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 2 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. 3 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). 4 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. 5 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 6 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 7 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 8 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 9 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.
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 10 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.
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. 11 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 12 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.
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[.]”). 13 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 14 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. 15 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.
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. 16 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. 17 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 18 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 19 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.
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 20 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).
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, 21 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.