1

UNITED STATES DISTRICT COURT

FOR THE DISTRICT OF NEW JERSEY

PPL ENERGYPLUS, LLC, et al.,

Plaintiffs,

v.

ROBERT M. HANNA, in his official 

capacity as President of the New Jersey 

Board of Public Utilities, et al., 

Defendants.

Civil Action No.: 11-745

MEMORANDUM

SHERIDAN, U.S.D.J. 

This non-jury case was tried before the Court over thirteen separate days in April and 

May, 2013. After trial, the parties submitted proposed findings of fact and conclusions of law as 

well as briefs, and thereafter, summations were heard. The Court, having considered the parties’ 

submissions and having deliberated over the facts and the law, submits this memorandum as its 

decision.

In broad terms, the issue before the Court is whether the New Jersey Long-Term 

Capacity Pilot Project Act, P.L. 2001, c. 9, approved Jan. 28, 2011, codified at N.J.S.A. §§ 48:3-

51, 48:3-98.2-.4 (“LCAPP” or “Act”), should be declared unconstitutional as violating the 

Supremacy Clause, and whether the New Jersey Board of Public Utilities (“NJBPU”, “BPU”, or 

as referred to herein as the “Board”) should be enjoined from engaging in activities in 

furtherance of the Act because the LCAPP is preempted by the Federal Power Act, 16 U.S.C. § 

824 et seq.. That is, whether actions by the State of New Jersey taken pursuant to the LCAPP 
2

intrude upon and interfere with the authority delegated to the Federal Energy Regulatory 

Commission (as referred to herein, “FERC” or “Commission”) by the Federal Power Act.

Before proceeding to the substance of this case, the Court provides two cautionary

observations regarding writing style and organization and a general reservation as to the

presentation and scope of the findings within this decision. First, on writing style. The electric 

energy industry has its own jargon which makes great use of acronyms. With so many acronyms

being used, the testimony and briefs become like alphabet soup where all the letters swirl around 

and may confuse the reader. As such, a list of acronyms which have been substantially agreed 

upon by the parties is attached as Rider A. The Court minimizes use of these acronyms in this 

decision. By way of reservation, the first part of the trial reviewed the extensive history of how 

the electric energy industry has developed into its present state. This opinion includes an 

overview of the relevant background for the purpose of providing sufficient information to 

decide the issues, however, it does not purport to be a historical work. And lastly on 

organization, there are many non-controversial facts presented within the Court’s overview of 

the relevant background, and a new term may present itself without prior introduction. In this 

case, the term will be explained later in the Court’s decision. After sifting through a confluence 

of facts, the Court has gleaned a set of manageable facts with which to evaluate the preemption 

issue. The decision is subdivided into several sections: (A) an identification of the parties to the 

action; (B) an identification of important non-parties; (C) an identification of witnesses who 

testified at trial; (D) a description of some basic facts regarding electricity; (E) background 

information on the electric energy industry; (F) a description of the “Reliability Price Model” 

(“RPM”) process; (G) a description of the LCAPP statute; (H) an explanation of the impacts of 

the LCAPP; (I) a description of the credibility of witness; (J) analysis; and (K) a conclusion. 
3

A. PARTIES TO THE ACTION

1. Defendants

New Jersey Board of Public Utilities. The defendants are Robert M. Hanna1

, Jeanne M. 

Fox, Joseph L. Fiordaliso, and Nicholas Asselta, all of whom are current or former

commissioners of the New Jersey Board of Public Utilities2

. Each is named in his official 

capacity against whom declaratory and injunctive relief is sought. Since each currently serves or 

formerly served as a commissioner on the Board, this opinion collectively refers to them as the 

“Board.” The Board has broad statutory authority over the activities of public utilities within the 

State of New Jersey. See In re Centex Homes, LLC, 411 N.J. Super. 244, 254 (App. Div. 2009). 

Specifically, Title 48 of the New Jersey Statutes provides that the Board has “general supervision 

and regulation of and jurisdiction and control over all public utilities.” N.J.S.A. § 48:2-13(a). As 

part of that authority, the BPU is authorized to require any public utility operating within the 

State to furnish safe, adequate, and proper service to consumer ratepayers at “just and 

reasonable” rates. N.J.S.A. § 48:2-21.

CPV Power Development, Inc. CPV Power Development, Inc. (“CPV”) is an 

Intervenor/Defendant. CPV is a Delaware corporation that, through its subsidiaries, is engaged in 

the development, ownership, and management of natural gas-fired facilities in North America (T. 

1587, 10-24). CPV owns and manages a natural gas-fired generation facility in Riverside 

County, California, and has taken steps to develop other natural gas-fired facilities, including 

 1 Mr. Hanna was named as President of the Board on December 21, 2011. At the time of the underlying facts, Lee A. 

Solomon served as Board President.

2 In New Jersey, the Board has always been a distinguished public entity known for its practical and professional 

decision making. Over the years, many prominent New Jersey leaders have served on the Board. For example, Mr. 

Solomon and Mr. Asselta served in the New Jersey State Assembly. Both Governor Byrne and Governor Whitman 

have served as Board President. Moreover, William Hyland, a former New Jersey Attorney General who has served 

the State of New Jersey in many esteemed capacities, was a former Board President. In reviewing this matter, the 

Court has considered the Board and its members, their sound judgment, and their professionalism in furtherance of 

the public good.
4

projects in Maryland, New York and New Jersey. CPV began to develop its Shore Project in 

New Jersey prior to implementation of the LCAPP Act. (T. 1588, 6 through T. 1589, 17). Most 

importantly for purposes of this case, CPV was named an eligible generator under the LCAPP by 

the Board and cleared the RPM Auction on its 2012 bid (T. 1588, 15-22).

2. Plaintiffs

The Plaintiffs are a group of wholesale, retail, and marketing companies who produce 

and sell energy and are located within the PJM market3

. Several Plaintiffs are identified below. 

Plaintiff Calpine Corporation is an electric generation and marketing corporation with a 

number of subsidiaries. It is a publicly traded, independent power producer based in Houston, 

Texas which operates ninety-one (91) power plants throughout the United States and Canada. 

The Calpine generation companies are physically located in the PJM market and participate in

the PJM wholesale energy and capacity markets. 

Plaintiff Exelon Generation Company, LLC is a Pennsylvania corporation headquartered 

in Kennett Square, Pennsylvania. Exelon Generation is a wholly-owned subsidiary of Exelon 

Corporation. Exelon Generation’s business consists of owning and operating electric generating 

facilities, wholesale power marketing operations, and competitive retail supply operations. 

Exelon Generation sells energy and capacity in the PJM interstate market and competes in PJM’s 

wholesale capacity auctions.

The PPL Parties are a group of related companies principally located in Allentown, 

Pennsylvania which are market and generation subsidiaries of PPL Corporation. They are 

physically located in the PJM market and participate in the PJM wholesale energy and capacity 

 3 Plaintiffs GenOnEnergy, NAEO Ocean Peaking Power, and Essential Power were never substantively discussed 

during trial and no injury was presented. 
5

markets. Together they control or own about 19,000 megawatts of generating capacity in the 

United States, some of which is located within the PJM market. 

Plaintiff PSEG Power, LLC is a Delaware limited liability company, headquartered in 

Newark, New Jersey. PSEG Power is a wholly-owned subsidiary of Public Service Enterprise 

Group, Inc.. PSEG Power owns approximately 11,850 megawatts of generating capacity within 

the PJM area, approximately 9,950 megawatts of which is located in New Jersey. PSEG Power 

sells energy and capacity at wholesale in interstate commerce, including in PJM’s capacity and 

energy markets.

Plaintiff Public Service Electric and Gas Company (“PSE&G”), a subsidiary of Public 

Service Enterprise Group, is located in New Jersey and is one of the largest combined electric 

and gas companies in the United States. It is also New Jersey’s oldest and largest publicly owned 

utility. PSE&G currently serves nearly three quarters of New Jersey’s population from Bergen to 

Gloucester Counties. 

Plaintiff Atlantic City Electric Company, based in New Jersey, is a subsidiary of Pepco 

Holdings, Inc., which provides electric service to approximately 547,000 customers in southern 

New Jersey. Pepco Holdings, Inc. is one of the largest energy delivery companies in the MidAtlantic region, serving about 1.9 million customers in Delaware, the District of Columbia, 

Maryland and New Jersey.

B. OTHER IMPORTANT NON-PARTIES

The Federal Energy Regulatory Commission (“Commission” or “FERC”) and PJM 

Interconnection, LLC (“PJM”) are two entities that are key players in the sale and delivery of 

energy. The Commission and PJM are not parties to this action, but are discussed throughout this 

memorandum. 
6

Pursuant to the Federal Power Act, 16 U.S.C. § 824 et seq., the Commission has federal 

statutory authority to regulate the transmission of electric energy in interstate commerce and the 

sale of electric energy at wholesale in interstate commerce. (Stipulated Facts ¶ 5). In this case, 

the scope of the Commission’s jurisdiction in regulating the sale of electric capacity in the 

wholesale market, and whether such jurisdiction is exclusive or concurrent with the Board’s 

jurisdiction, is at issue. The applicable federal statute from which the Commission derives its 

authority reads:

(b) Use or sale of electric energy in interstate commerce.

 

(1) The provisions of this subchapter shall apply to the 

transmission of electric energy in interstate commerce 

and to the sale of electric energy at wholesale in 

interstate commerce, but except as provided in 

paragraph (2) shall not apply to any other sale of 

electric energy or deprive a State or State commission 

of its lawful authority now exercised over the 

exportation of hydroelectric energy which is 

transmitted across a State line. The Commission shall 

have jurisdiction over all facilities for such 

transmission or sale of electric energy, but shall not 

have jurisdiction, except as specifically provided in this 

subchapter and subchapter III of this chapter, over 

facilities used for the generation of electric energy or 

over facilities used in local distribution or only for the

transmission of electric energy in intrastate commerce, 

or over facilities for the transmission of electric energy 

consumed wholly by the transmitter. 16 U.S.C. § 

824(b)(1).

PJM Interconnection, LLC is a voluntary association of different energy stakeholders 

which includes administrative bodies and electric generators.

4 (Stipulated Facts ¶ 13). PJM is 

primarily subject to Commission regulation through a tariff. It operates a regional wholesale 

 4 PJM was not well defined at trial. The issue of how these competing companies and regulatory bodies interact in 

terms of governance and voting procedures was not adequately addressed by any of the litigants. 
7

market that includes all or part of thirteen states including New Jersey. In addition, PJM is a 

regional transmission organization (“RTO”). (T. 47, 17 through T. 48, 11).

PJM was originally founded in 1927. The name “PJM” is the brainchild of its earliest 

members who were from the states of “Pennsylvania (P), New Jersey (J), Maryland (M)”. (T.

410, 22 through T. 411, 8). It was formed as a “power pool” for traditional utilities which 

recognized that a regional transmission organization could easily accommodate sharing of 

electric capacity more efficiently (T. 39, 5-10). The sharing of electrical capacity through such 

arrangements drastically drops consumer costs by limiting the number of electrical generation 

facilities required for peak hour production. As noted above, PJM operates pursuant to a tariff 

filed by PJM with the Commission called the “Open Access Transmission Tariff.” (Stipulated 

Facts ¶ 23). 

PJM has been a relatively successful operation. For instance, today, PJM is the “largest 

centrally dispatched power market . . . in the world,” covering 60 million customers and 185,000 

megawatts. (T. 69, 20 through T. 70, 1). Within PJM there are over 1,300 power plants and 

approximately 56,000 miles of transmission lines. (T. 406, 24 through T. 407, 11). Mr. Massey 

testified that PJM is the most sophisticated of all of the regional transmission organizations. In 

fact, “there are government officials and market participants from around the world that regularly 

travel to PJM for briefings about how the markets work. So [it is] considered state of the art.” (T. 

70, 1-8). 

Gradually, the traditional utilities within PJM transferred operational control of all their 

transmission to PJM. Currently, PJM is responsible for “[m]anaging a regional transmission grid 

encompassing all or part of thirteen states and the District of Columbia.” (Stipulated Facts ¶ 11). 
8

PJM, under the supervision of the Commission, is “responsible for planning the electric 

system to preserve the reliability of the electricity supply” in New Jersey. (Pl.’s Ex. 45, at 27).

That is, PJM “plan[s] expansions to transmission to improve the ability to transmit energy from 

where it is generated to serve load.” (Stipulated Facts ¶ 11). Most importantly, PJM is also 

responsible for the “dispatching” of generation in real time. It does this from “a very 

sophisticated control room in Valley Forge, Pennsylvania . . . which looks like an air traffic 

control system.” (T. 50, 6-13). From this control room, PJM “direct[s] this generator[], to ramp

up [and] . . . to ramp down all in real time. Because over this 13 state area they must insure that 

supply and demand are matched almost perfectly in real time.” (T. 50, 12-13). Despite these 

functions, PJM has no authority to construct or build a power plant, and likewise it has no 

authority to retire antiquated power plants. (Def.’s Ex. 183).

C. TESTIFYING WITNESSES

There were a number of witnesses who testified at trial, each of whom is identified 

below. All of these witnesses were very professional and proficient in their careers, and the 

Court weighed their credibility in light of these qualifications.

1. Plaintiffs’ Witnesses

William L. Massey obtained his Law Degree from the University of Arkansas School of 

Law in 1973, and later earned an LLM from Georgetown University Law Center in 1985. Upon 

his law school graduation, he clerked for the U.S. Circuit Court of Appeals for the Eighth 

Circuit. He later became Chief Counsel for U.S. Senator Dale Bumpers of Arkansas, where he 

focused on energy matters before the Senate Committee on Energy and Natural Resources. 

President Clinton later appointed Mr. Massey to be a Commissioner of the Commission where he 

served for over ten years. Mr. Massey currently serves as a partner in the Washington, DC office 
9

of the law firm Covington and Burling and is an Adjunct Professor at the Georgetown University 

Law Center. Mr. Massey was qualified as an expert “in the history and evolution of the 

electricity industry.” (T. 23, 12-15).

Joseph Dominguez is the Senior Vice-President for Governmental and Regulatory Affairs 

and Public Policy for Exelon Corporation. He obtained a Bachelor of Science Degree in 

Mechanical Engineering from the New Jersey Institute of Technology and a Law Degree from 

Rutgers University School of Law. He previously worked at the law firm of White & Williams in 

Philadelphia, Pennsylvania and served as an Assistant United States Attorney in the Eastern 

District of Pennsylvania.

Robert D. Willig, Ph.D. is a Professor of Economics and Public Affairs at Princeton 

University. Professor Willig studied mathematics at Harvard College and later obtained a 

Masters of Arts in Operations Research and Statistics, and a Doctorate in Economics from 

Stanford University. Professor Willig previously worked at Bell Labs performing research on the 

theory of economic regulation of regulated industries. After working there for five years, he 

became a Professor of Economics and Public Affairs at Princeton in 1978. Professor Willig’s 

specialty is industrial organization which involves the interrelationships between business, 

technology, the marketplace, and government. He was qualified as an expert in the fields of 

economics and regulatory policy with particular expertise in electric energy. (T. 623, 21-25). 

Michael Cudwadie is employed by PPL Energy Plus as Vice-President of Trading East. 

In that role, he is responsible for the hedging and trading activities of 9,000 megawatts of 

generation in the PJM markets. He has a Bachelor’s Degree in Accounting from Pennsylvania 

State University, and an MBA from Lehigh University. 
10

Zamir Rauf has been employed by Calpine Corporation as its Chief Financial Officer 

since 2008. In that role, he is responsible for the accounting and treasury functions of Calpine 

which include project finance, investor relations and risk management.

Daniel Cregg is the Vice-President of Finance for PSEG Power within PSEG Services 

Corporation. In this role, he develops business plans and near term earnings forecasts, prepares 

forecasts of market direction and analyzes elements of major investment decisions. He has a 

Bachelor’s Degree in Accounting from Lehigh University and an MBA from the University of 

Pennsylvania’s Wharton School of Business.

Anthony Robinson is employed by PSE&G as Director of Basic Generation Service and 

Basic Gas Supply Service. He has a Bachelor’s Degree in Economics, Applied Math and 

Statistics from Stoney Brook University. (T. 939, 14-17).

2. Defendants’ Witnesses

James P. Giuliano is Director of the New Jersey Board of Public Utilities’ Division of 

Reliability and Security. He is responsible for natural gas pipeline safety, underground damage 

prevention and emergency management and security. He has a Bachelor’s Degree in 

Communications, and has completed many state certifications in courses related to his job. 

Oden Sherman Knight is the Senior Vice President of Marketing and Organization at 

CPV where he manages power sales and gas purchases. (T. 1584, 16). He has a Bachelor’s 

Degree in Mechanical Engineering from Stanford University and a Masters in Business from 

Columbia University (T. 1584, 4-7).

Craig R. Roach is a principal of Boston Pacific Company, a consulting firm which 

focuses on power plant development. He has a Bachelor’s Degree in Economics from John 

Carroll University and a Doctorate in Economics from the University of Wisconsin. Mr. Roach 
11

was qualified as an expert in the design and implementation of competitive procurements and 

competitive markets for electricity.

Mr. Richard L. Levitan was the Board’s advisor for implementation of the LCAPP. He 

has served as President of the consulting firm Levitan & Associates since its founding in 1989. 

The firm provides management consulting and analytic expertise to regional transmission 

organizations and short form independent system operators. He is a graduate of Cornell 

University and received a Masters with a specialization in Energy Economics from Harvard 

University.

D. BASIC FACTS REGARDING ELECTRICITY

Energy is “the actual electricity” that electric generators produce and which residential 

and business consumers ultimately use5

. (Stipulated Facts ¶ 20). It cannot be stored in quantities 

large enough to supply customers during times of peak demand. (Id.). That is, energy cannot be 

canned or placed in a battery for a long period of time. It has no shelf life. As a result, “energy

generally must be produced when it is needed, and at the rate at which it is consumed.” (Id.) As 

Mr. Massey stated during his testimony, “[o]ne of the things about electricity is that it cannot be 

easily stored, and so supply and demand have to be matched instantaneously in real time.” (T. 

35, 4-6).

Energy is a product in interstate commerce. Regardless of which generator dispenses the 

energy, it ordinarily travels through interstate commerce to reach its destination. In 1927, the 

Supreme Court held that the interstate commerce clause prohibits states from regulating the rates 

for wholesale energy sales between utilities in different states because those sales are interstate 

transactions. Pub. Utils. Comm’n of R.I. v. Attleboro Steam & Elec. Co., 273 U.S. 83 (1927); 

(Stipulated Facts ¶ 4). Surprisingly, no witness precisely described the logistics of an energy 

 5 Residential and business customers are often referred to as “consumers” or “ratepayers”. 
12

delivery transaction (i.e., how energy is transmitted from a generator to a consumer) except to 

say that the delivery of energy is overseen by PJM and PJM routes energy through its 

transmission system. (T. 50, 6-13)

Amount of Energy. Energy is usually measured in megawatts. One megawatt of 

electricity powers approximately 1,000 households. Usually, megawatts are associated with 

lengths of time such as “per day” or “per hour.” (Stipulated Facts ¶ 18).

Capacity. “Capacity” is defined as “the ability to produce electricity when called upon.” 

(Stipulated Facts ¶ 17). In essence, capacity is the ability to produce sufficient energy to meet 

demand. At certain times, such as during the summer months when temperatures increase, 

demand for energy increases. Regardless of fluctuations, there must be sufficient capacity to 

meet the demand of high energy use at all times.

Capacity Resources. “Capacity resources include electric generation facilities (e.g., 

nuclear, natural gas, coal, wind, or solar), demand resources (i.e., the ability to call upon 

consumers to reduce their electricity demand), and energy efficiency resources (measures that 

reduce demand).” (Stipulated Facts ¶ 19). 

Reliability. “Reliability” is the delivery of electricity to customers in the amounts 

desired and within acceptable standards for frequency, duration and magnitude of outages and 

other adverse conditions or events. (T. 81, 23 through T. 83, 12). According to Mr. Levitan, 

electric reliability means being able to “keep consumers’ lights on” under duress and maintaining 

the power system when operating contingencies arise. (T. 1549, 8-11); see also I/M/O the 

Petition of Public Service Gas and Electric Company for a Determination Pursuant to the 

Provisions of N.J.S.A. 40:55D-19 (Susquehanna-Roseland Transmission Line). Resource 

adequacy is a key component of reliability. (T. 1549, 6-14). The key factor in meeting the 
13

reliability standard is having sufficient generators and transmission lines available to deliver 

energy as required by the circumstances. 

Generation Plants. Generation plants are categorized into three types – base load, midmerit, and peaking plants. The parties agree on the definition of base load and mid-merit. A base 

load plant is a plant that operates all or most of the time. A mid-merit plant, such as a combinedcycle gas turbine, is a plant that operates less than a base load plant but more than a peaking 

plant. The parties disagree on the definition of a peaking plant; but generally, a peaking plant is 

“a gas turbine, a simple cycle unit, a unit that is typically run sparingly, a unit that has certain 

technology characteristics that allow it to get started from a cold stand-by mode, and achieve full 

operation in just a few minutes.” (T. 1289, 12-16). 

E. BACKGROUND OF THE ELECTRIC ENERGY INDUSTRY

In the beginning of the twentieth century, the New Jersey Legislature, like many other 

state legislatures at the time, enacted a statute creating a public utility to oversee the operation of 

electric and gas utilities. During the early stages of utility regulation, states had exclusive 

authority over such utilities. During this time, the energy industry “was dominated by vertically 

integrated utility companies” (hereinafter, referred to as “traditional utilities”)

6

. (T. 24, 24

through T. 25, 1); (Stipulated Facts ¶ 1). 

Typically, the traditional utility was granted an exclusive right by state and local

governments to provide electric service to all consumers located in a defined territory. The 

traditional utility also had other powers, such as eminent domain authority, that would allow it to 

construct and operate power plants and local distribution networks to connect those power plants 

to local customers. In return, the traditional utility obligated itself to operate as a "common 

 6 The parties refer to the traditional utility as a “vertically integrated utility.” For purposes of minimizing confusion, 

this memorandum uses the term “traditional utility” because the word “utility” is now associated with an electric 

distribution company (EDC). 
14

carrier" with the duty to provide service on a non-discriminatory basis, and to subject its rates to 

regulation by a state public utility commission. The regulatory standards adopted by state 

commissions permitted rates that would reimburse utilities for their costs incurred in providing 

service and debt incurred in financing the construction of power plants and other equipment. 

The standards were also meant to afford investors in these utilities a reasonable rate of return. 

This structure enabled the traditional utility to raise capital through the issuance of stock or 

selling of debt, which, in turn, would allow the utility to expand its facilities. Recovery of and on 

an investment in a traditional utility, however, was always subject to a “prudence review” by the 

Board in New Jersey. (Stipulated Facts ¶ 2). 

In 1927, the Supreme Court of the United States decided the landmark case Pub. Utils. 

Comm'n of R.I. v. Attleboro Steam & Elec. Co., 273 U.S. 83 (1927). In that case, the Public 

Utilities Commission of Rhode Island attempted to regulate the sale of electricity from the 

Narragansett Electric Lighting Company to the Attleboro Steam & Electric Company located in 

Massachusetts. The Court struck down the Public Utilities Commission of Rhode Island’s efforts 

deeming that its regulation had placed a direct burden on interstate commerce. The Court’s 

decision ultimately created a regulatory gap wherein no regulator had the authority to oversee 

interstate transactions made by traditional utilities. 

In 1935, envisioning that the federal government should have a role in regulating

interstate energy transactions, Congress enacted the Federal Power Act, which gave the 

Commission exclusive regulatory authority over “the transmission of electric energy in interstate 

commerce” and “the sale of electric energy at wholesale in interstate commerce. 16 U.S.C. § 

824(b). While the statute vested this authority in the Commission, it also “reserved to the States 

certain . . . regulatory authority, including that over generation facilities.” (Stipulated Facts ¶ 5). 
15

Under the statute, state commissions “continued to regulate local utilities’ construction of new 

power plants, operations, and rates charged for retail service to customers” including “the costs 

incurred by local utilities in constructing and operating the power plants they used to generate 

electricity to service their retail customers. (Id.) From 1920 until the late 1980s, utilities operated 

under the concurrent supervision of both federal and state regulations. During that time, the 

Board and Commission acted cooperatively and respected their jurisdictional limits. 

Before the advent of federal authority in the electric power industry, a traditional utility 

“performed three main operational tasks: it built, owned, and operated electric power plants; it 

transmitted electricity from the power plants to the area of service in which it enjoyed a 

monopoly; and it distributed the electricity to its customers in that area of service using its local 

distribution network, that is, the poles and wires that it owned and maintained.” (Stipulated Facts 

¶ 1). Each traditional utility was, in essence, a “single company” that “generated power, 

transmitted that power, and distributed that power to its own customers, the homes and 

businesses that it serves”. (T. 2008, 13-18). In these early years, there was little to no relationship 

among the traditional utility companies, so each company generally only produced sufficient 

capacity to service its own customers’ needs. Each traditional utility had a service territory 

established by state regulation, a monopoly for electricity service within that territory, and an 

obligation to serve all customers in that service territory. “[I]n return for fulfilling that obligation 

to serve all customers, [traditional utilities] were given an assurance of a reasonable rate of 

return.” (T. 27, 16-21); (Stipulated Facts ¶ 2). As a result, a traditional utility’s sales of 

electricity to residential and business users within its service territory were considered retail sales 

to consumers and “largely regulated at the state level.” (T. 25, 5-6); (T. 30, 12-13); (Stipulated 

Facts ¶ 5). 
16

Often the lack of interaction among traditional utilities created inefficiencies because 

each utility would construct its own power plants to meet peak electric demand; that is, each 

traditional utility “was insuring that it had enough capacity to serve its own load.” (T. 37, 16-18). 

Because electricity demand peaks at limited times throughout the year, a utility may have needed 

to build a power plant that runs only “10, 15, 20, 50 hours a year.” (T. 35, 3-13). As a result, 

each traditional utility tended to have “plants that [were] sitting idle most of the time, because 

they [were] needed for a few hours.” (T. 37, 16-24). “[T]hat created some inefficiencies in the 

sense [that] . . . too many power plants to provide this capability were being built.” (T. 37, 16-

24).

In the early twentieth century, some electric utilities smartened up, adjusted their 

strategy, and “began to sell power or standby capacity to each other.” (Stipulated Facts ¶ 3). In 

order to accomplish this, the traditional utilities “built high voltage transmission lines among 

them in order to transact such ‘wholesale’ purchases and sales. This allowed utilities to lower 

costs because they no longer had to maintain sufficient capacity to supply peak demand at all 

times; instead, they could contract bilaterally in the interstate wholesale market to ensure that 

they had access to sufficient resources to supply peak demand when it was needed.” (Stipulated 

Facts ¶ 3). Thereafter, to protect against outages, traditional utilities would buy and sell capacity 

from one another for future years, so that they could be assured they would have sufficient 

supply when operating contingencies arose, without having to develop more power plants. 

As the traditional utilities engaged in increased wholesale sales and capacity purchases, 

the need for federal regulation became more obvious. In order to manage stand-by capacity sales, 

PJM was created to ensure reliability by managing interstate transmission lines and, in more 

recent years, by designing and operating wholesale auctions.
17

Deregulation of Wholesale Energy Sales by the Commission

In the 1980s, when governmental deregulation of business entities was a prevalent feature 

of federal policymaking, some federal legislators brainstormed that the structure for sales of 

energy and energy capacity could be modified from one in which sales were made at a 

governmentally imposed rate to one that was more economically efficient, competitive and based 

on the economic theory of supply and demand. This idea ultimately culminated in several 

initiatives during the 1990s. 

In 1992, Congress enacted the Energy Policy Act of 1992 (“EPAct”), Pub. L. No. 102-

486, 106 Stat. 2776, which authorized the Commission to ease restrictions on access to interstate 

transmission wires. This allowed more electric generators to provide energy to a broader area, 

and recognized the concept of separating generation facilities from other parts of traditional

utilities. That is, the generation segment of a traditional utility could operate separately from the 

other segments of the utility. A key objective of the Energy Policy Act was to “encourage[e] the 

development of independent generators” – sometimes referred to as “independent power 

producers” – “that could sell into the marketplace.” (T. 44, 11 through T. 46, 25).

In 1996, the Commission issued Order Number 888 which required “transmission owners 

in the United States . . . to offer access to their transmission wires to third-parties . . . on a

non-discriminatory basis.” (T. 45, 12-19). “Order 888 opened the transmission grid, and 

competition began to develop, and . . . . wholesale markets were actually emerging regionally.” 

(T. 47, 12-16). In 1996, through Orders 888 and 889, the Commission “established national

open-access rules that required all transmission-owning utilities under its jurisdiction- i.e., those 

utilities that ‘own, control, or operate transmission facilities used for transmitting electric energy 

in interstate transmission’ - to provide non-discriminatory transmission access under 
18

standardized tariffs. One significant impact of Orders 888 and 889 was to increase the 

opportunity for non-utility generators to sell their power to additional markets.” (Stipulated Facts

¶ 8). 

In December 1999, the Commission issued Order 2000 which encouraged industry 

participants to organize themselves into large regional entities called regional transmission 

organizations (“RTO”). The creation of such organizations “allow[ed] for regional operation of 

the transmission system and provide[d], among other things, a platform for regional wholesale 

electricity markets.” (Stipulated Facts ¶ 9). Notably, PJM is an RTO. 

PJM adapted some of its functions to meet the requirements of these statutes and 

regulatory directives. Most importantly, PJM instituted three types of wholesale markets: “[the] 

capacity market, the energy markets and the ancillary services markets.” (T. 74, 21 through T. 

75, 23). Each of these markets has a special function: 

(a) the “regional capacity market, called the reliability pricing model (RPM),

annually sets the price of capacity” three years forward. The controversy in this case involves the 

regional capacity market. (T. 74, 23-24).

(b) the energy markets price the cost of energy produced by the generators and used 

by consumers. (Stipulated Facts ¶ 20). PJM operates a “day ahead” energy market, meaning 

“generators offer to supply power into the market a day ahead of real time.” The day ahead 

market is a “planning tool that PJM uses to [e]nsure that it knows a day ahead of time what 

resources are going to be available 24 hours thereafter, when the generation is actually 

dispatched to keep the lights on.” PJM also operates a “real time energy market, which is an 

hourly market that is close to the time of operation. And capacity resources bid into that market, 

and offer to supply . . . the actual electricity.” (T. 74, 21 through T. 75, 23); and 
19

(c) the ancillary services markets price the sale of “ancillary services” such as 

“spinning reserves and load-following services” to improve reliability. (T. 74, 21 through T. 75, 

23).

Deregulation of Electric Generators by the Board

Following the federal lead, many traditional utilities chose to restructure by separating

their generation functions from their transmission and distribution functions. (Stipulated Facts ¶ 

6). According to Mr. Massey, there were two methods to accomplish this. First, the traditional

utilities could sell or transfer their power plants to a competitive generation company. Second, 

the traditional utilities could “create an affiliate corporation . . . within a holding company to 

own the generation.” (T. 53, 13-21). During the 1990s, many states restructured their electric 

industries to promote competitive markets in wholesale power generation. “Typically, the [s]tateordered restructuring resulted in the unbundling of [traditional] utilities into separate generation, 

transmission, and distribution companies. The distribution entities came to be known as ‘Electric 

Distribution Companies’ or ‘EDCs[.]’” (Stipulated Facts ¶ 6). In some cases, “restructuring also 

enabled third parties with no distribution assets to compete in the sale of electricity at retail.” 

(Id.) These entities are referred to as "Load Serving Entities" ("LSEs") (Id.).

In 1999, New Jersey followed suit. It restructured its utilities in a slightly different format 

than described above, but with the same result. In enacting the Electric Discount and Energy 

Competition Act (“NJ Energy Competition Act”), N.J.S.A. § 48:3-49 et seq., the New Jersey 

legislature unbundled the sale of energy to retail customers. The consumer could choose to be 

served by one of several load serving entities which would compete to provide service. These 

LSEs would deliver the energy through an electric distribution company (“EDC”). (T. 59, 2-9). 

As Mr. Dominguez explained in his testimony, the driving force behind the NJ Energy 
20

Competition Act was “customer choice” – that customers would have the right to choose their 

electricity suppliers or LSE. (Id.) Although the New Jersey Legislature focused on the benefit to 

the consumer, the NJ Energy Competition Act also “required the State’s [traditional] electric 

utilities to divest themselves of electricity generation assets.” (Stipulated Facts ¶ 7). Once the 

generation component was stripped, the word “utilities” became associated with the term

"electric distribution companies" because EDCs were responsible for distributing electricity over 

local distribution networks to consumers in monopolistic service areas and were required to act 

as common carriers.

7 “The electricity itself was supplied by retail electric suppliers, that is, 

LSEs.” (Stipulated Facts ¶¶ 7, 9).

At the time of enactment, the New Jersey Legislature recognized the magnitude of this 

fundamental change by declaring that “this bill would effectively end the system of government 

regulation of the electricity generation industry, which has existed in New Jersey since the years 

when Woodrow Wilson served as Governor.” Electric Discount and Energy Competition Act, 

P.L. 1999, c.23. eff. Jan. 25, 1999. Hence, the NJ Energy Competition Act recognized the demise 

of the traditional utility and the transformation of the electric energy industry into a more market 

driven system. Further, although the federal and state statutory amendments opened new 

competitive markets through restructuring, the State retained its authority over the siting and 

construction of power plants. (T. 167, 9 through T. 169, 6). So, after restructuring by the federal 

and New Jersey governments, the electric energy industry operates in the following manner:

(a) generators may sell energy and capacity at wholesale prices to PJM or negotiate 

power supply agreements (T. 64, 11 through T. 65, 4);

(b) PJM transmits and sells energy to load serving entities (“LSEs”); and 

 7 The electric distribution company is referred to as a utility, but its operation is not as expansive as a traditional 

utility. 
21

(c) LSEs sell to consumers and distribute the energy through electric distribution 

companies (“EDCs”) which have monopolistic service areas and operate as common carriers. 

Since the EDC transmits the electric to consumers within its monopolistic area, it receives a 

delivery fee from the LSE. 

In New Jersey, there are four EDCs: Rockland Electric Company, Public Service Electric 

& Gas Company (“PSE&G”), Jersey Central Power & Light Company (“JCP&L”), and Atlantic

City Electric. (Pl.’s Ex. 45, at 16-17). Each EDC owns and operates the local distribution wires 

located within its service territory. (T. 66, 17-22). After the restructuring, the State’s utilities 

“became more commonly known as ‘electric distribution companies’ (‘EDCs’) because they 

were responsible for distributing electricity over local distribution networks.” (Stipulated Facts ¶ 

7). An EDC is sometimes referred to as the “local utility,” but “the term EDC, electric 

distribution company, is intended to convey that this company is in the business of delivering 

electricity.” (T. 56, 6-12). The electricity sold to retail customers by LSEs is delivered by the 

EDC within their local distribution networks.

The 2008 New Jersey Energy Master Plan authorized by the Board summarized the 

importance of the NJ Energy Competition Act:

The owners of New Jersey power plants now have no legal expectation 

that they can recover all of their costs or a guaranteed return from retail 

customers. Hence, the plant owners (and their financiers) make their own 

decisions to invest in existing or new power plants, without [Board] 

oversight. They also make their own decisions about the price, using 

market signals, at which they are willing to sell their electricity, without 

traditional [Board] oversight. (Pl.’s Ex. 45, at 16). 

***

PJM, under the supervision of [the Commission], is responsible for 

planning the electric transmission system to preserve the reliability of the 

electricity supply in its territory. Electric generation companies and their 

financiers make decisions about how much generating capacity will be 
22

built, what types of power plants will provide that new capacity, and 

where the new plants will be located; those companies also decide what 

plants will be kept in service and what plants will be retired. Those 

decisions are informed by economic signals from the wholesale electricity 

markets that PJM designs and administers, again under the supervision of 

the [Commission]. (Id. at 27).

Despite deregulation which provided generators with more decision making powers, the 

Commission and PJM do not have substantial authority to require construction of power plants, 

prevent retirement of generation, select the generation technologies that will be constructed, or 

require demand resource or energy efficiency programs as a means of addressing resource 

adequacy. (Def.’s Ex. 563). However, as previously noted, the restructuring of the traditional

utilities required PJM and the Commission to institute three competitive markets which effect 

energy and capacity prices. The market of primary interest in this case is the regional capacity 

market called the reliability pricing model (“RPM”). 

F. THE RELIABILITY PRICING MODEL (“RPM”)

The RPM is intended to “secure sufficient capacity resources to meet standards for

serving the highest aggregate demand of the region’s electric customers.” (Stipulated Facts ¶ 12). 

To meet that objective, the RPM “establishes an annual Base Residual Auction (‘BRA’) [or 

“RPM Auction”] through which PJM administers procurements of capacity.” (Id.)

The RPM conducts the RPM Auction each May to secure the capacity that will be

needed three years in the future. (T. 419, 3-8); (Stipulated Facts ¶ 25). New Jersey is a voluntary 

member of PJM and is a part of the RPM market. (Stipulated Facts ¶ 13). RPM is a provision of 

the PJM tariff which is approved by the Commission. (Stipulated Facts ¶ 23); (T. 80, 25 through 

T. 81, 4); (Def.’s Ex. 184). As the parties stipulated: 
23

Through the [RPM Auction] PJM seeks to procure . . . the amount of 

capacity that it has determined . . . will be needed to meet the system (or in 

some cases, the Locational Deliverability Area (‘LDA’)) peak three years 

in the future, plus a reserve margin. PJM then bills each participating load 

serving entity for its load-ratio share of the costs incurred by PJM to 

secure that capacity through the [RPM Auction]. (Stipulated Facts ¶ 26). 

Generally, “The [RPM Auction] is a ‘forward market,’ meaning capacity is sold three years in 

advance of when it is needed. For example, the auction held in May 2012 [which is the subject of 

this lawsuit] concerned offers to sell capacity to be ‘delivered’ beginning June 1, 2015, through 

May 31, 2016.” (Stipulated Facts ¶ 27).

RPM was designed to provide price signals for both new and existing generation. PJM 

Interconnection, LLC, 132 F.E.R.C. ¶ 61,173, 61,870 (2010). The Commission has emphasized 

that “RPM was designed to provide long-term forward price signals, and not necessarily longterm revenue assurance for “generators and developers.” (Pl.’s Ex. 55, at 55-56). As Mr. 

Dominguez stated, “the RPM is a market-based mechanism that uses economic price signals to 

indicate scarcity and need for capacity,” and generators will decide from the price signal whether 

or not to expand or create new generation. (T. 413, 1-8).

“In the [RPM Auction] capacity resources . . . bid to supply capacity to PJM for one year 

beginning three years in the future, each offering to supply a particular quantity of capacity at an 

offer price.” (Stipulated Facts ¶ 28). The bids of capacity resources are “stacked” from lowestcost bids to highest-cost bids to construct a supply curve. (T. 92, 19-25). PJM also constructs a 

demand curve that is based on a forecast of peak electricity demand (“peak load”), plus a reserve 

margin. (T. 661, 13 through T. 662, 19). The PJM “reserve margin” is typically around 15 

percent or more. The reserve margin addresses the possibility that “some plants might fail, might 

not be able to meet their obligation,” or that there could be a “transmission outage.” (T. 89, 25 

through T. 90, 13). As Mr. Massey indicated, “[i]t also takes into account the fact that . . . [it is] 
24

hard to forecast electricity usage perfectly.” (T. 90, 2-3). “And so this reserve margin is an 

insurance policy.” (T. 90, 7). “The price of capacity in the [RPM Auction] is set by the 

intersection of supply and demand and is referred to as the ‘clearing price.’ That is, any capacity 

supplier that bids at or below the clearing price ‘clears’ the [RPM] auction and receives the 

clearing price for that capacity. Any capacity supplier that bids above the clearing price fails to 

‘clear’ the [RPM] auction, and its capacity does not sell in the auction.” (Stipulated Facts ¶ 29).

The clearing prices for capacity sold in the RPM are the Commission approved rates for capacity

sales made in PJM territory. (Pl.’s Ex. 26). When a generation resource has cleared the auction, it 

obligates itself to run through the delivery year. (T. 473, 22 through T. 474, 7). Thus, a capacity 

resource that clears the RPM Auction commits itself to make any investments necessary to fulfill 

its obligation. It also obligates itself to bid into the PJM energy and ancillary services markets. 

(T. 426, 1 through T. 473, 17). 

As Mr. Dominguez testified, RPM is designed to procure the least expensive mix of 

resources that are necessary to keep the lights on for that one year period, three years hence. (T. 

414, 14-18). Generally, the RPM Auction says to market participants “I am willing to serve 

capacity for one entire year three years forward.” (T. 414, 14-18). “The purpose” of RPM was to 

“guarantee[] that the reliability target in PJM is met in the least cost possible way.” (T. 763, 13-

23). As PJM has explained to the Board, its “RPM Capacity Market is designed to commit the 

least-cost set of capacity resources to ensure that [Commission]-established resource adequacy 

targets are met in the PJM footprint on a three-year forward basis.” (Pl.’s Ex. 230, at 10).

Generally, the single clearing price encourages capacity resources to operate more 

efficiently while keeping prices low. “[A] competitive market with a single, market-clearing 

price creates incentives for sellers to minimize their costs, because cost-reductions increase a 
25

seller’s profits. And when many sellers work to minimize their costs, competition among them 

keeps prices as low as possible. . . . This market result benefits customers, because over time it 

results in an industry with more efficient sellers and lower prices.” PJM Interconnection, LLC, 

117 F.E.R.C. ¶ 61.331, 62678 (2006); (Pl.’s Ex. 19, at 57); (T. 436, 8-24). As Mr. Massey

indicated, since there is a single price for the commodity, “the person who can provide the 

[capacity] cheapest will do the best in that market; [and the] person who cannot provide the 

[capacity] competitively is either going to go out of business or figure out how to do better.” (T. 

436, 19-24). Mr. Massey explained “economists would say it’s the law of one price. . . . It [does 

not] matter whether the electric energy’s produced by an old generator [or] new generator, [it is]

electric energy, it has the same value in the marketplace. And that [is] why pursuant to 

[Commission] rules that single clearing price model is used.” (T. 92, 19 through T. 93, 23).

Despite the goal of reaching a highly competitive price through the RPM Auction, price 

varies in certain areas of the PJM market. For example, in New Jersey the price is higher than 

that in western Pennsylvania because the transmission costs associated with delivering the 

energy in New Jersey are more costly. (Def.’s Ex. 204). “For purposes of the RPM, PJM is 

divided into regions known as [Locational Deliverability Areas, or] LDAs.” (Stipulated Facts ¶ 

30). “New Jersey is located in a Locational Deliverability Area called ‘EMAAC,’ which also

includes parts of Maryland, Pennsylvania, and Delaware. EMAAC is located within a wider 

[LDA] called ‘MAAC,’ which includes EMAAC, additional parts of Pennsylvania and 

Maryland, and the District of Columbia.” (Stipulated Facts ¶ 31). According to the parties, 

within EMAAC, “there are smaller LDAs, including (within New Jersey), one called ‘PSEG’, 

and within the PSEG LDA, another one called ‘PSEG North.’” (Stipulated Facts ¶ 33). As the 

parties explained: 
26

When constraints on the transmission lines limit the amount of electricity 

that can be imported into an LDA, RPM capacity prices can be higher in 

the constrained LDA - reflecting the fact that the LDA must rely on more 

expensive capacity resources located within the LDA rather than cheaper 

capacity resources located elsewhere. (Stipulated Facts ¶ 33). 

Prices are often different among the LDAs leading to “price separation.” As the Commission has

explained, “[c]apacity market prices must be locational in order to be fully effective. Because of 

transmission constraints, capacity in one location is not always deliverable to loads in other

locations[.]” (Pl.’s Ex. 26, at 34). As such, separate capacity prices are necessary to reflect the 

differences in costs and capacity needs among the locations. “Further, if a single capacity price is 

set for the entire region, capacity prices do not reflect the need for generation” in those particular 

locations. (Id.) For instance, as Mr. Dominguez stated “higher price for capacity gives a signal to 

those in the generation industry to consider developing a new plant or resource within the LDA 

because a better profit could be realized.” (T. 445, 24 through T. 446, 12). “[T]his price 

differential is reflective of the transmission constraints in moving power from west to east into 

New Jersey and [signals] the need for resources to be located inside New Jersey.” (Pl.’s Ex. 75, 

at 7).

From its initial inception in the early 2000s, the Board did not accept the RPM theory. 

Rather, the Board predicted that RPM would curtail development of new generation into New 

Jersey. The Board recommended that new generators should be given assurances to overcome

fears regarding the risk of long term financing packages of potential financiers. The Board also

complained that the RPM functions unfairly against new generators. First, the Board argued that 

the long term price signals of the RPM Auction were insufficient to attract new generators in 

New Jersey since little development had occurred. (Pl.’s Ex. 197). Second, the Board argued that 

financial institutions were reluctant to loan money for development because of uncertainty. That 
27

is, capacity prices fluctuate and the clearing price of the RPM Auction only lasts a year 

ultimately rendering a long term loan very speculative. In reality, these variables caused energy 

prices to increase in New Jersey. As then-Board Commissioner Frederick Butler advised the 

Commission in February 2006:

RPM, in its current form, will not have the intended effects on investment 

and will not result in the most cost effective means of solving future 

reliability problems. Thus, we are concerned that RPM, in its current form, 

will not ensure adequate electricity supply within New Jersey, and will 

lead to increased costs to our consumers. (Pl.’s Ex. 13, at 1).

Mr. Butler requested that the Commission undertake “additional dialogue . . . to shape the short

term and long term needs of [the] wholesale electricity market[,]” rather than adopting the RPM. 

(Id. at 6). Notwithstanding New Jersey’s policy objections, the Commission approved RPM 

because it disagreed with New Jersey’s argument that “the [RPM] Settlement will raise prices 

without improving reliability.” (Pl.’s Ex. 19, at 30); (T. 103, 11, through T. 104, 5).

In 2007, despite the Board’s objections, the RPM rule was adopted which included the 

minimum offer price rule (“MOPR”). PJM subsequently adopted new rules on how the RPM 

would operate. These rules contemplated, among other things, who may enter into the RPM 

market and how each generator may bid (T. 2653, 2-8). Most notably, the MOPR governed

biddings by new capacity resources. Over the last several years, the MOPR has been modified 

several times by PJM in 2011 and 2013. Some of these modifications occurred based on the facts 

of this case. 

The RPM Auction is not based on a pure open bidding process. For instance, an existing 

generator which previously operated as a part of a traditional utility is permitted to bid at zero. 

(T. 1652, 23 through T. 1653, 2). The rationale for permitting such bids is that these generation 

facilities have been operating longer than projected so capital costs have been recaptured. As 
28

such, the capital costs are deemed to be zero.

8 The ability of these long time generators to bid at 

zero when they may have sufficient capacity to provide to PJM raises a question as to whether 

the RPM Auction is actually necessary. In response to this question, PJM developed the MOPR, 

which it administratively calculates each spring from costs associated with the entry of a new 

generator; and then it lists administratively determined amount as the net cost of new entry (“net 

cone”). PJM converts that net cone into a price of megawatts per day (“benchmark price”) (T. 

1662, 17-19). While existing generators still bid at zero, they are accepting the net cone 

benchmark price in the RPM Auction. Hence, an existing generator became commonly known 

within the industry as a “price-taker.” If such a generator forecasted that the benchmark price

would fall below its projected cost, that generator may choose not to bid and retire the plant. 

(Def.’s Ex. 235). However, PJM was also concerned that new generators would bid below the 

benchmark price in order to be accepted into the capacity market. Hence, MOPR was also a 

“mechanism that s[ought] to prevent the exercise of buyer market power in the forward capacity 

market by ensuring that all new resources are offered into PJM’s Reliability Price Model (RPM) 

on a competitive basis.” (Def.’s Ex. 331, at 4). In order to determine the competitiveness of a 

new generator, PJM applies a “MOPR screen.” The MOPR screen has several components: 

(i) a conduct screen (i.e., a benchmark price used to determine whether a sell offer may 

be competitively low and thus warrants mitigation upward (described below); (ii) an impact 

screen test that compares the capacity clearing price with and without mitigation; and (iii) an 

incentive test, or net-short requirement (designed to distinguish between sellers who are net

buyers and may have incentives to depress market clearing prices below competitive levels and 

 8 Peculiarly, if a long time generator added more capacity to an existing plant, it may still bid at zero despite the 

development costs. 
29

sellers of planned generation who may have incentives to increase market clearing prices above 

competitive levels. (Def.’s Ex. 331).

Several exemptions applied to the MOPR’s application including the “state mandated”

and the “unit-specific” exemptions. When the MOPR was initially adopted, there was an 

exemption from the MOPR requirements if the project was undertaken pursuant to a state 

regulation or mandate (T. 1654, 12-15). According to Mr. Knight, a state mandated entrant could 

bid as an existing generator – price taker, and “bid whatever they wanted to bid.” (T. 1654, 18). 

In addition, there was a unit-specific exemption applying to new gas-fired generation. Such unitspecific exemptions permitted bids down to 80% of the benchmark price upon a showing that the 

net cone costs were at that level. Such a bid may be lower than the administrative benchmark 

price. 

As noted above, the MOPR was changed through tariff modifications in 2011 (MOPR II) 

and 2013 (MOPR III). MOPR II eliminated the exemption that previously permitted developers 

of certain state-sponsored projects from bidding as “price takers.” It also raised the “price floor” 

for new entrants’ bids from 80% to 90% of PJM’s benchmark price. (Def.’s Ex., at ¶¶ 24, 43, 

66). According to Mr. Knight’s testimony, in May 2013, the Commission further ruled that: (1) 

state-sponsored projects should be subject to the MOPR (which led the Commission to eliminate 

the “state exemption”); (2) the default MOPR level should be 100% of net cone; and (3) new 

projects should be allowed to demonstrate that their own projected costs will be lower than the 

benchmark price and should be able to pass a MOPR screen based on those projected costs. 

(MOPR III). (T. 1679, 20 through T. 1680, 3).

In addition to the MOPR screens, there was another accommodation for new entrants 

called the New Entry Price Adjustment (“NEPA.”) (Def.’s Ex. 238). The NEPA provision was 
30

intended to make investments in new generation less risky. The NEPA assures developers of 

projects in local deliverable areas (“LDAs”) that after their facilities become operational they 

will continue to receive, for a period of subsequent years, the capacity price of the RPM Auction

that prevailed at their time of their entry. In 2006, concerns regarding how long the NEPA 

guarantee should operate were addressed by PJM and the Commission. PJM and FERC 

ultimately settled on a period of three years. (Def.’s Ex. 238). Despite the MOPR and NEPA 

adjustments, the RPM costs left New Jersey residents with higher electricity prices due to

associated transmission costs. These higher costs displeased the Board.

In addition to the RPM, two other energy issues arose in New Jersey at this time which 

adversely affected the industry and its regulations. First, PJM forecasted that the amount of 

energy required for New Jersey would be greater than the state’s transmission capabilities 

potentially leading to outages. Notably, PJM identified twenty-three (23) power transmission 

violations which were likely to threaten PSE&G customers. Generally, these violations were

deficiencies in service and reliability. (Def.’s Ex. 563, at 24-30); (Def.’s Ex. 567, at 20). The 

other adverse issue which arose was the adoption of new environmental regulations requiring 

that coal-fired plants be retired unless renovations substantially reducing emissions were made.

As a result of these new environmental regulations, the Board projected that the amount of 

capacity within the PJM territory, particularly the amount of capacity in New Jersey, would be 

significantly reduced. Both of these adverse issues are discussed below. 

Lack of Adequate Transmission Capabilities

In 2010, PJM disclosed to the Board that reliability issues may arise due to insufficient 

transmission capabilities in New Jersey. According to the PJM: “Based on the latest studies 

performed by PJM and the transmission owners, PJM, PPL and PSE&G concluded that there are 
31

23 potential electric reliability violations that are expected to occur beginning in 2012, and 

extending out through PJM’s 15-year planning horizon of 2022.” (Def.’s Ex. 565, at 12). These 

violations had the potential to cause brownouts or blackouts. Since the violations were projected 

to occur within two or three years, the Board became concerned about whether transmission 

capabilities could be improved in such a short period of time. PJM found that this reliability 

issue could only be addressed in one of two ways — increased transmission through the 

construction of the Susquehanna-Roseland transmission line (“Susquehanna Connection”) or 

construction of additional generation in or near the location where the reliability violations 

would occur. (Def.’s Ex. 563, at 33). Given the difficulties associated with implementing either 

of these contingency plans in such a short period of time, from the Board’s perspective, New 

Jersey was at risk. As Mr. Roach summarized, “this is really, to put it mildly [an issue that] . . . 

[got] their attention.” (T. 1893, 22 through T. 1894, 2).

Environmental Issues

In 2008, newly imposed environmental regulations cast their shadow over the New Jersey 

energy industry when the federal and state governments partially prohibited coal-fired plants 

from being operated unless significant environmental modifications were made. At that time, 

federal environmental rules required 12 to 19 gigawatts of capacity in the PJM territory, which 

amounted to about 7 to 11 percent of all PJM generation, be retired or renovated. (T. 1612, 7 

through T. 1613, 15). In addition, about a year later, New Jersey adopted the High Energy 

Demand Day Rule (“HEDD”) which created a potential reliability issue by limiting the number 

of hours that certain electric generating units could operate. (T. 1897, 9-24). In short, from a 

resource adequacy or capacity perspective, the Board believed that New Jersey was vulnerable to 

the shutdown of 11,000 megawatts of coal-fired generation. (Pl.’s Ex. 127); (T. 1289, 22 through 
32

T. 1290, 9);(T. 1896, 21 through T. 1898, 10). As Mr. Roach explained it, the Board thought,

“I’ve got to put iron in the ground[.] I’ve got to get a new power plant locally to protect against 

these things.” (T. 1894, 12-16). 

G. INTRODUCTION OF THE LCAPP STATUTE

The Board undertook several measurers to address its concerns. First, the Board appealed 

the Commission’s decision implementing the RPM and MOPR rules. Second, the Board worked 

with the New Jersey Legislature to develop a bill that would create new capacity resources closer 

to or within the State.

The Board’s petition of review of the Commission’s decision was summarily denied by 

the United States Court of Appeals for the District of Columbia. In its decision, the Circuit Court 

concluded “that the Commission had a substantial basis on which to conclude that the RPM was 

an appropriate tool for increasing reliability in electricity markets, that the RPM did precisely 

what it was intended to do, even during the transition period before the three-year lag could take 

effect, and that the price hikes in its wake were attributable to legitimate causes.” Md. PSC v. 

FERC, 632 F. 3d 1283, 1286 (D.C. Cir. 2011). The Court did not specifically address the 

Board’s or the State of Maryland’s contentions regarding lack of reliability, the regional nature 

of increased capacity prices, or the impact of the newly implemented environmental regulations 

governing coal-fired plants. Rather, the court seemed to accept the Commission’s determination 

that the “rates were just and reasonable” at face value. Id. at 1285. 

On January 28, 2011, the New Jersey Legislature, with the Board’s support, enacted the 

LCAPP Act which authorized the construction of several gas-fired generators in or near New 

Jersey. (Stipulated Facts ¶ 35). The purpose of LCAPP was "[t]o address the lack of incentives 

under the reliability pricing model” by fostering the “construction of new, efficient generation . . 
33

. [to] ensure[] sufficient generation is available to the region, and thus the users in the State in a 

timely and orderly manner[.]" N.J.S.A. § 48:3-98(d)(2); (Stipulated Fact ¶ 36). In general terms, 

the LCAPP Act established a “pilot program,” overseen by the Board, to issue “Standard Offer 

Capacity Agreements” (“SOCAs”) to selected eligible generators. N.J.S.A. § 48:3-98.3. The 

statute requires New Jersey’s four electric distribution companies (“EDCs”) to enter such

contracts with eligible generators and obligates these EDCs to pay any difference between the 

RPM Auction price and their actual development costs approved by the Board. N.J.S.A. § 48:3-

98.3(c)(9). The LCAPP contemplated the awarding of SOCAs for 2,000 megawatts of generation 

capacity. It further directed that the selected LCAPP generators were to “participate in and clear 

the annual base residual auction [RPM Auction] conducted by the PJM . . . for each delivery year 

of the entire term of the agreement.” N.J.S.A. § 48:3-98.3(c)(12). In addition, the statute directed 

the Board to conduct a competitive solicitation of capacity and required winning bidders to enter 

into SOCAs lasting no longer than fifteen years with the State’s electric distribution companies 

(EDCs). N.J.S.A. § 48:3-98.3(c)(1)-(4); see also (T. 121, 7 through T. 122, 24). The main 

purpose of the legislation was to provide a transaction structure that would result in new power 

plants being constructed in the PJM territory that benefit New Jersey. The New Jersey 

Legislature was ultimately interested in ensuring that new resources were constructed in time to

help mitigate the reliability risks discussed above. N.J.S.A. § 48:3-98.2(b); see also (T. 1368, 17

through T. 1377, 1)

More specifically, the LCAPP statute required:

• that the Board hire an agent to: (1) “assist the Board with the establishment of the 

LCAPP program; (2) prequalify eligible generators for participation in LCAPP; and (3) 

recommend to the Board the selection of winning eligible generators based on the net 
34

benefit to ratepayers of each eligible generator’s offer price and term.” N.J.S.A. § 48:3-

98.3(b)(1)-(3);

• that the Board “establish criteria associated with the prequalification of eligible 

generators in the LCAPP through a showing of environmental, economic, and community 

benefits, and through a demonstration of reasonable certainty of completion of 

development, construction, and permitting activities necessary to meet the desired inservice date” N.J.S.A. § 48:3-93.3(c)(6); (Stipulated Facts ¶ 39);

• that an "eligible generator'' be "a developer of a base load or mid-merit electric power 

generation facility . . . that qualifies as a capacity resource under PJM criteria and

that commences construction after the effective date” of the LCAPP. N.J.S.A. § 48:3-51;

(Stipulated Facts ¶ 40); 

• that a “Standard Offer Capacity Price (“SOCP”) mean “the capacity price that is fixed for 

the term of the SOCA and which is the price to be received by eligible generators under a

[B]oard-approved SOCA[.]” N.J.S.A. § 48:3-51. This price represents the development 

costs of the new generation as approved by the Board.

• that selected eligible generators “participate in and clear the annual base residual 

auction” (RPM auction) for the sale of their capacity to PJM.” N.J.S.A. § 48:3-

98.3(c)(12); and 

• that the Board order that New Jersey’s four electric distribution companies (EDCs) –

Public Service Electric and Gas, Atlantic City Electric, Jersey Central Power & Light and 

Rockland Electric Company “procure 2,000 megawatts of financially-settled SOCAs 

from eligible generation” for a period up to 15 years. N.J.S.A. § 48:3-98.3(c)(1),(9). The 

Board was further obligated to “establish a method and the contract terms for providing 
35

for selected eligible generators to receive payments from the electric public utilities for 

the difference between the SOCP and the RCP multiplied by the SOCA capacity.” 

N.J.S.A. § 48:3-98.3(c)(4). 

With the LCAPP, the New Jersey Legislature and the Board concluded that they would 

have to act to increase electric generation in the State due to the fact that the Commission’s

policies were not creating new capacity. As Dr. Roach noted in his testimony, the LCAPP 

created “some tension” between the Commission and the Board. (T. 2034, 25 through T. 2035, 

1). One area of tension is summarized in the LCAPP. Within the statement of findings, the 

Legislature noted that the New Entry Price Adjustment was insufficient. It stated: 

The PJM reliability pricing model could, through structural changes, 

provide necessary incentives, such as the expansion of the “New Entry 

Price Adjustment” mechanism for the construction of new capacity, 

including new intermediate and base load plants, by allowing new 

resources to qualify and receive a guaranteed capacity price for a longer 

period of time. However, the implementation of similar structural changes 

was previously denied by FERC and any future implementation is 

uncertain at this time. N.J.S.A. § 48:3-98.2(c).

More specifically, the legislative findings declared that the Board would “allow new resources to 

qualify and receive a guaranteed capacity price for a longer period of time” than the RPM 

permitted. Id. 

In addition, Board President Lee Solomon, in a September 16, 2010 memorandum to

Governor Christie, affirmed that the purpose of the LCAPP was to establish a “multiyear pricing 

supplement” that would provide the new LCAPP generators with a premium payment or “RPM” 

adjustment that would guarantee a LCAPP generator a payment to secure multi-year capacity 

revenue.” (Pl. Ex. 84, at 2). President Solomon also emphasized that the three year NEPA 

guarantee would be expanded to 15 years.
36

Moreover, LCAPP mirrors or overlaps the RPM Auction procedure. For instance, 

LCAPP requires that the price within a SOCA must be expressed in a “price per megawatt day” 

which is the same standard used in the RPM. Compare N.J.SA. § 48:3-98.3(c)(2) with 

(Stipulated Facts ¶ 8) (stating that “the price of capacity in RPM is generally measured in dollars 

per megawatt-day (“$/MW-day”)).

Between 2008 and 2012, the transmission, reliability and environmental issues evolved. 

That is, many of the Board’s concerns had subsided through the deliberate actions of PJM 

stakeholders and/or economic circumstances. As Mr. Roach characterized it, New Jersey 

“dodged a bullet.” (T. 1894, 23 through 1895, 7). For example, PJM’s reliability forecasts failed 

to predict the 2009 recession, and therefore overstated the amount of capacity required. (Pl.’s 

Exs. 34, 65, 116, 275, 362). Accordingly, PJM reissued forecasts with lower usage estimates

which minimized PJM’s reliability concerns. During the trial, there was little to no evidence that 

this revised usage data proved to be false.

In addition, PJM recommended the construction of the Susquehanna Connection, a new 

145-mile high voltage transmission line to move electricity from Berwick, Pennsylvania to 

Roseland, New Jersey. Presently, officials of PJM and PSE&G anticipate that construction on the 

project should be completed in 2014 or 2015. This project has the potential to solve the

reliability violations that PJM projected. (Def.’s Ex. 563). Despite its ongoing construction, the 

Board argues that the length of time needed to complete the Susquehanna Connection project has 

left New Jersey vulnerable to outages. As such, according to the Board, new generation within 

New Jersey is needed to alleviate future reliability issues.

Lastly, the retirement of coal-fired plants has been an ongoing process. Despite the 

Board’s concerns, PJM has found that within its territory the RPM had sufficient bidders to 
37

cushion or absorb the impact of these shutdowns. In addition, through the RPM Auction, PJM

has acquired more than sufficient capacity to serve its territory. As PJM reported, although 

changes in environmental rules have led to significant retirements, “[t]he announced generation 

retirements sen[t] a strong signal that there would be a need for new resources, and [the 2012] 

auction witnessed a record number of new generation offers.” (Def.’s Ex. 204, at 2); (T. 1084, 

15-22). In fact, the 2012 RPM Auction cleared enough capacity to have a 20.2% reserve margin 

– significantly above the 15.4% reserve margin usually reserved. It is noteworthy that one of the 

Board’s witnesses confirmed that sufficient generation exists. Specifically, Mr. James Giuliano, 

Director of Reliability and Security of the Board, testified that he could not recall any power 

outages caused by insufficient generation. (T. 1104, 15-19). 

Appointment of LCAPP Agent and MOPR Rules Revisited

In the first quarter of 2011, following enactment of the LCAPP, two significant events 

occurred. First, the Board appointed Levitan & Associates to be the LCAPP agent. (Pl.’s Ex. 

136). Immediately after its appointment, Levitan began an exhaustive but expeditious selection 

process to identify generators capable of fulfilling both the requirements of the LCAPP statute 

and the policy objectives of the Board. Secondly, certain PJM stakeholders complained to PJM 

and the Commission that the state mandated exemption under MOPR should be prohibited

because, under the exemption, the Board was unilaterally changing the price of capacity by 

imposing its own approved costs rather than relying on the competitive price of the RPM.

Levitan’s evaluation of generators’ proposals through the eligibility, prequalification and 

commercial proposal stages was based on an evaluation process “consistent with the LCAPP 

Law that [was] centered on the maximization of economic, environmental and community 

benefits from the standpoint of ratepayers in New Jersey.” (Pl.’s Ex. 178, at 11). Specifically, 
38

“[a]pplicants were first reviewed in light of the requirements in the LCAPP Law to be an eligible 

generator. Eligible generators were then further reviewed to determine whether they should be 

prequalified on the basis of showing environmental, economic and community benefits, and the 

demonstration of meeting the proposed in-service date with reasonable certainty.” (Id.). 

Furthermore, “[t]he evaluation of commercial proposals was completed in parallel with the 

prequalification review.” (Id.).

According to Mr. Levitan, the “community benefits” aspect of the prequalification 

assessment concerned “the developer’s ability to drum up support in the community to achieve 

the [LCAPP Act’s] aggressive [construction] milestones.” (T. 1313, 7-15). The benefit sought 

was the timely construction of a qualifying new generation facility within the PJM territory. In 

evaluating the economic benefit of potential projects, Levitan “look[ed] at the completeness of 

the technology and operating data forms . . . [to] facilitate [its] analysis in the next phase.” (T. 

1312, 22 through T. 1313, 3).

In total, thirty-four (34) generation projects submitted prequalification applications to 

Levitan. (Stipulated Facts ¶ 43). Many of these projects were disqualified for various reasons. 

Notably, Levitan eliminated twenty-one (21) of the projects because they “were tied to existing 

generation units and therefore did not meet the condition of being a new generation facility.” 

(Stipulated Facts ¶ 45). The Board and Levitan also eliminated four (4) projects because they 

“were characterized as peaking units, rather than base load or mid-merit units as required by the 

LCAPP.” (Stipulated Facts ¶ 46). After three (3) generators withdrew their applications, only six 

(6) generators were prequalified. (Stipulated Facts ¶ 48). Of the six generation facilities that 

prequalified, Levitan recommended, and the Board later approved, that three be awarded 

SOCAs. These generators were Hess (625.0 MW of capacity), NRG (680.1 MW of capacity), 
39

and CPV (663.4 MW of capacity). (Stipulated Facts ¶ 54). All three of these generator projects 

are located in New Jersey. (Stipulated Facts ¶ 52). 

After the prequalification stage was completed, Levitan drafted the SOCA for each 

generator. The material terms of the three SOCAs are identical; they differ only with respect to 

the SOCA price, the quantity of capacity awarded, and the name of the generator. (T. 1368, 7-

11). Herein the Court utilizes the SOCA of CPV as an example.

The Board awarded CPV a SOCA with a fifteen-year term. (Pl.’s Ex. 203). Each SOCA 

contains an Attachment F, which provides the schedule of Standard Offer Capacity Prices for the 

LCAPP generator for the fifteen-year term. CPV received the following price schedule: 

Notably, CPV’s SOCA has provisions which relate to PJM activity. For instance, the 

SOCA refers to the RPM, the RPM Auction and/or other actions that occur within PJM. (Pl.’s 

Ex. 203). The SOCA responsibilities which correlate to PJM activities are listed below:

Delivery Year

(ending May 31st)

Standard Offer Capacity Price

($MW-day)

2016 286.03

2017 294.61

2018 303.45

2019 312.55

2020 321.93

2021 331.59

2022 341.54

2023 351.79

2024 362.34

2025 373.21

2026 384.41

2027 395.94

2028 407.82

2029 420.05

2030 432.65
40

“Available Capacity Amount” means the lesser of: (i) the quantity of 

Unforced Capacity from the Capacity Facility that is offered by Generator 

and cleared by PJM in the relevant Base Residual Auction [RPM

Auction], and (ii) the Awarded Capacity Amount. 

“Base Residual Auction” means the primary auction conducted by PJM as 

part of PJM’s Reliability Pricing Model [RPM] to secure electrical 

capacity as necessary to satisfy the capacity requirements imposed under 

the PJM reliability assurance agreement for the Delivery Year.

“Locational Deliverability Area” or “LDA” means the PJM sub-regions 

used to calculate Resource Clearing Prices as part of the Reliability 

Pricing Model. 

“PJM Interconnection, L.L.C.” or “PJM” means the Regional 

Transmission Organization that manages the regional, high-voltage 

electricity grid serving New Jersey and all or parts of other states and, 

among other things, administers the Reliability Pricing Model, and any 

successor.

“Reliability Pricing Model” or “RPM” means PJM’s capacity-market 

model that secures capacity on behalf of electric load serving entities to 

satisfy load obligations not satisfied through

the output of electric generation facilities owned by those entities or 

otherwise secured by those entities through bilateral contracts.

“Resource Clearing Price” or “RCP” means the clearing price expressed in 

$/MW-day for Unforced Capacity established by the Base Residual 

Auction for the LDA in which the Capacity facility is located and the 

applicable Delivery Year as posted by PJM.

“RPM Rules” means the provisions of PJM’s tariffs and agreements 

accepted by the Federal Energy Regulatory Commission and the 

provisions of PJM’s manuals governing the Reliability Pricing Model, as 

in effect from time to time during the term of this Agreement. (Pl.’s Ex. 

203). 

In addition to these terms, the term “delivery year” corresponds to the RPM availability 

requirement. Specifically, “Delivery Year” means “each 12-month period from June 1st through 

May 31st numbered according to the calendar year.” (Pl.’s Ex. 203). The term is the same under 
41

the SOCA. The SOCA obligates the generator to qualify within the RPM by clearing the RPM 

Auction and acting in accordance with PJM rules. The SOCA dictates the procedure:

2.3.1. Generator shall use all commercially reasonable efforts to cause the 

Capacity Facility to qualify under the RPM Rules as a capacity resource in 

an amount no less than the Awarded Capacity Amount for the Base 

Residual Auction associated with each Delivery Year during the term of 

this Agreement, commencing upon the Awarded Commencement Date.

2.3.3. Throughout the Delivery Term, Generator shall:

(a) Cause the Capacity Facility to comply with all obligations of a 

capacity resource under the RPM Rules, including without limitation the 

obligations relating to the submission of offers to supply electric energy 

and ancillary services in PJM markets, and Generator shall bear all costs 

associated with such compliance, including without limitation all fees and 

penalties imposed by PJM;

(b) Submit supply offers for an amount of Unforced Capacity no 

less than the Awarded Capacity Amount from the Capacity Facility in 

accordance with the RPM Rules in the Base Residual Auction associated 

with each Delivery Year during the term of this Agreement, such that the 

Unforced Capacity shall be offered at the lowest commercially reasonable 

price under the RPM rules;

(c) Submit supply offers from the Capacity Facility for the 

maximum amount of Associated Energy that the Capacity Facility can 

provide in the PJM day-ahead energy market in accordance with PJM 

Market Rules throughout the Delivery Term, such that the Associated 

Energy shall be offered at the lowest commercially reasonable price under 

PJM’s Market Rules;

(d) Submit supply offers from the Capacity Facility for the 

maximum amount of Associated Ancillary Services that the Capacity 

Facility can provide in the PJM ancillary services markets in accordance 

with PJM Market Rules throughout the Delivery Term, such that the 

Associated Ancillary Services shall be offered at the lowest commercially 

reasonable price under PJM’s Market Rules;

(e) Neither physically nor financially withhold any Unforced 

Capacity up to the amount of Awarded Capacity, or Associated Energy 

and Associated Ancillary Services, from the Capacity Facility;

(f) Provide on a timely basis . . . (i) documentation provided to 

Generator by PJM after the conclusion of each Base Residual Auction 
42

showing the amount of Unforced Capacity offered from the Capacity 

Facility and cleared by PJM in such Base Residual Auction; (ii) 

documentation provided to Generator by PJM in advance of each Delivery 

Year showing all EFORd measurements for the Capacity Facility for the 

Delivery Year; (iii) the result of any capability test for the Capacity 

Facility conducted by PJM; (iv) documentation provided to Generator by 

PJM in advance of each Delivery Year showing the showing the 

Availability Capacity Amount for the Delivery Year or required to 

calculate the Available Capacity Amount for the Delivery Year; and (v) 

documentation notifying Generator of any correction to an input to a 

calculation.” (Pl.’s Ex. 203). 

The electric distribution companies have one broad obligation to the Board under the 

SOCA. (Pl.’s Ex. 203). That is, they must report their compliance with the abovementioned

obligations to the Board. The SOCA reads, in relevant part:

2.4. Obligations of the Utility. The Utility shall prepare and file an annual 

report to the Board within thirty (30) calendar days after the end of each 

Delivery Year describing (i) the status of this Agreement, (ii) the amount 

of Unforced Capacity and cost of associated Transactions made under this 

Agreement, (iii) the performance of the Generator in supplying Unforced 

Capacity and Associated Energy and Associated Ancillary Services under 

this Agreement, and (iv) any material actions taken by the Generator or 

the Utility under this Agreement. Nothing in this Agreement imposes upon 

Utility the obligation to monitor, enforce, or declare an Event of Default 

with respect to the price of Unforced Capacity, or the price or amount of 

Associated Energy or Associated Ancillary Services, which Generator 

offers in or supplies to any PJM Market. (Pl.’s Ex. 203).

In addition, the SOCA sets forth a formula to make payments or receive refunds based on 

the SOCA amount and the clearing price at the RPM auction. The SOCA states: 

4.1.1. If, for a Delivery Year, the SOCP is greater than the [Recourse 

Capacity Price] then, subject to Section 2.5, Utility will pay Generator 

each Month during the Delivery Year one-twelfth of the product of (i) the 

difference between the SOCP and the [Resource Capacity Price], (ii) the 

Available Capacity Amount, (iii) the number of days in the Delivery Year; 

and (iv) Utility Load Ratio, each for the applicable Delivery Year.

4.1.2. If, for a Delivery Year, the [Resource Capacity Price] is greater than 

the SOCP then, subject to Section 2.5, Generator will pay Utility each 

Month an amount equal to one-twelfth of the product of (i) the difference 
43

between the RCP and the SOCP, (ii) the Available Capacity Amount, (iii) 

the number of days in the Delivery Year, and (iv) Utility Load Ratio, each 

for the applicable Delivery Year.

4.2. Structure of Transaction. Nothing in this Agreement shall entitle or 

obligate Utility to purchase, or take title to or delivery of, capacity, electric 

energy, or ancillary services from the Capacity Facility.

Under the SOCAs, “the LCAPP generators receive the payment set forth in the SOCAs 

only if they successfully sell the capacity from their facilities in the RPM base residual auction.”

(Stipulated Facts ¶ 56). The SOCAs also require the winning bidder to use all commercially 

reasonable efforts to construct an electric generation facility prior to the "commencement date"

of its RPM obligation. (Stipulated Facts ¶ 58). 

Finally, the SOCA requires that eligible generators maintain all approvals they have with 

PJM, and to “comply with Commission and RPM rules.” The agreement sets forth:

6.2. Maintain Authorizations. Each party will use all reasonable 

efforts, including the maintenance of records and provision of notices, to 

maintain in full force and effect all consents, licenses or approvals of PJM 

and of any Governmental Authority or other authority that are required to 

be obtained by it with respect to this Agreement, the Construction Period 

Security, and the Delivery Term Security and its obligations hereunder 

and thereunder and will use all reasonable efforts to obtain any that may 

become necessary in the future.

6.3. Comply with Laws and RPM Rules. Each party will comply in 

all material respects with all Applicable Laws and orders and all RPM 

Rules to which it may be subject if failure so to comply would materially 

impair its ability to perform its obligations hereunder or under the 

Construction Period Security or Delivery Term Security.

In accordance with the terms of its SOCA, CPV (as well as the other two eligible 

generators) sought admission into the RPM Auction. According to Mr. Knight, as part of CPV’s 

admissions process, representatives of CPV met with PJM to discuss the impacts of the MOPR II 

revisions and what information CPV would be required to submit. In response to a request for 

information issued by PJM, CPV sent an application consisting of more than 600 pages of 
44

materials. Within its application, CPV claimed it was exempt under the unit-specific exemption 

of MOPR II adopted in 2011, not the state mandated exemption provided for in the original 

MOPR. Under MOPR II, CPV could bid into the RPM auction at less than the minimum offer 

price floor (90 percent of net cone) if it could demonstrate that its actual costs were less than the 

benchmark price. (T. 1661:21 through T. 1673, 23); (Def.’s Ex. 51).

In determining whether CPV qualified for a unit-specific exemption pursuant to MOPR 

II, PJM did not consider any out-of-market payments that CPV would receive through New 

Jersey’s LCAPP program. (Def.’s Ex. 183, 751); (T. 1674, 14 through T. 1675). Pursuant to its 

practice under the MOPR screen, PJM advised CPV that it would accept a bid of no less than 

$151.24 / MW-day, which is the level at which CPV bid. (T. 1678, 18-20). The May 2012 RPM 

Auction cleared at $167.46 / MW-day. (Def.’s Ex. 204); (Stipulated Facts ¶ 59). According to 

Mr. Knight, the RPM Auction price was different than the Board’s approved costs due to “a 

difference in timing, and then secondarily a difference in the view on energy.” (T. 1677, 12).

With regard to the other eligible generator projects, Hess Corp’s project cleared the auction 

while NRG’s proposed project did not. Adamantly opposed, the four electric distribution 

companies signed the SOCAs under protest. 

H. IMPACT OF THE LCAPP STATUTE ON GENERATORS

Plaintiffs’ witnesses testified that their respective companies rely on the forward price 

signals of the RPM Auction in deciding whether to develop new generation resources or make 

investments in existing resources within a specific market. According to these witnesses, the 

LCAPP makes it more difficult for these companies to make such business decisions because 

they can no longer rely on the RPM Auction price signals to evaluate their future costs and 

predict future revenue streams. In the view of the plaintiffs, the RPM Auction clearing price 
45

($167.46) was essentially displaced and supplanted by the SOCA price written into the SOCA 

contracts ($286.03), causing less predictability in the energy capacity markets. 

Zamir Rauf, Plaintiff Calpine’s Chief Financial Officer, testified that the RPM Auction

price signals play a “huge role” in Calpine’s assessment as to whether an investment should be 

made because those prices are the basis for “projections as to where [Calpine] think[s] the 

market is going to be.” (T. 1112, 3-14); (Def.’s Ex. 289, at 1). He expressed Calpine’s reluctance

to proceed with expansion plans in light of the LCAPP’s enactment. In fact, according to Mr. 

Rauf, the LCAPP was a “very strong factor” in Calpine’s decision to construct only half of its 

Garrison project as opposed to completing the project as originally planned. (T. 1121, 15 through 

T. 1130, 15). Mr. Rauf noted that Calpine was initially attracted to invest in the PJM region 

because it was a competitive market “where you can put your capital at risk, and compete based 

on your efficiency[.]” (T. 1114, 15-18 through T. 1115, 6-21). While Calpine “would love to 

invest more money into PJM[,]” as a result of the LCAPP, the company is now “taking a step 

back and just holding up from putting too much money into PJM . . . pending this uncertainty.” 

(T. 1134, 8-12). Mr. Rauf summarized the conundrum for energy developers after the LCAPP’s

enactment:

[T]he PJM market was designed with certain rules, and everyone has to 

play by the same rules. . . . [H]ow do you know the state two months from 

now or six months from now, a year from now, two years from now 

suddenly decides we need to create jobs let’s build another power plant, or 

whatever political reason they may have for doing so. And all of a sudden 

they decide to build another plant, whereas you may have been in -- in the 

process of building one anyway or you may have started building one and 

now your capital’s at risk because the price signals that were in the 

marketplace are no longer there because of this new plant, so it really just 

disrupts the whole marketplace, it just in my mind creates enough chaos to 

where you’ve got to be very cautious about putting money in a market 

where you don't know what the rules are, especially when the rules are 

being manipulated by the politicians. (T. 1130, 20 through T. 1131, 14).
46

As Mr. Rauf plainly stated, in light of the LCAPP, Calpine would “put[] less money in PJM than 

[the company] otherwise would have, and [Calpine] would probably either be reinvesting that 

money in other regions, or buying back [its] stock.” (T. 1132, 6-12).

PSEG Power also had similar concerns regarding the impact of the LCAPP. According 

to Daniel Cregg, the LCAPP Act “dramatically change[d] how we look at what the market is.” 

(T. 888, 20 through T. 889, 8). He noted that PSEG Power “shifted entirely away from . . . 

looking at it as a merchant opportunity” and began rationalizing that the “opportunity [was] not 

going to be there for [them] this year”. (T. 879, 2-7). In the May 2012 RPM Auction, PSEG 

Power bid its Essex County project “at a fairly high level” in order to serve “as a backstop to the 

extent that the LCAPP units [did not] bid.” (T. 886, 22 through 888, 12). In other words, “absent 

the LCAPP Act . . . there might have been a price signal that would have been there” for the 

Essex County project, but instead, “the LCAPP units did bid in, and as a result [PSEG Power’s 

Essex] unit did not clear.” (T. 887, 4-8).

The LCAPP also had an impact on the operations of Exelon, as discussed by Mr. 

Dominguez during his testimony. Specifically, he testified that the RPM price signal “tells

[Exelon] whether to make investments in existing plants; whether to increase the capacity of 

existing plants; whether to do environmental retrofits; [and] whether to keep plants open.” (T. 

527, 2-10). Mr. Dominguez further testified that, given its impact on Exelon’s business 

strategies, the RPM is “fundamental to the way [Exelon] operate[s] [its] business.” (T. 527, 8-

10). In addition, Mr. Dominguez stated that the LCAPP Act has “fundamentally chang[ed] 

[Exelon’s] ability to predict revenue streams for existing megawatts.” (T. 564, 3-16). The 

LCAPP has also been a factor in Exelon’s decision to place its nuclear uprate program on hold. 

(T. 564, 16).
47

PPL has also had to modify its business strategies in light of the requirements imposed by 

the LCAPP. Michael Cudwadie, Vice President for PPL EnergyPlus, testified that PPL relies on 

capacity forward market prices and energy forward market prices to make decisions regarding

investments in new and existing generation, including whether to upgrade units, add pollution 

control equipment, or retire specific units. (T. 1041, 18-24).

The effects of the LCAPP described by these witnesses were echoed at trial by Plaintiffs’

experts Mr. Massey and Professor Willig. For example, Mr. Massey declared that “[t]he entire 

fabric of the contract in my judgment makes it a price for capacity. It so happens that the contract 

calls it a standard offer capacity price, I . . . can hypothesize about a lot of things, but I don’t 

know what can be clearer than that.” (T. 296, 19-23). Mr. Massey elaborated by stating that 

“[t]he price is measured in terms of the netting of revenues, is measured in terms of comparing 

the standard offer capacity price, with the price determined in the PJM capacity market. It’s all 

about capacity pricing.” (T. 298:2-10). Furthermore, the payments under the SOCA are

“inextricably linked to the sale of wholesale capacity.” (T. 298, 2-10).

Similarly, Professor Willig described the effect of the LCAPP as “wiping out the pricing 

mechanism of PJM . . . [and] taking it away and putting this alterative, the SOCA price, in the 

place of the market price.” (T. 638, 22 through T. 639, 1). Professor Willig opined that the

“architecture” of the RPM Auction was appropriately designed to address concerns in the energy 

capacity market (T. 763, 19-23) and that the RPM clearing price “is being displaced, . . . 

overridden, [or] supplanted, by the SOCA price through this mechanism which is written into the 

SOCA contract and governed by the LCAPP.” (T. 637, 15-18).
48

Professor Willig further stated that the LCAPP would actually undermine new generation 

projects because all future investors would insist on receiving similar government assistance. He 

explained:

Even though this is supposed to be an interstate market, the kinds of 

freedoms for the states, which they may have political incentives to act on, 

favoring their own development projects, will lead in a contagious way to 

other states taking measures that they think are only there in selfprotection but are really their own reaction to the beginnings of this 

movement if the Court allows it, so that it’s truly a contagion. We could 

very well be seeing a rash of programs of this kind, only furthering the 

rational insecurity of new investors who are not going to be part of these 

programs, fearing that the market will just be full of unfair competition for 

them, and thereby discourage their own investment activities. (T. 698, 11-

23).

Defendants’ Perspective

The defendants have a completely different view concerning the impact and effects of the 

LCAPP based on two factual disagreements with the plaintiffs. First, the defendants contend that 

the RPM and the SOCA are two separate and unrelated transactions. The fact that each provides 

a different price does not, according to the defendants, frustrate the purpose or goals of the RPM 

Auction because, in their view, the SOCA is a purely financial contract not subject to 

Commission oversight and authority. Second, the defendants argue that any jurisdictional 

conflicts between the Board and the Commission were resolved by the Commission’s 2013

MOPR revisions. Both of these arguments are addressed below.

According to the defendants, the RPM and the SOCA are unrelated. As Mr. Knight of 

CPV testified, the SOCA is “something separate and distinct.” (T. 1646, 6-13). In describing this 

distinction, Mr. Knight elaborated that the “SOCA is between CPV and the EDCs, and does not 

go through PJM or have to do with PJM.” (T. 1646, 6-13). He further pointed out that “[CPV] 

sell[s] physical capacity and energy to PJM,” and does “not sell any physical capacity to 
49

anybody else.” (T. 1644, 12-22). Mr. Knight distinguished the SOCA price from the RPM 

Auction clearing price by stating:

The SOCA -- I mean the general terms of the SOCA are relatively simple 

and straightforward, but the obligation is for us to build a power plant, and 

to bid into, connect into PJM, and sell all our energy and capacity into 

PJM. And then in return for that we receive a financial payment from the 

EDCs, that is based upon a formula we're all . . . familiar with. It's a fixed 

price for a floating price, the floating price being the index in the PJM 

capacity market. (T. 1644, 12-22). 

Defendants further contend that because the SOCA is a purely financial contract, it is not 

subject to Commission oversight. (T. 1911, 13-16). In fact, Defendants liken the SOCA to other

financial contracts such as swaps, collars, or contracts for differences. (T. 682,2 through T. 683,

7). While the latter term (contract for differences) was mentioned frequently throughout trial, it 

was not fully defined except as an instrument that is routinely used to manage commodity price 

risks. (T. 1347, 1-15). For example, Mr. Levitan explained that a contract for differences is a 

“financially settled mechanism that provides revenue assurance for the seller and risk 

management benefits for the buyer.” (T. 1282: 10-18). In the view of the defendants, because the 

SOCAs do not involve the sale of actual physical energy capacity, they fall outside the 

jurisdictional authority of the Commission. (T. 1282, 10-18). Mr. Knight agreed with this 

analysis and likened the SOCAs to insurance policies indemnifying against forced power 

outages. He testified:

Because the payment mechanism is contingent upon something, it 

doesn't mean that we're delivering capacity . . . . [A]n example 

would be we have forced outage insurance in which we get paid by 

someone under a derivative contract if we are forced out. That 

doesn't mean that that's forced outages . . . it's just a contingency 

within the contract by which you get paid, it's not [like] you're 

actually delivering some good. T. 1648, 20 through T. 1649, 3). 
50

So, under the defendants’ analysis, the SOCAs are ultimately just financial risk management 

tools through which no capacity or energy is bought or sold. (T. 1283, 17-24); (T. 1360, 9 

through T. 1369, 10); (T. 1644, 9 through T. 1645, 9).

With the adoption of the MOPR III revisions, the defendants argue that issues between 

the Board and the Commission concerning participation of new generators in the RPM Auction 

are resolved; and since there is no controversy between the Board and the Commission, there is 

no need for the Court to impose any remedy. The Court, however, rejects this argument for 

several reasons. Although the Board and the Commission may now have a more cooperative 

relationship, the Court is in the best position to determine whether the LCAPP and the related 

policies implemented by the Board violate the Supremacy Clause. In addition, despite the 

increased cooperation between the Board and the Commission, this remains a controversy 

between the plaintiffs (generators and distributors of electricity) and the Board.

Other Alternatives

Since the Board retained authority over the siting of generation facilities, a question arose

as to whether the Board had any alternative means to incentivize construction of new generation 

facilities besides enacting a statute like the LCAPP. The parties agree that the Board had a 

number of ways to support and encourage the development of generation projects. These include 

the utilization of tax exempt bonding authority, the granting of property tax relief, the ability to 

enter into favorable site lease agreements on public lands, the gifting of environmentally 

damaged properties for brownfield development, and the relaxing or acceleration of permit 

approvals. (T. 266, 25-26 through T. 267, 6); (T. 1313-14 through T. 1316, 2).
51

I. CREDIBILITY OF WITNESSES AND WEIGHING OF THE EVIDENCE

As opposed to the facts set forth above, to which the Court has given considerable 

weight, the trial record reveals an extensive number of other facts which were given little weight 

in this decision. Those facts, and the reasons they were given little weight, are discussed below. 

First, Defendants presented a plethora of facts about initiatives in Maryland and 

Connecticut which they believe present issues similar to those being considered in this case. The 

Maryland initiative is subject to a separate ongoing lawsuit. As Mr. Roach testified, it is based 

upon reimbursement of 400 megawatts of new demand response as opposed to a capacity 

requirement. (T. 2066, 20-24). Any analysis of the Maryland proposal would necessarily require 

this Court to review a set of facts as substantial as those presented herein. Based on the facts 

presented at trial, the Court is not able to discern whether Maryland’s proposal is sufficiently 

similar to the LCAPP. As such, the Court considers the value in comparing and contrasting the 

Maryland initiative and the LCAPP to be minimal for purposes of this opinion.

In regards to the Connecticut proposal, the defendants contend that a Connecticut peaking 

facility has a very similar financial structure as a New Jersey peaking facility under the LCAPP.

(T. 1377, 24 through T. 1379, 11). Evidently, PSEG Power or one of its subsidiaries previously

accounted for SOCA-like payments to a New Haven generator as financial contracts. According 

to the defendants, the payments in question were not listed as energy or capacity contracts 

required to be filed with the Commission. (Def.’s Ex. 630). The defendants argue that this

supports their proposition that SOCAs are purely financial instruments. The Court, however, did 

not have sufficient information to fully analyze the Connecticut payments and, therefore, gave 

the defendants argument little weight. In the Court’s view, the most compelling evidence 

regarding how the SOCAs should be defined under the law was adduced by the witnesses at trial. 
52

Therefore, in terms of credibility, the evidence regarding the Connecticut contracts was of little 

value.9

The Plaintiffs argue that certain written and oral statements allegedly made by Board 

staff and CPV executives are admissions against interest supporting the plaintiffs’ case. 

Examples of these alleged admissions include:

a. Comments to President Solomon made by Frank Perrotti, Assistant Director of the Board,

in which he stated that the LCAPP has the “potential to drive out other forms of investment or, at 

least, cause future developers to demand the same premiums before deploying capital.” (Pl.’s 

Exs. 70, 406). 

b. Comments made by President Solomon’s aide Kristi Miller in which she stated that the

LCAPP “could encourage future developers to demand identical premiums before deploying 

capital.” (Pl.’s Ex. 406, at 20).

c. Comments made by CPV Chief Executive Officer Douglas Egan in which he indicated

that in order to develop generation in New Jersey, a generator may need “out-of-market pricing” 

(Pl.’s Ex. 61) or “pricing that was higher than what was available at that point in time.” (Pl.’s Ex. 

409).

d. Comments made by the Board’s Fed. R. Civ. P. 30(b)(6) designated witness, Mr. 

Dembia, in which he indicated that the LCAPP is a “guaranteed payout.” (Pl.’s Ex. 406).

The Court gave little weight to these alleged admissions which occurred during the 

lobbying effort to enact the LCAPP. See Kentucky W. Va. Gas Co. v. Pennsylvania Pub. Util. 

Comm'n, 837 F.2d 600, 615 (3d Cir. 1988). The Court found that the witnesses at trial presented 

 9 On a motion in limine prior to trial, the Court ruled that the Connecticut initiative was not relevant because it 

involved a different state. During trial, the Court reopened that decision since the plaintiff’s presented evidence 

involving initiatives in other states. The Court determined fairness required an evaluation of the Connecticut 

evidence.
53

the facts and issues in a forthright manner. Since the statements were not subject to crossexamination, and could not be assessed for credibility, the Court believes the constitutionality of 

the New Jersey statute and program is best determined by reviewing the merits of the case rather 

than relying on isolated statements.

Plaintiffs also introduced a report prepared by the Brattle Group for purposes of showing 

the successes of the RPM. The Brattle Group is a consulting firm hired by PJM to evaluate the 

RPM. (Pl.’s Ex. 49). No one from the Brattle Group testified at trial. As a result, the Brattle 

Group’s report on the RPM Auction was not subject to cross-examination. As such, the Court 

gave the report little weight.

J. ANALYSIS

“Preemption is a doctrine of American constitutional law under which state and local 

governments are deprived of their power to act in a given area, whether or not the state or local 

law, rule or action is in direct conflict with federal law . . . . The analysis of a preemption dispute 

focuses upon statutory construction . . . in the context of a constitutional framework of 

sovereignty, commerce regulation, or other predicate for federal powers.”10 More specifically, 

preemption doctrine is rooted in the Supremacy Clause of the United States Constitution. Article 

VI declares that the laws of the United States "shall be the supreme Law of the Land; . . . any 

Thing in the Constitution or Laws of any State to the Contrary notwithstanding." U.S. Const. art. 

VI, cl. 2. In order to determine whether the LCAPP is preempted under federal law, the first 

factual issue to resolve is whether the Board-ordered SOCAs occupy the same field of regulation

as the Commission and intrude upon the Commission’s authority to set prices for wholesale 

energy sales.

 10 JAMES T. O’REILLY, FEDERAL PREEMPTION OF STATE AND LOCAL LAW: LEGISLATION, REGULATION AND 

LITIGATION 1 (2006).
54

According to the defendants, the Commission’s oversight authority is “limited to sales of 

the actual physical electricity (or capacity) to a buyer.” (Def.’s Post-Trial Br. at 11).

Furthermore, the defendants contend that “[c]ontracts that do not effect a physical sale of 

electricity . . . are not subject to [Commission] jurisdiction.” (Id.). In the defendants’ view, the 

SOCAs are purely financial contracts that do not involve physical sales of electricity.11 As such,

according to the defendants, the SOCAs are separate and unrelated to the RPM Auction process

and free from Commission oversight. Plaintiffs argue, in opposition, that the “State, through the 

LCAPP Act and Board-ordered SOCAs, has set a price to be received for the wholesale sale of 

capacity to PJM.” (Pl.’s Post-Trial Br. at 3). In the plaintiffs’ view, the LCAPP ultimately 

“award[s] an impermissible price supplement for an interstate wholesale sale of electricity” and 

replaces the RPM price with the Board-ordered SOCA price. (Id. at 1). In doing so, according to 

the plaintiffs, the Board essentially sets a price for wholesale energy sales and, therefore,

“regulat[es] in a field that is reserved exclusively” for the Commission. (Id.). 

The Court finds that the SOCAs occupy the same field of regulation as the Commission 

and intrude upon the Commission’s authority to set wholesale energy prices through its preferred

RPM Auction process. As previously discussed, many of the terms defined in the SOCAs make 

substantial use of RPM terminology. In addition, the SOCAs obligate eligible generators to: 

(1) “qualify under the RPM rules as a capacity resource in an amount no less that the 

Awarded Capacity Amount for the [RPM Auction]” (Pl.’s Ex. 203, at 9);

(2) “comply with all obligations of a capacity resource under the RPM Rules” (Id.); 

(3) “[s]ubmit supply offers . . . in accordance with the RPM Rules” (Id.); and 

 11 The Commission has previously held that “electricity price risk management transactions (futures, options, swaps, 

and the like)” that do not result in the actual delivery of electricity are “purely financial” and need not be reported to 

the Commission.” Morgan Stanley Capital Group, Inc., 69 F.E.R.C. ¶ 61,175, 61,696 (1995).
55

(4) “[s]ubmit supply offers . . . in accordance with PJM Market Rules[.]” (Id. at 9-10).

The LCAPP Act itself defines the SOCA as a “capacity price . . . to be received by eligible 

generators under a Board-approved SOCA.” (Pl.’s Ex. 127, at 10). Furthermore, payment of the 

SOCA price is made only if the LCAPP generators successfully sell and deliver wholesale 

capacity to PJM. Given the fact that the SOCAs require eligible generators’ to satisfy certain 

RPM rules and mandate that the generators undertake certain performance under those rules, the 

Court finds that the performance of the SOCAs is contingent upon clearing the RPM Auction. As 

such, the SOCAs are not separate from, and to the contrary, occupy the same field as the RPM 

Auction. 

"Under the Supremacy Clause, federal law may supersede state law in several different 

ways." Hillsborough County v. Automated Med. Labs., Inc., 471 U.S. 707, 713 (1985). 

Specifically, the Supreme Court has recognized three types of preemption: express preemption, 

implied conflict preemption, and field preemption. Id. In this case, Plaintiffs argue that the 

Federal Power Act supersedes the LCAPP under both the field and conflict preemption theories.

Courts must begin their analysis of preemption questions by applying a presumption 

against preemption. Cipollone v. Liggett Group, Inc., 505 U.S. 504, 516 (1992). “In areas of 

traditional state regulation, we assume that a federal statute has not supplanted state law unless

Congress has made such an intention ‘clear and manifest.’” Bates v. Dow AgroSciences 544 U.S. 

341, 449 (2005) (citing New York State Conference of Blue Cross & Blue Shield Plans v. 

Travelers Ins. Co., 514 U.S. 645, 655 (1995). “That assumption applies with particular force 

when Congress has legislated in a field traditionally occupied by the States.” Altria Grp., Inc. v. 

Good, 555 U.S. 70, 77 (2008). Thus, when the “text of a pre-emption clause is susceptible of 

more than one plausible reading, courts ordinarily ‘accept the reading that disfavors pre-
56

emption.’” Id. (citing Bates, 544 U.S. at 449). See also Cipollone, 505 U.S. at 518. Nonetheless, 

in the face of clear evidence, the presumption against preemption can be overcome. See Crosby 

v. Nat’l Foreign Trade Council, 530 U.S. 363, 374 n.8 (citing Hines v. Davidowitz, 312 U.S. 52, 

67 (1941). (“Assuming, arguendo, that some presumption against preemption is appropriate, we 

conclude . . . that the state Act presents a sufficient obstacle to the full accomplishment of 

Congress’s objectives under the federal Act to find it preempted.”). While applying the 

presumption against the preemption, the Court reviews whether the Federal Power Act preempts 

the LCAPP under either the field preemption or conflict preemption theories.

Field Preemption

Field preemption arises by implication when state law occupies a "field reserved for 

federal regulation." United States v. Locke, 529 U.S. 89, 111 (2000). The Supreme Court has 

explained that “[f]ield preemption reflects a congressional decision to foreclose any state 

regulation in the area, even if it is parallel to federal standards.” Arizona v. United States, 132 S. 

Ct. 2492, 2502 (2012). This occurs when “Congress has left no room for state regulation of these 

matters.” Locke, 529 U.S. at 111 (citing Fidelity Fed. Savings & Loan Ass’n v. De La Cuesta, 

458 U.S. 141 (1982). The Supreme Court has explained that a congressional intent to occupy a 

field can be inferred when “[t]he scheme of federal regulation may be so pervasive as to make 

reasonable the inference that Congress left no room for the States to supplement it.” Rice v. 

Santa Fe Elevator Corp., 331 U.S. 218, 230 (1947). It may also be inferred where “an Act of 

Congress ‘touches a field in which [the] federal interest is so dominant that the federal system 

will be assumed to preclude enforcement of state laws on the same subject.’” English v. General 

Elec. Co., 496 U.S. 72, 79 (quoting Rice, 331 U.S. at 230). Nonetheless, because field 

preemption typically arises in areas traditionally regulated by states under their police powers, 
57

“congressional intent to supersede state laws must be ‘clear and manifest.’” English, 496 U.S. at 

79 (quoting Jones v. Rath Packing Co., 430 U.S. 519, 525 (1977). Generally, “[t]he factors used 

to determine if the field has been fully occupied by federal power include the dominant federal 

interest, the expression of congressional purpose, and the pervasiveness of the federal regulatory 

system.” O’Reilly, supra note 10, at 70.

Since the Supreme Court’s 1927 decision in Public Utils. Comm’n v. Attleboro Steam & 

Elec. Co., 273 U.S. 83 (1927), there has been a dominant federal interest over wholesale sales of 

electricity in interstate commerce. In that case, the Supreme Court invalidated an attempt by 

Rhode Island to regulate the rates charged by a Rhode Island plant selling electricity to a 

Massachusetts company, which resold the electricity to the City of Attleboro, Massachusetts. 

The Court found that the State’s attempt to regulate rates “place[d] a direct burden upon 

interstate commerce” and, as a result, the “State [was] restrained by the force of the Commerce 

Clause.” Id. at 89. Ever since the Court’s ruling, the federal government has asserted jurisdiction 

over wholesale sales of electricity in interstate commerce. As noted in Section E of this 

memorandum, in the absence of any federal regulatory body, interstate wholesale electricity 

pricing was left entirely unregulated after the Attleboro decision. In order to fill that regulatory 

gap, Congress enacted the Federal Power Act which provided that the Commission shall have 

jurisdiction over “the transmission of electric energy in interstate commerce” and “the sale of 

electric energy at wholesale in interstate commerce.” 16 U.S.C. § 824(b)(1). See New York v. 

FERC, 535 U.S. 1, 20-21 ( 2002) (“It is clear that the enactment of the FPA in 1935 closed the 

‘Attleboro gap’ by authorizing federal regulation of interstate, wholesale sales of electricity – the 

precise subject matter beyond the jurisdiction of the States in Attleboro. . . . It is, however, 

perfectly clear that the original FPA did a good deal more than close the gap in state power 
58

identified in Attleboro. The FPA authorized federal regulation not only of wholesale sales that 

had been beyond the reach of state power, but also the regulation of wholesale sales that had 

been previously subject to state regulation.”).

Plaintiffs contend that in enacting the Federal Power Act, Congress “chose to occupy the 

field of wholesale electricity sales, including the price at which electricity is sold at wholesale, 

and the terms and conditions under which such electricity is sold.” (Pl.’s Post-Trial Br. at 12).

Such a contention is supported by previous decisions in which courts have held that the 

Commission has the exclusive authority to regulate wholesale electricity sales and the 

transmission of energy in interstate commerce. As stated by Justice Scalia, “It is common ground 

that if FERC has jurisdiction over a subject, the States cannot have jurisdiction over the same 

subject.” Miss. Power & Light Co. v. Miss. Ex rel. Moore, 487 U.S. 354, 377 (1988) (Scalia, J., 

concurring in the judgment). The Supreme Court has held that the Federal Power Act “left no 

power in the states to regulate licensees’ sales for resale in interstate commerce.” FPC v. S. Cal. 

Edison Co., 376 U.S. 205, 215 (1964). Moreover, the Court has repeatedly held that the federal 

statute “delegated to . . . the Federal Energy Regulatory Commission, exclusive authority to 

regulate the transmission and sale at wholesale of electric energy in interstate commerce, without 

regard to the source of production.” New England Power Co. v. New Hampshire, 455 U.S. 331, 

340 (1982) (citing United States v. Pub. Utils. Comm’n of Ca., 345 U.S. 295, 311 (1953). See 

also Nantahala Power & Light Co. v. Thornburg, 476 U.S. 953, 956 (1986) (stating that the 

Commission “has exclusive jurisdiction over interstate wholesale power rates.”). The Third 

Circuit has similarly found that the “wholesale market for electrical energy is regulated by [the 

Commission]” and “[o]ne of [the Commission’s] duties is to set ‘just and reasonable’ wholesale 

electric rates.” Utilimax.com v. PPL Energy Plus LLC, 338 F.3d 303, 305 (3d Cir. 2004). The 
59

Commission’s decision to exercise its exclusive authority to regulate wholesale electricity sales 

through the RPM Auction process indicates both a dominant federal interest in the RPM and a 

pervasive federal regulatory structure to ensure its proper implementation. 

To support their proposition that the SOCAs are not “[c]ontracts . . . effect[ing] a physical 

sale of electricity” and, therefore, “not subject to [Commission] jurisdiction[,]” the defendants 

rely on the case of New York Mercantile Exch., 74 F.E.R.C. ¶ 61, 311, 1996 F.E.R.C. LEXIS 

454 (1996) (“NYMEX”); (Def.’s Post-Trial Br. at 12). In NYMEX, the Commission held that the 

Federal Power Act and its reporting requirements did not apply to an electricity futures contract 

that was approved for trading by the Commodity Futures Trading Commission (“CFTC”) except 

if the “contract goes to delivery, the electric energy sold under the contract will be resold in 

interstate commerce, and the seller is a public utility.” NYMEX, 74 F.E.R.C. at 61,984. Without 

reviewing all of the facts of NYMEX, the Court finds the case distinguishable for several reasons. 

First, no evidence was presented to indicate that the SOCAs have been approved for trading by a 

separate federal regulator. Second, there is a caveat in NYMEX that if a contract “goes to 

delivery” it may give rise to Commission jurisdiction. Here, the SOCA agreements are 

contingent upon the LCAPP generators’ successful sale of capacity to PJM. Such capacity sales 

may constitute delivery within the meaning of NYMEX and, therefore, give rise to Commission 

jurisdiction.

The most credible testimony presented at trial confirming that the SOCA contracts are 

not purely financial contracts, and that they, therefore, intrude upon the exclusive jurisdiction of 

the Commission, was that of Professor Willig. He explained that, in economics, a purely 

financial arrangement is one that does not “involve any real performance.” (T. 681, 5-6). He 

elaborated that “[a] financial deal does not involve any performance of a real side activity as part 
60

of the deal. So that’s really the dividing line, and I think it’s quite clear, it goes back to what we 

mean by price in economics, payment for performance.” (T. 681, 21-24). Here, the SOCAs 

expressly condition payment on physical performance. As Professor Willig explained, under the 

SOCAs, the LCAPP generator has “got to build a plant, it’s got to provide capacity, the capacity 

has to be available, had to be bid into RPM and into the auction, it has to clear the auction; there 

are all these elements of performance to which the SOCA payments are conditioned. So it’s 

payment for performance.” (T. 684, 10-15). Here, the LCAPP supplants the federal statute, and 

intrudes upon the exclusive jurisdiction of the Commission, by establishing the price that LCAPP 

generators will receive for their sales of capacity. The Court finds that in doing so, the LCAPP 

“places a direct burden upon interstate commerce” within the meaning of the Attleboro decision.

Accordingly, the LCAPP Act invades the field occupied by Congress and is preempted by the 

Federal Power Act.

Defendants argue against preemption by stating that “Congress expressly reserved to the 

States exclusive jurisdiction to regulate generation.” (Def.’s Post-Trial Br. at 23). According to 

the defendants, “State regulation of generation will not be pre-empted if the regulation’s impacts 

on wholesale rates are merely ‘incident of efforts to achieve a proper state purpose.’” (Id. 

(quoting Nw. Central Pipeline Corp. v. State Corp. Comm’n of Kansas, 489 U.S. 493, 515-16 

(1989). Although the State of New Jersey and the Board retained the responsibility for the siting 

and construction of power plants, they are required to exercise this responsibility without 

interfering with the Commission’s exclusive authority to regulate wholesale sales of electricity in 

interstate commerce. As discussed in Section H of this memorandum, there were other 

alternative measures which New Jersey could have employed to incentivize the development of 

new generation. While New Jersey retained the authority to take a wide range of actions to 
61

ensure reliable electric service for its citizens and encourage the construction of new electric 

generation facilities, it chose to advance those goals through a mechanism that intrudes upon the 

authority of the Commission and violates federal law.

The defendants also contend that preemption analysis “does not justify a ‘freewheeling 

judicial inquiry into whether a state statute is in tension with federal objectives.” (Def.’s PostTrial Br. at 23) (quoting Chamber of Commerce of U.S. v. Whiting, 131 S. Ct. 1968, 1985 (2011).

Here, however, the Commission’s exclusive authority over wholesale energy sales has existed 

since Attleboro and been confirmed by the Supreme Court and many lower courts decisions. An 

application of these prior decisions acknowledging the exclusive authority of the Commission to

regulate wholesale electricity sales to the facts in this case certainly does not constitute 

“freewheeling.”

Conflict Preemption

Conflict preemption occurs where there is a conflict between a state law and a federal 

law. See Crosby, 530 U.S. at 372 (“[E]ven if Congress has not occupied the field, state law is 

naturally preempted to the extent of any conflict with a federal statute.”). Such a conflict occurs 

when “the challenged state law stands as an obstacle to the accomplishment and execution of the 

full purposes and objectives of Congress.” 132 S. Ct. at 2501. When confronting arguments that 

a law stands as an obstacle to Congressional objectives, a court must use its judgment: "What is a 

sufficient obstacle is a matter of judgment, to be informed by examining the federal statute as a 

whole and identifying its purpose and intended effects." Crosby, 530 U.S. at 373. The court must 

look to "'the entire scheme of the statute'" and determine "'[i]f the purpose of the [federal] act 

cannot otherwise be accomplished--if its operation with its chosen field [would] be frustrated and 
62

its provisions be refused their natural effect.'" Id. (quoting Savage v. Jones, 225 U.S. 501, 533 

(1912)). 

Where a state law conflicts with a federal law, the Court does not balance the competing 

federal and state interests. In fact, the Supreme Court has held that “[u]nder the Supremacy 

Clause of the Federal Constitution, ‘[t]he relative importance to the State of its own law is not 

material when there is a conflict with a valid federal law,’ for ‘any state law, however clearly 

within a State’s acknowledged power, which interferes with or is contrary to federal law, must 

yield.’” Felder v. Casey, 487 U.S. 131, 138 (1988) (quoting Free v. Bland, 369 U.S. 663, 666 

(1962)); see also Gade v.Nat’l Solid Wastes Mgmt. Ass’n, 505 U.S. 88, 108 (1992) (“[E]ven state 

regulation designed to protect vital state interests must give way to paramount federal 

legislation.” (quoting De Canas v. Bica, 424 U.S. 351, 357 (1976)).

From reviewing the entire scheme of the RPM process, it is clear that the LCAPP Act 

poses as an obstacle to the Commission’s implementation of the RPM. The testimonies of 

Messrs. Dominguez, Rauf and Cudwadie indicated that their companies rely on the competitive 

price signals of the RPM Auction to determine future company business plans. Each testified that

the SOCA prices undermine their respective company’s ability to use those RPM price signals to 

make sound business decisions. Each also contended that the future expansion of their respective 

companies would be contingent on whether the SOCA price continues to supplant the RPM 

Auction price. The effects described by the witnesses demonstrate that the SOCA’s imposition of 

a government imposed price creates an obstacle to the Commission’s preferred method for the 

wholesale sale of electricity in interstate commerce.
63

Commerce Clause

The Plaintiffs argue that the LCAPP Act also must be invalidated under the Commerce 

Clause. This argument concerns the procurement of the capacity wherein Plaintiffs argue that 

Board discriminated against out-of-state generators in its solicitation of bids to become eligible 

generators under the LCAPP. The “dormant” aspect of the Commerce Clause prohibits states 

from using their regulatory power to discriminate in favor of in-state producers at the expense of 

those out-of-state. C&A Carbone, Inc. v. Town of Clarkstown, 511 U.S. 383, 389-90 (1994); W.

Lynn Creamery, Inc. v. Healy, 512 U.S. 186, 192 (1994); Wyoming v. Oklahoma, 502 U.S.

437, 454-55 (1992). The Supreme Court has defined forbidden discrimination as “differential 

treatment of in-state and out-of-state economic interests that benefits the former and burdens the 

latter.” United Haulers Ass ‘n v. Oneida-Herkimer Solid Waste Mgmt. Auth., 550 U.S. 330, 338 

(2007) (quotation marks omitted): W. Lynn Creamery, 512 U.S. at 192.

When a law discriminates against out-of-state producers on its face, the State bears the 

burden of demonstrating, “under rigorous scrutiny, that it has no other means to advance a 

legitimate local interest.” C&A Carbone, 511 U.S. at 392. “Statutes that discriminate by 

‘practical effect and design,’ rather than explicitly on the face of the regulation, are similarly 

subjected to heightened scrutiny.” Tri-M Group, LLC v. Sharp, 638 F.3d 406, 427 n.28 (3d Cir. 

2011).

The plaintiffs argue that the “community benefit” points awarded to generators in New 

Jersey effectively prohibited out-of-state generators from competing to be eligible generators

under the LCAPP Act. According to the plaintiff’s, the LCAPP Act – through its express 

consideration of economic and community benefits – favored in-state enterprises over out-ofstate enterprises.” (Pl.’s Post-Trial Br. at 48). To demonstrate this, the plaintiffs rely on the 
64

following evidence: (1) President Solomon’s letter to Governor Christie that mentions a 

preference for in-state generators (Pl.’s Ex. 84); (2) the initial draft of the LCAPP legislation that 

promoted construction of qualified in-state electric generators (even though such language was 

deleted prior to enactment) (Pl.’s Ex. 94); (3) language in the LCAPP which required the Board 

to consider the “economic[] and community benefits” of a project (Pl.’s Ex. 127); and (4) 

language in the 2011 New Jersey Energy Master Plan which discussed fostering the 

commercialization of new generation plants in New Jersey. (Pl.’s Ex. 270).

Despite the abovementioned evidence, the plaintiffs fail to overcome the most persuasive 

evidence that substantiates the reasons the State is seeking in-state development. A significant 

portion of the trial focused on locational deliverability areas (LDAs). (Stipulated Fact ¶ 30). As 

previously noted, New Jersey is located in such an area that is known as EMAAC. In addition,

there are two other locational deliverability areas within New Jersey known as PSEG and PS 

North (T. 1529, 3-13). Generally, these LDAs have higher capacity prices than other PJM areas

due to transmission costs. Even the Plaintiffs agree that a capacity price cannot be set for an 

entire region. (Pl.’s Ex. 26, at 34). As a result, there is separation in price which is authorized by 

PJM and the Commission. The record as a whole supports the proposition that the closer the 

generation facility is to the delivery area, transmission costs will subside. As Mr. Herling 

concluded when discussing the reliability crisis, reliability issues could only be resolved in one 

of two ways – transmission via the Susquehanna Connection or additional generation in or near 

the location where the reliability issue will occur. (Def.’s Ex. 563, at 33) (emphasis added). As 

such, it appears reasonable that the Board would incentivize construction in areas where 

reliability concerns are in flux. As such, the Board has the authority to incentivize construction 

within New Jersey. What is good for the goose is good for the gander. As such, the incentive for 
65

community benefits to generators in New Jersey appears reasonable. Since Plaintiffs have not 

briefed or argued the commerce clause in such a fashion, the Court finds that Plaintiff has not 

met its burden of proof. 

K. CONCLUSION

Based on the foregoing facts and law, the Court declares that the Long Term Capacity 

Agreement Pilot Program Act (LCAPP) is preempted by the Federal Power Act and in violation 

of the Supremacy Clause of the United States Constitution; and is therefore null and void.

s/Peter G. Sheridan 

PETER G. SHERIDAN, U.S.D.J. 

October 11, 2013
66

GLOSSARY OF ACRONYMS

BGS Basic Generation Service

BPU OR NJBPU The Board of Public Utilities of the State of 

New Jersey; also referred to as

“the Board”

BRA Base Residual Auction

CC Combined cycle

COD Commercial Operation Date

CONE Cost of New Entry

CT Combustion Turbine

DAM Day Ahead Market

DG Distributed Generation

DR Demand Response

EDC Electric Distribution Company

EDECA Electric Discount and Energy Competition Act

EE Energy Efficiency

EMAAC Easter Mid-Atlantic Area Council

EMP Energy Master Plan

FERC Federal Energy Regulatory Commission

FPA Federal Power Act

FRR Fixed Resource Requirement

GT Gas turbine

GW Gigawatt

GWh Gigawatt hour

HEDD High Energy Demand Day

ICAP Installed Capacity

ISO Independent System Operator

KW Kilowatt

KWh Kilowatt hour

LCAPP Long Term Capacity Agreement Pilot Program

LDA Locational Deliverability Area

LMP Locational Marginal Price

LSE Load Serving Entity

MAAC Mid-Atlantic Area Council

MAAP Mid-Atlantic Power Pathway

MOPR Minimum Offer Price Rule

MW Megawatt

MWh Megawatt Hour

NEPA New Entry Price Adjustment

NERC North American Electric Reliability 

Corporation

NRC Nuclear Regulatory Commission

P3 PJM Power Providers Group
67

PATH Potomac-Appalachian Transmission Highline

PJM PJM Interconnection, LLC

PPA Power Purchase Agreement

RCP Resource Clearing Price

RMR Reliability Must Run

RPM Reliability Pricing Model

RPS Renewable Portfolio Standard

RTEP Regional Transmission Expansion Plan

RTM Real Time Market

RTO Regional Transmission Organization

SIS System Impact Study

SOCA Standard Offer Capacity Agreement

TO Transmission Owner

TRAIL Trans-Allegheny Interstate Line

TRC Total Resource Cost

UCAP Unforced Capacity

VRR Variable Resource Requirement