2014 Decisions

Opinions of the United

States Court of Appeals

for the Third Circuit

2-20-2014

NJ Board of Public Utilities v. FERC

Precedential or Non-Precedential: Precedential

Docket 11-4245

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"NJ Board of Public Utilities v. FERC" (2014). 2014 Decisions. Paper 208.

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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
2

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.;
3

*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
4

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)
5

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
6

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
7

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
8

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
9

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
10

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
11

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
12

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
13

O P I N I O N

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. 
14

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

 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. § 

 Petitioners New 
15

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. CrossPetitioners 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. 
16

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).
17

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, nondiscriminatory access to their transmission facilities.2

 2 Promoting Wholesale Competition Through Open Access 

Non-discriminatory Transmission Services by Public Utilities 

 
18

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 marketbased 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.”).
19

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 

 
20

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 “loadserving 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 
21

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 
22

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

 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 

 Those offers 
23

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 
24

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. 
25

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

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 

C. The Minimum Offer Price Rule

 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.
26

competition from other buyers.7

Under the original MOPR approved by FERC in the 

2006 Order, offers for capacity were subject to mitigation if 

 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. 

 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.
27

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

 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). 

 

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.” 
28

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-day9

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 

, 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. 

 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).
29

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 
30

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

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 

 

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. 

 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.
31

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 statemandated 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 “LongTerm 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 

 
32

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 longterm 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 longterm 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)
33

(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 predetermined contract price.12

 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.

 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
34

Shortly after the LCAPP was enacted, an association 

of PJM’s power providers, known as “P3”13

 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. 

, 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 
35

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 
36

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 
37

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

 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)

 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”
38

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 highestearning 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 statemandated 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
39

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

 15 Despite numerous references to the Independent Market 

Monitor in their briefing, the parties have not done the Court 

 Put more simply, FERC wanted PJM, not 
40

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) 
41

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, 
42

“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
43

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 CrossPetitioners’ behalf.18

 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. 

 Both PJM and FirstEnergy Solutions 

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, 
44

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 statemandated 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 realtime 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

 

LLC; PPL Renewable Energy, LLC; and Electric Power 

Supply Association.

 After 

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, 
45

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

 

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. 

 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 selfsupply 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 
46

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
47

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 
48

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 statemandated 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 
49

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 belowcost 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 
50

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.”). 
51

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 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, 

 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)). 

 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.
52

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 
53

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 

 
54

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 
55

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

 

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.

 Such action falls squarely within FERC’s 

jurisdiction. 

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 
56

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.”).
57

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 longterm 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 
58

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)
59

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.”). 
60

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 
61

(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 bargainedfor 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 
62

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 
63

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

 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. 

 FERC 

does not counter this evidence; rather the agency merely 
64

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 statemandated 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 
65

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 
66

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

 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 selfsupply—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 

 In doing so, Load 
67

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 selfsupply 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 
68

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 selfsupply sell offers that receive an adjusted, unit-specific offer 

floor.”). FERC asserted that guaranteed clearance for selfsupply 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

 

self-supply offers were subject to the MOPR’s mitigation 

features. Id.

 In approving the removal of that 

provision, FERC eliminated guaranteed clearance for self30 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). 
69

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 
70

But while we have concerns about FERC’s decisionmaking 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 policybased 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. 
71

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 
72

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 
73

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 
74

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 gasfired 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 gasfired 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 gasfired 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 gasfired 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 
75

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 
76

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
77

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. 

 
78

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 
79

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 
80

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

 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 

 November 17 Order ¶ 28 
81

(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. 
82

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 
83

auction clearing rule. Id. at 54.34

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 

 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.

 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).
84

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

 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 

 FERC further addressed P3’s arguments at length in 
85

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 OffRamp 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 OffRamp. Accordingly, P3 has dropped its challenge to that 

particular part of the 2011 Orders. Its challenge to the oneauction clearing rule, however, remains alive.
86

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)).
87

V.

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

the 2011 Orders.