Advanced Energy Management All v. FERC
OPINION  filed PER CURIAM OPINION (Pages: 32). [16-1234, 16-1235, 16-1236, 16-1239]
USCA Case #16-1234
United States Court of Appeals
FOR THE DISTRICT OF COLUMBIA CIRCUIT
Argued February 14, 2017
Decided June 20, 2017
ADVANCED ENERGY MANAGEMENT ALLIANCE,
FEDERAL ENERGY REGULATORY COMMISSION,
OLD DOMINION ELECTRIC COOPERATIVE, ET AL.,
Consolidated with 16-1235, 16-1236, 16-1239
On Petitions for Review of Orders of
the Federal Energy Regulatory Commission
Randolph Lee Elliott argued the cause for petitioner
American Public Power Association. Katherine Desormeau
argued the cause for petitioner Natural Resources Defense
Council. With them on the joint briefs were Gerit F. Hull, Jill
Barker, Paul Breakman, Adrienne E. Clair, Casey A. Roberts,
Delia D. Patterson, Christopher S. Porrino, Attorney General,
Office of the Attorney General for the State of New Jersey,
Carolyn McIntosh, Deputy Attorney General, Aaron S.
Colangelo, Jennifer Chen, David Bender, Gary J. Newell,
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Andrea I. Sarmentero-Garzón, Susan Stevens Miller, and Jill
Bruce A. Grabow, Jennifer Brough, and Eugene Grace
were on the briefs for intervenors American Wind Energy
Association, et al. in support of petitioners.
Carol J. Banta, Senior Attorney, Federal Energy
Regulatory Commission, argued the cause for respondent. With
her on the brief were Robert H. Solomon, Solicitor, and Nicholas
M. Gladd, Attorney.
Matthew E. Price argued the cause for intervenors PJM
Interconnection, L.L.C., et al. in support of respondents. With
him on the brief were Ishan K. Bhabha, Jeffrey A. Lamken, Paul
M. Flynn, Ryan J. Collins, Jennifer H. Tribulski, Jeffrey
Whitefield Mayes, Abraham Silverman, Kenneth R. Carretta,
Cara J. Lewis, Neil Lawrence Levy, Cortney Madea, and Larry
Ashley C. Parrish, Paul Alessio Mezzina, David G.
Tewksbury, Stephanie S. Lim, Jason A. Levine, John S. Decker,
and Stacy Linden were on the brief for amici curiae The Electric
Power Supply Association, et al. in support of respondent.
Before: BROWN, Circuit Judge, and SENTELLE and
RANDOLPH, Senior Circuit Judges.
Opinion for the Court filed PER CURIAM1:
We shared the writing of this opinion. Judge Brown wrote
Section VI. Judge Sentelle wrote Sections III, VII, and VIII. Judge
Randolph wrote Sections I, II, IV, and V.
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The Federal Energy Regulatory Commission approved new
rules governing the buying and selling of “capacity.”
“Capacity” is the ability to produce electricity. Purchasers of
capacity acquire the right to buy electricity in the future.
Petitioners object to the Commission’s approval of revisions to
the rules for capacity markets operated by PJM Interconnection.
PJM Interconnection is a regional transmission
organization that oversees the electric grid covering all or parts
of thirteen Mid-Atlantic and Midwestern states and the District
Regional transmission organizations are
independent organizations that manage the transmission of
electricity over the electric grid and ensure electricity is reliably
available for consumers. See generally 18 C.F.R. § 35.34. In
the PJM region, independent generation resources—such as
nuclear power plants, renewable energy resources, and oil-,
coal-, and natural-gas-fired plants—produce electricity. The
resource owners sell electricity at wholesale to traditional
utilities, or “load serving entities,” which deliver it to
consumers. PJM operates competitive “markets” for the
wholesale sale of electricity and other related products. One of
these markets is a capacity market.
Capacity is not actual electricity. It is a commitment to
produce electricity or forgo the consumption of electricity when
required. Generation resource owners sell capacity to utilities,
which need sufficient capacity to provide electricity to their
customers reliably. This creates a kind of options contract.
When a utility experiences a high demand for electricity, it can
call on the capacity resource to produce that electricity. See
Conn. Dep’t of Pub. Util. Control v. FERC, 569 F.3d 477, 479
(D.C. Cir. 2009).
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PJM procures capacity for the entire system. It is more
efficient if utilities share capacity. Each utility needs enough
capacity to be able to meet its expected peak demand.
Individual utilities will experience peak demand at different
times, and PJM can transmit electricity to where it is needed.
See generally Gainesville Utils. Dep’t v. Fla. Power Corp., 402
U.S. 515, 518-20 & n.3 (1971). PJM uses a capacity market to
determine what resources will provide capacity and at what
PJM’s capacity market involves a yearly auction. The
auction works as follows. Resource owners offer to sell a set
amount of capacity at a specific rate. PJM accepts offers,
beginning with the offer at the lowest rate, until the system has
sufficient capacity to meet projected demand. Regardless of the
resource owner’s offer price, PJM purchases all capacity at the
rate of the highest accepted bid—the market-clearing price. The
utilities then pay for their assigned share of capacity. When the
utilities within PJM’s system need more electricity in order to
meet consumer demand, PJM calls on resources with a capacity
commitment. Capacity resources must provide their committed
share of the needed electricity. See Hughes v. Talen Energy
Mktg., L.L.C., 136 S. Ct. 1288, 1293 (2016).
PJM has operated this capacity market since 2006. See
generally PJM Interconnection, L.L.C., 117 FERC ¶ 61,331
(2006). It had market rules in place to enforce capacity
commitments. According to PJM, the rules were not working.
Resource owners were making capacity commitments but not
providing electricity when it was needed. The penalties for a
capacity resource that did not provide electricity were slight and
PJM wanted to establish new enforcement mechanisms to
ensure resources that made a capacity commitment provided
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electricity when called upon. In December 2014, PJM submitted
revised capacity market rules to the Federal Energy Regulatory
Commission for its approval under section 205 of the Federal
Power Act, 16 U.S.C. § 824d. PJM concurrently submitted a
separate filing under section 206 of the Federal Power Act, 16
U.S.C. § 824e, which suggested that some of PJM’s energy
market rules would become unjust and unreasonable if the
Commission approved the new capacity market rules. We will
more thoroughly discuss the relevant details of the revised rules
when addressing each of petitioners’ various challenges.
Generally, PJM’s revised rules would require resources
participating in the capacity market to be able to deliver the
committed level of electricity at any time for the entire delivery
year. PJM proposed various market mechanisms to ensure the
resources would actually deliver the electricity when it is
needed. These included the ability to offer capacity at a higher
price in the auctions; bonuses for producing additional
electricity; and steep penalties for resources that did not meet
their capacity commitment, with very limited exemptions.
In June 2015, the Commission approved PJM’s proposed
changes. PJM Interconnection, L.L.C., Order on Proposed
Tariff Revisions, 151 FERC ¶ 61,208 (2015) (“Tariff Order”).
The Commission denied rehearing. PJM Interconnection,
L.L.C., Order on Rehearing and Compliance, 155 FERC
¶ 61,157 (2016) (“Rehearing Order”). Nine organizations2
Three petitioners are environmental groups: the Natural
Resources Defense Council, Sierra Club, and Union of Concerned
Three petitioners—the American Public Power
Association, the National Rural Electric Cooperative Association, and
the Public Power Association of New Jersey—are service
organizations representing utilities, with members within PJM’s
service region. The Advanced Energy Management Alliance is a
national trade association representing demand response resources.
The New Jersey Board of Public Utilities is a state administrative
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petitioned this court for review. The petitioners, together and
separately, raise eight challenges.
Seven of the petitioners argue that the Commission did not
adequately consider the costs and benefits of PJM’s proposal.
The Commission balanced the benefits of the revised rules
against the increased costs and reached a reasoned judgment.
See, e.g., Blumenthal v. FERC, 552 F.3d 875, 885 (D.C. Cir.
2009). The Commission’s decision was not arbitrary or
capricious. See, e.g., Pub. Utilities Comm’n of State of Cal. v.
FERC, 254 F.3d 250, 253 (D.C. Cir. 2001).
PJM presented significant evidence that the old capacity
market was not ensuring reliable electricity. PJM explained that
the system obtained sufficient capacity during auctions. But
resources frequently did not perform when called upon. PJM
faced particular problems in January 2014. The PJM service
region experienced unusually cold weather that resulted in very
high demand for electricity. Twenty-two percent of PJM’s
resources experienced an outage and could not provide any
power. In addition, PJM demonstrated increasing levels of
resource outages. And those outages were likely to continue.
Many of PJM’s traditional coal- and oil-fired generators were
aging and retiring. PJM found itself depending more on new,
natural-gas-fired generation plants, which presented new
reliability concerns.3 Resource outages lead to increased energy
agency charged with supervising public utilities. American Municipal
Power is a nonprofit composed of both utilities and resources; it both
buys and sells capacity in PJM’s market.
Unlike coal- and oil-fired resources, natural-gas-fired resources
do not store fuel on site. They are particularly vulnerable to fuel
interruptions, especially during winter storms.
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costs, because energy supply is low. Eventually, they can lead
to power outages.
The Commission identified three primary reasons for the
old market’s failure: “(i) a lack of an adequate penalty structure;
(ii) a limited ability to recover costs of necessary investments;
and (iii) an incentive to trim capital improvement plans and
operating budgets.” Rehearing Order P 23. The revisions would
address these concerns in three ways.
First, the new rules would eliminate most of the excuses for
resources that did not perform. Under the old rules, PJM did not
impose a penalty if the resource’s failure to perform was outside
of management control. This exception encouraged resource
owners to shift the blame to other parties instead of ensuring
reliability. Even when PJM deemed the resource owner
responsible for the outage, it only imposed a direct penalty if the
resource’s average performance over 500 high-demand hours
during the year was worse than that resource’s own five-year
average. A resource owner could offset the resource’s complete
non-performance during the worst hours by performing during
other “high-demand” hours. In the revised market, resource
owners would face direct penalties if the resource failed to
perform during any emergency hour.4 The new rules would
exempt resource owners from penalties in only two narrow
circumstances. The first is if the resource was on a preapproved outage, such as for maintenance. The second is if PJM
independently decided not to schedule the resource for reasons
unrelated to the costs of operating the resource.
PJM’s proposed tariff defines emergency hours, or
“Performance Assessment Hours.” PJM will declare emergency hours
when the PJM system is stressed and at risk of a shortage.
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Second, the new rules would significantly increase the
direct penalties for resources that do not perform. The direct
financial penalties under the old rules were slight. For the 20132014 year, PJM estimates that those resources that were assessed
penalties lost only 3.5% of their capacity revenues. The new
penalties could deprive resource owners of all of their capacity
revenues. These more robust penalties would discourage
resources from not meeting their capacity commitments.
Third, resource owners could offer their capacity at higher
prices under the new rules. And resources that provide more
electricity than their capacity commitment would receive
bonuses. These changes would encourage resource owners to
invest in capital improvements and upgrades to ensure
reliability. They would reduce the incentives for resource
owners to cut corners in order to submit a more competitive
The Commission concluded that the revised rules would
benefit the PJM system. The revisions would help avoid the
financial costs of energy price peaks and system outages likely
under the old system. These rules would also increase system
reliability. Higher payments and the possibility of bonuses
would encourage reliable resources to enter the market. At the
same time, higher penalties would encourage less reliable
resources to exit the market. Eventually, PJM would need to
procure less capacity to ensure reliability.
The Commission also considered the costs of the new
capacity market. See, e.g., Michigan v. E.P.A., 135 S. Ct. 2699,
2707 (2015); TransCanada Power Marketing Ltd. v. FERC, 811
F.3d 1, 11-12 (D.C. Cir. 2015). It acknowledged that the
revisions would increase the costs of obtaining capacity by
billions of dollars. On rehearing the Commission cited a formal
cost-benefit analysis, the Exelon study, which concluded that the
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new market rules would have net savings of between $900
million and $4.7 billion annually, starting in 2016. Rehearing
Order P 34. Petitioners are correct that the Exelon study used a
higher penalty for resources that failed to perform than the
penalty the Commission approved. But the savings the study
found do not depend on the amount of the penalty. The savings
come from the penalty successfully increasing reliability. The
Commission approved the lower penalty because it decided that
the penalty would sufficiently induce resources to perform and
increase reliability. See discussion infra Section IV. Even with
a lower penalty, the net savings may be substantial.
Regardless, the Commission decided that, on balance,
increased system reliability justified even a net increase in costs.
See Consol. Edison Co. of N.Y., Inc. v. FERC, 510 F.3d 333, 342
(D.C. Cir. 2007). Increased costs can be “just and reasonable”
if the costs are warranted. 16 U.S.C. § 824d(e). The
Commission explained the important non-cost reasons for
approving PJM’s proposal. It does not have to find net savings.
Process Gas Consumers Grp. v. FERC, 866 F.2d 470, 476-77
(D.C. Cir. 1989). We defer to the Commission’s weighing of
the various considerations and ultimate “policy judgment.” Md.
Pub. Serv. Comm’n v. FERC, 632 F.3d 1283, 1286 (D.C. Cir.
The Federal Power Act (the “Act”) requires that “[a]ll rates
and charges . . . by any public utility for or in connection with
the transmission or sale of electric energy” “and all rules and
regulations affecting or pertaining to such rates or charges” must
be “just and reasonable” and not “undu[ly] preferen[tial].” 16
U.S.C. § 824d(a), (b). Two sections of the Act “govern FERC’s
adjudication of just and reasonable rates . . . .” FirstEnergy
Serv. Co. v. FERC, 758 F.3d 346, 348 (D.C. Cir. 2014). Under
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section 205, when a public utility seeks to “change” any rates or
rules, it must file the proposed changes with the Commission.
16 U.S.C. § 824d(d). The utility bears “the burden of proof to
show that the increased rate . . . is just and reasonable . . . .” Id.
§ 824d(e). When acting on a public utility’s rate filing under
section 205, the Commission undertakes “an essentially passive
and reactive role” and restricts itself to evaluating the confined
proposal. City of Winnfield v. FERC, 744 F.2d 871, 875-76
(D.C. Cir. 1984).
Relatedly, section 206 authorizes the Commission to
investigate existing rates on a complaint or its own initiative. 16
U.S.C. § 824e(a). If the Commission finds that a rate is “unjust,
unreasonable, unduly discriminatory or preferential, the
Commission shall determine the just and reasonable rate . . . and
shall fix the same by order.” Id. Thus, under section 206, “[i]t
is the Commission’s job—not the petitioner’s—to find a just and
reasonable rate.” Md. Pub. Serv. Comm’n, 632 F.3d at 1285 n.1.
When the Commission changes an existing filed rate under
section 206, it is “the Commission’s burden to prove the
reasonableness of its change in methodology.” PPL Wallingford
Energy L.L.C. v. FERC, 419 F.3d 1194, 1199 (D.C. Cir. 2005).
PJM filed proposed changes to the capacity market under
section 205 (“Capacity Performance Filing”). PJM concurrently
submitted a section 206 complaint (“Energy Market Filing”),
which stated that certain PJM energy market rules were now
unjust and unreasonable and proposed replacements. Most of
the energy market rules were contained in PJM’s Operating
Agreement. PJM could not file changes to the Operating
Agreement under section 205 because it did not hold the
member vote necessary to amend the Operating Agreement.
Therefore, PJM asked the Commission to make the changes to
the Operating Agreement under section 206. The Commission
accepted PJM’s section 205 Capacity Performance Filing as just
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and reasonable, subject to compliance requirements not at issue
in this case. At the same time, the Commission granted PJM’s
section 206 Energy Market Filing, finding that provisions in
PJM’s then-current Operating Agreement were unjust and
unreasonable. A basis for the Commission’s section 206 finding
was that PJM’s Capacity Performance filing under section 205
made provisions in PJM’s Operating Agreement unjust and
unreasonable: “We agree with PJM that given the changes we
are accepting to its capacity market provisions, its existing
energy market rules with respect to operating parameters, force
majeure, and generator outages are unjust and unreasonable and
must be revised.” Tariff Order P 400.
Petitioners American Public Power Association, National
Rural Electric Cooperative Association, and Public Power
Association of New Jersey5 (“Public Power Petitioners”) assert
that the Commission’s section 205 findings were thus
irreconcilable with its section 206 findings, arguing that the
Commission could not accept PJM’s section 205 Capacity
Performance Filing as just and reasonable while simultaneously
finding that this very filing rendered the Operating Agreement
unjust and unreasonable under section 206. “In effect,” they
argue, “FERC found that PJM had created the factual premise
and legal basis for FERC to order a change in rates that PJM
could not have unilaterally made. This bootstrapping of results
is impermissible.” Pet’rs’ Br. at 54. Instead, Public Power
Petitioners assert that the Act required the Commission “to act
under section 206 alone, without first accepting a portion” of the
proposed market rule changes under section 205. Id. at 54-55.
The Commission objects to the Public Power Association of
New Jersey joining in this argument, asserting that only the American
Public Power Association and the National Rural Electric Cooperative
Association raised it on rehearing. See Resp’ts. Br. at 33-34 n.5.
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The Commission rejected this argument, noting that PJM is
permitted to make unilateral filings under section 205 to revise
capacity market provisions because they relate to the reliability
of the regional system. The Commission determined: “[W]e
cannot conclude that a proper interpretation of the FPA would
deny PJM the right it has reserved unilaterally to file changes to
its [Tariff] under section 205 merely because some related
provisions of the Operating Agreement may be implicated by the
filing.” Rehearing Order P 16.
Public Power Petitioners do not explain why PJM’s
section 205 filings regarding the capacity market necessarily
must complement existing energy market agreements to be just
and reasonable. The Commission could find that PJM’s
proposed capacity market rules were just and reasonable under
section 205 even though they rendered some rules in PJM’s
energy market unjust and unreasonable. Effects on other tariff
provisions are not dispositive. The Commission has broad
discretion to balance competing concerns. “If the total effect of
the rate order cannot be said to be unjust and unreasonable,” we
will defer to the Commission’s finding. Fed. Power Comm’n v.
Hope Nat. Gas Co., 320 U.S. 591, 602 (1944). In the analogous
Natural Gas Act context, the court has specifically recognized
that the Commission can approve a proposal as just and
reasonable even if the Commission recognizes that other rates or
rules are unjust and unreasonable. Pub. Serv. Comm’n of N.Y.
v. FERC, 866 F.2d 487, 491 (D.C. Cir. 1989).
Relatedly, the Public Power Petitioners cite no precedent for
their theory that the Commission was required to act “under
section 206 alone” in this instance. Had PJM simply waited for
the Commission’s approval of its section 205 filing to submit its
section 206 filing, there would be no issue. The Commission
has previously exercised its authority under section 206 to
modify energy market rates after determining that the
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implementation of the capacity market system via section 205
had rendered the energy market rates unjust and unreasonable.
For example, in PJM Interconnection, L.L.C., 149 FERC
¶ 61,091, P 30 (2014), the Commission found pre-existing
energy market price adders “ha[d] been rendered unjust and
unreasonable due to evolving market mechanisms, including
PJM’s implementation of its capacity market auctions.” We
have held that the Commission’s actions under the two sections
“need not be exercised in separate proceedings.” Sea Robin
Pipeline Co. v. FERC, 795 F.2d 182, 184 (D.C. Cir. 1986)
(construing equivalent provisions in the Natural Gas Act). Also,
in Public Service Commission, we noted in the context of
equivalent Natural Gas Act provisions that “where a § 4
proceeding is under way, the Commission may discover facts
that persuade it that . . . changes are appropriate that require the
exercise of its § 5 powers . . . . [T]he Commission is free to act
on those discoveries, so long as it shoulders the § 5 burdens.”
866 F.2d at 491. We therefore see no reason why the
Commission was not entitled to approve changes under section
206 in anticipation of the impacts of the section 205 filing rather
than wait for those impacts to be realized.
Moreover, the Commission did not rely solely on the
section 205 changes. It specifically found that certain existing
energy market rules were unjust and unreasonable in light of
basic capacity market objectives. The Commission found that
PJM’s existing operating-parameter provisions were “unjust and
unreasonable because they can allow capacity resources to
submit energy market offers with inflexible operating
parameters that do not reflect their current, actual operating
capabilities.” Tariff Order P 433. Such action by a capacity
resource would be “inconsistent with its obligation to make its
capacity available to the PJM region, including during the most
critical hours of the year.” Id. The Commission also found that
existing generator outage provisions “impede PJM’s ability to
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ensure reliability” because they do not give PJM the authority to
rescind approval for a planned outage when there is an
emergency. Id. P 493. Finally, the Commission found “an
expansive definition of force majeure . . . incompatible with
reasonable expectations of performance” in the context of PJM’s
“markets”—including both the capacity and energy market. Id.
P 462. These rationales support the Commission’s finding that
the energy market rules were unjust and unreasonable, even
independent of the section 205 changes to the capacity market
Because the Commission’s interpretation of the Act’s
requirements is reasonable, we defer to its judgment. See
Transmission Access Policy Study Grp. v. FERC, 225 F.3d 667,
687 (D.C. Cir. 2000) (the Commission’s interpretation of the
Act it administers is entitled to Chevron deference).
Under the revised market rules, a resource that fails to meet
its capacity commitment during an emergency hour must pay a
penalty. Two of the petitioners6 claim the penalty is too low and
will not adequately ensure performance.
petitioners argue that the formula overestimates the number of
emergency hours the PJM system will experience in a year.
Recall that generation resources can sell capacity through
the yearly auctions. When the PJM system needs additional
electricity, such as during an emergency hour, it calls on the
resources with a capacity commitment to provide the
The Public Power Association of New Jersey, a non-profit
organization representing utilities in New Jersey, and the New Jersey
Board of Public Utilities, the state agency responsible for overseeing
the state’s utilities, bring this challenge.
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corresponding level of electricity. For example, say that PJM
procures 1000 megawatts of capacity during an auction.
Resource A made a 100 megawatt capacity commitment.
During a particular emergency hour, the PJM system needs 900
megawatt-hours of energy. PJM then calls on the capacity
resources. Resource A must provide 90 megawatt-hours. If
resource A can only produce 80 megawatt-hours, it owes a
penalty for 10 megawatt-hours. And if resource A cannot
perform at all, it owes a penalty for the full 90 megawatt-hours.
The Commission approved a penalty rate of
megawatt-hour of electricity the resource does not produce.
NetCONE is the theoretical value of capacity and it is a set
number each year.7 Thirty is the estimated number of
emergency hours PJM will experience in a year. 8 To calculate
the penalty, PJM multiplies the megawatt-hours of electricity a
resource failed to provide by NetCONE . The idea is that under30
performing resource owners should repay PJM the value of the
capacity their resource did not in fact provide.
Specifically, CONE stands for the “Cost of New Entry,” and it
is the estimated cost of obtaining capacity from a new combustion
PJM initially proposed thirty hours, based on the number of
emergency hours in 2013-2014. In its Answer, PJM defended its
original estimate; however, it stated that it would be “willing to
revise” its tariff to use a rolling average of the number of emergency
hours for the three previous years. J.A. 753-54. The Commission
acknowledged that PJM was willing to make this change. Tariff Order
P. 135. The Commission decided that thirty was a just and reasonable
estimate. Thirty does not have to be better than other estimates. Duke
Energy Trading & Mktg., L.L.C. v. FERC, 315 F.3d 377, 382 (D.C.
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Petitioners claim that the Commission’s estimate of thirty
hours is too high. But petitioners’ real concern is the effect the
number thirty has on the overall penalty. Because the estimated
number of emergency hours is in the denominator, a higher
estimate results in a lower penalty. If the penalty rate is too low,
resources can make money by participating in the capacity
market even if they fail to perform during emergency hours.
This could encourage resources to make a capacity commitment
without investing in their resources to be able to meet the
The Commission acknowledged that the average number of
emergency hours over recent years is less than thirty. However,
thirty is within the range. In 2013-2014, PJM experienced thirty
emergency hours. In other recent years, many areas within PJM
experienced more than thirty emergency hours.
Commission also considered that PJM’s older oil- and coal-fired
generators are retiring and PJM is relying increasingly on
natural-gas-fired generators. These changes could cause PJM to
declare emergency hours more frequently in coming years.9
Because the Commission explained why it chose thirty hours
and pointed to supporting evidence in the record, we will not
disturb its decision. FERC v. Elec. Power Supply Ass’n, 136 S.
Ct. 760, 784 (2016).
The Commission had good reason to conclude that the
formula results in a high enough penalty to encourage resources
to meet their capacity commitments. The penalty is appropriate
The Commission’s approval was contingent on PJM filing
information about the penalty rate each delivery year. The filings
must include the revenue and penalties for various resources using the
thirty-hour estimate and higher and lower estimates. The Commission
can revise the penalty in the future if it becomes unjust and
unreasonable. See 16 U.S.C. § 824e.
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even if the region typically experiences fewer than thirty
emergency hours in a year. After all, it is “the possibility of zero
or negative net capacity revenues” that incentivizes
performance. Rehearing Order P 72. The Commission decided
the penalty was also low enough to avoid introducing “excessive
risk” into the capacity market. Id. P 73. Too high a penalty
could discourage even reliable resources from entering the
market. We defer to the Commission’s balancing of these
competing concerns. Blumenthal, 552 F.3d at 885. The
Commission adequately explained and supported its decision.
See, e.g., Elec. Power Supply Ass’n, 136 S. Ct. at 784.
PJM requires resource owners to offer capacity at a costbased rate. If a resource owner offers capacity at too high of a
rate, PJM will not consider the offer during the auctions. This
requirement prevents dominant resource owners from exercising
market power and raising the price of capacity. Under the old
market rules, resource owners could only offer capacity at a rate
equal to each individual resource’s avoidable costs. A
resource’s avoidable costs are the operational costs the resource
would not incur in the following year if it did not have a
The revised rules set a default offer cap. PJM will assume
offers below this cap are cost based and include the offer in the
capacity auction. It will independently investigate any offers
above the cap, and will only include the offer in the auction if it
determines it is cost based. Five of the petitioners, four
organizations representing utilities and the New Jersey Board of
Public Utilities, claim the cap is too high.
The Commission approved the default offer cap because it
reflects the new penalties and bonuses. Recall that resources
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with a capacity commitment must provide their share of
electricity or face a penalty. If some capacity resources do not
provide their committed share of electricity, PJM may obtain
electricity from other resources to satisfy demand. Under the
new rules, PJM would use the revenue from penalties to pay
bonuses to resources that fill the gap. Capacity resources can
earn bonuses if they produce more electricity than their
commitment. Resources without a capacity commitment earn
bonuses for all of the electricity they produce. The bonuses help
incentivize resources to perform when electricity is most needed.
The penalties and bonuses create opportunity costs for
resources with a capacity commitment. Say, for example,
Resource A and Resource B can both produce 50 megawatts of
power for a given emergency hour. Resource A has a 45
megawatt capacity commitment and Resource B does not have
a capacity commitment. Resource A will receive bonuses for
only 5 megawatt-hours. Resource B, on the other hand, will
receive bonuses for all 50 megawatt-hours. If both resources
can only produce 40 megawatts of power during the emergency
hour, Resource A will owe a penalty for 5 megawatt-hours and
receive no bonuses. But resource B will still receive bonuses for
all 40 megawatt-hours. Resource A has to earn enough in the
capacity market to make up for these lost bonuses. The new
default offer cap is set at this rate. The cap is the rate10 a
resource needs in the capacity market to earn more with a
The rate can be expressed algebraically as NetCONE × B.
Remember, NetCONE is the theoretical value of capacity. B is the
expected proportion of a resource’s capacity commitment it will need
to produce during emergency hours. It is currently set at 0.85,
meaning that PJM predicts it will need capacity resources to provide
85% of their committed capacity during emergency hours. Petitioners
do not challenge the algebraic derivation of the formula.
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capacity commitment than without. It is by definition a
competitive offer for a low-cost resource.11
Petitioners counter that the offer cap does not reflect the
resources’ actual costs. Resource owners must offer their
capacity in PJM’s capacity market in order to participate in
PJM’s energy market. Therefore, petitioners argue, a resource
owner cannot forgo a capacity commitment in order to earn
There are two problems with this argument. First, resource
owners do not have to sell capacity in PJM’s capacity market.
They only have to offer it. If PJM does not purchase the
capacity, because the offer price is too high, the resource owners
can still sell energy in PJM’s markets. Some resource owners
could also forgo participating in PJM’s markets and sell to
external energy markets. Second, PJM and the Commission can
allow resource owners to submit offers that take into
consideration opportunity costs, even if they require resource
owners to offer all available capacity. The must-offer
requirement is a market mechanism to prevent artificial
scarcity.12 It prevents resource owners from making rational
economic decisions based on the risks and benefits of offering
to sell capacity in the market. PJM can still allow resources to
recover these costs from the market. Market mitigation
A low-cost resource is a resource that could make a profit
without any capacity commitment. A resource that must make a
capacity commitment in order to be profitable does not have the same
opportunity costs. PJM will continue to calculate unit-specific offer
caps for resources that cannot cover their operating costs without
making a capacity commitment.
The must-offer requirement prevents resource owners from
withholding some of their capacity from the market in order to drive
up the price of capacity.
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measures do not need to protect consumers from the actual costs
of capacity. The Commission reasonably concluded that
resource owners can consider all of their costs and risks in
formulating an offer.
This brings us to petitioners’ other objection: that the offer
cap will raise the price of capacity and could harm reliability.
The Commission had three responses. First, increased capacity
prices are necessary. Resource owners need to be able to offer
capacity at a higher price in order to recover the costs of
improvements. PJM wants to encourage new, reliable resources
to enter the capacity market. Second, although capacity will
become more expensive, it will not necessarily reach the default
offer cap. Resource owners take into consideration a variety of
factors in formulating offers. Third, the higher clearing prices
will not encourage resource owners to make capacity offers they
do not intend to keep. As we have already discussed, underperforming resources face significant, unavoidable penalties
under the new rules. The Commission was aware of the
potential for higher capacities prices when it approved the
penalty. It reasonably determined that the penalty is sufficient
to encourage performance. See discussion supra Section IV.
To ensure year-round capacity, PJM’s revised market rules
require sustained, predictable operation from all capacity
resources. The Commission found PJM’s year-round capacity
requirement reasonable, both in the Commission’s initial order
and on rehearing, “because [the requirement] creates the same
expectations for all Capacity Performance Resources (i.e., the
expectation that such resources will be available to provide
energy and reserves when called upon), without regard to
technology type.” Tariff Order P 99; Rehearing Order P 59
(“PJM is treating all resources identically . . . .”). The
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performance of some capacity resources, however, such as wind
and solar resources, will necessarily vary by season. This led
the Commission to conclude that “non-year-round resources do
not provide equivalent service as year-round resources,” which
“could result in a loss of reliability during the fall, winter and
spring.” Rehearing Order P 59.
Concerns over reliable capacity led the Commission to
reject exempting non-year-round resources from the year-round
requirement, see id., but the Commission allowed those
resources to aggregate their respective performance and make a
single capacity offer, id. P 51. Aggregation allows the non-yearround resources an opportunity to expand competition within the
capacity market by bidding alongside the year-round resources.
For example, wind resources generate more electricity during
the winter than during the summer and no amount of investment
can change that. Because of the Capacity Performance market’s
year-round requirement, a wind resource could only offer at its
summer generation limit without risking significant penalties.
Under PJM’s plan, wind resources could pair with summerpeaking resources, such as solar resources, to offer more
capacity. At the same time, by not allowing all resources to
submit aggregated offers, sustained, predictable capacity
operation by each bidding resource is preserved, and the
individual-resource bidding process is not “transform[ed]” into
a “portfolio-bidding approach” that neither the Commission nor
PJM embraced. See Tariff Order P 102.
Various petitioners challenge this entire scheme—the
metric of annual capacity performance, the disparate treatment
it poses for non-year-round resources, and the use of and
limitations on aggregate offers—as unduly discriminatory. See
16 U.S.C. § 824d(b) (prohibiting a utility from “grant[ing] any
undue preference or advantage” or “subject[ing] any person to
any undue prejudice or disadvantage”); cf. Ala. Elec. Coop., Inc.
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v. FERC, 684 F.2d 20, 21, 27-28 (D.C. Cir. 1982) (explaining
that, in the “unusual case,” the same rate charged to differentlysituated customers could be undue discrimination). Petitioners
Natural Resources Defense Council, Sierra Club, and Union of
Concerned Scientists challenge the year-round capacity
requirement both as a metric of quality and the “disparate
burdens” it imposes on non-year-round resources. Aggregation,
in their view, does not dissipate the discrimination; non-yearround resources are required to absorb aggregation’s
“transaction costs” that are not experienced by annual resources.
Petitioner American Municipal Power (“AMP”) contends that
the aggregation does not go far enough, and the new capacity
market rules should allow all resources to aggregate. In AMP’s
view, limiting aggregation to non-year-round resources is
discriminatory because some traditional resources may also be
unable to upgrade to ensure performance. And the Commission
did not explain, AMP claims, how allowing all resources to
aggregate would transform the individual-resource bidding
process into a portfolio approach, but allowing non-year-round
resources to aggregate would not. In AMP’s view, aggregation
should either apply to all resources or to none. AMP also
contends the Commission’s decision to reject aggregation across
“Locational Deliverability Areas,” geographically designated
areas within PJM where PJM may be unable to transmit enough
capacity from other parts of the PJM region to ensure reliability,
was also unreasoned. None of these challenges overcome the
deferential standard of review afforded the Commission’s
The Commission suggests these challenges were not raised
within petitioners’ rehearing request and are, accordingly, waived.
Petitioners, while conceding their arguments were raised only
“brief[ly]” below and not in the plainest of language, note their
arguments were mentioned in the “body” of their rehearing request.
As “even [a] brief assertion” of the grounds for rehearing is
“sufficient,” petitioners’ arguments are not waived. See, e.g., La.
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The year-round capacity commitment is at the core of what
PJM expects of capacity resources and the essential attribute of
its revised market rules. PJM’s experience with winter weather
events in 2014, discussed above, confirmed the virtue of
capacity that is available to perform at any time, year round.
This experience reinforced the prior treatment of solar and wind
as “an Annual Resource,” see PJM Interconnection, L.L.C., 146
FERC ¶ 61,052, P 2 (2014), and the rejection of “seasonal
pricing and operational reliability requirements” since the
creation of PJM’s capacity market, see PJM Interconnection,
L.L.C., 117 FERC ¶ 61,331, P 29 (2006). The Commission
explained why allowing non-year-round resources to meet only
a seasonal capacity standard would threaten annual capacity
reliability. See Rehearing Order P 59. The Commission
explained that exempting non-year-round resources from the
annual capacity requirement would mean PJM would not have
as many available resources in non-summer months, which
could reduce reliability. The Commission’s statements are
supported by record evidence justifying PJM’s connection of
annual capacity availability with reliability. See J.A. 74-76
(explaining how PJM had to alter its reliability goals by ten
percent “to facilitate the commitment of less-available resources
to be an acceptable level of risk”). Even if, as the environmental
petitioners claim, some measurement of reliability other than
annual capacity availability is just and reasonable, the relevant
question here is whether the annual standard the Commission
approved is just and reasonable. See Fla. Gas Transmission Co.
v. FERC, 604 F.3d 636, 645 (D.C. Cir. 2010). The
Commission’s policy decision to assess reliability through a
year-round capacity commitment is the type of policy judgment
Intrastate Gas Corp. v. FERC, 962 F.2d 37, 42 (D.C. Cir. 1992).
Moreover, the Commission explicitly considered—and rejected—the
substance of these arguments on rehearing. See, e.g., Rehearing Order
P 59. Sidestepping petitioners’ arguments here would elevate form to
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to which we afford deference, and that deference is justified by
We reject petitioners’ claim that the year-round
requirement imposes undue discrimination against non-yearround resources. 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. To be sure, if the rate
requirement at issue is a uniform requirement based on a
generator’s costs, but costs vary based on the generator, insisting
all generators meet one generator’s costs would be the “unusual
case” of a uniform standard constituting undue discrimination.
See, e.g., Alabama Electric Cooperative, Inc., 684 F.2d at 21,
27-28. But “Alabama Electric does not stand for the proposition
that charging the same rates to differently situated customers
always constitutes undue discrimination.” Complex Consol.
Edison Co. of N.Y., Inc. v. FERC, 165 F.3d 992, 1013 (D.C. Cir.
To assess undue discrimination, the “critical determination”
is whether the uniform performance requirement at issue—here,
the requirement of year-round capacity availability—constitutes
undue discrimination against non-year-round resources. See id.
Requiring that capacity be available at any time does
disadvantage resources with seasonally-fluctuating capacity.
But, “the difference in service here was not unreasonable
because of operational constraints.” Id. at 1014. As the
Commission observed, “non-year-round resources do not
provide equivalent service as year-round resources.” Rehearing
Order P 59; id. P 51 (“no reasonable amount of investment can
mitigate the non-performance risk they face”). Indeed, even
petitioners acknowledge that, on the metric of annual
availability, “of course annual resources will appear superior.”
Pet’rs’ Br. at 74. “The court will not find a Commission
Page 24 of 32
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determination to be unduly discriminatory if the entity claiming
discrimination is not similarly situated to others.” Transmission
Agency of N. Cal. v. FERC, 628 F.3d 538, 549 (D.C. Cir. 2010).
Using an annual performance standard is a reflection of the
Commission’s policy judgment as to the level of capacity
performance the market requires, not an undue privileging of
one resource’s costs over another’s. We defer to the
Moreover, the disparate effect on non-year-round resources
is mitigated by their ability to make aggregated capacity offers.
The Commission considered aggregated offers “a reasonable
accommodation to permit greater participation in the capacity
market” from non-year-round resources; expanding competition
within the capacity market to the benefit of consumers while not
undermining the annual capacity requirement’s reliability goal.
Rehearing Order P 51. The aggregation accommodation is only
available to non-year-round resources, see id., and for good
reason: this accommodation reflects the resources’ operational
nature, it is not intended to undermine individual capacity
bidding in general. See Tariff Order P 102. The environmental
petitioners contend aggregation does not obviate the
discrimination of a year-round performance standard because
aggregation itself imposes “transaction costs.” Petitioners cite
no record evidence for this proposition, however, and their
briefing does not specify what these costs are. Their brief makes
only the vague assertion that “resources with complementary
availability within the same delivery area” will be “burden[ed]
. . . with” “finding each other,” putting together a single capacity
offer, and determining how to “share the risks and rewards of
Capacity Performance.” Pet’rs’ Br. at 75. Even if such costs are
bona fide, aggregation is merely an accommodation, not a rate,
and the rate standard does not itself produce undue
discrimination. Nothing in applicable law requires a rate
standard to result in no disparate impact on any power resource
Page 25 of 32
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whatsoever. The aggregated offer accommodation is just and
Finally, the challenges to the limitations on the aggregation
accommodation are without merit. The accommodation’s goal
is to expand the number of capacity resources that can
participate in capacity auctions, not change the bidding process
itself. Yet that would be the result of expanding the aggregation
accommodation beyond non-year-round resources, as AMP
Such “portfolio” bidding is, according to the
Commission, not necessary to ensuring reliable capacity, and we
defer to the Commission’s policy judgments. Similarly, the
Commission acted reasonably in limiting aggregation to those
capacity resources within the same “Locational Deliverability
Areas.” These Areas are designed to ensure prompt response to
a capacity demand. If PJM relied on the capacity promised by
an aggregated bid, and the aggregation occurred across multiple
Areas, an obvious risk to the sustained, predictable deliverability
of reliable capacity comes into view. See, e.g., Tariff Order P
103. PJM indicated in its Answer that “it can permit
aggregation across” Locational Deliverability Areas. J.A. 714.
But the Commission reasonably concluded that PJM had not
proven that the proposal was just and reasonable. PJM
designates a Locational Deliverability Area as constrained if
PJM predicts it will have limited ability to transfer enough
capacity into the area to ensure reliability. In such cases,
capacity commitments from outside the Locational
Deliverability Area might not help during emergency conditions.
See Rehearing Order P 52. The Commission’s decision to
disallow aggregation across these Areas was just and reasonable.
Petitioner Advanced Energy Management Alliance
(“AEMA”) raises a narrow challenge to the Commission’s
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orders approving PJM’s demand resource rules, asserting that
the orders are arbitrary and capricious because “[t]he
Commission accepted, without explanation, the same type of
demand resource performance rules it had previously rejected in
approving PJM’s prior capacity market construct.” Pet’rs’ Br.
Demand resources do not produce electricity. Instead, a
demand resource provides capacity by obtaining commitments
from consumers to decrease electricity consumption during peak
periods. See Elec. Power Supply Ass’n, 136 S. Ct. at 767. PJM
calculates a demand resource’s performance in order to
determine whether the demand resource met its capacity
commitment. A demand resource’s performance at any given
time equals its customers’ expected consumption—i.e., how
much they are expected to consume if PJM does not instruct
them to reduce their consumption—minus their actual
consumption. AEMA challenges PJM’s proposed method of
calculating a demand resource’s expected consumption.
PJM proposed to use two formulas for calculating expected
consumption—one for estimating expected consumption during
summer months and one for estimating expected consumption
during non-summer months (with one limited exception not
relevant to this case). The summer formula (termed the annualpeak or “Peak Load Contribution” method) is based on a
demand resource customer’s contribution to the five hours of the
previous year when system-wide demand peaked. See, e.g.,
PJM Interconnection, L.L.C., 137 FERC ¶ 61,108, P 1 n.2
(2011). In comparison, the non-summer formula (termed the
recent-peak or “Customer Baseline Load method”) is based on
a demand resource customer’s contribution to the system’s load
for the four days of peak system-wide load during the most
recent forty-five days. See, e.g., id. P 10 n.24; PJM
Interconnection, L.L.C., 137 FERC ¶ 61,216, P 47 (2011).
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AEMA supports the annual-peak method but challenges the
recent-peak method. AEMA contends that the Commission’s
orders are arbitrary and capricious because the Commission’s
“approval of PJM’s rules governing demand resource
performance departs from prior determinations addressing the
same subject matter without providing a reasoned explanation.”
Pet’rs’ Br. at 76. AEMA asserts that the Commission previously
rejected the recent-peak method and accepted the annual-peak
method, id. at 78 (citing PJM Interconnection, L.L.C., 137
FERC ¶ 61,108 (2011)), consistent with precedent, id. at 78-79
(citing La. Pub. Serv. Comm’n v. FERC, 184 F.3d 892, 895
(D.C. Cir. 1999); Town of Norwood v. FERC, 962 F.2d 20, 26
(D.C. Cir. 1992)). Further, AEMA argues, the recent-peak
method “is unrelated to the quantity of capacity . . . PJM avoids
purchasing when the customer commits to reduce load[,]”
instead “measur[ing] demand resource performance in off-peak
periods that do not affect the cost of PJM’s capacity
procurement.” Pet’rs’ Br. at 82.
As the Commission noted, “PJM’s Capacity Performance
proposal was put in place, in part, to create the proper incentives
for resources to perform all year round, and more specifically in
the winter.” Rehearing Order P 120. Demand resources, like all
other capacity resources under the Capacity Performance rules,
are annual products and thus their performance must be
measured any time the PJM system has an urgent need for
capacity—i.e., during emergency hours.
performance in the winter against the summer peak is
problematic because a customer’s normal energy use in the
winter may already be lower than its summer peak. If called
upon to reduce usage in the winter, a demand resource could
claim to have reduced its energy usage below its summer peak,
when in reality it continued its normal winter usage and is
requesting payment despite doing nothing to alleviate the
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Measuring demand resource performance against its recent
peak load “help[s] guarantee that Demand Resources are
available to be dispatched to help supply meet demand in the
winter period.” Id. It was therefore reasonable for the
Commission to accept PJM’s proposal to use the recent-peak
method for non-summer months. See Elec. Power Supply Ass’n,
136 S. Ct. at 784 (finding reasoned decision-making where the
Commission “weighed competing views, selected a
compensation formula with adequate support in the record, and
intelligibly explained the reasons for making that choice”).
AEMA’s principal argument is that the Commission did not
adequately distinguish its action in an earlier proceeding
affirming reliance on the annual-peak method to measure
performance. But the previous proceeding concerned only
summer performance. See PJM Interconnection, L.L.C., 137
FERC ¶ 61,108, P 51 (2011). The annual demand resource
product, expected to perform year-round, did not yet exist.
Indeed, the Commission expressly recognized that the annualpeak method may not be appropriate for non-summer
measurement and urged PJM “to give consideration to how to
appropriately measure performance of capacity for resources
that are procured specifically to perform outside of PJM’s June
through September summer period.” Id. P 85. The Commission
thus reasonably distinguished the 2011 action, explaining that
Capacity Performance “has stronger performance incentives
than the preexisting capacity product, with an emphasis on
improved resource performance in winter periods,” which
“provides PJM adequate justification to move to a stronger
measurement standard than was approved through [the earlier
proceeding].” Rehearing Order P 124.
Finally, AEMA argues that under the proposed method,
demand resources “are penalized by not receiving compensation
for the full value of their on-peak summertime load reduction
Page 29 of 32
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capability and may even be precluded from participating.”
Pet’rs’ Br. at 77. This argument simply rehashes the more
general dispute with the annual requirement of the Capacity
Performance proposal as applied to demand resources and is
Because it was reasonable for the Commission to accept
PJM’s proposal to use the recent-peak method for non-summer
months and any alleged departure from past practice was
adequately explained, we defer to the Commission’s
determination on this issue. See, e.g., Elec. Power Supply Ass’n,
136 S. Ct. at 784.
Petitioner AMP also challenges the imposition of Capacity
Performance penalties on resources that fail to perform due to
unit-specific constraints. Under PJM’s proposal, resources
generally incur non-performance penalties if they do not operate
in an emergency hour. However, PJM proposed two exceptions.
First, a resource would not incur a non-performance penalty if
it is unavailable due to a PJM-approved planned outage or
maintenance outage. Second, a resource generally would not
incur a non-performance penalty for failing to perform during an
emergency hour if PJM did not schedule it to operate. However,
if the reason PJM did not schedule the resource to operate is (1)
due to the seller’s own operating-parameter limitations or (2)
because the seller offered its energy at a market-based price that
was higher than its cost-based price, then a resource nevertheless
incurs a non-performance penalty.
AMP argues that these rules are inconsistent with energy
market rules, which require PJM to cover a resource’s costs if
PJM schedules the resource to run outside of its parameter
limits. AMP also argues that penalizing a resource for failing to
Page 30 of 32
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operate when the resource “ha[s] little or no ability to operate
beyond [its] unit-specific parameters at any cost” is
unreasonable. Pet’rs’ Reply Br. at 37-38.
Given the different purposes of the capacity market and the
energy market, there is no inconsistency in treating the
operating-parameter limitations differently in the two markets.
A Capacity Performance resource commits to perform whenever
needed and sets its market offer to cover the costs of ensuring its
ability to perform. Given this commitment, it is reasonable for
PJM to apply a non-performance charge when a resource is not
available pursuant to its obligation. In contrast, a resource in the
energy market—which does not have the same
commitments—may choose not to perform when called upon to
perform outside its operating parameters if the cost of
performing is higher than the price it will receive. In that
scenario, PJM covers the resource’s actual costs so that the
resource is incentivized to run when called upon. “If PJM did
not cover the costs resulting from the parameter limit, the
resource might choose not to run when scheduled, potentially
causing reliability problems.” Rehearing Order P 105.
Finally, the Commission concluded that it is reasonable to
penalize a resource for failing to operate outside of its parameter
limitations. It explained that
parameter limits should not be viewed as a
permanent entitlement to under-perform.
Instead, those limits should be exposed to
financial and market consequences: if sellers of
resources with fewer operating limits earn more
from the capacity market (after taking NonPerformance Charge and Performance credits
into account) than sellers of resources with more
restrictive operating limits, then all sellers will
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be incented to find ways to minimize those
operating limits, which should over time increase
overall fleet performance and benefit loads in the
Id. P 103 (quoting PJM December 12, 2014 Capacity Markets
Filing at 46) (internal quotation marks and alterations omitted).
In other words, the Commission approves of PJM’s decision to
hold resources with restrictive operating limits to the same
standards as resources with fewer limitations. Over time, the
Commission believes, the market will incentivize all sellers to
minimize operating limits, thereby increasing overall
Because the Commission’s explanation is reasonable, we
defer to its conclusion that operating limits cannot excuse nonperformance in the capacity market. See S.C. Pub. Serv. Auth.
v. FERC, 762 F.3d 41, 55 (D.C. Cir. 2014) (“[T]he Commission
must have considerable latitude in developing a methodology
responsive to its regulatory challenge[.]”) (internal quotation
omitted); see also Tenn. Gas Pipeline Co. v. FERC, 400 F.3d 23,
27 (D.C. Cir. 2005) (noting that “[t]he court properly defers to
policy determinations invoking the Commission’s expertise in
evaluating complex market conditions”).
For the foregoing reasons, the petitions for review are
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