the nationwide
energy system from delays in bringing new generation online.
“[A]ny residual uncertainty as to [a system operator’s] ability
to recover penalty costs,” FERC found, “is outweighed by the
critical need for all transmission providers, including [system
operators], to process interconnection studies in a timely
manner.” Order 2023-A at P 401.
In short, FERC directly addressed those transmission
providers’ concerns and provided a reasoned explanation for
its decision accompanied by tailored accommodations. Having
done so, FERC’s decision to incentivize uniformly all
transmission providers, including system operators, to meet
study deadlines is “the type of policy judgment to which we
afford deference, and that deference is justified by the record”
in this case. Advanced Energy Mgmt. All. v. FERC, 860 F.3d
656, 670 (D.C. Cir. 2017) (per curiam); see also id. (“The law
provides no basis to claim the Commission cannot approve
uniform performance requirements simply because those
requirements will be easier to satisfy for some generators than
for others.”).
69
*****
FERC reasonably explained that the potential
discriminatory impact of Order 2023 has not been
demonstrated on this record, and that the Order provides
avenues for individualized relief as needed. Should FERC fail
in the future to adequately address a pattern of discriminatory
impact, affected parties can seek relief from FERC and, if
necessary, the court.
V. Energy-Service Modeling
Certain Transmission Petitioners also challenge as
arbitrary and capricious Order 2023’s requirement that all
affected-system studies be conducted using the Energy
Resource Interconnection Service modeling standard. That
argument fails. 17
16F
By way of background, interconnection customers are new
energy-generating facilities, such as solar farms, wind turbines,
or natural gas plants. See Tenaska Clear Creek Wind, 108 F.4th
at 863. These energy generators seek to connect to a
transmission provider, which is an entity that both operates
transmission equipment like power lines and manages regional
energy movement on the grid. See Green Dev., LLC v. FERC,
77 F.4th 997, 1001 (D.C. Cir. 2023). New energy generators
must connect to a transmission provider to move their newly
generated energy onto the larger energy grid and, eventually,
to consumers of their energy. Id.
17
Avangrid, Inc., New York State Electric & Gas Corp.,
Rochester Gas and Electric Corp., Midcontinent Independent System
Operator Transmission Owners, the Midcontinent Independent
System Operator, Inc., and PacifiCorp do not join this challenge.
70
When a prospective customer seeks to connect to a
transmission provider, the transmission provider initiates a
study of the new generator’s impact on its transmission system
to determine whether any system updates are required to add
the new energy generation. Before that study goes forward, a
customer must select one of two types of service for the
delivery of its power.
The first option, Network Resource Interconnection
Service, also known as “firm service,” provides a high level of
connectivity that permits customers to “demand power or
transmission at any time.” Tenaska Clear Creek Wind, 108
F.4th at 864 (quoting Fort Pierce Utils. Auth. v. FERC, 730
F.2d 778, 785–86 (D.C. Cir. 1984)); Order 2023 at P 1277 &
n.2413. When an interconnection customer selects firm
service, it is given priority access to transmit its power over the
grid even when the transmission provider is overloaded and has
to curtail or cut off service to some energy-generation sources.
See Advanced Energy United, Inc. v. FERC, 82 F.4th 1095,
1104 (D.C. Cir. 2023). Put another way, firm service ensures
that the energy output of the interconnection customer “will not
be ‘bottled up’ during peak load conditions” on the host
transmission system, allowing that customer to keep supplying
energy to the grid and thus to profit from sales to consumers.
NPRM at P 209 n.290 (quoting Order 2003-A, 106 FERC
¶ 61,220, at P 531 (2004)).
The second option, known as Energy Resource
Interconnection Service (“energy service”), is a lower-level
service that means that the transmission provider can “shut off
[service] at any point” if its capacity to provide service falls
below what is needed “to guarantee the needs of the
[transmission service’s] firm [service] customers.” Tenaska
Clear Creek Wind, 108 F.4th at 864 (quoting Fort Pierce, 730
F.2d at 786). Because energy service is less flexible and those
71
customers are the first to have the energy they are putting into
the grid curtailed, energy service “is typically offered at a
significant discount” compared to firm service. Id. (quoting
Fort Pierce, 730 F.2d at 786).
Once the customer designates the level of service desired,
the host transmission system uses that type of service to model
the impacts on its system if the customer were to connect and
demand that level of transmission capacity full-time.
Another issue that arises with new customer
interconnection is that the provision of service to a new
customer may occasionally impact a neighboring “affected
system.” NPRM at PP 213–14; Order 2023 at P 1284. That is
because a host system may share transmission lines with a
nearby system to increase overall efficiency. But at certain
times, such as peak energy production, higher inputs of energy
from generators on the host system could cause the excess
energy to spill over into the affected system. See NPRM at
PP 213–14; Order 2023-A at P 511. That is, energy pumped
into one transmission system could end up adding to the energy
level on an affected system. See Indiana Michigan Power Co.
and Ohio Power Co., 64 FERC ¶ 61,184, at 2 (1993) (“[I]n
reality power flows are rarely confined to a designated contract
path. Rather, power flows over multiple parallel paths that may
be owned by several utilities that are not on the contract path.”).
If that affected system were already overloaded with excess
energy, the injection of energy from the host system could
cause the affected system to have to curtail its transmission
service for its regular customers that contracted for firm
service. See NPRM at PP 213–14.
Because of the potential for such repercussive effects
when new generation is added to a transmission system,
interconnection studies often include an analysis of the impact
72
that the new interconnection could have on an affected system.
See NPRM at PP 174–75, 214–15. Interconnection customers
are then required to pay for any system upgrades for affected
systems that the host’s provision of service could occasion. Id.
at PP 191–92, 210.
The prior FERC order, Order 2003, required host systems
to coordinate any needed affected-systems studies with their
neighboring systems. See Order 2003 at P 121; NPRM at
P 175. But FERC did not regulate how the affected system
would conduct those studies. FERC instead left it to the
affected system to choose whether to run its studies using firm-
or energy-service modeling. See Order 2003, at P 121; NPRM
at P 175.
Due to the lack of oversight for the affected-systems study
process, significant problems arose, including a lack of
transparency in how the studies were conducted and
unpredictability as to how expensive the identified upgrades
would be. See Order 2023 at PP 1278–80. For example, a
prospective customer could be charged for first-class upgrades
needed to support firm service on the affected system even if
the customer would never receive firm service from the
affected system. Id. at P 1278. That is because, although a
customer’s host system is contractually obliged to enable firm
service if its customer has paid for it, an affected system owes
no such duty to its neighbor’s customer. Id. So if there is an
overload of energy on the affected system, it has no obligation
to prioritize the energy generation of its neighboring system’s
customer even if that customer paid for upgrades needed to
provide firm service, and the customer may well lose out to the
affected system’s own energy generators that are benefiting
from those paid-for upgrades. Id. at P 1279–80.
73
Order 2023 changed that. Instead of allowing the affected
system to select whether it wanted to study the customer’s
impact on its system using firm or energy service, the affected
system is now required to use an energy-service model at the
interconnection-study stage. Order 2023 at P 1276.
Transmission Petitioners challenge this requirement,
arguing that it (i) is not supported by substantial evidence,
(ii) fails to address the problems identified by commenters, and
(iii) departs from prior precedent without adequate
explanation.
Because substantial evidence and reasoned analysis by
FERC support the newly required energy-service baseline for
interconnection studies on affected systems, this challenge
fails.
A
FERC’s adoption of energy-service modeling is grounded
in substantial evidence demonstrating both the problems with
the prior system and the benefits of adopting energy-service
modeling as the default for interconnection studies of affected
systems. As FERC noted, sixteen commenters urged it to adopt
such a rule based on their own difficult experiences with the
prior regime. Order 2023 at P 1263 & nn.2373, 2377. FERC
also accorded weight to a case study of the energy-service
modeling approach that was used successfully by a Regional
Transmission Organization for the midcontinental region of the
United States for “many years.” NPRM at P 213; see Order
2023 at P 1285 (citing J.A. 922); see also EDF Renewable
Energy, Inc. v. MISO, 168 FERC ¶ 61,173, at PP 71–72, 80–81
(discussing the organization’s practice of using energy-service
modeling for affected-system studies).
74
Substantial evidence is “such relevant evidence as a
reasonable mind might accept as adequate to support a
conclusion, and requires less than a preponderance of
evidence.” Kentucky Mun. Energy Agency, 45 F.4th at 174
(formatting modified). In crafting a nationwide rule, FERC
“may rely on generic or general findings of a systemic problem
to support imposition of an industry-wide solution.” South
Carolina, 762 F.3d at 67 (citation modified); see Transmission
Access, 225 F.3d at 710–11 (same).
In adopting Order 2023, FERC credited over a dozen
comments that explained the benefits of adopting energy-
service modeling as a uniform standard for affected-system
studies and illustrated the adverse effects of the prior regime.
See, e.g., Order 2023 at P 1263 nn.2373–78. For example,
Shell Energy North America (US), L.P., and its related entities
urged FERC to “require the lowest cost solution with
‘guardrails’ to ensure that transmission is not being overbuilt.”
J.A. 1065. Shell also explained that “if the study is
implemented reasonably, a traditional [energy-service]
analysis will identify power flow, short-circuit, and stability
impacts on the affected system.” Id. at 1066.
NextEra Energy, Inc., echoed Shell’s concerns about firm-
service modeling leading to affected systems overbuilding their
transmission systems on the financial backs of their neighbor’s
customers. NextEra explained that its “subsidiaries have
experience with excessive network upgrades being identified
in affected system studies based on [firm-service] analysis.”
J.A. 817. NextEra complained that “[t]here is no rational
basis” for permitting affected systems to use firm-service
modeling “because the [new] project’s output is not supposed
to be delivered to the affected system,” but rather to the host
transmission provider. Id. In NextEra’s view, only in rare
75
cases would a customer’s energy input have an impact on an
affected system. See id.
Enel North America, Inc., also supported the energy-
service modeling rule because, “based on its experience in
interconnection queues, many Transmission Owners push for
more stringent study criteria and minimum impact thresholds
which will result in more network upgrades being assigned to
Interconnection Customers.” J.A. 751.
Fervo Energy Company added that the lack of
“consistency in the use of modeling standards” leads to
affected systems’ “identification of a wider range of required
network upgrades,” and so “require[s] interconnection
customers to incur additional unjust and unreasonable costs
that are not related to the provision of transmission service for
the interconnection customer.” Initial Comments of Fervo
Energy Company on Commission Notice of Proposed
Rulemaking at 6 (Oct. 13, 2022); see also J.A. 1007 (Pine Gate
Renewables, LLC comment that “[e]nforcing [energy-service]
modeling standards—rather than [firm-service] modeling
standards—better aligns the modeling and network upgrade
identification with the intended operation of the resources.”);
Initial Comments of Utah Municipal Power Agency at 6 (Oct.
13, 2022) (similar).
Pattern Energy Group LP offered yet another perspective,
explaining that “interconnection studies are based on
‘snapshots’ of system conditions” including “peak load[s]” and
“very low load[s]” of energy that “only exist a few times per
year.” Initial Comments of Pattern Energy Group LP at 26
(Oct. 12, 2022). Pattern asserted that an energy-service
modeling requirement more closely approximates what the
average load on an affected system is throughout the year than
firm-service modeling, which focuses on “snapshot, simulated
76
conditions [that] are not the norm.” Id. That is, using a less
strict modeling standard would balance out the fact that these
studies generally overestimate possible impacts on affected
systems by focusing on peak energy production days.
The SEIA added that the high cost of affected-system
upgrades due to the use of firm-service modeling leads to the
“cascading withdrawals” of interconnection customers,
causing interconnection queue delays for more than just the
impacted customer. Initial Comments of The Solar Energy
Industries Association at 11 (Oct. 13, 2022).
Buttressing these comments was a study of MISO’s use of
energy-service modeling across the fifteen states it serves. See
J.A. 815; Order 2023 at P 1285 (citing MISO’s comments at
J.A. 922); Order 2023-A at P 510. FERC noted that MISO had
successfully employed energy-service modeling for “many
years” for its affected-system studies “without adverse
reliability impacts.” NPRM at P 213; Order 2023 at P 1285;
Order 2023-A at P 510. MISO also explained that its use of the
energy-service approach had proved “adequate to cover the
reliability needs of the MISO system.” J.A. 922. MISO’s past
experience, FERC noted, indicates that mandating an energy-
service modeling standard across the board “will not cause
unnecessary curtailment or redispatch on affected systems.”
Order 2023-A at P 510. That finding was critical because the
justification for having interconnection customers foot the bill
for expensive, firm-service upgrades to affected systems had
been the assumption that the new customers would cause
energy overloads on an affected system that would force that
system to curtail movement of the energy of its own customers.
See J.A. 1345–46; see also EDF Renewable Energy, 168 FERC
¶ 61,173, at P 80.
77
FERC’s consideration of the MISO case study—which
had successfully operated across a significant swath of the
country—as empirical evidence from which to predict the
impact of adopting a nationwide energy-service modeling
standard was reasonable. “It is . . . quite clear FERC may make
predictions[,]” and we uphold a rule based on such predictions
so long as it is “rationally based on record evidence.” Michigan
Consol. Gas Co. v. FERC, 883 F.2d 117, 124 (D.C. Cir. 1989)
(citation modified).
In sum, the adverse experiences of those with direct and
repeat involvement in the interconnection process over time, as
well as the proven track record in the MISO system of FERC’s
chosen remedy, provide substantial evidence supporting the
modeling rule.
B
The same Transmission Petitioners next challenge FERC’s
explanation for its adoption of the energy-service modeling
standard as arbitrary and capricious, arguing that FERC failed
to grapple with important aspects of the problem, including the
impact on Independent System Operators and Regional
Transmission Organizations (collectively “System
Operators”). Because FERC adequately explained its
reasoning for adopting the energy-service modeling standard
and directly addressed the concerns voiced by these
Transmission Petitioners, their arbitrary and capricious
challenge fails.
1
FERC provided three explanations for its decision to
require interconnection studies for affected systems to be
conducted under an energy-service framework, rather than
78
allowing the affected systems to choose whichever model they
preferred.
First, FERC reasoned that selecting the energy-service
model for affected-system studies will create a fairer
relationship between the prospective interconnection customer
and the affected system. See Order 2023 at PP 1277–78; Order
2023-A at PP 511–12. Unlike a host transmission provider, an
affected system “has no obligation to continually ensure
deliverability” on its transmission system even for an
“interconnection customer that has obtained [firm service] on
its host system.” Order 2023 at PP 1277–78. As a result,
modeling conducted by an affected system using firm service
caused the customer to pay for system upgrades aimed at
providing a level of service the customer had no guarantee of
ever receiving. Order 2023-A at PP 511–12. That is because
the affected system can prioritize deliverability to its own
customers over a neighboring system’s customers, and when
congestion or curtailment of energy flow occurs, the
neighboring customer that paid for the system upgrades must
take a back seat to the affected system’s primary customers.
See Order 2023 at P 1278; Order 2023-A at PP 507–11; see
also J.A. 751 (Fervo Energy comment that “many
Transmission Owners push for more stringent study criteria
and minimum impact thresholds which will result in more
network upgrades being assigned to Interconnection
Customers and thus not funded by” the affected system’s own
customers), id. at 817 (NextEra Resources comment that its
“subsidiaries have experience with excessive network
upgrades being identified in affected system studies based on
[firm-service] analysis”).
Put another way, allowing the affected system to impose
upgrade expenses on a prospective customer for service it will
rarely use and might never receive gave the affected system and
79
its customers an unreasonable windfall at the expense of new
energy generators. At the same time, the use of energy-service
modeling would bring upgrade expenses more in line with the
service guarantees a prospective customer would receive. See
Order 2023 at P 1280; Order 2023-A at P 511.
Second, after two decades of experience with allowing
affected systems to charge for firm-service upgrades, FERC
reasonably concluded that mandating one standard modeling
system across affected systems “will create consistency and
provide transparency for affected system interconnection
customers[,]” one of the major goals of Order 2023. Order
2023 at P 1280.
Similarly, because the previous order permitted affected
systems to use different modeling standards, it was harder for
customers seeking interconnection to predict what network
upgrades would be required and how much they would cost.
As Order 2023 explains, “interconnection customers could be
assigned dramatically different affected-system network
upgrade costs due to those varying modeling standards, without
any factual or service differences to justify the discriminatory
treatment.” Order 2023 at P 1280.
That inability to accurately predict the likely costs of
interconnection set up artificial barriers to the addition of new
energy generation on the grid. See Order 2023 at PP 1279–80;
Order 2023-A at P 511. FERC’s decision, by contrast,
facilitates the addition of new power source customers by
adopting a uniform modeling system that can reduce the
“‘sticker shock’ from affected system network upgrades.”
Order 2023 at P 1151.
Third, FERC found that using energy-service modeling
would result in lower upgrade costs for new energy generation
80
customers. That, in turn, would reduce the number of
prospective customers that are forced to withdraw from the
interconnection queue—the line of energy generators seeking
to connect to any given transmission system—after receiving
an unexpectedly high bill for affected-system upgrades. See
Order 2023 at PP 1279–80.
Reducing such late-stage withdrawals was a critical goal
of Order 2023 both because withdrawals keep new energy
sources off the grid and because those withdrawals can result
in cascading withdrawals and restudies as each prospective
customer in the queue either bows out when confronted with a
higher price tag for its interconnection (since the study costs
are shared among the remaining prospective customers), or
must face a whole new study of its impact on the grid if
interconnected. See Order 2023 at PP 49–50, 1279–80.
FERC, in short, identified a real problem in the energy
generation system, selected a reasonable alternative to the
status quo, and provided rational policy reasons for its decision.
Nothing more is required. See also South Carolina, 762 F.3d
at 55 (“[T]he Commission must have considerable latitude in
developing a methodology responsive to its regulatory
challenge . . . .” (citation modified)); Coal. of MISO
Transmission Customers v. FERC, 45 F.4th 1004, 1017 (D.C.
Cir. 2022) (“Arbitrary and capricious review is ‘narrow’—we
are ‘not to ask whether a regulatory decision is the best one
possible or even whether it is better than the alternatives.’”
(quoting Motor Vehicle Mfrs. Ass’n of the U.S. v. State Farm
Mut. Auto. Ins. Co., 463 U.S. 29, 93 (1983))).
2
Transmission Petitioners do not contest the accuracy of
these three reasons. Instead, they argue that FERC failed to
81
consider the negative impacts that the new modeling rule
would have on affected systems in regions managed by System
Operators. They also argue that the modeling rule violates
cost-causation principles and favors interconnection customers
over affected systems. Neither argument holds up.
Far from ignoring the effect of the new rule on System
Operators, FERC relied upon the success of an energy-service
modeling approach that had already been adopted and used “for
many years” across fifteen states by a Regional Transmission
Organization, MISO. NPRM at P 213; Order 2023-A at
PP 510–11. FERC noted, in particular, that MISO’s adoption
of energy-service modeling had “not result[ed] in reliability
issues and [has] not cause[d] unnecessary curtailment or
redispatch on affected systems,” contrary to the Transmission
Petitioners’ arguments. Order 2023-A at P 510. 18 17F
With respect to the subgroup’s concerns about affected
systems’ ability to preserve their transmission capacity for their
own customers, FERC found that, “in the majority of
circumstances, interconnection alone is unlikely to affect the
reliability of an affected system transmission provider’s
transmission system.” Order 2023 at P 1288; Order 2023-A at
18
The Transmission Petitioners have not argued that, for
purposes of their argument, there is any relevant difference between
Independent System Operators and Regional Transmission
Organizations such that FERC could not draw on the lessons gleaned
from MISO and apply them to Independent System Operators. See
Transmission Petitioners Br. 81–82 (arguing only that FERC ignored
the impact of the energy-service modeling rule on “System Operator
areas[,]” a term inclusive of both Independent System Operators and
Regional Transmission Organizations); see also Energy Markets,
FERC, https://www.ferc.gov/opp/energy-markets (explaining
similarities between Independent System Operators and Regional
Transmission Organizations).
82
P 507. In addition, FERC determined in Order 2003 that
“interconnection and delivery [are] separate aspects of
transmission service,” Order 2003 at P 118, and Order 2023
regulates affected-system studies at the interconnection stage
only, see Order 2023 at PP 1284–85. So any concerns about
the impact of interconnection customers on affected systems at
the deliverability stage are beyond the scope of Order 2023.
Further, at that later stage, other tariff requirements kick in,
such as a common tariff requirement that renders a new
customer “responsible for obtaining any necessary
engineering, permitting, and construction” on affected systems.
Id. at P 1284.
One Regional Transmission Organization, Southwest,
argues that the separate treatment of interconnection and
deliverability does not address its situation, which is that one
of its neighboring System Operators grants interconnection and
deliverability simultaneously. So that one single operator will
not have a second opportunity to address any needed
deliverability upgrades.
As a commenter noted, “this appears to be a problem of
[Southwest]’s own making, based on how it has implemented
[energy service] and [firm service] on its own system,” and
Southwest could fix the problem by “revising its own methods
for determining what is firm or deliverable” service. J.A. 1381.
In any event, FERC addressed Southwest’s situation and
reasonably concluded that its one-off problem did not
undermine FERC’s rationale for adopting the energy-service
modeling standard as a default rule nationwide. Order 2023-A
at P 507–08; cf. South Carolina, 762 F.3d at 67 (“[B]ecause
petitioners have not shown that the deficiencies identified by
the Commission exist only in isolated pockets, . . . the
Commission could reasonably proceed to address a systemic
83
problem with an industry-wide solution.”) (citation modified).
FERC added that Southwest could seek an “independent entity
variation” from aspects of Order 2023 when it files its
compliance paperwork. See Order 2023-A at P 508 n.944; see
also Order 2023 at P 1764 & n.3346. Alternatively, Southwest
has the right to submit a Federal Power Act “section 205 filing”
in which it could “request [to] use [a firm-service] modeling
standard in affected system studies.” Order 2023 at P 1293;
see Transmission Access, 225 F.3d at 710–11 (holding that
FERC may make generic nationwide rules if they are in the
“generic public interest” and address outliers on a “case-by-
case” basis when reviewing applications for individual
variations). 19
18F
Finally, contrary to these Transmission Petitioners’
argument, energy-service modeling comports with cost-
causation principles and does not impermissibly preference the
interests of interconnection customers over affected systems.
FERC found that the use of energy-service modeling will
reduce late-stage withdrawals of customers from the
interconnection queue, and that change will help transmission
providers as well as customers. That is because speculative
projects that progress through various studies before being
scrapped end up wasting transmission providers’ time, while
also delaying the interconnection of needed and viable
generation customers that are later in the queue. See NPRM at
P 14 (noting that the consequences of late-stage withdrawals
“can then impede the transmission provider’s ability to process
its interconnection queue in an efficient manner”).
19
Southwest is well aware that Section 205 filings can allow
for individual exceptions to FERC Orders since FERC granted
several of Southwest’s Section 205 filings over the past seventeen
years to override aspects of Order 2003. See Order 2003 at PP 4–5,
39–40.
84
In any event, FERC can “reasonably chang[e] its policies,
and implement[] the consequences of those changes to the
detriment of some parties and the benefit of others” as long as
the change reflects a reasoned exercise of FERC’s policy
judgment about the most efficient and effective approaches to
bringing more power to the grid for the Nation as a whole.
Union Pac. Fuels, Inc. v. FERC, 129 F.3d 157, 162 (D.C. Cir.
1997). After all, “[p]olicy changes sometimes have distributive
effects that may appear arbitrary from the perspective of their
corporate victims, but in fact proceed logically from the
reasoned premises underlying the changes.” Id.; see also
Belmont Mun. Light Dep’t v. FERC, 38 F.4th 173, 184 (D.C.
Cir. 2022) (“Due to practical challenges and myriad divergent
interests, FERC must be given the latitude to balance the
competing considerations and decide on the best resolution in
its regulation of electricity markets.” (quoting New England
Power Generators Ass’n, 881 F.3d at 210)).
As for the concerns about cost-causation principles,
nothing in Order 2023 requires affected systems to ever
provide service to a neighboring system’s customer. Plus, the
use of energy-service modeling to protect against customers
having to pay for expensive upgrades from which they might
never benefit fully aligns with cost-causation principles. See
Order 2023 at P 1278 (describing the prior regime as a
“mismatch between costs and services received” because,
while the customer had to pay for “significant network
upgrades” on the affected system, that system had “no
obligation” to provide firm service to the customer or prevent
curtailment of that customer’s energy); Order 2023-A at P 511
(same).
85
C
Finally, these Transmission Petitioners argue that FERC
acted arbitrarily and capriciously by changing its modeling
standard policy from previous orders without adequate
justification. But all that is required of an agency facing
arbitrary and capricious review to a policy change is to “display
awareness that it is changing position[,]” and to provide “good
reasons” for the change. FCC v. Fox Television Stations, Inc.,
556 U.S. 502, 515 (2009). FERC’s decision meets that mark.
FERC expressly acknowledged its change from its past
laissez-faire approach to modeling choices, stating that it had
“previously allowed affected system transmission providers to
justify their own approach to selecting the modeling standard
used to evaluate affected system impacts.” Order 2023-A at
P 511; see also Order 2023 at P 1292 (noting that the energy-
service modeling standard is different from “the status quo”).
FERC then provided sound reasoning for the changed
approach: The frequent use of firm-service modeling resulted
in customers having to undertake “significant” upgrades
“without a commensurate increase in service” and “would
result in unjust and unreasonable rates[,]” Order 2023-A at
P 511, which the Federal Power Act prohibits, 16 U.S.C.
§ 824e(a); see Transmission Access, 225 F.3d at 708 (“Simply
put, it has been traditionally required that all approved rates
reflect to some degree the costs actually caused by the customer
who must pay them.” (citation modified)).
FERC then reiterated its three specific reasons supporting
the adoption of energy-service modeling as the default rule:
avoiding the imposition of significant costs with no
commensurate effect on service; the acutely disruptive queue
withdrawals caused by high upgrade price tags; and the goal of
86
increasing transparency, consistency, and fairness in the
interconnection process. See Order 2023-A at P 511; Section
V.B, supra.
Because FERC explicitly acknowledged the change in
course from Order 2003, and its reasoning is logical and draws
on supportive evidence from involved parties, FERC has met
its burden to address its policy shift.
VI
For the foregoing reasons, the petitions for review are
denied.
So ordered.