New Jersey Board of Public Utilities v. Federal Energy Regulatory Commission , 744 F.3d 74 ( 2014 )

PRECEDENTIAL
UNITED STATES COURT OF APPEALS
FOR THE THIRD CIRCUIT
Nos. 11-4245, 11-4405, 11-4486, 11-4487, 12-1085, 12-1086
and 12-1764
NEW JERSEY BOARD OF PUBLIC UTILITIES
AND NEW JERSEY DIVISION OF RATE COUNSEL,
Petitioners in Case No. 11-4245
v.
FEDERAL ENERGY REGULATORY COMMISSION,
Respondent
MARYLAND PUBLIC SERVICE COMMISSION,
Petitioner in Case No. 11-4405
v.
FEDERAL ENERGY REGULATORY COMMISSION,
Respondent
PJM POWER PROVIDERS GROUP,
Petitioner in Case No. 11-4486
v.
FEDERAL ENERGY REGULATORY COMMISSION,
Respondent
PSEG ENERGY RESOURCES & TRADE LLC,
Petitioner in Case No. 11-4487
v.
FEDERAL ENERGY REGULATORY COMMISSION,
Respondent
OLD DOMINION ELECTRIC COOPERATIVE;
AMERICAN PUBLIC POWER ASSOCIATION;
NATIONAL RURAL ELECTRIC COOPERATIVE
ASSOCIATION;
NORTH CAROLINA ELECTRIC MEMBERSHIP
CORPORATION;
DELAWARE MUNICIPAL ELECTRIC CORPORATION
AMERICAN MUNICIPAL POWER, INC.;
2
*SOUTHERN MARYLAND ELECTRIC COOPERATIVE,
INC.,
Petitioners in Case No. 12-1085
v.
FEDERAL ENERGY REGULATORY COMMISSION,
Respondent
* Pursuant to Clerk Order of 2/14/12.
HESS CORPORATION,
Petitioner in Case No. 12-1086
v.
FEDERAL ENERGY REGULATORY COMMISSION,
Respondent
OLD DOMINION ELECTRIC COOPERATIVE;
AMERICAN MUNICIPAL POWER, INC.;
NORTH CAROLINA ELECTRIC MEMBERSHIP CORP.;
AMERICAN PUBLIC POWER ASSOCIATION;
DELAWARE MUNICIPAL ELECTRIC CORP.; and
3
NATIONAL RURAL ELECTRIC COOPERATIVE
ASSOCIATION,
Petitioners in Case No. 12-1764
v.
FEDERAL ENERGY REGULATORY COMMISSION,
Respondent
Petition for Review of an Orders of the
Federal Energy Regulatory Commission
(FERC-1:135 FERC 61,022; FERC-1:137 FERC 61,145;
FERC-1:FERC-ER11-2875-000; FERC-1:FERC-EL11-20-
000; FERC-1:FERC-ER11-2875-001; FERC-1:138 FERC 61,
194)
Argued September 10, 2013
Before: RENDELL, JORDAN and GREENAWAY, JR.,
Circuit Judges
(Opinion filed February 20, 2014)
4
Jennifer S. Hsia, Esquire
Office of Attorney General of New Jersey
Division of Law
Richard J. Hughes Justice Complex
25 Market Street
Trenton, NJ 08625
Alex Moreau, Esquire
Office of Attorney General of New Jersey
124 Halsey Street
P. O. Box 45029
Newark, NJ 07102
Counsel for New Jersey Board of Public
Utilities
Stefanie A. Brand, Esquire
Felicia Thomas-Fried, Esquire
Office of Public Defender
Division of the Ratepayer Advocate
140 East Front Street, 4th Floor
P. O. Box 003
Trenton, NJ 08625
Scott H. Strauss, Esquire (Argued)
Jeffrey A. Schwarz, Esquire
Spiegel & McDiarmid
1333 New Hampshire Avenue, N.W.
Washington, D.C. 20036
Counsel for New Jersey Division of Rate
Counsel
5
Harvey L. Reiter, Esquire
Dennis Lane, Esquire (Argued)
Adrienne E. Clair, Esquire
Stinson Morrison & Hecker, LLP
1775 Pennsylvania Avenue, N. W.
Washington, D. C. 20006
Counsel for Old Dominion Electric
Cooperative; American Public Power
Association; National Rural Electric
Cooperative Association, Delaware
Municipal Electric Corp; Southern
Maryland Electric Cooperative Inc,
American Municipal Power, Inc
Larry F. Eisenstat, Esquire
Crowell & Moring
1001 Pennsylvania Avenue, N. W.
Washington, D. C. 20004
Counsel for CPV Power Development,
Inc.
Werner L. Margard, III, Esquire
Office of Attorney General of Ohio
Public Utilities Division
180 East Broad Street
Columbus, OH 43266
Counsel for Public Utilities Commission
of Ohio
6
Susanna Chu, Esquire (Argued)
Randall L. Speck, Esquire
Kaye Scholer
901 15th Street, N.W.
Washington, D. C. 20005
Counsel for Maryland Public Service
Commission
Regina A. Iorii, Esquire
Delaware Department of Justice
820 North French Street
Carvel Office Building, 6th Floor
Wilmington, DE 19801
Counsel for Delaware Public Service
Commission
Gregory T. D’Auria, I, Esquire
Office Attorney General of Connecticut
55 Elm Street
P. O. Box 120 Hartford, CT 061606
Counsel for Attorney General
Connecticut
Stuart A. Caplan, Esquire
Dentons US
1221 Avenue of the Americas
New York, NY 10020
Counsel for Hess Corp
7
Gary J. Newell, Esquire
Jennings Strouss
1350 I Street, N. W.
Suite 810
Washington, D. C. 20005
Counsel for American Municipal Power,
Inc.
Sandra E. Rizzo, Esquire
Charles H. Shoneman, Esquire
Bracewell & Guiliani
2000 K Street, N. W.
Suite 500
Washington, D. C. 20006
Counsel for PPL Electric Utilities
Corporation; PPL Energy Plus, LLC;
PPL Brunner Island; PPL Holtwood,
LLC; PPL Martins Creek; PPL Montour,
LLC; PPL Susquehanna, LLC; PPL New
Jersey Solar, LLC; PPL New Jersey
Biogas, LLC; PPL Renewable Energy,
LLC; Lower Mount Bethel Energy, LLC
8
Paula M. Carnody, Esquire
William F. Fields, Esquire
Maryland Peoples Counsel
6 St. Paul Street, Suite 2102
Baltimore, MD 21202
Counsel for Maryland Office of Peoples
Counsel
Christopher R. Jones, Esquire
Troutman Sanders
401 9th Street, N.W.
Suite 1000
Washington, D. C. 20004
Counsel for Dominion Resources
Services
Denise C. Goulet, Esquire
Miller, Balis & O’Neil
1015 15th Street, N. W.
Washington, D. C. 20005
Counsel for North Carolina Electric
Membership Corporation
9
Robert A. Weishaar, Jr., Esquire
McNees, Wallace & Nurick
777 North Capitol Street, N. E.
Suite 401
Washington, D. C. 20002
Counsel for PJM Industrial Customer
Coalition
Carol Banta, Esquire (Argued)
Holly E. Cafer, Esquire (Argued)
Federal Energy Regulatory Commission
888 1st Street, N. E.
Washington, D. C. 20426
Counsel for Federal Energy Regulatory
Commission
Ashley C. Parrish, Esquire
David G. Tewksbury, Esquire
King & Spalding
11700 Pennsylvania Avenue, N. W.
Suite 200
Washington, D. C. 20006
Counsel for Electric Power Supply
Association; Calpine Corporation
10
Paul M. Flynn, Esquire (Argued)
Wright & Talisman
1200 G Street, N. W.
Suite 600
Washington, D. C. 20005
Counsel for PJM Interconnections
Adam M. Conrad, Esquire
King & Spalding
100 North Tryon Street
Suite 3900
Charlotte, NC 28202
Counsel for LS Power Associates, LP
John N. Estes, III, Esquire (Argued)
John L. Shepherd, Jr., Esquire (Argued)
Paul F. Wight, Esquire
Skadden, Arps, Slate, Meagher & Flom
1440 New York Avenue, N.W.
Washington, DC 20005
Counsel for PJM Power Providers
Group; Exelon Corporation
11
Richard P. Bress, Esquire
Andrew D. Prins, Esquire
Latham & Watkins
555 11th Street, N.W.
Suite 1000
Washington, DC 20004
Counsel for FirstEnergy Solutions
Corporation
Vilna W. Gaston, Esquire
Tamara L. Linde, Esquire
PSEG Corporation
Room T5G
80 Park Plaza
Newark, NJ 07101-0570
Counsel for PSEG Energy Resources &
Trade, LLC
Robert C. Fallon, Esquire
Jonathan W. Gottlieb, Esquire
Stinson Leonard Street
1775 Pennsylvania Avenue, N.W.
Suite 800
Washington, DC 20006
Counsel for Commonwealth Chesapeake
Corp
12
OPINION
RENDELL, Circuit Judge:
In what is a relatively unusual task for our court, we
are asked to review a ruling of the Federal Energy Regulatory
Commission (“FERC”) approving a revised tariff submitted
by PJM Interconnection, LLC, that effectively changes
several aspects of PJM’s tariff as approved in a prior FERC
order. FERC is the independent federal agency tasked under
the Federal Power Act (the “FPA”) with, among other things,
ensuring that rates charged by public utilities for the
transmission and sale of energy in interstate commerce, and
the “rules and regulations affecting or pertaining to such
rates”, are “just and reasonable.” 16 U.S.C. § 824d.
In 2006, FERC issued an order (the “2006 Order”)
approving a new tariff—a set of rules and policies governing
the interstate sale of electricity and electric capacity—for the
PJM market, a vast region covering thirteen states and the
District of Columbia. The terms and policies embodied in the
2006 Order—the result of an extensively negotiated
settlement between power providers, utility companies, state
and local authorities and other stakeholders in the region—
sought to ensure the existence of sufficient power generation
facilities to meet the needs of the PJM market. To this end,
the order required that load serving entities (LSEs) in the PJM
market procure a certain amount of energy capacity—that is,
additional generation resources that the market may access
during times of peak load. The 2006 Order also contained
rules designed to curb the ability of market participants to
distort wholesale prices through the exercise of market power.
13
A chief means to that end was the rule that offers for the sale
of capacity in the PJM markets at artificially low prices
would, with some notable exceptions, be required to be
“mitigated”, or raised to a competitive level, based on their
costs.
Beginning in April 2011, FERC issued three orders
(the “2011 Orders”) that altered the terms of the 2006 Order
in several ways, some substantial. Among other things, the
2011 Orders eliminated an exemption from mitigation for
resources built pursuant to a state mandate. In addition, the
2011 Orders eliminated a provision that had guaranteed that
LSEs that owned their own generation resources, or had
procured capacity through bilateral contracts, would be able
to use this “self-supply” to satisfy their own capacity
obligations. The 2011 Orders also changed several factors
used in determining whether a particular offer was subject to
mitigation.
As discussed infra, multiple parties have timely filed
Petitions for Review of the 2011 Orders. 1 Petitioners New
1
We have jurisdiction to review FERC’s orders under FPA §
313(b), 16 U.S.C. § 825l(b), which provides that, “[a]ny party
to a proceeding under this chapter aggrieved by an order
issued by the Commission in such proceeding may obtain a
review of such order in the United States Court of Appeals for
any circuit wherein the licensee or public utility to which the
order relates is located or has its principal place of business,
or in the United States Court of Appeals for the District of
Columbia, by filing in such court, within sixty days after the
order of the Commission upon the application for rehearing, a
written petition praying that the order of the Commission be
modified or set aside in whole or in part.” 16 U.S.C. §
14
Jersey and Maryland contend that the 2011 Orders amount to
direct regulation of power facilities in violation of the FPA,
and that FERC acted arbitrarily and capriciously in
eliminating the exemption from mitigation for state-mandated
resources. Similarly, several municipal and cooperative
electric utilities challenge FERC’s elimination of the
assurance that LSEs could use their own self-supply to satisfy
their capacity obligations. Finally, various energy providers
take issue with new rules governing the calculation of a
resource’s net cost of new entry, which is used in determining
whether an offer for the sale of capacity will be mitigated,
and with FERC’s determination that a new generation
resource must clear only one capacity auction in order to
avoid further mitigation. We have considered these
arguments and find them without merit. Accordingly, we
deny the petitions for review.
I.
At the time the FPA was passed in 1935, “most
electricity was sold by vertically integrated utilities that had
constructed their own power plants, transmission lines, and
local delivery systems. Although there were some
interconnections among utilities, most operated as separate,
local monopolies subject to state or local regulation.” New
825l(b). New Jersey, Maryland, Hess Corporation, and Load
Petitioners filed petitions for review in this Court. Cross-
Petitioners PJM Power Providers Group and PSEG Energy
Resources & Trade, LLC (collectively, “P3”) filed petitions
for review in the D.C. Circuit. On December 8, 2011, the
U.S. Judicial Panel on Multidistrict Litigation consolidated all
petitions for review in this Court.
15
York v. FERC, 535 U.S. 1, 5 (2002). In 1927 the Supreme
Court held in Public Utilities Commission v. Attleboro Steam
& Electric Co., 273 U.S. 83 (1927), that only Congress, and
not the states, could regulate the sale of electrical power in
interstate commerce. To meet this charge, Congress enacted
the FPA, which authorized federal regulation of the interstate
sale of electricity, and created a new independent agency, the
Federal Power Commission (precursor to FERC), to
administer the statute. New York, 535 U.S. at 6-7. Section
201 of the FPA defined the Commission’s jurisdiction as “the
transmission of electric energy in interstate commerce and the
sale of such energy at wholesale in interstate commerce . . . .”
16 U.S.C § 824(a). The statute gave the Commission
regulatory power over “all facilities for such transmission or
sale of electric energy”, but withheld jurisdiction over
“facilities used for the generation of electric energy” which
remained subject to state and local regulation. § 824(b)(1).
Section 205 tasked the Commission with ensuring that “[a]ll
rates and charges made, demanded or received 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 shall be just and
reasonable,” and prohibited utilities engaged in the
transmission or sale of energy in interstate commerce from
“mak[ing] or grant[ing] any undue preference or advantage to
any person or subject[ing] any person to any undue prejudice
or disadvantage, or [] maintain[ing] any unreasonable
difference in rates, charges, service, facilities, or in any other
respect, either as between localities or as between classes of
service.” § 824d. Section 206 gave the Commission the
power to correct rates, or “any rule, regulation, practice, or
contract affecting such rate[s]” that it deemed unjust and
unreasonable. § 824e(a).
16
In the nearly eight decades since the FPA was enacted,
technological advances have revolutionized the way electric
power is generated and transmitted. Transmission grids are
now largely interconnected, which means that “any electricity
that enters the grid immediately becomes a part of a vast pool
of energy that is constantly moving in interstate commerce.”
New York, 535 U.S. at 7. In addition to making the transfer of
electricity over long distances more efficient, the
development of a national, interconnected grid has made it
possible for a generator in one state to serve customers in
another, thus opening the door to potential competition that
did not previously exist. Id. at 8. Public utilities still retain
ownership over transmission lines, however, and so, until
recently, had the ability to stifle competition from new
generators by “refus[ing] to deliver energy produced by
competitors or [by] deliver[ing] competitors’ power on terms
and conditions less favorable than those they apply to their
own transmissions.” Id. at 8-9. Congress changed this with
two pieces of legislation—the Public Utility Regulatory
Policies Act of 1978 (“PURPA”), Pub. L. 95-617, and the
Energy Policy Act of 1992, Pub. L. 102-486. Respectively,
those two statutes obligated traditional utilities to purchase
electricity from “nontraditional facilities,” and authorized
FERC to order utilities to provide transmission services to
independent generators. New York, 535 U.S. at 9. In 1996,
FERC issued a landmark ruling requiring the “functional
unbundling” of wholesale generation and transmission
services, and requiring utilities to provide open, non-
discriminatory access to their transmission facilities. 2
2
Promoting Wholesale Competition Through Open Access
Non-discriminatory Transmission Services by Public Utilities
17
In response to the changing conditions in the energy
market in recent years, FERC has changed its approach to
regulating rates. Rather than setting rates for each public
utility, FERC now seeks to ensure that market-based rates are
“just and reasonable” largely by overseeing the integrity of
the interstate energy markets. See Consol. Edison Co. of
N.Y., Inc. v. FERC, 347 F.3d 964, 967 (D.C. Cir. 2003) (“The
Federal Energy Regulatory Commission oversees this market-
based system pursuant to the Federal Power Act”); La.
Energy & Power Auth. v. FERC, 141 F.3d 364, 365 (D.C. Cir.
1998) (“[T]he Commission approves applications to sell
electric energy at market-based rates only if the seller and its
affiliates do not have, or adequately have mitigated, market
power in the generation and transmission of such energy, and
cannot erect other barriers
to entry by potential competitors.”). 3
and Recovery of Stranded Costs by Public Utilities, Order
No. 888, FERC Stats. & Regs. Preambles ¶ 31,036 (1996),
aff’d in relevant part, Transmission Access Policy Study Grp.
v. FERC, 225 F.3d 667 (D.C. Cir. 2000), aff’d sub nom, New
York v. FERC, 535 U.S. 1 (2002).
3
See also Order Directing Submission of Information with
Respect to Internal Processes for Reporting Trading Data,
103 FERC P61,089, ¶ 11 (April 30, 2003) (“This Commission
has a statutory obligation to ensure the justness and
reasonableness of rates for wholesale electric power, . . . . In
this regard, . . . the Commission’s vision has been to ensure
the delivery of dependable, affordable energy through
reliance on sustained competitive markets rather than through
a rigid adherence to strict-cost-of service principles.”).
18
II.
A. PJM Interconnection
Though the grid has become nationally interconnected
and competition among generators has increased,
transmission lines for a particular geographic area are still
typically owned by a single utility company. To manage the
complexities of the grid, FERC has encouraged the
development of “regional transmission organizations,” or
“RTOs,” which are voluntary associations of the owners of
transmission lines. Ill. Commerce Comm’n v. FERC, 576
F.3d 470, 473 (7th Cir. 2009). RTOs were promoted by
FERC to increase competition among energy providers by
ensuring that owners of transmission lines provide access in a
nondiscriminatory manner. Midwest ISO Transmission
Owners v. FERC, 373 F.3d 1361, 1364 (D.C. Cir. 2004).
Each RTO acts as the system operator in its region, managing
the transmission grid on behalf of transmission-owning
member utilities. See NRG Power Mktg., LLC v. Me. Pub.
Utils. Comm’n, 558 U.S. 165, 169 n.1 (2010). The parties do
not dispute that RTOs are “public utilities” under the FPA,
and are thus subject to FERC’s regulation.
PJM Interconnection (“PJM”) is the RTO that manages
the regional transmission system spanning from New Jersey
west to Chicago and south to North Carolina. As such, PJM
governs the transmission of electricity to fifty million
consumers in thirteen different states and the District of
Columbia. One of PJM’s primary responsibilities as system
19
operator is to ensure that there is a sufficient amount of
electrical capacity within its system to provide reliable
electricity to its consumers during periods of peak demand.
“‘Capacity’ is not electricity itself but the ability to produce it
when necessary.” Connecticut DPUC v. FERC, 569 F.3d
477, 479 (D.C. Cir. 2009). In a reliable transmission system,
the full potential of the system is used only during periods of
peak demand. That means that much of the rest of the time
there will be generation capacity that is idle. One of PJM’s
functions is to ensure that there are enough idle generators
connected to the transmission grid for the system to function
at peak load. It does this by predicting the expected peak load
three years in advance and then setting a target level of
capacity. The member-utilities that sell electricity to end-use
consumers—known in administrative parlance as “load-
serving entities,” or “LSEs”—are then each responsible for
providing a proportionate share of the capacity target.
PJM is also responsible for administering the regional
markets for energy and energy capacity that have developed
as competition among generators has increased. Energy—
that is, actual electricity—is sold wholesale via a “day-ahead
market” and a “real-time market.” See Black Oak Energy,
LLC v. FERC, 725 F.3d 230, 233 (D.C. Cir. 2013). The term
for the market mechanism used to determine energy prices in
each area within the PJM region is “Locational Marginal
Pricing,” or “LMP.” Id. “Under LMP, the price any given
buyer pays for electricity reflects a collection of costs
attendant to moving a megawatt of electricity through the
system to a buyer’s specific location on the grid.” Id. at 233-
34. In some areas, the transmission system is more
“congested”, which means that PJM must dispatch more
expensive generators to meet the area’s demand. “The cost of
20
congestion results in different prices at different nodes of the
system, depending on how congested the wires leading to
those nodes are.” Id. at 234.
Energy capacity, on the other hand, is sold in the PJM
market at annual capacity auctions, which are the subject of
this appeal. Capacity auctions allow LSEs to buy the capacity
they need to satisfy PJM’s capacity requirements. Capacity
auctions also, at least in theory, incentivize the development
of new generation resources by establishing a market-based
means by which those resources can recover their investment
costs.
Because the energy and energy capacity auctions
determine the rates for the transmission and sale of energy in
interstate commerce, they are subject to FERC oversight.
PJM is therefore obligated to obtain FERC approval of any
changes it makes to its “tariff,” which is the term of art used
to refer to the “classifications, practices, and regulations” a
public utility uses to establish electricity rates. See 16 U.S.C.
§ 824d(c). FERC reviews PJM’s proposed changes to its own
tariff under § 205 of the FPA to determine whether such
changes result in rates that are “just and reasonable.” 16
U.S.C. § 824d(a). FERC can also make changes to PJM’s
tariff under § 206 of the FPA, either on its own initiative or
pursuant to a complaint from a third party, if it determines
that the rates produced under the tariff are unjust or
unreasonable. Id. § 824e(a).
B. The Reliability Market
Prior to 1999, PJM required LSEs that were unable to
provide sufficient capacity in advance of when it was needed
21
to pay a deficiency charge based on the fixed costs of a new
generator. In 1999, PJM modified the reliability requirement
to allow LSEs to procure capacity up to the day before it was
needed, while also instituting market opportunities to
purchase “capacity credits.” LSEs that failed to obtain
sufficient capacity in those markets were then subject to the
deficiency charge. Those methods soon proved inadequate,
however, as they resulted in supply insufficiencies and
volatile capacity prices in certain locations. In particular, the
retirement of many aging generators in the mid-Atlantic
resulted in reliability problems throughout the region, and
volatile prices made the capacity market ineffective at
incentivizing development of new generation resources.
Therefore, in 2000, PJM began negotiating with its
stakeholders to reform the capacity market.
In 2006, after a period of extended negotiation, an
administrative law judge facilitated a settlement that created
the Reliability Market. The settlement was approved with
modification by FERC and incorporated into PJM’s tariff in
the 2006 Order. See PJM Interconnection, LLC., 117 FERC ¶
61,331 (2006). Under the FERC-approved tariff that resulted
from that settlement, all capacity suppliers (i.e., generation
and transmission resources) that wish to receive a capacity
payment or satisfy an LSE’s capacity obligation are required
to offer their available capacity into an auction. 4 Those offers
4
As discussed herein, some LSEs supply their own
capacity—that is, they own their own generation resources,
which they use to fulfill their capacity obligations. In order to
have those resources counted toward their capacity
obligations, however, the LSE must introduce them into the
auction. See Initial Order on Reliability Pricing Model, 115
22
are grouped based on the particular “locational delivery area,”
or “LDA,” the resource will serve. Offers are then accepted
by the auction, or “cleared”, in order of price, starting with
the lowest price offered, and continuing until there is
sufficient capacity in the auction to satisfy PJM’s
requirements for each LDA. All offers that clear for a given
LDA are then paid the “clearing price” for that area, which is
equal to the last offer (i.e., the highest offer) necessary to
meet the area’s reliability needs as determined by PJM. The
auction therefore sets the price that the LSEs will pay for
capacity in a given area. Only capacity offers that
successfully clear the auction can be counted towards an
LSE’s capacity requirements. PJM refers to this approach to
determining the cost of capacity as the “Reliability Pricing
Model,” or “RPM.” 5
FERC ¶ 61,079, at ¶ 115 (Apr. 20, 2006) (“To prevent
physical withholding, all existing generator capacity
resources have a must offer requirement with regard to all
unsold capacity. To encourage compliance with the must
offer rule, generators that fail to comply in each auction will
not be allowed to use its [sic] resource to satisfy any capacity
requirement or receive any capacity payments in the Delivery
Year.”).
5
The price and amount of annual capacity needed for each
LDA is set using the Variable Resource Requirement
(“VRR”) Curve, which is a construct meant to mimic a
demand curve that can show the price PJM expects to pay for
capacity based on the amount of capacity available in the
market. Under the VRR curve, the price for capacity will
decrease as more supply enters the market, up until the point
at which PJM’s capacity objective is fully satisfied. To
23
Pursuant to the 2006 Order, PJM actually operates two
types of capacity auctions: “base residual auctions” and
“incremental auctions.” See 2006 Order ¶ 55 (Joint App.
3046-47). Base residual auctions are held three years in
advance of when the capacity offered at the auction will be
needed. The forward-looking nature of the auctions serves
two functions: it provides PJM advance assurance that its
system will be reliable, and it allows new generation
resources, though not yet complete, to test the market and
perhaps obtain financing for their construction. The
incremental auctions then allow LSEs to purchase additional
capacity if needed to meet greater-than-expected demand.
Although both auctions function similarly, the base residual
auctions are the primary subject of this appeal.
The capacity auctions are not the only method by
which LSEs can satisfy their capacity obligations. If an LSE
prefers not to participate in the auctions, it can instead utilize
the “Fixed Resource Requirement” (“FRR”) option, which
allows an LSE to opt out of the auctions by building or
directly contracting with generation resources to meet its
capacity obligations. To qualify for the FRR option,
however, the LSE must demonstrate to PJM that it has access
to sufficient generation and transmission resources to meet
projected capacity obligations for a five-year period,
beginning three years in the future. If it succeeds in doing so,
the LSE can forego the capacity auctions and pay its
ensure reliability in the transmission system, there must be
more capacity available than is generally needed by
consumers. PJM thus artificially creates the demand for
capacity, and it now does so via the VRR curve.
24
generation resources whatever price the parties agree to.
However, if an LSE chooses the FRR option, it loses the
ability to participate in the auctions during that five-year
period; it cannot buy additional capacity, nor can it “defray
the costs of new resources” it builds by offering their excess
capacity into the auctions. See PJM Interconnection, LLC,
135 FERC ¶ 61,022 (Apr. 12, 2011) [hereinafter, “April 12
Order”] (Joint App. 81-82 n.98). In other words, participating
in the FRR option is an all-or-nothing proposition, and
appeals as a practical matter only to large utilities that still
follow the traditional, vertically integrated model. 6
C. The Minimum Offer Price Rule
In addition to establishing the capacity auctions, the
2006 Order created several mechanisms designed to prevent
market manipulation in those auctions. First, to prevent
sellers from exercising monopoly power, the 2006 Order
imposed a rigid price cap on all offers. Second, the
settlement provided for a “Minimum Offer Price Rule,” or
“MOPR,” that is designed to curb monopsony power, i.e., the
power of a buyer facing many sellers and little to no
6
The record indicates that the FRR was incorporated into the
2006 Order at the request of American Electric Power (AEP),
one of the country’s largest utilities, and AEP is the only
utility that has used the FRR option in recent years.
25
competition from other buyers. 7 The exercise of buyer
market power is possible in part because many utility
companies are both buyers and sellers of capacity in the
capacity auctions. If, for example, an LSE owns a small
generator, the LSE must offer that generation capacity into
the auction in order for it to count towards the LSE’s capacity
obligation. To fully satisfy that obligation, however, the
same LSE may also have to purchase additional capacity from
the auction. When such LSEs buy more capacity than they
offer into the auction, they have an incentive to keep auction
prices as low as possible. Theoretically, those net-buyers can
achieve that objective by offering their capacity at artificially
low prices that are sure to clear the auction. Such offers
crowd out other capacity that is priced at a higher, cost-based
rate, and thus result in a lower overall clearing price. To
counteract that manipulation of the market, the MOPR seeks
to identify uneconomic offers and “mitigate” them by raising
them to a price that more accurately approximates their net
costs.
Under the original MOPR approved by FERC in the
2006 Order, offers for capacity were subject to mitigation if
7
Technically, a monopolist is a single seller and a
monopsonist is a single buyer, see Black’s Law Dictionary
1028 (8th ed. 2004), but the terms are used loosely by the
parties to mean, respectively, sellers and buyers who exercise
disproportionate power in imperfectly competitive markets.
More particularly, they use the term “monopsony” to mean
net-buyers in the auction who sell into the auction at
artificially low prices in order to depress the clearing price.
We adopt that imprecise usage.
26
they failed three “screens”: a conduct screen, an impact
screen, and an incentive screen (also known as the “net-short
test”). The conduct screen identified offers that might be
artificially low by comparing them to a “threshold” price,
which was based on PJM’s estimate of the net cost of new
entry into the market, or net “CONE,” for the relevant LDA. 8
PJM determined the estimated net CONE for two types of
generators—combustion turbines (“CT” generators) and
combined cycle turbines (“CC” generators)—both of which
are gas-fired generators. The threshold price for each of those
generators was either 70% or 80% of its estimated net CONE
(depending on the type of resource). Any offer that was
below the threshold price would fail the “conduct screen.”
8
Like the VRR Curve, the net CONE is an administrative
construct. PJM arrives at the net CONE figure by estimating
the costs needed to build a particular type of generation
resource, and then deducting from those costs the estimated
revenue the new unit would receive through sales of “energy
and ancillary services”, discussed infra. In other words, the
more revenue a new generator is expected to make through
energy sales, the larger the amount deducted from the costs of
developing the resource. For example, if a new resource
costs $100 to build, and is expected to earn $25 in energy
sales, its net CONE would be $75. The net CONE and the
VRR Curve are also related concepts. As discussed supra,
the VRR Curve is meant to demonstrate the change in
expected capacity prices as the amount of capacity in the
market increases. Those expected prices – the “y axis” for a
curve – are determined by PJM’s estimate of the net CONE
(the “x axis” being quantity of capacity).
27
Offers that failed the conduct screen would then be
subject to the “impact screen,” which was conducted by
rerunning the auction to determine whether the offer would
reduce the clearing price by 20% to 30% in the relevant LDA,
or by $25/MW-day 9, whichever was greater. Put more
simply, the impact screen determined whether a below-cost
offer actually affected the clearing price in a substantial way.
If it did, then the offer would be subjected to the final screen,
the “net-short test”, in which PJM determined whether the
seller had an incentive to depress prices. Specifically, PJM
would determine whether the seller was in a “net-short
position”, that is, whether the seller bought substantially more
capacity from the auction than it sold, and thus had the
incentive to reduce the clearing price. An offer that failed all
three screens would then be “mitigated” by raising it to 80%
or 90% of the estimated net CONE, depending on the
resource type. That adjusted offer could still clear the
auction, but only if it was at or below the clearing price.
Importantly, however, not all offers were subject to the
MOPR. First, the MOPR applied only to new entrants to the
market, not to existing resources. Although existing
resources, like all available capacity, had to be offered into
the auction, they could be offered at any price below the
upper limit. In fact, because existing resources already
incurred the costs needed to generate capacity, and could thus
often afford to offer capacity at very low prices, they were
9
Capacity is measured in megawatt-days (MW-day) and bid
into the RPM market as a dollar amount per megawatt-day.
See PPL Energy Plus, LLC. v. Nazarian, Civil Action No.
MJG-12-1286, 2013 U.S. Dist. LEXIS 140210, at *43 (D.
Md. Sept. 30, 2013).
28
permitted to offer their capacity at a price of zero dollars,
which would ensure that it cleared the auction and received
the clearing price. The MOPR also did not apply to upgrades
or additions to existing resources. Second, certain types of
resources were never subject to the MOPR, including nuclear,
coal, and hydroelectric resources. Third, the MOPR
exempted from its operation “any planned resource being
developed in response to a state regulatory or legislative
mandate to resolve a projected capacity shortfall.” April 12
Order ¶ 124 (Joint App. 61-62). In order for an offer to
qualify for that exemption, the state’s capacity shortfall had to
be established “pursuant to a state evidentiary proceeding that
includes due notice, PJM participation and an opportunity to
be heard.” Id.
The original MOPR also provided special treatment to
resources designated as “self-supply,” which are capacity
resources that an LSE builds to serve its own load. Such a
resource had to offer its capacity into the auction, and the
resource had to clear the auction, in order for it to be counted
toward the LSE’s capacity obligation. Unlike the three types
of resources described above, self-supply resources were not
listed among the exemptions to the MOPR, and so could be
subject to mitigation if they failed the three screens. But the
MOPR went on to state that, after offers were mitigated as
needed and the clearing price was determined, PJM must
accept capacity offers in the following order:
(i) first, all Sell Offers in their
entirety designated as self-supply
committed regardless of price; (ii)
then, all Sell Offers of zero . . .
and (iii) then all remaining Sell
29
Offers in order of the lowest price
....
PJM Tariff Attachment DD, Section 5.14(h)(4) (emphasis in
original). The MOPR therefore suggested that self-supply
offers would clear the auction before all other offers, even if
the self-supply offers were actually higher than the clearing
price. In other words, although they were not “exempt” from
the MOPR, and thus could be mitigated, self-supply offers
were entitled to what amounted to automatic clearance. 10
For all resources, the original MOPR only applied the
first time a resource was offered at an auction, regardless of
whether it cleared the auction. Resources that failed to clear
the first time could therefore be offered at subsequent
auctions without facing the three screens and potential
mitigation.
In sum, the original MOPR would mitigate first-time
offers from certain resources that had the potential to
manipulate the market through the exercise of buyer market
power. The original MOPR did not affect resources that were
built pursuant to a state mandate intended to correct a
capacity deficiency, and it appeared to allow self-supply
10
The original MOPR’s treatment of self-supply offers is a
subject of some disagreement among the parties. FERC,
PJM, and Cross-Petitioners P3 claim that the original MOPR
was ambiguous as to whether there was an exemption for
self-supply. The Load Petitioners, on the other hand, urge that
the provision is clear—there was no exemption from
mitigation, but all self-supply offers would clear the auction.
We discuss this in detail infra.
30
offers to clear regardless of price. Notably, during the entire
period it was in effect, the original MOPR was never
triggered, meaning that no offer was subject to mitigation.
III.
A. The New Jersey and Maryland Initiatives
The chain of events leading up to FERC’s 2011 Orders
was set in motion by the efforts of two states—New Jersey
and Maryland—to invoke the MOPR’s exemption for state-
mandated resources, efforts which, if successful, would result
in the introduction of thousands of megawatts of subsidized
capacity into the PJM market. On January 28, 2011, New
Jersey Governor Chris Christie signed into law the “Long-
Term Capacity Agreement and Pilot Program” (“LCAPP”),
2011 N.J. Sess. Law Serv. Ch. 9 (codified at N.J. Stat. Ann. §
48:3-98.2 (2011)), which launched a state initiative to
develop new generation resources. According to the statute,
New Jersey faced an “electrical power capacity deficit” due to
transmission system overloads and aging generation facilities.
Id. § 48:3-98:2(e), (h). Because PJM’s “reliability pricing
model [had] not resulted in large additions of” generation
facilities or load resources, “the construction of new, efficient
generation [had to] be fostered by State policy.” Id. § 48:3-
98.2(b), (d). 11
11
FERC disagrees that the RPM has failed to secure
sufficient capacity in the PJM region. See, e.g., “Order on
Compliance Filing, Rehearing, and Technical Conference.”
137 FERC ¶ 61,145 (November 17, 2011), ¶ 3 (“[T]he
evidence before us suggests that RPM has in fact succeeded
31
Pursuant to the LCAPP, the New Jersey Board of
Public Utilities would conduct a competitive bidding process,
in which it would evaluate proposed resources based on their
“environmental, economic, and community benefits.” Id. §
48:3-98.3(b)(2). Winning bidders would then enter into long-
term contracts with New Jersey’s four electric public utilities,
pursuant to which they would build new capacity resources in
exchange for payments at a specified rate. Id. § 48:3-51; id. §
48:3-98.3(c)(9). The new generation resources would be
required by those contracts to attempt to clear the PJM base
residual auction. Id. § 48:3-98.3(c)(12). Once a resource
cleared, New Jersey’s public utilities would then pay the
generators the difference between the contract price and the
amount they were able to receive from the auction, or if the
clearing price was higher than the contract price, the
generators would reimburse the public utilities for the excess
payment. Id. at (c)(4). To ensure that its resources would
clear, New Jersey intended to offer the capacity into the base
residual market at a price below their actual cost.
Spurred to action by similar concerns regarding long-
term reliability needs and the suspension of a key
transmission project, the Maryland Public Service
Commission (PSC) in December 2010 released a draft
Request for Proposals (“RFP”) for Generation Capacity
Resources Under Long-Term Contract. The RFP
contemplated that the PSC would conduct an evidentiary
hearing to determine whether it would, similarly to New
Jersey, require Maryland’s electric distribution companies
in securing sufficient capacity to meet reliability requirements
for the PJM region.”). (Joint App. 105)
32
(EDCs) to enter into long-term contracts to purchase new
capacity, or to construct new generation on their own. After
the close of briefing in this matter, the PSC did issue a
Generation Order directing each of three Maryland EDCs to
contract with Commercial Power Ventures (CPV) Maryland.
See Nazarian, 2013 U.S. Dist. LEXIS at *5. As in New
Jersey, the Maryland contracts require CPV to sell capacity in
the PJM markets, and for the EDCs to pay CPV any
difference between the price received in the market and a pre-
determined contract price. 12 Like New Jersey, Maryland
intended to offer its new capacity resources into the PJM
market at a price below its actual cost to ensure that they
would clear.
B. The P3 Complaint and PJM’s Revisions to the
MOPR
12
We note that, since oral argument in this case, two federal
district courts have issued decisions invalidating the New
Jersey and Maryland initiatives on the ground that they seek
to legislate or regulate wholesale prices for energy in
interstate commerce, a field occupied exclusively by FERC,
in violation of the Supremacy Clause. See generally PPL
EnergyPlus, LLC v. Nazarian, supra; PPL EnergyPlus, LLC
v. Hanna, Civil Action No. 11-745, 2013 U.S. Dist. LEXIS
147273 (D.N.J. Oct. 11, 2013). While we are mindful of the
implications of these decisions on certain issues in this case,
we deal here with the legality of actions taken by FERC, not
of those taken by the states. Accordingly, we do not address
those decisions.
33
Shortly after the LCAPP was enacted, an association
of PJM’s power providers, known as “P3” 13, filed a complaint
with FERC under § 206 of the FPA, arguing that the MOPR
implemented in the 2006 Order was not an effective tool for
curbing buyer market power. Specifically citing the New
Jersey and Maryland initiatives, P3 urged that “without
effective mitigation, the exercise of buyer market power will
sound the death knell of competitive markets—and with them
the cost savings that markets create for consumers.” (Joint
13
P3 is a nonprofit organization of PJM stakeholders
consisting of Calpine Corporation; DPL Energy, LLC; Edison
Mission Group; EquiPower Resources Corp.; Essential
Power, LLC; Exelon Corp.; GDF SUEZ North America, Inc.;
Homer City Generation, L.P.; NextEra Energy Resources,
LLC; NRG Energy Inc.; PPL Corporation; and PSEG Energy
Resources & Trade LLC (PSEG). It appears that P3 had a
slightly different membership when it filed its initial
complaint with FERC, see April 12 Order ¶ 2 n.4 (Joint App.
27) (listing members of P3, some of which differ from the
membership listed in P3’s brief). However, no party has
asserted that this apparent membership change has any
relevance for purposes of our review. We further note that in
its brief, despite listing PSEG as a member of P3 in its
corporate disclosure statement, P3 at various points refers to
“P3 and PSEG” as if they are distinct from one another. See,
e.g., P3 Br. 2, 63. PSEG also filed its own petition for review
separate from the other members of P3. However, because
PSEG did not file a brief independently from the other
members of P3, and because PSEG does not appear to make
any independent arguments in addition to those made by P3,
we assume for purposes of this opinion that PSEG is a
member of P3.
34
Ohio App. 204) Accordingly, P3 urged PJM to eliminate the
MOPR’s exemption for state-mandated resources.
P3 also requested other reforms of the MOPR in its
complaint, all geared toward mitigating buyer-side market
power: (1) adjustment of the conduct screen so that any offer
that was less than 100% of the estimated net CONE would
trigger the MOPR; (2) elimination of the two subsidiary
screens (the impact screen and the net-short test) entirely; (3)
elimination of the exemption for self-supply (to the extent
that one existed); (4) addition of a requirement that a new
resource successfully clear two auctions before becoming
exempt from the MOPR; and (5) addition of an exemption to
the MOPR “for any new resource whose sponsor affirms it
will not receive any form of out-of-market subsidy or
preferential treatment by state regulators,” which it called a
“No-Subsidy Off-Ramp”. P3 Br. 19.
On February 11, 2011, in response to P3’s complaint,
PJM submitted to FERC proposed changes to its tariff that
had incorporated the original MOPR, under § 205 of the FPA.
The original MOPR, PJM explained, was designed to
“address a concern that some market participants might have
an incentive to depress market clearing prices by offering
some self-supply at less than a competitive level.” (Joint
App. 393 (internal quotation marks omitted)). Because the
original MOPR had never been triggered, PJM urged that the
existing rule was not adequate to serve these purposes. PJM
also noted that “state programs intended to support new
generation entry through out-of-market payments to the
generator”—like those developed by New Jersey and
Maryland—had the potential to “raise the price-suppression
35
concerns that MOPR-type provisions are intended to
address.” (Id.)
The reforms PJM proposed differed somewhat from
the changes P3 suggested, however. PJM adopted P3’s
recommendations that the MOPR be amended to eliminate
the impact screen and the net-short requirement, and “to
clarify that self-supply offers are subject to the MOPR.” (Id.
at 411). According to PJM, self-supply offers were never
intended to be exempt from the MOPR, and the additional
screens made the MOPR too lenient and “too easily gamed”.
(Id. at 406) PJM also accepted, with some significant
changes, P3’s proposals that the state-mandated exemption be
eliminated, that the conduct screen threshold be increased,
and that a resource be required to clear an auction before
becoming exempt from the MOPR. Specifically, (1) rather
than simply eliminating the state-mandated exemption, PJM
proposed to amend the MOPR to provide that a resource that
failed the conduct screen could, via a § 206 filing, justify the
state program to FERC and seek an individual exemption
from the MOPR; (2) PJM agreed to increase the conduct
screen threshold to 90% of the estimated net CONE, rather
than to 100% of that value, as proposed by P3, explaining that
net CONE “is merely an estimate,” and that “[a] 90% factor
strikes the right balance” between granting some wiggle room
for slightly below-CONE offers and minimizing “the risk that
a seller can evade the MOPR and use a below-cost price to
suppress clearing prices for all sellers.” (Id. at 401-02); (3)
PJM agreed that a new resource should have to actually clear
an auction, and not merely participate in one, to become
exempt from the MOPR in future auctions. PJM went further
than P3 requested, however, proposing that a resource be
required to clear three times before becoming exempt, rather
36
than merely twice. The only P3 proposal that PJM rejected in
its entirety was P3’s proposed “No-Subsidy Off-Ramp,” by
which any new resource could avoid the MOPR by affirming
that its sponsor had not received an out-of-market subsidy.
PJM also incorporated several changes to the MOPR
that P3 had not suggested. First, it added wind and solar
resources to the list of resources that would always be
exempt from the MOPR, and thus could offer their capacity
at prices as low as zero. As a result of those additions, the
MOPR would only apply to new gas-fired facilities. Second,
PJM explained for the first time how an offer that fails the
MOPR can nonetheless avoid mitigation by demonstrating to
FERC under § 206 that the MOPR screen is unjust and
unreasonable “as applied to its specific costs and its specific
revenue expectations.” (Id. at 404)
Third, PJM clarified and amended the method used to
determine the estimated net CONE for each LDA. Relevant
here, it defined the method for calculating “energy and
ancillary services offsets” to be used in determining the
MOPR trigger threshold for a new resource. 14 Under the
existing guidelines used to construct the VRR Curve, “PJM
associate[d] the gross CONE in [an LDA] . . . with the
energy revenues calculated for a zone within that area.” (Id.
at 400) PJM proposed an approach similar to this
methodology with one adjustment. Instead of basing
revenues on the zone in which a generic “reference resource”
14
The original MOPR referred to energy and ancillary
services offsets, but “never explain[ed] how the energy and
ancillary service revenues [would] be determined.” (Joint
App. 399)
37
was located—the method used in the VRR Curve
guidelines—PJM would instead use the revenues earned by
resources in the highest-earning “zone” within the LDA. In
other words, all new resources in a given LDA would be
presumed to have the same earning potential as the highest-
earning generators in the LDA. PJM was concerned that, if
the presumed location of a “reference resource” were used to
determine energy and ancillary services revenues, a new
entrant might “fail the MOPR screen merely because it is
located in a zone with higher [marginal prices] than the zone
in which the hypothetical reference resource was assumed to
be built.” (Joint App. 400) PJM therefore erred on the side
of allowing more resources to avoid mitigation. PJM also
provided that those prices would be based on the prices for
energy in the “real-time” energy market, as opposed to the
“day-ahead” market.
PJM’s tariff revisions prompted numerous comments,
protests, answers, and cross-answers from interested parties.
Several states and LSEs argued that “eliminating the state-
mandated exemption and other related MOPR conditions
would transform [the capacity auctions] from a residual
market into the primary market for securing new capacity,”
and would impermissibly interfere with legitimate state
policies. (Petitioners/Cross Respondents’ Joint Statements
17-18) Similarly, several municipal and rural cooperative
utility companies “protested that eliminating automatic
clearance for self-supply resources would undermine their
traditional business models.” (Id. at 18) PJM responded to
those protests in two filings with FERC in March of 2011,
but it did not propose any further revisions to the MOPR.
C. FERC’s MOPR Orders
38
On April 12, 2011, FERC issued the April 12 Order,
accepting, with some modifications, PJM’s revised tariff as
“just and reasonable.” 135 FERC ¶ 61,022 (2011). FERC
agreed with PJM that it was just and reasonable to: (1)
calculate energy and ancillary services revenues in the
manner PJM proposed (using real-time energy prices and the
highest-priced zones within an LDA); (2) raise the conduct
screen to 90% of the estimated net CONE; (3) eliminate the
net-short screen and the impact screen; (4) add exemptions
for wind and solar generation resources; and (5) clarify that
self-supply resources are subject to the MOPR. FERC
disagreed, however, with three components of the revised
MOPR: (1) the method by which a resource can obtain an
individual exemption to the MOPR; (2) the replacement for
the state-mandated exemption; and (3) the number of
auctions a resource must clear before becoming exempt from
the MOPR.
With regard to individual exemptions to the MOPR,
FERC found unjust and unreasonable PJM’s proposal to
require parties to submit at the outset a § 206 filing with
FERC to demonstrate that a sell offer was consistent with the
project’s costs. FERC agreed that offers that were in fact
competitive and cost-based should not be mitigated, but it
found unreasonable the “complex and lengthy litigation” that
could result from the § 206 review process. Instead, FERC
directed PJM to modify the tariff to provide that PJM and its
Independent Market Monitor would review such cost
justifications. 15 Put more simply, FERC wanted PJM, not
15
Despite numerous references to the Independent Market
Monitor in their briefing, the parties have not done the Court
39
FERC, to conduct the review process. FERC concluded that,
with the unit-specific cost review process in place, P3’s
proposed “No-Subsidy Off-Ramp” was unnecessary.
As for the state-mandated exemption, FERC agreed in
part with PJM, concluding that the exemption needed to be
eliminated due to “mounting evidence of risk from what was
previously only a theoretical weakness in the MOPR rules,”
namely, that state-subsidized resources would suppress
auction prices. April 12 Order ¶ 139 (Joint App. 66). FERC
disagreed with PJM’s proposed replacement mechanism,
however. Specifically, it declined to adopt a formal process
for a state to justify its initiative and thus obtain an
exemption from the MOPR. FERC explained that states, like
all parties, were free to file for an exemption from the MOPR
under § 206. But FERC concluded that there was no need for
a review process like the one PJM had proposed, which
would have balanced the state’s interests against the adverse
price effects of below-cost offers, because “there is no valid
state interest” in ensuring that uneconomic offers would clear
the auction. Id. at ¶ 142 (Joint App. 68). Accordingly,
FERC declined to accord states an opportunity to justify their
initiatives on policy grounds, instead removing the state
exemption and requiring them to submit cost-based offers
like other entrants or suffer the consequences of mitigation.
the favor of explaining the precise role of this entity.
Intervenor First Energy Solutions Corp. helpfully describes
the Independent Market Monitor as “a neutral entity that
monitors compliance with PJM’s market rules.” (FirstEnergy
Br. 12)
40
Finally, FERC rejected PJM’s proposal that the MOPR
be applied to a given resource until that resource has cleared
the auction three times. Instead, FERC concluded that the
MOPR should apply only until a resource clears an auction
once, because by clearing one auction “the resource
demonstrates that its capacity is needed by the market at a
price near its full entry cost . . . .” Id. at ¶ 176 (Joint App.
76). In so concluding, FERC partially adopted a
recommendation submitted by the Independent Market
Monitor. FERC rejected the second component of the
Independent Market Monitor’s proposal, however, which
would have continued to impose the MOPR in later auctions
unless the resource could “show it is not receiving
discriminatory subsidies.” Id. at ¶ 177 (Joint App. 77).
FERC declined to adopt that requirement because “even if
discriminatory subsidies are being received, if the resource is
needed at the MOPR bid then it is a competitive resource and
should be permitted to participate in the auction regardless of
whether it also receives a subsidy.” Id. On May 12, 2011,
PJM submitted a compliance filing that responded to FERC’s
instructions in the April 12 Order.
Following FERC’s ruling, numerous parties sought
rehearing. In response to those requests, FERC convened a
technical conference on July 28, 2011, to explore the issues
raised on rehearing, specifically on issues regarding the
MOPR’s applicability to self-supply. After the technical
conference, parties submitted formal comments for FERC to
consider.
On November 17, 2011, FERC issued an “Order on
Compliance Filing, Rehearing, and Technical Conference.”
137 FERC ¶ 61,145 (November 17, 2011) [hereinafter,
41
“November 17 Order”]. Although that order slightly
modified some of the revisions approved in its April 12
Order, FERC did not change its fundamental position on any
of the issues relevant to this appeal. Rather, it reaffirmed its
commitment to its initial reaction to the revised tariff,
explaining that, although the capacity auctions had generally
been successful since their adoption, the MOPR had to be
amended to prevent “subsidized entry supported by one
state’s or locality’s policies” from “disrupting the
competitive price signals [the auction] is designed to produce
. . . .” November 17 Order ¶ 3 (Joint App. 105-06). FERC
emphasized that offers that fail the conduct screen (that is,
appear to be below-cost) have two options for avoiding
mitigation: they can appeal to PJM through the unit-specific
cost justification process or they can seek an exemption from
FERC by using § 206 of the FPA. FERC further explained
that if an LSE does not want to be subject to the MOPR at
all, it can utilize the FRR option. FERC therefore continued
to find the majority of the revisions approved in the April 12
Order “just and reasonable.”
Several parties sought rehearing of FERC’s November
17 Order, which FERC denied on March 15, 2012. See
“Order on Rehearing”, PJM Interconnection, LLC, 138
FERC ¶ 61,194 (March 15, 2012) [hereinafter “March 15
Order”].
D. Petitions for Review
42
Numerous parties have timely petitioned for review of
the 2011 Orders. 16 Specifically, Petitioners in this appeal are
the New Jersey Board of Public Utilities and the New Jersey
Division of Rate Counsel (collectively, “New Jersey”), the
Maryland Public Service Commission (“Maryland”), a group
of governmentally-owned utilities and rural cooperative
utilities referred to as the “Load Petitioners” 17, and Hess
Corporation (“Hess”). Intervening on those Petitioners’
behalf is CPV Power Development, Inc., which is the parent
corporation of two companies that have received contracts
from New Jersey and Maryland to build new generation
resources. In addition, P3 has filed a cross-petition
challenging various aspects of the Orders. A group of
energy generation companies has also intervened on Cross-
Petitioners’ behalf. 18 Both PJM and FirstEnergy Solutions
16
All Petitioners and Cross-Petitioners challenge the April 12
and November 17 Orders. Load Petitioners additionally
challenge the March 15 Order.
17
Specifically, the Load Petitioners are Old Dominion
Electric Cooperative, American Public Power Association,
National Rural Electric Cooperative Association, North
Carolina Electric Membership Corporation, Delaware
Municipal Electric Corporation, American Municipal Power,
Inc., and Southern Maryland Electric Cooperative, Inc.
18
Those companies are PPL Electric Utilities Corporation;
PPL EnergyPlus, LLC; PPL Brunner Island, LLC; PPL
Holtwood, LLC; PPL Martins Creek, LLC; PPL Mountour,
LLC; PPL Susquehanna, LLC; Lower Mount Bethel Energy,
LLC; PPL New Jersey Solar, LLC; PPL New Jersey Biogas,
43
Corp., another energy provider (“FirstEnergy”) have
intervened on FERC’s behalf.
As discussed infra, Petitioners and Cross-Petitioners
challenge different provisions of the MOPR. Petitioners take
issue with: (1) the elimination of the exemption for state-
mandated resources; (2) FERC’s decision that the MOPR did
not provide for automatic clearance for self-supply offers;
and (3) the addition of solar and wind-powered generators to
the list of resources that are exempt from the MOPR.
Cross-Petitioners, on the other hand, challenge: (1) the
policy of basing the calculation for energy and ancillary
services offsets on the zone with the highest revenues; and
(2) the policy of exempting resources from the MOPR once
they have cleared only one capacity auction.
Cross-Petitioners’ Petition for Review originally
challenged three additional components of the revised
MOPR: (1) the decision to set the conduct screen at 90% of
estimated net CONE, rather than 100%; (2) the use of real-
time prices, rather than day-ahead prices, in calculating
energy and ancillary services offsets; and (3) the rejection of
the “No-Subsidy Off-Ramp” proposal. Since this petition
was filed, however, FERC has further altered the MOPR to
effectively adopt P3’s positions on these issues. 19 After
LLC; PPL Renewable Energy, LLC; and Electric Power
Supply Association.
19
See PJM Interconnection, LLC, 138 FERC ¶ 61,062, at ¶¶
17, 67, 144 (Jan. 30, 2012) (approving a change in
methodology for calculating revenues to determine net CONE
to consider day-ahead prices); PJM Interconnection, LLC,
44
determining that the existence of these provisions did not
cause any economic harm to them in the 2011 and 2012
annual auctions, P3 no longer seeks redress on these points.
In addition to these changes, in a May 2, 2013 Order
[hereinafter, the “2013 Order”], FERC also provided, for the
first time, a limited exemption from MOPR mitigation for
resources designated as self-supply. Rather than merely
providing for guaranteed clearing for self-supply resources,
which Load Petitioners argue existed under the 2006 MOPR,
FERC’s 2013 Order finds just and reasonable PJM’s proposal
to completely exempt self-supply from mitigation, subject to
net-short and net-long tests. 20 In other words, if a sponsor
LSE introduces new self-supply but can demonstrate that it is
not a net buyer of capacity (and therefore does not have an
incentive to artificially lower the clearing price), the self-
supply will be exempt from mitigation under the MOPR.
This new rule, in essence, enables self-supply resources to be
“price-takers”, i.e., new self-supply resources may be entered
into the auction at artificially low costs, with the expectation
that they not be the most costly offer, and therefore will not
143 FERC ¶ 61,090 (May 2, 2013), at ¶ 24 (approving PJM’s
proposal to exempt from mitigation resources that do not
receive out-of-market subsidies) and ¶¶ 183, 195 (approving
PJM’s proposal to increase MOPR benchmark values to
100% of net CONE).
20
Again, a “net-short” position “refers to the circumstance
where an LSE owns and/or contracts for an amount of
capacity . . . that is less than its capacity needs . . . .”. On the
other hand, a “net-long” position “refers to the circumstance
where an LSE owns or contracts for generation in excess of
its capacity needs . . . .” 2013 Order ¶ 25 n.19.
45
set the clearing price. Rather, they will take whatever
clearing price results from the auction. It does not appear that
the Load Petitioners have sought rehearing on this issue.
IV.
This Court reviews FERC Orders under § 313(b) of the
FPA, 16 U.S.C. § 825l(b) and § 10(e) of the Administrative
Procedure Act (APA), 5 U.S.C. § 706(2). Under the FPA,
FERC’s factual findings are determinative as long as they are
supported by substantial evidence. 16 U.S.C. § 825l(b). The
“substantial evidence” standard “‘requires more than a
scintilla, but can be satisfied by something less than a
preponderance of the evidence.’” La. PSC v. FERC, 522 F.3d
378, 395 (D.C. Cir. 2008); accord Mars Home for Youth v.
NLRB, 666 F.3d 850, 853 (3d Cir. 2011) (“Substantial
evidence is more than a mere scintilla. It means such relevant
evidence as a reasonable mind might accept as adequate to
support a conclusion.” (internal citation and quotation marks
omitted)). If the evidence is susceptible to more than one
rational interpretation, we must uphold the agency’s
determination. Fla. Mun. Power Agency v. FERC, 315 F.3d
362, 368 (D.C. Cir. 2003) (“The question we must answer . . .
is not whether record evidence supports [petitioner]’s version
of events, but whether it supports FERC’s.”).
In reviewing FERC’s orders, the Court must determine
“whether a rational basis exists for a conclusion, whether
there has been an abuse of discretion, or . . . whether the
Commission’s order is arbitrary or capricious or not in
accordance with the purpose of the [FPA].” Cities of Newark
v. FERC, 763 F.2d 533, 545 (3d Cir. 1985) (internal quotation
marks omitted). “‘We affirm the Commission’s orders so
46
long as FERC examined the relevant data and articulated a
rational connection between the facts found and the choice
made.’” Sacramento Mun. Util. Dist. v. FERC, 616 F.3d 520,
528 (D.C. Cir. 2010) (quoting Alcoa Inc. v. FERC, 564 F.3d
1342, 1347 (D.C. Cir. 2009) (internal alterations omitted)).
FERC’s decisions regarding wholesale rate issues are entitled
to broad deference. See Morgan Stanley Capital Grp., Inc. v.
Public Util. Dist. No. 1, 554 U.S. 527, 532 (2008) (“The
statutory requirement that rates be ‘just and reasonable’ is
obviously incapable of precise judicial definition, and we
afford great deference to the Commission in its rate
decisions.”); Md. Pub. Serv. Comm’n v. FERC, 632 F.3d
1283, 1286 (D.C. Cir. 2011) (“[B]ecause issues of rate design
are fairly technical and, insofar as they are not technical,
involve policy judgments that lie at the core of the regulatory
mission, our review of whether a particular rate design is just
and reasonable is highly deferential.” (internal quotation
marks and citations omitted)); see also N. Penn. Gas Co. v.
FERC, 707 F.2d 763, 766 (3d Cir. 1983) (FERC’s exercise of
its expertise carries “a presumption of validity”).
Under § 205 of the FPA, 16 U.S.C. § 824d, public
utilities may change their rates unilaterally, upon 60 days’
notice to FERC, which then reviews the changed rates to
ensure that they are “just and reasonable.” It is not necessary,
in a filing pursuant to § 205, that FERC find that the
previous rate was unjust or unreasonable. See Atl. City Elec.
Co. v. FERC, 295 F.3d 1, 9-10 (D.C. Cir. 2002) (with respect
to a filing under § 205, “FERC plays ‘an essentially passive
and reactive role.’”) (quoting City of Winnfield v. FERC, 744
F.2d 871, 876 (D.C. Cir. 1984)). In contrast, under § 206,
FERC may change a rate in response to a complaint or on its
own motion, only if the moving party demonstrates that the
47
existing rate is unjust and unreasonable and the proposed
alternative is just and reasonable. 16 U.S.C. § 824e.
A. Petitioners’ Arguments
1. The Elimination of the Exemption for
State-Mandated Resources
State Petitioners’ attack on the elimination of the
exemption for state-mandated resources contains two
overarching arguments: (1) that the MOPR changes amount
to direct regulation of generating facilities, which FERC is
prohibited from doing under § 201 of the FPA; and (2) that
FERC erred in approving PJM’s elimination of the state-
mandated exemption as just and reasonable by failing to
sufficiently explain its reasons for departing from the 2006
Order, which arbitrarily and capriciously denies the exception
upon which they had relied. We address each of these in turn.
a. FERC’s Jurisdiction
New Jersey Petitioners urge that, by eliminating the
state-mandated exemption, FERC effectively attempts to
substitute its own power supply preferences for those of the
states and LSEs in violation of § 201 of the FPA, which
provides that states retain authority over “facilities used for
the generation of electric energy”. See 16 U.S.C. §
824(b)(1). New Jersey asserts that FERC’s elimination of the
state-mandated exemption thus goes “beyond protecting the
wholesale rates against the effects of” the entry of
uneconomic resources, and instead “seeks to prevent the entry
itself.” N.J. Br. 24. Relatedly, New Jersey argues that in
mandating that state-sponsored capacity resources clear based
48
on cost and cost alone, FERC has usurped the state’s right to
rely on integrated resource planning. The state argues that
cost should not be the only permissible consideration in
choosing among capacity suppliers because “[t]echnology
and fuel diversity are essential to ensuring that customers
avoid both price and reliability risks from over-dependence
on a single supply input.” N.J. Reply Br. 4-5.
FERC responds that the FPA bestows on it broad
authority over rules affecting wholesale rates. It argues that
courts have consistently upheld its jurisdiction over its
“regulation of capacity markets, including charges,
requirements, and market rules, as practices ‘affecting’ rates .
. . .” FERC Br. 40. In the FERC Orders at issue in this
action, FERC repeatedly asserts jurisdiction to review PJM’s
proposed change to the state-mandated exemption as a rule
affecting prices paid for energy in interstate commerce. See,
e.g., April 12 Order ¶ 143 (Joint App. 68) (“Because below-
cost entry suppresses capacity prices and because the
Commission has exclusive jurisdiction over wholesale rates,
the deterrence of uneconomic entry falls within the
Commission’s jurisdiction, and we are statutorily mandated to
protect the RPM against the effects of such entry.”);
November 17 Order ¶ 89 (Joint App. 130) (“[T]he MOPR
does not interfere with states or localities that, for policy
reasons, seek to provide assistance for new capacity entry if
they believe such expenditures are appropriate for their state.
We seek only to ensure the reasonableness of the wholesale,
inter-state prices determined in the markets PJM
administers.”).
Under the APA, we are charged with reviewing
whether an agency action is “in excess of statutory
49
jurisdiction, authority, or limitations, or short of statutory
right”. 5 U.S.C. § 706(2)(C). The Supreme Court recently
confirmed that an agency’s assertion of jurisdiction is entitled
to Chevron deference. See City of Arlington v. FCC, 569
U.S. __, 133 S. Ct. 1863, 1868-69 (2013).
After reviewing the FERC Orders at issue here and the
relevant case law, we conclude that FERC did not exceed its
jurisdiction in eliminating the state-mandated provision.
Under the FPA, FERC has jurisdiction over rules affecting
the rates of the transmission or sale of energy in interstate
commerce. See 16 U.S.C. § 824d. Here, it is undisputed that
New Jersey and Maryland’s plans to introduce thousands of
megawatts of new capacity into the Base Residual Auction
would have had an effect on the prices of wholesale electric
capacity in interstate commerce. See Mississippi Power &
Light Co. v. Mississippi, 487 U.S. 354, 374 (1988) (holding,
among other things, that FERC had jurisdiction over power
allocations that affect wholesale rates, and stating that
“[s]tates may not regulate in areas where FERC has properly
exercised its jurisdiction to determine just and reasonable
wholesale rates or to insure that agreements affecting
wholesale rates are reasonable.”) (emphasis added);
Municipalities of Groton v. FERC, 587 F.2d 1296, 1302 (D.C.
Cir. 1978) (rejecting jurisdictional challenge to FERC’s
authority to levy deficiency charges on utilities that failed to
procure generating capacity sufficient to meet its load
requirements, and stating that, “[i]t is sufficient for
jurisdictional purposes that the deficiency charge affects the
fee that a participant pays for power and reserve service,
irrespective of the objective underlying that charge.”).
50
In Connecticut Department of Utility Control v. FERC,
569 F.3d 477 (D.C. Cir. 2009), the Court of Appeals for the
D.C. Circuit rejected a similar argument to the one New
Jersey makes here with respect to the New England capacity
market. In that case, the Connecticut Department of Public
Utility Control (“DPUC”) challenged FERC’s authority to
require it to obtain specific amounts of capacity and to adjust
resource offer prices to levels where the supply of available
capacity meets the pre-determined demand. Id. at 480. 21 The
Connecticut DPUC argued that any movement upward in the
capacity requirement mandated by the New England-area
RTO amounted to a requirement that LSEs install new
capacity, and therefore contravened Section 201 of the FPA,
which states that FERC “shall not have jurisdiction . . . over
facilities used for the generation of electric energy.” Id. at
481 (internal quotation marks omitted) (alteration in original)
(citing 16 U.S.C. § 824(b)(1)).
The court rejected Connecticut DPUC’s claim that
FERC’s approval of the capacity requirement imposed by the
ISO-NE (the New England area’s equivalent to PJM)
amounted to direct regulation of generation facilities. First,
the court pointed out that the mechanism did not actually
require the installation of additional capacity at all; rather, it
merely set a peak demand estimate, and employed market
forces to locate a price at which market incentives were
sufficient to meet that demand. Id. at 481-82. State and local
authorities retained control over their power plants, including,
21
As in the instant matter, New England’s Forward Capacity
Market, like the Reliability Market at issue here, was the
result of a settlement among power system stakeholders.
Connecticut DPUC, 569 F.3d at 481.
51
among other things, forbidding new entrants from providing
new capacity, limiting new construction, and requiring
retirement of existing generators, without interference from
FERC. Id. at 481. However, states were still required to
shoulder the economic consequences of their choices—
decisions to limit the amount of capacity in the market in turn
affected the market clearing price for capacity. Id.
In addition, the court pointed out that FERC was not
seeking to impose a capacity requirement at all. Rather,
FERC was merely seeking to “ensure that the capacity
charges actually imposed by ISO-NE are fair to suppliers and
consumers. That reasonable concerns about system adequacy
might factor into the fairness of those charges is precisely
what brings them within the heartland of [FERC’s]
jurisdiction.” Id. at 483. In other words, FERC had the duty
to ensure that the mechanism employed by the ISO-NE to
determine the clearing price would yield rates that were just
and reasonable. Because ISO-NE’s preferred mechanism
employed a capacity requirement, FERC was within its
jurisdiction in reviewing and approving that capacity
requirement.
New Jersey attempts to distinguish Connecticut
Department of Utility Control, urging that, in that case, FERC
“did not seek to dictate which resources LSEs used to fulfill
their capacity obligations,” N.J. Br. 26 (emphasis in
original), while here, FERC is preventing New Jersey from
using the resources it has chosen to promote. But FERC is
doing no such thing. The states may use any resource they
wish to secure the capacity they need. The elimination of the
state-mandated exemption means only that if the states wish
to use a new generation resource to satisfy their capacity
52
obligations required under the Reliability Pricing Model, the
resource must clear the Base Residual Auction at or near its
net cost of new entry. Such a requirement ensures that the
new resource is economical—i.e., that it is needed by the
market—and ensures that its sponsor cannot exercise market
power by introducing a new resource into the auction at a
price that does not reflect its costs and that has the effect of
lowering the auction clearing price. Furthermore, even if the
states’ preferred generation resources fail to clear the auction,
the states are free to use them anyway; the only caveat is that
the states cannot use the resources to offset their capacity
obligations in the RPM, as such obligations can only be
satisfied by resources that are demanded by the capacity
market at a price reflecting their cost. Thus, as in
Connecticut Department of Utility Control, New Jersey and
Maryland are free to make their own decisions regarding how
to satisfy their capacity needs, but they “will appropriately
bear the costs of [those] decision[s],” id. at 481, including
possibly having to pay twice for capacity. 22
22
New Jersey also cites Maine Public Utilities Commission v.
FERC, 520 F.3d 464 (D.C. Cir. 2008) for the point that
FERC’s jurisdiction to approve the capacity requirements in
the New England market depended on the fact that LSEs were
free to satisfy their capacity obligations by building their own
capacity or entering into long-term bilateral contracts. N.J.
Reply Br. 11 n.23. But there is no indication in Maine Public
Utilities Commission that this was essential to FERC’s
jurisdiction in that case. Indeed, the court in Maine Public
Utilities Commission noted that “[t]he protracted litigation
over Must-Run agreements, the locational installed capacity
market, and the Forward Market is fundamentally a dispute
over the rates that will be paid to suppliers of capacity”, a
53
FERC’s enumerated reasons for approving the
elimination of the state-mandated exception relate directly to
the wholesale price for capacity, which is squarely, and
indeed exclusively, within FERC’s jurisdiction. See id. at
484 (“Where capacity decisions about an interconnected bulk
power system affect FERC-jurisdictional transmission rates
for that system without directly implicating generation
facilities, they come within the Commission’s authority.”). 23
concern squarely within FERC’s jurisdiction. Me. PUC, 520
F.3d at 479.
23
The remaining cases cited by New Jersey do not dictate
otherwise. Pacific Gas & Electric Co. v. State Energy
Resources Conservation & Development Commission, 461
U.S. 190 (1983) dealt with a state’s authority to halt the
construction of new nuclear plants for environmental reasons.
While noting the multiple aspects of power generation over
which states retained control, the Court specifically excepted
“the broad authority of the . . . Federal Energy Regulatory
Commission, over the need for and pricing of electrical power
transmitted in interstate commerce. . . .” Id. at 205. Nor is
Otter Tail Power Co. v. Federal Power Commission, 473
F.2d 1253 (8th Cir. 1973), helpful to New Jersey’s argument,
as FERC is not requiring the state to enlarge its generating
facilities or to purchase standby facilities. Finally, FERC’s
opinion in Ameren Energy Marketing Co., 96 FERC ¶ 61,306
(Sept. 14, 2001) is in no way contrary to our holding here. In
that opinion, FERC clarified that its previous order approving
market-based rates in a contract for the sale of capacity
between affiliates did not preclude the Missouri Public
Service Commission from inquiring into the reasonableness
of the public utility’s decision to enter into the contract with
54
New Jersey Petitioners argue that, unlike in Connecticut
DPUC, “FERC here interferes directly and materially with
state efforts to sponsor new capacity resources precisely
because those efforts could affect market prices.” N.J. Reply
Br. 15. New Jersey Petitioners are wrong; what FERC has
actually done here is permit states to develop whatever
capacity resources they wish, and to use those resources to
any extent that they wish, while approving rules that prevent
the state’s choices from adversely affecting wholesale
capacity rates. 24 Such action falls squarely within FERC’s
jurisdiction.
its affiliate. The language in Ameren that “wholesale
ratemaking does not, as a general matter, determine whether a
purchaser has prudently chosen from among available supply
options”, meant simply that FERC does not dictate the
particular supplier from which a buyer must purchase
capacity.
24
Cross-Petitioners P3 urge that “affecting capacity rates is
precisely what New Jersey and Maryland intended to do”
with their state initiatives. See P3 Br. 66 and n.16. It is not
necessary for us to pass upon whether the states’ intention
was valid, as neither New Jersey nor Maryland contest that
their initiatives would affect clearing prices in the base
residual auction. The states’ intent is not relevant for
purposes of FERC’s jurisdiction or the reasonableness of the
agency’s actions. See November 17 Order ¶ 3 (Joint App.
105-06) (“Our intent is not to pass judgment on state and
local policies and objectives with regard to the development
of new capacity resources or unreasonably interfere with
those objectives. We are forced to act, however, when
subsidized entry supported by one state’s or locality’s policies
55
b. Whether the Elimination of the
State-mandated Exemption was Arbitrary and Capricious
Having concluded that accepting PJM’s elimination of
the state-mandated exemption was within FERC’s
jurisdiction, we now turn to whether the agency has
adequately justified its reasoning for rescinding the
exemption it previously deemed “just and reasonable” at the
very moment states began to make use of it.
As an initial matter, New Jersey claims a procedural
defect in FERC’s elimination of the state-mandated
exemption. New Jersey urges that FERC improperly
eliminated the exemption as part of its review process under
the guise of § 205, whereas this effected a change that could
only be accomplished under § 206 based on a finding that the
prior provision was “unjust and unreasonable.” Because PJM
did not actually propose to eliminate the exemption entirely—
but just made it subject to FERC review—New Jersey urges,
FERC could not accept one part without the other.
FERC responds that it was correct in applying the §
205 “just and reasonable” standard to each part of PJM’s
proposal—both the elimination of the existing exemption and
PJM’s proposed replacement mechanism—and was therefore
entitled to accept the former and reject the latter. Moreover,
the elimination of PJM’s provision for FERC to assess the
adequacy of a state’s procedures was inconsequential since
the right to petition the Commission under § 206 for an
has the effect of disrupting the competitive price signals that
PJM’s RPM is designed to produce, and that PJM as a whole,
including other states, rely on to attract sufficient capacity.”).
56
exemption from the rules was preserved in any event as a
statutory right. We agree with FERC because the agency’s
refusal to adopt PJM’s replacement mechanism does not limit
states in any way that they would not otherwise be limited if
FERC had accepted PJM’s proposal in full. But in any case,
we need not decide whether FERC is entitled to parse a
particular proposal contained in a tariff filing and analyze
each part under § 205’s “just and reasonable” standard
because, as we explain below, we hold that FERC acted
reasonably in eliminating the state-mandated exemption
under either § 205 or § 206.
New Jersey and Maryland strenuously object to the
elimination of the state-mandated exemption as arbitrary and
capricious and an unjustified departure from the terms of the
2006 settlement that created the Reliability Pricing Model.
New Jersey insists that “fostering development of the selected
[state-mandated] resources would address New Jersey’s
reliability concerns while furthering the state’s environmental
and economic goals.” N.J. Br. 6; see also Md. Br. at 6
(“[T]he Maryland PSC submitted extensive, uncontested
evidence” regarding the state’s “serious and significant long-
term reliability needs . . . .”). It is necessary, the states argue,
that these new resources be offered into PJM’s auction at
below-cost prices to ensure that they will clear. New Jersey
Petitioners claim that the new, gas-fired resources it seeks to
build are needed to address New Jersey’s capacity deficiency,
and are “valuable enough to warrant long-term contracts even
if the resources might not be—in the short run—the cheapest
options available.” Id. at 8. In other words, the states
acknowledge that their selected resources might not be
economic—that is, they might not be able to clear the PJM
auction if offered at a price reflecting cost. Nevertheless, the
57
states assert that the new capacity they seek to build is
justified, arguing that new resources “are developed for many
reasons, including meeting non-cost environmental, siting and
infrastructure goals.” N.J. Reply Br. 13 n.26; see also Md.
Reply Br. 6 (“FERC’s refusal to consider . . . non-cost factors
. . . constitutes arbitrary and capricious decision-making.”).
Despite its admission that the new generating plants it
seeks to build may not be the lowest cost option, New Jersey
persuasively argues that “every fact that FERC identifies as
rendering the existing tariff unjust and unreasonable was
present when FERC approved the state exemption.” N.J. Br.
at 21. Though FERC cites the New Jersey and Maryland
initiatives as evidence that the possibility of price suppression
as a result of the state-mandated exemption was no longer
merely “theoretical”, FERC does not explain why it failed
initially to foresee that providing state-mandated resources
with an exemption to the MOPR would lead states to
structure their contracts in a way that would result in the
suppression of clearing prices. 25
25
When the original state exemption was adopted, P3
members raised the possibility that states would mandate new
reliability projects that could reduce clearing prices far below
cost and urged that the MOPR did not sufficiently address
this problem. (Joint App. 2993) Opponents also discussed
pending efforts by the state of Connecticut to procure new
capacity, which was to be bid into New England’s capacity
market at low, subsidized prices. (Id. at 2478-79) These
facts demonstrate that FERC was aware of possible price
suppression concerns relating to the state exemption, but
nonetheless found PJM’s tariff, including the exemption, just
and reasonable. (Id. at 2480-81)
58
Though we are not unsympathetic to New Jersey’s and
Maryland’s arguments that they reasonably relied on the
availability of the state-mandated exemption in contracting
for the construction of new capacity resources, we find no
fault with FERC’s ability to, and reasons for, eliminating the
state-mandated exemption. Courts have repeatedly held that
an agency may alter its policies despite the absence of a
change in circumstances. See Motor Vehicle Mfrs. Ass’n of
United States, Inc. v. State Farm Mut. Auto. Ins. Co., 463
U.S. 29, 57 (1983) (“‘An agency’s view of what is in the
public interest may change, either with or without a change in
circumstances.’”) (quoting Greater Bos. Television Corp. v.
FCC, 444 F.2d 841, 852 (D.C. Cir. 1970)). Accordingly, in
reviewing FERC’s action here, we ask only whether FERC’s
factual conclusions were based on substantial evidence,
whether, taking into account that evidence, each of the
changes it made to the MOPR in its orders had a rational
basis and were not arbitrary or capricious, and whether FERC
adequately explained its reasoning. See Nat’l Cable &
Telecomms. Ass’n v. FCC, 567 F.3d 659, 669 (D.C. Cir.
2009) (“[T]he existence of contrary agency precedent gives
us no more power than usual to question the Commission’s
substantive determinations. We still ask only whether the
Commission has adequately explained the reasons for its
current action and whether those reasons themselves reflect a
‘clear error of judgment.’”) (quoting DirecTV v. FCC, 110
F.3d 816, 826 (D.C. Cir. 1997)). See also Elec. Consumers
Res. Council v. FERC, 407 F.3d 1232, 1239 (D.C. Cir. 2005)
(court’s deference to FERC on complex rate market design
“is based on the understanding that the Commission will
monitor its experiment and review it accordingly.”).
59
With our limited scope of review in mind, we conclude
that FERC sufficiently explained its reasoning for eliminating
the state-mandated exemption as unjust and unreasonable.
FERC’s decision rested mainly upon the “mounting evidence
of risk” that the state-mandated exemption could permit
uneconomic entry into the RPM capacity market. Such
“mounting evidence” was sufficient, FERC said, to cause the
agency to reconsider its prior approval of the exemption in
the 2006 RPM settlement. See FERC Br. 50:
Thus, the actual prospect of
thousands of megawatts of new
generation, developed under
arrangements that would
explicitly subsidize the resources
regardless of Auction price,
potentially being offered into the
Reliability Market at a zero bid
brought into focus the distortive
effect—no longer “theoretical”—
that the state exemption could
have on market prices for all
capacity.
In the April 12 Order, FERC explained that “[b]ecause
below-cost entry suppresses capacity prices . . . [it was]
statutorily mandated to protect the RPM against the effects of
such entry.” April 12 Order ¶ 143 (Joint App. 68). FERC
further noted its agreement with its Independent Market
Monitor that “permitting a state exemption may in fact, over
the long run, result in less investment in capacity and
demand-side resources and the need in the future for
additional subsidies from the state.” November 17 Order ¶ 97
60
(Joint App. 132). In addition, FERC took into particular
consideration the concern, as expressed by the Pennsylvania
Public Utility Commission, that the state exemption could
adversely affect other states that wished to rely on prices in
the capacity market to incentivize new entry, as opposed to
relying on state subsidies. See April 12 Order ¶ 142 (Joint
App. 67-68); November 17 Order ¶ 96 (Joint App. 132). In
sum, FERC noted that while its “intent [was] not to pass
judgment on state and local policies and objectives with
regard to the development of new capacity resources, or
unreasonably interfere with those objectives”, the agency was
“forced to act, however, when subsidized entry supported by
one state’s or locality’s policies has the effect of disrupting
the competitive price signals that PJM’s RPM is designed to
produce, and that PJM as a whole, including other states, rely
on to attract sufficient capacity.” November 17 Order ¶ 3
(Joint App. 106).
In addition, FERC adequately responded to various
arguments against eliminating the exemption. In response to
arguments from New Jersey and Maryland that eliminating
the state exemption would do away with a state’s bargained-
for ability to generate resources the state believed the RPM
process had failed to provide, FERC noted that “any state is
free to seek an exemption from the MOPR under section
206,” if it believes that the resources available through RPM
are not adequately fulfilling its capacity needs. See April 12
Order ¶ 143 (Joint App. 68). FERC opined that the states’
right to petition for an individual exemption under § 206
preserved their ability to provide for new generation entry
while avoiding interfering with FERC’s “duty under the FPA
to assure just and reasonable rates in wholesale markets.” Id.
In response to concerns about timing, FERC pointed out that
61
states are free to file for an exemption under § 206 prior to
initiating the process to select new resources. November 17
Order ¶ 99 (Joint App. 133). In response to arguments from
various parties, including Petitioners in this case, that the
RPM’s emphasis on cost alone ignored other important state
objectives, including “environmental or technological goals,
[and] reliability concerns beyond a three-year forecast,”
FERC invited PJM stakeholders to propose a solution. See
November 17 Order ¶ 90 (Joint App. 130): “If PJM market
participants agree that RPM should account for resource
attributes that reflect broader objectives than three-year
forward reliability, then PJM and its stakeholders should
begin a process to consider how to incorporate these features
into RPM’s market design.” Id. However, FERC counseled
that such solution must not “undermine the objective of RPM
to procure the least-cost, competitively-priced combination of
resources necessary to meet the region’s reliability objectives
on a three-year forward basis.” Id.
We note briefly that our conclusion that FERC’s
elimination of the state-mandated exemption was justified
does not rely upon the existence or availability of the FRR
alternative. In its Orders, FERC pointed out that states and
LSEs “seeking full independence in resource procurement
choices” could opt out of the RPM altogether through the
FRR, and forego the opportunity to purchase or sell any
capacity through the RPM market. See, e.g., April 12 Order ¶
137 (Joint App. 65); id. at ¶ 193 (Joint App. 81) (“The FRR
option is the alternative for load serving entities that wish to
secure their own capacity resources outside of a competitive
62
market, whether as directed by state-authorized integrated
resource plans, or pursuant to other considerations.”). 26
In its briefing and throughout the record, FERC notes
the existence of the FRR as an “alternative” to the Reliability
Market in responding to states’ and LSEs’ concerns regarding
the MOPR. Petitioners New Jersey and Maryland and the
Load Petitioners all provide convincing evidence, however,
that the FRR is not a viable alternative for them. 27 FERC
does not counter this evidence; rather the agency merely
26
Exclusion from the RPM market for entities using the FRR
option is necessary to ensure that sponsoring entities cannot
take advantage of the market-based nature of the RPM while
withholding its own supply sources. See April 12 Order ¶
193 (Joint App. 81) (“To protect the integrity of PJM’s
wholesale capacity markets under RPM . . . , new self-supply
seeking to participate in the RPM market must compete with
other planned generation on the same competitive basis.”);
see also P3 Br. 81 (“[I]f [the FRR] alternative were designed
to require procurement of only a subset of the buyers’
capacity needs, the buyer could segment its purchasing
activities, reducing the volume of its purchase through RPM
in order to reduce auction clearing prices, while using the
FRR process for the remainder.”).
27
As noted supra, Petitioners argue that, because it requires
an LSE to demonstrate to PJM that it can use its self-supply
to meet projected capacity obligations for an entire five-year
period, and to forego the ability to buy or sell capacity in the
PJM auctions during that time, the FRR option is a viable
alternative only for large utilities that still follow the
vertically integrated model.
63
responds that it never indicated that the FRR would be a
“desirable or appropriate” alternative for all states or LSEs.
See FERC Br. 39-40. We agree with Petitioners that the
agency has given short shrift to their arguments that the FRR
is simply not a feasible alternative for them. But Petitioners
provide no authority for the proposition that FERC is actually
required to provide states and LSEs wishing to purchase or
sell capacity in interstate commerce with an alternative to the
Reliability Market. Absent such authority, we cannot hold
that the lack of a feasible alternative that would allow states
and LSEs to avoid having their capacity sell offers mitigated
is fatal to FERC’s Orders here.
FERC’s reasoning repeatedly refers to the economic
harm that could result from the potential price suppression
permitted by the state-mandated exemption. The agency
explicitly cites the “mounting evidence of risk” that the state-
mandated exemption “could allow uneconomic entry” to the
RPM. April 12 Order ¶ 139 (Joint App. 66). Although it
could easily be argued that this danger was foreseeable in
2006 when the MOPR was first approved, FERC has
adequately advanced a rationale for its about-face—namely,
that states were actually structuring contracts for the
development of new resources in a way that would
substantially suppress prices, threatening imminent economic
harm. The speculation has become reality. As such, it cannot
be said that FERC acted without substantial evidence.
It is more than mildly disturbing that, by endorsing a
state-mandated exemption with perfectly predictable
incentives, FERC would allow sovereign states and private
parties to be drawn into making complex and costly
investments, only to later pull the rug out from under those
64
who were persuaded that the exemption was somehow real.
That FERC has done so based on little more than the claim
that the agency had an “ah ha” moment when foreseeable
outcomes approached fruition only makes matters worse. Our
power to rein in bureaucratic behavior like this is, however,
constrained. The “arbitrary and capricious” standard of the
APA is a high bar indeed, and many agency actions worthy of
condemnation are not so deficient that they can be said to
cross it. Such is the case here.
2. Automatic Clearance for Self-Supply
As noted supra, prior to the 2011 MOPR reforms at
issue in this matter, PJM’s tariff provided that, in the Base
Residual Auction, PJM would accept “first, all Sell Offers in
their entirety designated as self-supply committed regardless
of price; (ii) then, all Sell Offers of zero, prorating to the
extent necessary, and (iii) then all remaining Sell Offers in
order of the lowest price . . . .” PJM Tariff Attachment DD,
Section 5.14(h)(4) (emphasis in original). In its original §
206 filing with FERC, P3 construed this language in PJM’s
tariff as providing a complete exemption from the MOPR for
resources designated as self-supply. Accordingly, in its
revised tariff filing, PJM proposed to delete this subsection.
PJM claimed that in eliminating this language, it sought
merely to “clarify” that self-supply offers were not exempted
from the MOPR. April 12 Order ¶ 184 (Joint App. 78).
FERC accepted this “clarification”, stating that it “agree[d]
with PJM that its current tariff does not exempt resources that
are planned to be self-supply from the MOPR and therefore
agree[d] that the current revisions do not change the tariff.”
Id. at ¶ 139 (Joint App. 80-81). Furthermore, FERC held,
“even if this did constitute a change,” the agency “agree[d]
with PJM that planned generation designated by a load
65
serving entity as self-supply should be classified as a capacity
resource and be subject to an offer floor based on its entry
costs until it clears in the base residual auction.” Id. (Joint
App. 81).
Load Petitioners take issue with FERC’s
characterization of this as a “clarification”. Load Petitioners
urge that FERC, in approving PJM’s change, has essentially
set up a straw-man argument by considering and rejecting a
complete exemption for self-supply from the MOPR. Load
Petitioners argue that, by gearing its response to an argument
that self supply investment should receive a complete
exemption from the MOPR—an argument that Load
Petitioners never made—FERC failed to address Load
Petitioners’ real concerns regarding the elimination of
guaranteed clearance for self-supply. 28 In doing so, Load
28
Namely, Load Petitioners contend that FERC’s approval of
the elimination of guaranteed clearance for self-supply
“departs from its prior orders that consistently recognized
self-supply as the preferred capacity source for LSEs” and
“disregards reasons rational LSEs have long chosen self-
supply—including long-term cost and revenue benefits,
increased long-term reliability, economic development, and
resource diversity.” Load Petitioners’ Br. 12, 21. They
argue that FERC’s action was in contradiction to FERC’s
own determination that self-supply offers should not be
“automatically suspect.” Id. at 20. Furthermore, they assert
that while existing resources are shielded from competition,
consumers served by self-supplying LSEs may have to pay
twice for their capacity if the self-supply resources fail to
clear the auction. Accordingly, as the LSEs see it, FERC’s
elimination of guaranteed clearance for self-supply provision
66
Petitioners argue, FERC acted arbitrarily and capriciously,
and without substantial evidence.
Indeed, FERC based much of its reasoning for
accepting PJM’s elimination of this provision on economic
arguments that assumed that the language as it previously
existed might be interpreted to mean that such offers would
not be subject to price mitigation. See April 12 Order ¶ 195
(Joint App. 81-82) (“[P]ermitting new self-supply to compete
as a price-taker in RPM impermissibly shifts the investment
costs of self-supply to competitive supply by suppressing
market clearing prices . . . .”); November 17 Order ¶ 205
(Joint App. 163) (“[W]e reaffirm the Commission’s finding in
the April 12 Order that a blanket, across-the-board MOPR
exemption for resources designated as self-supply would
allow for an unacceptable opportunity to exercise buyer
market power and thus could inhibit competitive
investment.”). 29
violated antitrust principles by favoring existing competitors.
Id. at 24-30.
29
Indeed, in its briefing before this Court, FERC continued to
assert arguments as to why the MOPR should not afford self-
supply a complete exemption from mitigation. See, e.g.,
FERC Br. 4 (describing the issue for review as whether FERC
reasonably determined “that revising the tariff to clarify that
the Minimum Offer Price Rule applies to planned resources
designated as self-supply was just and reasonable”).
Furthermore, the policy reasons FERC advances against
guaranteed clearance for self-supply deal with preventing
artificial price suppression. FERC fails to explain why the
danger of such price suppression would remain even where
67
It was not until the Order on Rehearing that FERC
addressed Load Petitioners’ arguments that the original
MOPR guaranteed that self-supply would clear the auction,
albeit at a potentially mitigated price. See March 15 Order ¶
27 (Joint App. 192) (dismissing the “assertion that the
Commission erred by not guaranteeing clearance for all self-
supply sell offers that receive an adjusted, unit-specific offer
floor.”). FERC asserted that guaranteed clearance for self-
supply would not serve the goals of the MOPR, because
“[s]imply receiving an adjusted unit-specific floor does not
mean that the market requires that unit at the adjusted floor
bid. Assuring every unit with an adjusted unit-specific floor
that it will clear the market could result in PJM rejecting the
offer from a less expensive unit that otherwise would have
cleared.” March 15 Order ¶ 28 (Joint App. 193). Even while
purporting to consider and reject these arguments, however,
FERC’s Orders never actually addressed the plain language
of the original MOPR, which unambiguously stated that, in
Base Residual Auction, PJM must accept “first, all Sell Offers
in their entirety designated as self-supply committed
regardless of price”. 30 In approving the removal of that
provision, FERC eliminated guaranteed clearance for self-
self-supply offers were subject to the MOPR’s mitigation
features. Id.
30
Although reviewing courts “generally give[] substantial
deference to [FERC’s] interpretation of filed tariffs, even
where the issue simply involves the proper construction of
language . . . we do not defer to FERC’s interpretation when
the tariff language is unambiguous.” Old Dominion Elec.
Coop., Inc. v. FERC, 518 F.3d 43, 48 (D.C. Cir. 2008)
(internal quotations marks and citations omitted).
68
supply offers, fundamentally changing the MOPR’s treatment
of self-supply, but barely acknowledging that it was making
any change at all. One strains to accept such scant treatment
as “reasoned analysis” sufficient to satisfy the demands of the
APA. See State Farm, 463 U.S. at 57 (“[A]n agency
changing its course must supply a reasoned analysis” for the
change) (internal quotation marks omitted); FCC v. Fox
Television Stations, Inc., 556 U.S. 502, 515 (2009) (requiring
agencies to generally “display awareness” of a change in
position); Nat’l Cable & Telecomms. Ass’n v. FCC, 567 F.3d
at 667 (an agency departing from its prior position must
“suppl[y] a reasoned analysis . . . showing that prior policies
and standards are being deliberately changed, not casually
ignored.”) (internal quotation marks and citations omitted);
Greater Bos. Television, 444 F.2d at 852 (“[I]f an agency
glosses over or swerves from prior precedents without
discussion it may cross the line from the tolerably terse to the
intolerably mute.”). 31
31
In contrast to FERC’s light treatment of the issue, PJM
provided an extensive response to Load Petitioners’
arguments regarding automatic clearing of self-supply. See
Answer of PJM to Comments and Protests, March 21, 2011
(Joint App. 2269-72); see also PJM Intervenor Brief 23-29.
PJM’s argument is essentially that (1) the provision as it
existed was ambiguous; and (2) in light of this ambiguity, this
Court should agree with PJM that the provision did not
guarantee automatic clearance for self-supply. As to the latter
point, PJM argues against interpreting the provision to
guarantee clearance because such interpretation would have
so contradicted the purposes of the MOPR that it could not
have possibly been correct. Id. at 28. We cannot accept
PJM’s argument for several reasons. First, as we have
69
But while we have concerns about FERC’s decision-
making process in this regard, we do not have jurisdiction to
review its action, because while this petition was pending,
FERC has again changed its stance on the proper treatment of
self-supply, rendering the Load Petitioners’ challenge moot.
As noted supra, FERC recently approved an exemption to the
MOPR for self-supply resources. 143 FERC ¶ 61,090 (May
2, 2013). Specifically, it decided that “providing exemptions
for resources properly designated as self-supply when they
meet suitable [requirements] is reasonable.” Id. at ¶ 108.
Although the Load Petitioners are not satisfied with the new
exemption, PJM’s treatment of self-supply resources has
fundamentally changed. Under the 2011 orders challenged
here, self-supply offers received no special treatment, but
rather were forced to compete at cost-based prices. Under the
2013 Order, such offers are exempt from mitigation entirely if
previously noted, the language of the provision itself,
requiring PJM to accept “first, all Sell Offers in their entirety
designated as self-supply committed regardless of price”, was
not ambiguous. See PJM Tariff Attachment DD, Section
5.14(h)(4) (emphasis in original). Second, PJM’s claim that it
would never have provided for guaranteed clearance due to
the economic inefficiencies of such policy is undermined by
the fact it has since revised the MOPR to guarantee a more
extensive exemption than Load Petitioners had originally
urged. Even if FERC had expressly adopted PJM’s policy-
based arguments against guaranteed clearing for self-supply,
we would have a difficult time agreeing that such adoption
was the subject of a reasoned analysis absent an
acknowledgment that such treatment constituted a
fundamental change in the MOPR’s treatment of such
resources.
70
they satisfy proposed “net-short” and “net-long” tests. Id. at ¶
107. Indeed, in justifying its proposed change to FERC, PJM
emphasized the importance of protecting “traditional business
models” by exempting “projects developed as self-supply by
municipals, cooperative utilities, and vertically integrated
utilities operating under integrated resource plans developed
under state-approved rules.” Id. at ¶ 81.
Such “a fundamental change in the state of affairs”
renders our review of this issue moot. See Motor & Equip.
Mfrs. Ass’n v. Nichols, 142 F.3d 449, 459 (D.C. Cir. 1998).
The Load Petitioners may still have complaints about PJM’s
treatment of self-supply, but the nature of that treatment is
completely different than it was under the challenged orders.
“The old set of rules, which are the subject of this lawsuit,
cannot be evaluated as if nothing has changed.” Nat’l Min.
Ass’n v. U.S. Dept. of Interior, 251 F.3d 1007, 1011 (D.C.
Cir. 2001). Rather, because “[a] new system is now in place,”
id., our review of the old system would merely be advisory,
unless the Load Petitioners suffered a redressable injury while
the old system was in place. See Freeport-McMoran Oil &
Gas Co. v. FERC, 962 F.2d 45, 46 (D.C. Cir. 1992)
(concluding that a case was “plainly moot” because the
challenged orders had been “superseded by a subsequent
FERC order, and while the challenged orders were in effect
petitioners suffered no injury this court can redress”). The
record does not show any injury-in-fact that the Load
Petitioners experienced during the 2011 and 2012 capacity
auctions, and at oral argument the only possible injury they
could point to was having to briefly negotiate with the
Independent Market Monitor before their offered resources
successfully cleared an auction. Although that negotiation
may have been frustrating to the Load Petitioners, it does not
71
amount to “a concrete and particularized invasion of a legally
protected interest.” Motor & Equip., 142 F.3d at 457 (citing
Lujan v. Defenders of Wildlife, 504 U.S. 555, 560 (1992)).
Therefore, as “interim . . . events have completely and
irrevocably eradicated the effects of the alleged violation,” id.
at 459, we conclude that the Load Petitioners’ challenge to
FERC’s treatment of self-supply resources is moot.
3. Undue Discrimination
a. Exemption for Solar and Wind
Powered Resources
From its inception, the PJM Reliability Market has
exempted from the MOPR nuclear, coal and hydroelectric
generation, permitting those resources to bid zero-price offers
into the Auction. In the 2011 Orders, FERC accepted PJM’s
proposal to add wind and solar facilities to this list of
exemptions. As a result, the only resources subject to the
MOPR are natural gas-fired technologies. New Jersey, Hess
Corporation, and Intervenor CPV Power urge that targeting
only gas-fired resources for mitigation amounts to undue
discrimination in violation of the FPA. They argue that
“[b]elow-cost offers from gas, nuclear, hydroelectric, wind, or
solar facilities all have the same ‘price suppression’ impacts”,
N.J. Br. 28, and therefore, subjecting only gas-fired resources
to the MOPR undermines the competitive goals FERC is
purportedly trying to achieve.
New Jersey does not attempt to argue that FERC failed
to justify its decision to apply the MOPR to gas-fired
resources and not to other types of generation. The state
admits that FERC “asserts that the characteristics of gas units
72
make them more likely to be used as price suppression tools.”
Id. at 28; see also id. at 29 (noting FERC’s recognition that
gas units “are relatively large and can be developed quickly”).
New Jersey merely asserts that those very characteristics
make them useful in abating New Jersey’s energy crisis, and
therefore are “useless in distinguishing legitimate from
illegitimate intent.” Id. at 29.
FERC points out that the FPA prevents only “undue”
discrimination, and that “according different treatment to
different classes of entities . . . does not amount to undue
discrimination under the FPA when the classes are not
similarly-situated.” November 17 Order ¶ 109 (Joint App.
135). In the April 12 Order, FERC set out its reasoning for
sanctioning PJM’s proposal:
[Gas-fired generators] have the
shortest development time to
respond to capacity needs and
thus are more efficient resources
to suppress capacity prices. In
addition, . . . wind and solar
resources are a poor choice if a
developer’s primary purpose is to
suppress capacity market prices.
Due to the intermittent energy
output of wind and solar
resources, the capacity value of
these resources is only a fraction
of the nameplate capacity. This
means that wind and solar
resources would need to offer as
much as eight times the nameplate
73
capacity of a [gas-fired] resource
in order to achieve the same price
suppression effect.
April 12 Order at ¶ 153 (Joint App. 70); see also
November 17 Order at ¶ 111 (Joint App. 136) (“In accepting
PJM’s proposal to subject [gas-fired] resources to the MOPR,
the Commission’s focus was on those factors that could
contribute to price suppression.”). FERC also notes that gas-
fired resources can be constructed within the three-year time
frame between the auction and the time the resource must be
put into use. Accordingly, the net incremental costs of a gas-
fired resource at the time of the first auction in which it
participates are near its full construction costs. Other
resources, on the other hand, take longer to build and
therefore must begin construction well in advance of entering
the capacity market. By the time they participate in an
auction, they have much lower incremental costs and would
therefore have a minimum price floor substantially below full
construction cost. In addition, the short build time of gas-
fired resources means that sponsors of such projects are able
to offer bids which, if they do not clear, may be reassessed or
abandoned, whereas other resources may already have
invested significant capital by the time they are required to
offer their capacity into the auction. For all of these reasons,
FERC argues, the exempted resources are not similar to gas-
fired resources; accordingly, the MOPR’s disparate treatment
of the various types of capacity resources does not constitute
undue discrimination.
In sum, FERC fully explained its reasons for
approving PJM’s proposal to subject gas-fired resources to
the MOPR while exempting other types of generation; New
74
Jersey’s disagreement with FERC’s justification does not
render the agency’s decision arbitrary and capricious.
b. Discrimination Against New
Subsidized Entry
New Jersey also argues that the new unit-specific
review process, which permits a seller to justify a sell offer
below the MOPR trigger threshold based on the resource’s
competitive cost advantages, permits undue discrimination
based on the type of subsidy a resource receives. PJM
provided examples of the types of “competitive cost
advantages” it would view as legitimately lowering the offer
price of a resource, including “costs resulting from the
capacity market seller’s business model, financial condition,
tax status, access to capital[, . . . and] net revenues that are
reasonably demonstrated, under the MOPR, to be higher than
estimated for the MOPR screen.” See November 17 Order ¶
213 (Joint App. 166). In effect, PJM would “evaluate
whether a subsidy, grant, or revenue is of the type
customarily enjoyed by the type of seller at issue and whether
the cost or revenue item pre-existed RPM.” Id. at ¶ 245 (Joint
App. 176). On the other hand, PJM would not view as
legitimately lowering cost “claimed cost savings or revenue
sources that appear irregular or anomalous, that do not reflect
arm’s-length transactions, or that are not in the ordinary
course of the seller’s business.” Id. at ¶ 213 (Joint App. 66).
Presumably, the state initiatives in New Jersey and Maryland
would fit into the latter category. New Jersey argues that this
is unduly discriminatory, because “‘new’ and ‘customary’
subsidies do not differ in their effects” on competition. New
Jersey asserts that FERC “wrongly treat[s] a subsidy’s
vintage as indicating whether it was motivated to suppress
75
RPM prices or to accomplish a legitimate purpose.” N.J. Br.
32.
Here again, FERC fully explained its reasons for
permitting PJM, in administering the unit-specific review
process, to view some methods of cost-savings differently
from others. FERC notes that “the MOPR was not intended
to change the long-standing business models parties use to
support investment in specific capacity procurement
projects.” November 17 Order ¶ 242 (Joint App. 175).
FERC agreed with PJM that the unit-specific review process
“appropriately recognizes varying long-standing business
structures and practices [such as tax status, access to capital,
and other advantages customarily enjoyed by that type of
seller] while also protecting against attempts to exercise
buyer market power.” Id. at ¶ 244 (Joint App. 175). In other
words, FERC recognized the desire of generators to retain the
cost-saving advantages they had traditionally enjoyed since
before the RPM came into existence, and balanced this desire
against the danger that some entities would provide “irregular
and anomalous” subsidies not available to other resources in
an attempt to exercise buyer market power. FERC’s asserted
reason for this differing treatment is not arbitrary or
capricious, and is consistent with its statutory duty to protect
the integrity of the capacity markets.
B. Cross-Petitioners’ Arguments
1. Calculation of Energy and Ancillary
Services Offsets
76
PJM’s § 205 filing for the first time defined a method
for calculating “energy and ancillary services offsets,” which
are the expected revenues a new generation resource will
likely earn from the sale of energy and ancillary services.
These revenues are used to “offset”, i.e., are subtracted from,
a resource’s estimated construction costs to determine the
resource’s net CONE—the higher the estimated revenues, the
lower the net CONE, and therefore the lower the threshold
used to determine whether a new resource will trigger the
MOPR. Prior to the 2011 Orders, PJM’s tariff did not
provide for any method for estimating energy and ancillary
services offsets. In its § 205 filing, PJM proposed to calculate
these offsets for a given resource based on the revenues
earned by the highest-earning resources in the PJM zone
where the resource is located. This calculation would,
presumably, lead the resource to be assigned a lower net
CONE and, consequently, a lower mitigation threshold.
P3 assails the “zonal” approach as unjust and
unreasonable. It argues that the artificially low mitigation
threshold “will . . . permit uneconomic resources to enter,
clear the Base Residual Auction and artificially suppress
prices. This outcome is neither administratively necessary
nor just, reasonable and non-discriminatory.” (Joint App.
1572) P3 argues that FERC instead should have directed
PJM to calculate energy and ancillary services offsets using a
“nodal” approach, which would base expected revenues on
the actual location of the new resource. 32
32
The parties appear to agree that location-specific “nodal”
data is readily available.
77
FERC’s justification for finding PJM’s proposal just
and reasonable is two-fold. First, FERC asserted that PJM’s
proposed method for calculating revenues is consistent with
the existing VRR Curve guidelines, which are used to
construct the simulated demand curve used in PJM’s capacity
auctions. See November 17 Order ¶ 30 (Joint App. 113)
(“[W]e find that use of zonal LMPs, rather than nodal LMPs,
for the MOPR screens is appropriate, given this
methodology’s consistency with PJM’s existing VRR Curve
guidelines.”). P3 asserts that this justification for using the
zonal approach must be rejected because the zonal
methodology is not actually the same as that used to construct
the VRR curve, and notes that PJM itself described the zonal
approach as an “adjustment” to the VRR Curve guidelines.
See P3 Br. 48. FERC responds that it did not condition its
approval on the new approach being identical to the VRR
Curve guidelines; rather it noted that PJM’s proposed
approach was “consistent” with the guidelines, and indeed it
expressly approved PJM’s proposed “adjustment” from the
guidelines’ approach. FERC Br. 81. Furthermore, FERC
argues that P3 waived this argument by failing to raise it on
rehearing. P3 disagrees that it waived the argument, stating
that the April 12 Order did not sufficiently put P3 on notice
that consistency with VRR Curve guidelines was a basis for
FERC’s approval of the zonal approach, and therefore P3
could not have been expected to contest this rationale on
rehearing.
We agree with P3 that FERC did not clearly tie the
VRR Curve consistency justification to the zonal approach in
the April 12 Order, and therefore P3’s argument is not
waived. We further agree with P3 that the zonal approach
appears to be no more “consistent” with the methodology
78
used in the VRR Curve guidelines than P3’s proposed nodal
approach. However, FERC advanced an additional rationale
for finding PJM’s proposed zonal approach just and
reasonable, and for rejecting P3’s preferred approach.
Namely, FERC urged that “the use of nodal LMP values
could trigger the market power screen even though the
resource was simply using its historical energy and ancillary
services revenues offset for its zone.” April 12 Order ¶ 47
(Joint App. 41). In other words, FERC agreed with PJM that
the methodology for calculating energy and ancillary services
offsets—a calculation that is, after all, merely an estimate—
should make it easier, and not more difficult, for a resource to
avoid mitigation.
P3 argues that structuring the calculation to permit
more resources to pass the MOPR screens “is not a proper
objective”. P3 Br. 45. However, P3 fails to explain why
erring on the side of allowing more resources to avoid
mitigation is not a permissible policy. Surely FERC is
permitted to weigh the danger of price suppression against the
counter-danger of over-mitigation, and determine where it
wishes to strike the balance. See NRG Power Marketing,
LLC v. FERC, 718 F.3d 947, 961 (D.C. Cir. 2013) (declining
to “review FERC’s balancing of competing interests”);
Sacramento Mun. Util. Dist., 616 F.3d at 541-42 (upholding
FERC’s tariff order where the agency “reflected on the
competing interests at stake to explain why it struck the
balance it did”).
P3 may be correct that basing energy and ancillary
services offsets on a resource’s actual location results in a
more accurate calculation of net CONE. However, the fact
that there may be a better, or more accurate, calculation does
79
not render PJM’s proposal unjust or unreasonable, or FERC’s
approval of it arbitrary and capricious. FERC noted as much
in its November 17 Order, stating that “[t]here may be more
than one method that provides a reasonably accurate forecast
of future revenues over time. The relevant question here is
whether PJM’s proposed method is likely to provide a
reasonably accurate forecast.” 33 November 17 Order ¶ 28
33
In the November 17 Order, FERC stated that it was “not
required to consider whether additional, alternative
approaches might also have been reasonable.” November 17
Order ¶ 30 (Joint App. 113). According to P3, this statement
indicates that FERC had incorrectly characterized its
proposed approach as a § 206 challenge to PJM’s tariff, as
conditionally approved on April 12, 2011, and therefore
inappropriately placed the burden on P3 to demonstrate that
PJM’s proposal was unjust and unreasonable. P3 cites
several cases to support the general principle that FERC,
before choosing a particular course of action, must consider
facially reasonable alternatives. See P3 Br. at 46-47 and n.12.
None of the cases cited, however, actually involves FERC’s
application of the “just and reasonable” standard under § 205,
pursuant to which a utility proposes revisions to its own tariff,
and FERC’s review is limited to determining whether the
utility’s preferred revision is just and reasonable. FERC
denies that it construed P3’s challenge to the tariff revision as
a § 206 challenge and argues that P3 simply fails to
understand the burden-shifting mechanism under § 205,
whereby PJM had the burden of showing that its tariff
proposal was just and reasonable, after which the burden then
shifted to P3 to demonstrate that PJM’s proposed approach
was unjust and unreasonable. FERC determined that PJM
carried its burden, and P3 did not. We believe that FERC has
80
(Joint App. 113). See ExxonMobil Gas Mktg. Co. v. FERC,
297 F.3d 1071, 1084 (D.C. Cir. 2002) (“The burden is on the
petitioners to show that the Commission’s choices are
unreasonable and its chosen line of demarcation is not within
a zone of reasonableness as distinct from the question of
whether the line drawn by the Commission is precisely
right.”) (internal quotation marks omitted); Serono Labs, Inc.
v. Shalala, 158 F.3d 1313, 1321 (D.C. Cir. 1998) (“[C]ourts
are bound to uphold an agency interpretation as long as it is
reasonable—regardless of whether there may be other
reasonable, or even more reasonable, views.”). FERC has
articulated legitimate reasons for finding PJM’s preferred
method for calculating energy and ancillary services offsets
just and reasonable, and that is all that is required to do.
2. Single-Auction Clearance Requirement
Prior to the 2011 MOPR revisions, new resources were
automatically exempt from mitigation after participating in,
but not necessarily clearing, one auction. Asserting that such
allowance “rendered the MOPR toothless,” P3 instead urges
in its § 206 complaint that a new resource should be required
to clear two annual auctions. See P3 Br. 49. In support of
this position, P3 notes that such an approach would closely
approximate FERC’s recently approved standard for the
NYISO (the New York area equivalent of PJM). In its § 205
filing, PJM itself proposed an even stronger rule, by which
the MOPR would apply to a new resource up to and including
the second successive annual auction after a resource first
clears. Finally, PJM’s Independent Market Monitor proposed
the better argument on this point, and in any case, FERC
adequately, albeit succinctly, responded to P3’s criticisms.
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a hybrid rule permitting a new resource to clear only one
auction, as long as it also demonstrated that it was not
receiving any out-of-market subsidies.
FERC did not accept any of these proposals in its
entirety. Rather, FERC decided that a new resource would no
longer be subject to mitigation after it cleared one auction at
an offer price near its full cost of entry. FERC’s rationale
was that a resource that has successfully cleared an auction at
or near its cost is “needed” by the market and is therefore
economic. It does not matter, FERC ruled, whether or not the
resource later receives a subsidy.
P3 claims that FERC’s decision was arbitrary and
capricious. First it argues that though FERC purported to be
adopting the recommendation of the Independent Market
Monitor, the agency in fact adopted only part of the Market
Monitor’s recommendation (the one-auction requirement)
while declining to adopt the other, key part: that the resource
not receive any subsidies from outside the PJM market. P3
contends that “[t]hat cherry picking left FERC standing alone,
adopting a proposal supported by no party, testimony, or
evidence.” Id. at 51. Second, P3 argues that by allowing a
resource to receive discriminatory subsidies after clearing
only one auction, FERC is essentially sanctioning the exercise
of buyer-side market power. Third, P3 asserts that FERC’s
decision “departs, without reasoned explanation” from the
rule it recently approved for the NYISO. Id. at 53. P3 cites
testimony from its own expert, who urged that, because
NYISO’s monthly auctions and PJM’s annual auction are
both “driven by the requirement to meet peak demand in the
summer”, NYISO’s rule is “directly analogous” to a two-year
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auction clearing rule. Id. at 54. 34 P3 argues that FERC’s
application of a different standard for PJM than the one it
applied for the NYISO represents a “chang[e] in course,” and
that FERC must supply a reasonable analysis for the
differential treatment. See Motor Vehicle Mfrs. Ass’n, 463
U.S. at 57.
FERC has adequately responded to P3’s arguments.
First, as FERC points out, P3 does not provide any support
for its suggestion that FERC must adopt a third party’s
proposal in full in order to meet the “substantial evidence”
standard. Under § 206, FERC may act on its own accord to
change any practice that, in its opinion, renders a rate, charge
or classification unjust, unreasonable, or discriminatory. 16
U.S.C. § 824e. In doing so, it is free to eschew the proposals
of other parties and invoke its own expertise, as long as it
does so in a manner that is not arbitrary or capricious. See
EarthLink, Inc. v. FCC, 462 F.3d 1, 12 (D.C. Cir. 2006)
(“[A]n agency’s predictive judgments about areas that are
34
See NYISO Mitigation Enhancements Order, 133 FERC ¶
61,178. Under the rule FERC originally approved for
NYISO, resources become exempt after clearing at least
twelve of the previous 24 monthly auctions. P3 alleges that
this clearance requirement was also subject to a minimum
period of six “capability periods”, or approximately three
years. P3 Br. 53-54. However, FERC asserts that P3
misunderstands this portion of its ruling, and that FERC
actually “expressly rejected any minimum” and instead
“allowed resources to become permanently exempt from
mitigation after clearing the market for one year (12 monthly
auctions in the New York market).” FERC Br. 88 (citing 133
FERC ¶ 61,178 at ¶ 51).
83
within the agency’s field of discretion and expertise are
entitled to particularly deferential review, as long as they are
reasonable . . . .”) (internal citations omitted) (alteration in
original)).
In the 2011 Orders, FERC described the reasons it
chose to require a new capacity resource to clear one auction
before escaping mitigation under the MOPR. Namely, FERC
concluded that “once a new resource has cleared in one
auction at the offer price floor, the resource has demonstrated
that it is needed by the market and it is therefore economic.”
See April 12 Order ¶ 175 (Joint App. 76). FERC believed
that applying the MOPR after that point “could therefore
inefficiently discourage the entry of a new capacity that is
economic.” Id. Furthermore, FERC explained its reasons for
declining to implement the other component of the
Independent Market Monitor’s proposal because “even if
discriminatory subsidies are being received, if the resource is
needed at the MOPR bid then it is a competitive resource and
should be permitted to participate in the auction regardless of
whether it also receives a subsidy.” Id. at ¶ 177 (Joint App.
77). 35 FERC further addressed P3’s arguments at length in
35
P3 generally argues that FERC’s one-auction clearing
requirement is discriminatory because it permits a new
resource to receive subsidies, and therefore bid into the
auction at an artificially low cost, only one year after clearing
its first auction. They argue that allowing a new resource to
receive discriminatory subsidies in its second auction would
affect the clearing price in the second year in the same way a
below-cost offer would have done in the first year the
resource was implemented. Of course, if FERC had adopted
P3’s proposal that a new resource escape mitigation after
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the November 17 Order. See November 17 Order ¶¶ 130-133
(examining how P3’s proposal would function under various
market conditions and concluding that clearing in one auction
at a price approximating its full cost of entry demonstrates
that a new resource is needed by the market and should not be
subject to further mitigation). See Tenn. Gas Pipeline Co. v.
FERC, 400 F.3d 23, 27 (D.C. Cir. 2005) (“The court properly
defers to policy determinations invoking the Commission’s
expertise in evaluating complex market conditions.”).
Nor was FERC required to replicate the standard it
approved for NYISO. P3 offers no authority for the
proposition that FERC must apply the same mitigation period
for all RTOs under its jurisdiction; after all, under § 205,
these organizations are largely tasked with coming up with
their own rates, rules, and procedures, subject only to FERC’s
determination that such rates, rules and procedures are “just
and reasonable.” 16 U.S.C. § 824d. Indeed, the two RTOs
employ substantially different auction processes—PJM’s
clearing two auctions, then such procedure could be criticized
for permitting discriminatory subsidies in the third year.
Accordingly, P3’s argument here is less about the number of
auctions a new resource must clear before being subject to
mitigation, than a rehashing of its complaints regarding
FERC’s rejection of the No-Subsidy Off-Ramp. As discussed
supra, FERC’s decision not to adopt the No-Subsidy Off-
Ramp was originally one of P3’s five independent challenges
to FERC’s 2011 Orders. In its 2013 Order, as described
supra, FERC has now adopted a form of the No-Subsidy Off-
Ramp. Accordingly, P3 has dropped its challenge to that
particular part of the 2011 Orders. Its challenge to the one-
auction clearing rule, however, remains alive.
85
capacity auctions are annual (or incremental), while NYISO
holds auctions on a monthly basis. Accordingly, it would be
impossible for FERC to apply the exact same mitigation rules
(with respect to both mitigation period and number of
auctions a resource is required to clear) in both regions. Nor
do the decisions cited by P3 indicate that FERC’s approval of
a different mitigation period for PJM than for NYISO would
require remand. See P3 Br. 54. None involved an agency’s
application of differing procedures in different regions, each
with its own unique circumstances, and each largely tasked
with formulating its own rules and procedures, subject only to
the qualification that they be just and reasonable. 36
36
Finally, P3 urges us to remand FERC’s orders in light of
FERC’s subsequent order in Astoria Generating Co. v. New
York Independent System Operator, Inc., 140 FERC ¶ 61,189
(2012), where FERC required NYISO to apply a market
power screen that would subject a capacity resource to an
offer floor despite the fact that the resource had already
cleared in several auctions. We are not convinced that
Astoria is inconsistent with the FERC order at issue here, as
the capacity resource in that matter had cleared the NYISO
auctions without being subject to an offer floor. See id. at ¶
141. On the contrary, the FERC rule at issue here requires
that a new resource clear the PJM auction at or near its net
cost of new entry once before escaping mitigation in
subsequent auctions. In any case, as P3 acknowledges, “[a]n
agency’s decision is not arbitrary and capricious merely
because it is not followed in a later adjudication.” Brooklyn
Union Gas Co. v. FERC, 409 F.3d 404, 406 (D.C. Cir. 2005)
(quoting MacLeod v. ICC, 54 F.3d 888, 892 (D.C. Cir.
1995)).
86
V.
For the foregoing reasons, we deny the petitions for review of
the 2011 Orders.
87