New Jersey Board of Public Utilities v. Federal Energy Regulatory Commission

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

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).

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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)).

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V.

For the foregoing reasons, we deny the petitions for review of

the 2011 Orders.

87