Entergy Arkansas, LLC v. Federal Energy Regulatory Commission

United States Court of Appeals
FOR THE DISTRICT OF COLUMBIA CIRCUIT
Argued March 8, 2024 Decided July 26, 2024
No. 22-1335
ENTERGY ARKANSAS, LLC, ET AL.,
PETITIONERS
v.
FEDERAL ENERGY REGULATORY COMMISSION,
RESPONDENT
ARKANSAS PUBLIC SERVICE COMMISSION, ET AL.,
INTERVENORS
Consolidated with 23-1111
On Petitions for Review of Orders of the
Federal Energy Regulatory Commission
Jennifer Quinn-Barabanov argued the cause for
petitioners. With her on the briefs were Andrea J. Weinstein,
Glen S. Bernstein, and Shaun M. Boedicker.
William D. Booth, Gary M. Bridgens, Alex L. Peterson,
Nicole A. Vele, Noel Darce, Glen L. Ortman, Dennis Lane, M.
Denyse Zosa, and F. Alvin Taylor, Jr. were on the briefs for

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intervenors in support of petitioners. Paul L. Zimmering
entered an appearance.
Beth G. Pacella, Deputy Solicitor, Federal Energy
Regulatory Commission, argued the cause for respondent.
With her on the brief were Matthew R. Christiansen, General
Counsel, and Robert H. Solomon, Solicitor.
Before: MILLETT, KATSAS and CHILDS, Circuit Judges.
Opinion for the Court filed by Circuit Judge MILLETT.
MILLETT, Circuit Judge: In February 2021, a weeks-long
cold snap devastated the central United States, cutting power
to millions of Americans and killing hundreds. That cold snap
confirmed what power grid operators in the region already
knew: Extreme weather events that put an increased strain on
the grid were becoming increasingly common, and updated
means of ensuring grid reliability were needed.
The Midcontinent Independent System Operator
(“MISO”) operates the electrical grid in much of the central
United States, subject to regulatory supervision by the Federal
Energy Regulatory Commission (“FERC”). Citing the 2021
cold snap and other growing grid reliability issues, MISO
proposed overhauling its capacity market—in which electricity
distributors buy commitments from generators to provide
electricity in the future—and making related rule changes.
Under MISO’s new system, MISO would operate seasonal,
rather than annual, capacity markets. That is, MISO would
calculate the amount of capacity each generator can sell, and
each distributor must buy, for each of the four seasons. MISO
also proposed changing its method for calculating generator
capacity and its rules regarding generator outages. FERC
approved MISO’s changes. See Midcontinent Indep. Sys.

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Operator, Inc., 180 FERC ¶ 61,141, at P 1 (2022) (“Initial
Order”).
The Entergy Operating Companies (“Entergy”)
collectively petitioned for review of FERC’s decisions.
Entergy claims that FERC acted arbitrarily and capriciously by
approving MISO’s new (1) method for calculating the amount
of capacity that generators can offer into the capacity market;
(2) requirement that generator owners must replace promised
capacity if their generators go offline for more than 31 days in
a season; and (3) requirement that generator owners provide
120 days’ notice prior to a planned outage. Entergy is
supported by a group of Intervenors.
Because FERC adequately explained its approval of
MISO’s changes, we deny Entergy’s petitions for review. We
do not reach any of the issues raised solely by the Intervenors.
I
A
MISO operates electrical transmission systems and
wholesale electricity markets throughout the central United
States. It also works to balance electrical supply and demand
and ensure a reliable transmission system within that area.
Public Citizen v. FERC, 7 F.4th 1177, 1186–1187 (D.C. Cir.
2021). In that role, MISO must file a tariff with FERC that sets
forth MISO’s procedures and rules governing, as relevant here,
its capacity markets and efforts to ensure transmission
reliability and safety. 16 U.S.C. § 824d(c); see Public Citizen,
7 F.4th at 1184. FERC reviews changes to MISO’s tariff under
Section 205 of the Federal Power Act to determine if they are
“just and reasonable.” 16 U.S.C. § 824d(a).

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This case involves MISO’s capacity market, in which
electricity distributors purchase in advance generators’
“capacity” to provide electricity. Public Citizen, 7 F.4th at
1186. Capacity is a “commitment[]” from a generator “to
produce set amounts of electricity in the future.” Id. The idea
is that, by requiring distributors to buy enough commitments
from generators, MISO can ensure that there will be enough
electricity to meet demand in the future. Id. at 1187.
In broad strokes, MISO’s capacity market has three steps.
First, MISO determines how much capacity each source of
electricity can sell in the market. Sources of electricity, such
as generators, are known in the industry as “resources.” The
determination of an individual resource’s capacity to provide
electricity is referred to as “accreditation.”
Second, MISO calculates how much capacity will be
required to meet the system’s needs. Public Citizen, 7 F.4th at
1187. MISO does so by forecasting peak electricity demand
over a specified time period. It then adds a safety margin by
conducting a reliability study that determines how much extra
capacity is needed to meet a target level of reliability.
Electricity distributors must acquire capacity to meet their
projected demand or pay a fee.
Third, MISO conducts an auction at which resource
owners offer capacity into the market at varying prices. Public
Citizen, 7 F.4th at 1187. This auction provides one mechanism
through which electricity distributors can acquire their required
capacity. MISO accepts the lowest offers until it meets the
system’s capacity requirements. Id. The last offer MISO
accepts then sets the price at which all capacity is purchased by
electricity distributors. Id.

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Until recently, MISO held a capacity auction once per
planning year, which runs from June 1st to May 31st. For those
auctions, MISO accredited a resource by determining the
amount of electricity the resource could be expected to
generate and adjusting that figure for periods when the resource
might experience forced outages due to some unanticipated
emergency, mechanical failure, or other uncontrollable cause.
MISO then determined how much capacity had to be bought
and sold at the capacity auction by estimating how much
electricity would be needed on a peak day in summer, the
season when electricity demand is typically at its highest.
B
In 2021, MISO proposed overhauling its capacity market
and related rules. MISO explained that the changes were
necessary because it was becoming increasingly common for
the amount of energy demanded to be dangerously close to the
amount of energy available, especially outside of summer.
Between 2016 and 2021, MISO declared 40 grid emergencies,
a number that “significantly exceeds historical norms[.]” J.A.
570. Prior to 2021, “MISO had experienced at most eight
[emergency] events in a similar timeframe.” J.A. 570. In
addition, more than 60% of the 40 emergencies occurred
outside of summer. MISO attributed these trends to several
factors, including retirement of generators that were available
24 hours a day, generator outages outside of the summer,
increased reliance on intermittent resources like wind and
solar, and increased frequency of extreme weather that forces
generators offline.
This case involves three of MISO’s changes.
First, MISO moved from conducting one capacity auction
for an entire year to conducting four capacity auctions, one for
each season. Consistent with that change, MISO started

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accrediting resource capacity and determining how much
capacity distributors must buy on a seasonal basis.
Second, MISO changed its accreditation methodology to
focus on resources’ actual performance during periods of peak
electricity demand over the last three years, rather than
resources’ projected capacity. MISO explained that its new
method is designed “to ensure that resources are available
when needed the most by aligning resource accreditation with
availability during the highest risk period in each Season.” J.A.
592.
To achieve this goal, MISO divides all the hours in a year
into two tiers. Tier 1 hours are all hours in a season other than
Tier 2 hours. In most circumstances, Tier 2 hours are the 65
hours in a season when the margin between electrical supply
and electrical demand is at its tightest.
MISO then calculates an “intermediate seasonal accredited
capacity” value based on resources’ actual availability in past
years during Tier 1 and Tier 2 hours. Resource availability
during Tier 2 hours, which are the greatest times of need, is
weighted far more heavily, accounting for 80% of the
accredited capacity value. Availability during Tier 1 hours
accounts for only 20%.
After calculating every resource’s intermediate seasonal
accredited capacity, MISO converts those values (through a
process not relevant here) into each resource’s final seasonal
accredited capacity, which indicates how much capacity that
resource can sell in the capacity market in a given season.
Third, MISO changed its rules regarding planned resource
outages. Under MISO’s new rules, resource owners can
participate in the capacity market regardless of how many days
they are offline during the season. But resource owners must

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replace capacity if they plan a resource outage longer than 31
days in a season, or else pay a fine greater than the cost of
acquiring replacement capacity.
For example, say a company owns a nuclear reactor that
participates in the summer capacity market. If the owner’s bids
are accepted at the capacity auction, the reactor owner will
receive payment for the capacity it sold regardless of whether
the reactor is online. But if the owner were to take the nuclear
reactor offline for 40 days in the summer, then the owner would
need to replace that lost capacity. If the reactor owner does not
acquire replacement capacity, then it would have to pay a fine.
Alternatively, had the owner known of the maintenance
sufficiently far in advance, it could have opted out of the
summer capacity market.
MISO also added timing requirements for planned
generator outages. By default, planned resource outages are
not exempt from the accreditation process. As a result, a
nonexempt outage will likely lower a resource’s accredited
capacity, especially if the outage includes Tier 2 hours.
MISO will, however, exempt outages from the
accreditation analysis if they are scheduled: (1) more than 120
days in advance; (2) more than 120 days after the end of the
resource’s previous outage; and (3) for a period throughout
which the maintenance margin is greater than or equal to zero.
The “maintenance margin” is the amount of power “that can be
taken out of service for planned maintenance for a given time-
period without undue risk to supply adequacy[.]” Initial Order
at P 97 n.134.
C
FERC approved MISO’s changes to its tariff. Initial Order
at P 1. FERC denied all the requests for rehearing by operation

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of law on October 31, 2022. FERC later supplemented its
denial of rehearing with an order explaining its rationale. See
Midcontinent Indep. Sys. Operator, Inc., 182 FERC ¶ 61096,
at P 1 (2023) (“Rehearing Order”). Commissioners Danly and
Christie concurred separately in the initial approval, and
Commissioner Danly concurred separately in the denial of
rehearing. Commissioner Clements dissented from both the
initial approval and the denial of rehearing.
Two sets of parties now seek review.
Entergy consists of a group of companies that generate,
transmit, distribute, and sell electricity in Arkansas, Louisiana,
Mississippi, and Texas. The companies are members of MISO
and filed comments objecting to MISO’s changes and a request
for rehearing before FERC. Entergy petitioned for review of
both FERC’s initial approval and FERC’s rehearing denial, and
this court consolidated both petitions.
Entergy is supported by a group of Intervenors consisting
of public utilities commissions in Mississippi, Louisiana, and
Arkansas, and the East Texas Electric Cooperative, a nonprofit
corporation that operates the electrical grid in eastern Texas.
II
We have jurisdiction over Entergy’s petitions for review
under 16 U.S.C. § 825l(b). Section 825l(b), however, imposes
an “unusually strict” exhaustion requirement. Ameren Servs.
Co. v. FERC, 893 F.3d 786, 793 (D.C. Cir. 2018) (quoting
Wabash Valley Power Ass’n v. FERC, 268 F.3d 1105, 1114
(D.C. Cir. 2001)). We lack jurisdiction to consider any
objection “unless such objection shall have been urged before
[FERC] in the application for rehearing unless there is
reasonable ground for failure so to do.” 16 U.S.C. § 825l(b).
Because this limit is jurisdictional, “we have no discretion to

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disregard it.” New England Power Generators Ass’n v. FERC,
879 F.3d 1192, 1198 (D.C. Cir. 2018) (quotation marks
omitted).
We review FERC’s finding that MISO’s rule changes are
just and reasonable under the Administrative Procedure Act’s
arbitrary-and-capricious standard. Belmont Mun. Light Dep’t
v. FERC, 38 F.4th 173, 184 (D.C. Cir. 2022). We must uphold
FERC’s decision if FERC has “examine[d] the relevant data
and articulate[d] a satisfactory explanation for its action
including a rational connection between the facts found and the
choice made.” Id. (quoting Motor Vehicle Mfrs. Ass’n v. State
Farm Mut. Auto. Ins. Co., 463 U.S. 29, 43 (1983)).
III
Entergy challenges FERC’s approval of MISO’s new
accreditation methodology and new planned outage rules.
Because FERC reasonably explained its approval of those
changes, we deny Entergy’s petitions for review. We do not
reach any issues raised only by the Intervenors.
A
We begin with FERC’s approval of MISO’s accreditation
methodology. Entergy’s main complaint is that MISO’s new
accrediting methodology too heavily weights a too-small
subset of hours in a year. Entergy Opening Br. 34. Recall that
MISO’s new method accredits capacity based on performance
over the past three years and gives 80% weight to Tier 2 hours,
which are the 65 hours in each year when electrical supply is
tightest. All other hours are weighted only 20%.
Entergy argues that, by relying so heavily on just 65 hours,
random chance could have an outsized effect on generators’
capacity ratings if a planned outage happens to overlap with

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Tier 2 hours. Entergy Opening Br. 34. Based on that
possibility, Entergy claims that FERC failed (1) to explain how
the new accreditation methodology can accurately predict
future performance, and (2) to address the impact of the
resulting volatility on resource owners and other stakeholders.
Entergy Opening Br. 34–49.
Neither of Entergy’s arguments succeeds.
1
To start, FERC relied on a study that gives evidence that
MISO’s new methodology is more accurate than its prior
approach when predicting resource performance during
periods of highest demand. Rehearing Order at P 26. Entergy
has failed to show that FERC’s reliance on this study was
unreasonable. MISO examined eleven emergency days from
2021. For those eleven days, MISO determined (1) how much
electricity resources actually offered into the market over those
days; (2) how much capacity resources had been accredited
under the old methodology; and (3) how much capacity
resources would have been accredited under the new
methodology had it been in effect. See J.A. 521–522. That
study resulted in a finding that MISO’s old methodology
overestimated how much electricity would actually be offered
into the market by roughly 8% to 22%. J.A. 521–522. By
contrast, the new methodology’s estimates were off by only
about 1%. J.A. 521–522.
Based on that accuracy study, FERC reasonably concluded
that MISO’s new methodology of looking to resources’ past
seasonal performance would accurately predict resources’
future performance during the periods of highest demand. See
Rehearing Order at P 26.

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Entergy attacks this study in two ways, arguing that: (1)
the study’s eleven-day sample size was too small; and (2) the
study did not convert intermediate seasonal capacity figures
into final seasonal capacity figures. See Entergy Opening Br.
35–40.
We lack jurisdiction to consider these arguments because
Entergy did not raise them in its rehearing request. As noted
earlier, the Federal Power Act’s exhaustion requirement is
“unusually strict,” and “[p]etitioners must raise each argument
with specificity; objections may not be preserved either
indirectly or implicitly.” Ameren, 893 F.3d at 793 (formatting
modified). Entergy did not discuss MISO’s accuracy study at
all in its rehearing request. See J.A. 785–790. As a result,
Entergy failed to “alert[] the Commission to the legal
arguments” it now raises before us. Ameren, 893 F.3d at 793
(quoting Save our Sebasticook v. FERC, 431 F.3d 379, 381
(D.C. Cir. 2005)).
Entergy separately argues that FERC failed to explain why
individual resources’ accreditations would be accurate if they
can fluctuate significantly from year to year under the new
methodology. Entergy Opening Br. 34–35.
FERC adequately addressed that objection. It explained
that MISO’s new methodology more accurately predicts
individual resources’ future performance because it
“comprehensively addresses all reasons for unavailability,
compared to [the old methodology] that only reflects forced
outage rates.” Rehearing Order at P 26. To the extent an
individual resource’s accreditation varies year-to-year, FERC
explained that such variation “is warranted and is appropriately
captured” by MISO’s accreditation method because the new
method tracks a resource’s historical performance. Initial
Order at P 260. That is, because MISO now accredits resources

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based on three years of prior performance, it is reasonable for
an individual resource’s accreditation to change based on
whether it has under- or over-delivered in the past.
2
Next, Entergy argues that volatility under MISO’s new
system will be very high, and that such swings impose costs on
market participants and make it harder for them to plan for the
future. Entergy Opening Br. 40, 49. Entergy argues that FERC
failed to address these volatility concerns.
But FERC did address Entergy’s volatility concerns,
reasonably explaining that it expected volatility to be low and
that any volatility would not pose significant problems.
Specifically, based on data provided by MISO, FERC
found that volatility under MISO’s new accreditation
methodology is anticipated to be low both systemwide and at
the individual participant level. MISO calculated total seasonal
accredited capacity for every MISO market participant’s
resources for four planning years, 2017–2018 to 2020–2021.
J.A. 227. Using those numbers, MISO calculated the standard
deviation for each market participant as a measure of how
much volatility each MISO market participant would have
experienced across those years had the new accreditation
method been in use. J.A. 227.
The study found that volatility is “very low” at the
systemwide level, with a standard deviation of less than 2%.
Initial Order at P 259. The study also demonstrated that
volatility would be relatively low at the market participant
level, finding that 75% of market participants would have had
a standard deviation of less than 7.6%. J.A. 227; see Initial
Order at P 260 (FERC explaining that it expects “any additional
volatility to be low[.]”).

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Entergy does not dispute that, in this context, a standard
deviation of less than 7.6% is low. It instead cherry-picks a
single number from MISO’s volatility study: 15.5%. Entergy
Opening Br. 42. That number is the largest standard deviation
MISO calculated for a single market participant (excluding
statistical outliers). J.A. 227. Based on that number, Entergy
argues that individual market participants face an intolerable
degree of volatility. But 15.5% was only one data point before
FERC. FERC also had before it a comprehensive study of the
entire MISO system that demonstrated that systemwide
volatility would be very low and that the vast majority of
market participants would experience far less volatility than the
extreme, worst-case scenario that Entergy singled out. See
Initial Order at PP 259–260; J.A. 227. FERC’s decision to
focus on all of the data and volatility as measured across the
board was well within reason.
FERC also sensibly explained why it found that any
volatility is unlikely to unduly impact market participants.
First, FERC reasonably determined that, even when there
is volatility at the resource-specific level, the volatility will
usually be lower at the market-participant level. Many entities
that participate in MISO’s capacity markets buy or sell capacity
from a wide range of resources. See Initial Order at P 260. So
even if one resource’s accreditation might fluctuate, a market
participant’s total capacity over its entire portfolio of resources
is unlikely to significantly fluctuate year-to-year. As FERC
recognized, “a key consideration” for market participants is
“the stability of the accreditation of their resource portfolio
* * * rather than the higher volatility expected from individual
resources.” Rehearing Order at P 24.
Second, FERC explained that using a three-year rolling
average minimizes the impact of random chance. Initial Order

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at P 259. If bad luck besets a resource one year, the impact of
such bad luck is blunted by the fact that other years can help
balance out an anomalous season. And FERC explained that
“volatility will subside over time as outage behavior changes”
in response to “greater incentive to avoid unavailability during
times of need.” Rehearing Order at P 25.
Third, FERC reasonably explained why volatility will
have a minimal impact on market participants’ ability to plan.
Because accreditation under the new methodology is primarily
based on a resource’s historic performance, resource owners
can rely on past performance data to get at least a rough
estimate of future capacity accreditations. See Initial Order at
P 260; Rehearing Order at P 28. MISO also provided resource
owners with the tools needed to estimate future capacity
accreditation, such as “detailed data to stakeholders” that
included “unit-level [seasonal accredited capacity] values on a
seasonal basis,” as well as “extensive and detailed data for at
least one individual resource for each stakeholder,” which
included “all inputs and calculations necessary to allow
stakeholders to independently validate how MISO derived the
[seasonal accredited capacity] values for that resource.” Initial
Order at P 167; see J.A. 475–476.
As for electricity distributors, FERC explained that many
distributors have “diverse resource fleets[.]” Initial Order at P
260. So it is unlikely that they will have to plan around
resource-specific fluctuations because such fluctuations likely
will even out across a broad portfolio. Id. To the extent that
distributors have less diverse portfolios, see Entergy Opening
Br. 50, those distributors can purchase additional capacity to
make up any shortfall. Initial Order at P 260.

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B
We turn next to FERC’s approval of MISO’s new resource
outage rules. Entergy objects to two new requirements. First,
it challenges MISO’s rule that resources must either acquire
replacement capacity or pay a penalty if they are offline for
more than 31 days in a three-month season. Entergy Opening
Br. 23–33. Second, it challenges MISO’s rule that resources
must schedule planned outages and notify MISO 120 days in
advance to receive an exception from the ordinary calculation
of Tier 2 hours for planned outages. Entergy Opening Br. 50–
53. We reject Entergy’s challenges because FERC reasonably
explained its approval of both rules.
1
We begin with the 31-day capacity replacement rule. That
rule incentivizes resources to be online for most of a season in
which they committed—and were paid—to supply electricity.
See Public Citizen, 7 F.4th at 1186. As FERC explained, “it is
critical” that owners deliver on their promises such that MISO
can “depend on * * * resources” offered into the capacity
market. Initial Order at P 341. Accordingly, MISO expects
that resources that make commitments, and have been paid to
do so, will deliver on their commitments. Id. at P 334 (The 31-
day capacity replacement rule “reflect[s] a reasonable
expectation that a Planning Resource receiving capacity
payments for a given Season should not be unavailable for a
significant portion of that Season.”).
It would be equally unfair for electricity distributors,
having already spent money to acquire capacity, to bear the full
cost of purchasing capacity if those resources go offline for
long stretches in a season. Initial Order at P 338.

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At the same time, FERC acknowledged that resource
owners must have time to go offline for “needed and prudent
maintenance” essential to MISO’s long-term grid reliability.
Initial Order at P 335.
Weighing those competing interests, FERC found that a
31-day threshold would give generators enough time to
perform maintenance, while also ensuring that generators
would be online for the majority of each season. Initial Order
at P 335. To the extent that another number of days might also
balance those interests, “FERC is not required to choose the
best solution, only a reasonable one.” Petal Gas Storage, LLC
v. FERC, 496 F.3d 695, 703 (D.C. Cir. 2007); see Initial Order
at P 335 (“While we recognize that other thresholds could also
be just and reasonable, we find that MISO’s proposed 31-day
threshold appropriately balances” the competing interests.).
Entergy does not dispute that 31 days out of a three-month
season is a “significant portion” of that time period, that a
resource that chooses and is paid to participate in the capacity
market for a season should generally be online for that season,
or that 31 days is enough time for most generators to perform
necessary maintenance. Instead, Entergy argues that (1) the
rule unduly burdens resources that require extended
maintenance longer than 31 days; and (2) the rule is not
necessary to ensure grid reliability. Entergy Opening Br. 24–
32. We reject both arguments.
First, FERC adequately explained why the 31-day capacity
replacement rule does not unduly burden resources that need
extended maintenance periods.
As a threshold matter, we have jurisdiction to consider this
argument. FERC argues that we lack jurisdiction because
“Entergy did not specifically assert in its request for rehearing
that this proposal was ‘unduly discriminatory.’” FERC Br. 33.

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That is true. But Entergy’s argument here is not that FERC’s
order unlawfully discriminates against similarly situated
parties, as prevailing on an undue-discrimination challenge
requires. See NRG Power Marketing, LLC v. FERC, 718 F.3d
947, 957–958 (D.C. Cir. 2013). Instead, it contends that FERC
inadequately explained why the 31-day capacity replacement
rule is just and reasonable with respect to resources that require
extended maintenance. See Entergy Opening Br. 24 (“The 31-
day replacement-or-penalty rule unreasonably and unduly
burdens certain types of generators[.]”). Entergy preserved that
just-and-reasonable challenge by arguing before FERC that its
approval was irrational because “the duration of planned
outages for nuclear units is commonly longer than 31 days,”
and that “[t]he 31-day threshold also can impede efficient
maintenance of other types of generating units” for which
“outages for longer than 31 days can be efficient[.]” J.A. 781.
We therefore reach, and reject on the merits, Entergy’s
arguments regarding resources that need extended maintenance
periods. FERC reasonably explained that owners of such
resources have four options: (1) shortening maintenance; (2)
acquiring replacement capacity; (3) opting out of the capacity
market for a season while maintenance is undertaken; and (4)
scheduling maintenance so that it straddles two seasons,
enabling planned outages of up to 62 days in length. Initial
Order at P 339. As a result, resource owners that choose to
perform extended maintenance can schedule that maintenance
either (1) across two seasons without any financial cost, or (2)
within one season subject to having to pay for replacement
capacity or opting out of the capacity market and losing the
associated profit.
Entergy’s objections to these alternatives are not
persuasive. Entergy points out that opting out of the capacity
market requires the approval of MISO’s independent market

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monitor, an independent entity that monitors the performance
of MISO’s markets. See J.A. 21. Even so, Entergy has
admitted that it “is true” that “a resource owner can opt out of
the capacity market for a Season.” J.A. 783.
In any event, a resource owner denied permission to opt
out still can schedule extended maintenance across two
seasons. Entergy does not dispute that a 62-day outage would
be sufficient to meet its extended maintenance needs. Instead,
it argues that this option is inconsistent with FERC’s position
capping outages at 31 days in a season. Entergy points out that,
under FERC’s reasoning, a 60-day outage across two seasons
would be permitted while a 32-day outage within one season
would not be. According to Entergy, that makes no sense. See
Entergy Reply Br. 15.
Entergy is mistaken. MISO’s new capacity market
employs a seasonal, rather than annual model. MISO accredits
capacity and projects electrical demand on a season-by-season
basis and treats each season independently. So FERC
reasonably prioritized a resource’s availability in each season,
not its availability across multiple seasons. See Rehearing
Order at PP 64–65. For example, when MISO plans for the
spring, it focuses on resources’ availability in the spring. It
does not consider resources’ availability in the summer until it
plans for the summer. So it is not arbitrary for FERC to
approve a rule providing that scheduling a 32-day outage in the
spring triggers replacement obligations for the spring, while
scheduling a 31-day outage in the spring followed by a 31-day
outage in the summer does not.
Second, Entergy argues that a 31-day capacity
replacement rule is not necessary when a planned outage
overlaps with periods when the maintenance margin is positive,
meaning that there is no undue risk of inadequate supply

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despite the outage. Entergy Opening Br. 29–30. According to
Entergy, if the maintenance margin is positive, then a resource
can be taken offline with no threat to grid reliability. So there
is no need to acquire replacement capacity.
But FERC gave an additional reason for the 31-day
capacity replacement rule beyond grid reliability. As FERC
explained, it is unfair for resources to go offline for more than
31 days in a season when distributors have paid for the
resource’s commitment to supply electricity during that season,
“even if [the outage] occurs in a period with relatively low
reliability risks.” Initial Order at P 338. That makes sense.
Few employers would hire and pay someone for a three-month
summer job and then permit that employee to take 32 days’
paid leave without any repercussions. FERC’s decision
reflects that same common-sense intuition that line-drawing
was needed.
2
Entergy also objects to the sufficiency of FERC’s rationale
for upholding MISO’s new 120-day notice requirement for
planned outages, on two grounds. First, Entergy argues that
there is no need for a notice requirement because MISO also
requires that planned outages take place when resources can be
taken offline without endangering the grid, that is, when the
maintenance margin is greater than or equal to zero. Entergy
Opening Br. 51–52. Second, it argues that FERC and MISO
failed to explain why a shorter notice window was
inappropriate. Entergy Opening Br. 52–53. Neither argument
holds up.
First, FERC sensibly explained that requiring advance
notice serves purposes other than ensuring grid reliability.
Specifically, requiring advance notice incentivizes resource
owners to inform MISO of planned outages ahead of time so

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that MISO and other stakeholders can plan appropriately.
Initial Order at P 264; see J.A. 527.
Second, FERC found a simple reason for setting the notice
requirement at 120 days. Providing 120 days’ notice ensures
that “MISO [has] the information needed prior to the start of
the Season in order to identify and mitigate potential reliability
issues.” J.A. 527; see Rehearing Order at P 55 & n.144 (“[T]he
Commission considered MISO’s response to Commission
staff’s deficiency letter regarding the criteria for planned
outage justifications.”) (citing J.A. 527–528).
C
We turn lastly to the Intervenors’ arguments. We reject
the arguments raised by the Intervenors that were also raised
by Entergy for the reasons given above. See Intervenors
Opening Br. 14–18. Specifically, we reject the Intervenors’
challenges to the 31-day capacity replacement rule and the
weighting of Tier 2 hours.
We do not reach the Intervenors’ remaining arguments,
which object to FERC’s approval of MISO’s (1) inclusion of
certain resources when identifying Tier 2 hours; (2) decision to
fully accredit certain offline resources; and (3) implementation
timeline for these changes. See Intervenors Opening Br. 7–14,
18–25.
We lack jurisdiction to reach the Intervenors’ first two
arguments because none of the Intervenors raised them in their
rehearing requests. 16 U.S.C. § 825l(b); see J.A. 760–761,
778–780.
As for the Intervenors’ third argument, we do not reach it
because Entergy did not raise any implementation timeline
issues before us. “[A]bsent extraordinary circumstances,

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intervenors may join issue only on a matter that has been
brought before the court by a petitioner.” California Dep’t of
Water Res. v. FERC, 306 F.3d 1121, 1126 (D.C. Cir. 2002)
(quotation marks omitted). The Intervenors, though, do not
identify any extraordinary circumstances that warrant review,
and we find none.
There is an exception to this rule if the intervenor moved
to intervene within the time limit for petitioning for review of
the Commission’s order. California Dep’t of Water Res., 306
F.3d at 1126. None of these intervenors did so. They each
moved to intervene after the deadline for petitions for review
passed. See 16 U.S.C. § 825l(b).
As such, we decline to reach the Intervenors’
implementation timeline arguments.
* * *
For all of the foregoing reasons, we deny the petitions for
review.
So ordered.

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