Full opinion text
MEMORANDUM SHERIDAN, District Judge. 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 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. A. PARTIES TO THE ACTION 1. Defendants New Jersey Board of Public Utilities. The defendants are Robert M. Hanna, Jeanne M. Fox, Joseph L. Fiordaliso, and Nicholas Asselta, all of whom are current or former commissioners of the New Jersey Board of Public Utilities. 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, 985 A.2d 649 (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, in-eluding 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 market. 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 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 Pepeo Holdings, Inc., which provides electric service to approximately 547,000 customers in southern New Jersey. Pepeo Holdings, Inc. is one of the largest energy delivery companies in the Mid-Atlantic 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. 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. (Stipulated Facts ¶ 13). PJM is primarily subject to Commission regulation through a tariff. It operates a regional wholesale 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). 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 “direet[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 of the law firm Covington and Bur-ling 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. Zamir Rauf has been employed by Cal-pine 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 Le-high 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 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 use. (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, 47 S.Ct. 294, 71 L.Ed. 549 (1927); (Stipulated Facts ¶ 4). Surprisingly, no witness precisely described the logistics of an energy 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 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, mid-merit, 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 combined-cycle 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”) . (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 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, 47 S.Ct. 294, 71 L.Ed. 549 (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). 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). 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. 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 nondiscriminatory transmission access under 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 (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]tate-ordered 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 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. “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 (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 built, what types of power plants will provide that new capacity, and where the new plants wall 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: 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 long-term 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 lowest-cost 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] 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 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, 62,678 (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: 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 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. 18, 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 bid-dings 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 such, the capital costs are deemed to be zero. 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 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 unit-specific 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 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 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.