Full opinion text
MEMORANDUM OF DECISION MARVIN J. GARBIS, District Judge. The Court has heard the evidence, reviewed the exhibits, considered the materials submitted by the parties, and had the benefit of the arguments of counsel. The Court now issues this Memorandum of Decision as its findings of fact and conclusions of law in compliance with Rule 52(a) of the Federal Rules of Civil Procedure. The Court finds the facts stated herein based upon its evaluation of the evidence, including the credibility of witnesses, and the inferences that the Court has found reasonable to draw from the evidence. I. INTRODUCTION Prior to 1999, Maryland utilized a vertically integrated model of electric energy regulation. A single electric utility (such as BGE or Pepeo) owned the facilities that produced and delivered electricity to the users in its exclusive territory. Maryland electric power users purchased electricity from the one utility that served the territory in which they were located. The Maryland Public Service Commission (“PSC”) ultimately determined whether additional generation resources were needed in Maryland and provided for the financing of those resources through the approval of rate increases. In 1999, the Maryland General Assembly passed the Electric Customer Choice and Competition Act (the “1999 Act”), which restructured, or deregulated, Maryland’s electric energy market. The 1999 Act separated the Maryland “utilities’ generating assets from their distribution and transmission functions” by transferring ownership of those generation assets to other companies that owned and operated the power plants. P.391 (2007 PSC Interim Report) at 10. The PSC is empowered by the State of Maryland to assure “safe, adequate, reasonable, and proper [electric] service.” Md.Code Ann., Pub. Util. § 5-101(a). However, Maryland-based utilities, which now no longer own generating facilities, must purchase energy on federally regulated wholesale markets. Thus, the utilities and, correspondingly, Maryland ratepayers are directly affected by the wholesale prices determined on the federally regulated wholesale markets. In mid-2000, the PSC and others began to voice concerns over the operations of Maryland’s electricity markets, the post-restructuring consumer electricity rates, and the existence of adequate generation resources to serve the energy needs of Maryland ratepayers. In 2007, the PSC filed a report with the General Assembly, stating that the federally regulated wholesale markets had not responded to Maryland’s needs and opining that those markets were unlikely to respond in the immediate future to the state’s “looming capacity shortage.” P.391 (2007 PSC Interim Report) at 1. The PSC concluded that it should require the Maryland utilities to enter into long-term contracts to induce the construction of new electric generation facilities in Maryland. Ultimately, on April 12, 2012, the PSC issued the Generation Order at issue, directing Baltimore Gas and Electric Company (“BGE”), Potomac Electric Power Company (“Pepeo”), and Delmarva Power & Light Company (“Delmarva”) to enter into a Contract for Differences (“CfD”) with CPV Maryland, LLC (“CPV’). In essence, the CfD provided that regardless of the price set by the federally regulated wholesale market, the Maryland utilities would assure that CPV received a guaranteed price fixed by a contractual formula. The result was that CPV had a secure income stream available to finance construction of a generating facility in a designated area within Maryland. Plaintiffs present claims in three Counts: • Count I Violation of the Supremacy Clause, U.S. Constitution, art. VI, cl. 2; • Count II Violation of the Commerce Clause, U.S. Constitution, art. I, § 8, cl. 3; and • Count III Violation of 42 U.S.C. § 1983. As discussed at length herein, the Court holds that Plaintiffs have established their claim that the Generation Order violates the Supremacy Clause of the United States Constitution by virtue of field preemption but does not violate the dormant Commerce Clause. II. BACKGROUND A. Electric Power Grids In A Nutshell As once said in reference to the Rule in Shelley’s case, it is one thing to put the subject of electric power grids in a nutshell, but impossible to keep it there. Nevertheless, even an oversimplified, incomplete, and imprecise introduction may be useful to those totally unfamiliar with electric power grids. To start, think of a power grid as analogous to a network of pipes utilized to transport water from various pumping stations, which take water from natural sources (lake, river, etc.), to reservoirs. The water in the reservoirs is then, as demanded by a local utility, transported by pipes in the grid to the local utility for distribution to the utility’s customers. However, for a closer analogy, think of the same grid without any reservoirs. When an amount of water is placed into the grid by a pumping station, an equal amount must flow out of the grid to a local utility. Thus, the grid operator must insure that, at all times, the supply (water put into the grid by the pumping stations) equals the demand (water sent out of the grid to the local utilities). This balance is maintained by affecting the supply through adjustments of the price paid to pumping station suppliers, payments to local utilities (or customers) to reduce their usage, adjustments to the price paid by the local utilities for the water they demand, etc. B. Federal Regulation of Electric Energy 1. The Federal Power Act and FERC In 1927, the United States Supreme Court held that the dormant Commerce Clause prohibited states from regulating the rates for wholesale power sales between utilities in different states. The Court reasoned that, unlike the regulation of the rates charged to local consumers, regulation of interstate rates places “a direct burden upon interstate commerce, from which the state is restrained by the force of the commerce clause.” Pub. Utils. Comm’n of R.I. v. Attleboro Steam & Elec. Co., 278 U.S. 88, 89, 47 S.Ct. 294, 71 L.Ed. 549 (1927). In response to the Attleboro decision, Congress enacted the Federal Power Act (“FPA”) in 1935, which “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.” New York v. F.E.R.C., 535 U.S. 1, 20, 122 S.Ct. 1012, 152 L.Ed.2d 47 (2002). Specifically, the FPA gave the Federal Power Commission, the predecessor agency to FERC, jurisdiction over the regulation of interstate wholesale sales of electricity and of interstate transmissions of electric energy. See 16 U.S.C. § 824(a); New York, 535 U.S. at 20-21, 122 S.Ct. 1012. The FPA vested FERC with the responsibility for setting the “rates and charges” of wholesale electric energy and for ensuring that those rates are “just and reasonable.” Id. § 824d(a); Entergy La., Inc. v. La. Pub. Serv. Comm’n, 539 U.S. 39, 47-48, 123 S.Ct. 2050, 156 L.Ed.2d 34 (2003). In essence, FERC exercises this authority through an intricate regulatory framework whereby transactions for the wholesale sale of electricity are filed with FERC (on either an individual basis or, more often, under a market-based rate tariff). FERC determines on its own initiative, or in response to a request by some party, whether such rates are “just and reasonable” and not unduly preferential, discriminatory, or disadvantageous to any party. See 16 U.S.C. § 824e; id. § 824d. As to the physical facilities that generate electric energy, the FPA gave FERC jurisdiction “over all facilities for [the] transmission or sale of electric energy” in interstate commerce. Id. § 824(b)(1). But, “except as specifically provided in this sub-chapter and subchapter III of this chapter,” FERC has no jurisdiction “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.” Id. The witnesses generally agreed that FERC has no authority or power to order directly the siting, building, or construction of a generation facility generally or in any particular location within a state. Tr. Mar. 5(PM) at 82:4-21 (Nazarian); Tr. Mar. 6(AM) at 44:1-21, 46:12-47:7 (Massey); Tr. Mar. 7(AM) at 32:10-21 (Wodyka). As discussed infra, that authority is retained by the states under the FPA. The FPA created an exclusive area of federal jurisdiction in the electric energy realm regarding the regulation of interstate wholesale energy sales and transmission, including the entities that engage in such acts. The FPA also retained a sphere of state jurisdiction with respect to interstate retail sales, distribution of electric energy, and the construction of local generation facilities. See New York, 535 U.S. at 22-23, 122 S.Ct. 1012 (explaining “the legislative history [of the FPA] is replete with statements describing Congress’ intent to preserve state jurisdiction over local facilities”). As summarized by the U.S. Court of Appeals for the District of Columbia Circuit: Jurisdiction over this sale and delivery of electricity is split between the federal government and the states on the basis of the type of service being provided and the nature of the energy sale.... Thus transmission occurs pursuant to FERCapproved tariffs; local distribution occurs under rates set by a state’s public service commission. Niagara Mohawk Power Corp. v. F.E.R.C., 452 F.3d 822, 824 (D.C.Cir.2006). 2. Development of Wholesale Energy Markets a. Traditional Vertically Integrated Utilities “When Congress enacted the FPA, networks of high-voltage, long-distance transmission lines which today criss-cross the United States” simply “did not exist.” See Transmission Access Policy Study Grp. v. F.E.R.C., 225 F.3d 667, 691 (D.C.Cir.2000), aff'd sub nom. New York v. F.E.R.C., 535 U.S. 1, 122 S.Ct. 1012, 152 L.Ed.2d 47 (2002). The absence of this infrastructure likely was a factor in the development of the vertically integrated structure of electric utilities that generally predominated in the United States until the 1990’s. The term “vertically integrated electric utilities” refers to “generation, transmission, and distribution facilities [which are] owned by a single entity and sold as part of a bundled service (delivered electric energy) to wholesale and retail customers.” Promoting Wholesale Competition Through Open Access Non-discriminatory Transmission Services by Public Utilities, Recovery of Stranded Costs by Public Utilities and Transmitting Utilities; Proposed Rulemaking and Supplemental Notice of Proposed Rulemaking, 60 Fed.Reg. 17,662, 17,668 (Apr. 7, 1995) (hereinafter Open Access). Under the vertically integrated structure: Most electric utilities built their own power plants and transmission systems, entered into interconnection and coordination arrangements with neighboring utilities, and entered into long-term contracts to make wholesale requirements sales (bundled sales of generation and transmission) to municipal, cooperative, and other investor-owned utilities (IOUs) connected to each utility’s transmission system. Each system covered limited service areas. Id. A utility operating in the vertically integrated structure typically generates electricity with power plants it owns; transmits the electricity from those power plants to its service territory, usually defined by the state of location; and distributes that electricity to end-use customers within its service territory through local distribution networks, poles, and wires that the utility owns and maintains. See Tr. Mar. 4(AM) at 121:14-122:21 (Alessandrini); Tr. Mar. 4(PM) at 8:28-10:20 (Carretta); Tr. Mar. 6(AM) at 11:8-20 (Massey). Where utilities operated in a vertical integration structure, states often controlled the fiscal feasibility of a utility’s plans to expand its existing generation facilities or to construct new power plants through a regulatory framework. Thus, state regulators could decide whether to allow an increase in the retail rate charged by the utility to end-use customers sufficient to permit the utility to recover the cost of financing the construction of new generation facilities or the development of existing facilities. See Tr. Mar. 4(AM) at 121:14-122:25 (Alessandrini). If the state approved an adequate increase in retail rates, then the utility acquired a financial guarantee that assisted the utility in raising capital for its generation projects. See id. When most electric utilities were vertically integrated one-stop shops with monopolies over designated service territories, the electric energy industry operated predominately as a retail market subject to state regulation without significant intervention from the federal government. See Tr. Mar. 4(AM) at 121:14-122:26 (Alessandrini). In this scenario, the “wholesale market” regulated by FERC consisted primarily of transactions between vertically integrated utilities whose service territories were physically situated near each other. Tr. Mar. 6(AM) 13:3-16 (Massey), b. FERC’s Fostering of Wholesale Energy Markets In the 1970’s and 1980’s, significant “[technological improvements ... made feasible the transmission of electric power over long distances at high voltages.” See Transmission Access, 225 F.3d at 681 (D.C.Cir.2000). In response to, among other things, advancements in technology, the wholesale electricity market began to blossom producing, inter alia, independent and non-utility owned power plants capable of providing competitively priced generation to the wholesale market. See id. With a burgeoning wholesale market came more federal legislation and regulation. For instance, in 1978 Congress passed the Public Utility Regulatory Policies Act (“PURPA”), which called for “a program to improve the wholesale distribution of electric energy” and “the reliability of electric service.” 16 U.S.C. § 2601(2). However, the traditional vertically integrated utilities that owned transmission lines were inhibiting the development of this wholesale electricity market by “deny[ing] alternative producers access to their transmission lines on competitive terms and conditions.” Transmission Access, 225 F.3d at 682. Congress and FERC took action during the 1990’s to facilitate the development of wholesale power markets by. “opening up transmission services” and reducing the ability of vertically integrated public utilities to deny customers access to competitively priced electric generation. See Open Access, 60 Fed.Reg. at 17,663-64. “[I]n 1992, Congress enacted the Energy Policy Act, which amended sections 211 and 212 of the FPA to authorize FERC to order utilities to ‘wheel’ power — ie., transmit power for wholesale sellers of power over the utilities’ transmission lines — on a case-by-case basis.” Transmission Access, 225 F.3d at 682 (citing Energy Policy Act of 1992, Pub.L. No. 102-486, §§ 721-22, 106 Stat. 2776 (codified at 16 U.S.C. §§ 824j-k) (giving non-utility generators the right to have FERC order transmission-owning utilities to interconnect and obtain access to the local utilities’ delivery systems)). In 1996, FERC issued Order No. 888, which “ordered the national deregulation of electricity transmission services” and required all public utilities that owned or controlled transmission facilities to provide open access to their transmission lines on the same basis on which they provide access to themselves. See Sacramento Mun. Util. Dist. v. F.E.R.C., 616 F.3d 520, 523 (D.C.Cir.2010) (internal quotation marks omitted). In a further effort to facilitate the development of competitive wholesale power markets and to “increase the efficiency of the electric transmission systems,” FERC “strongly encouraged the [electric power] industry to organize itself into Regional Transmission ■ Organizations” (“RTOs”). See generally Delmarva Power & Light Co., 106 FERC ¶ 61,290, 62,080 (2004); Tr. Mar. 6(AM) at 48:7-11 (Massey). RTOs are voluntarily formed independent entities that have “consolidate[ed] control of all transmission services in a particular region” and that provide a platform for regional wholesale power markets. See Braintree Elec. Light Dep’t v. F.E.R.C., 550 F.3d 6, 8 (D.C.Cir.2008); Tr. Mar. 6(AM) 14:20-15:8, 48:3-11 (Massey); Tr. Mar. 6(PM) at 5:6-6:l (Wodyka). FERC explained that such consolidation of control in particular regions was needed because “traditional management of the transmission grid” by vertically integrated electric utilities was inadequate to support the efficient and reliable operation that is needed for the continued development of competitive electricity markets.” Regional Transmission Organizations, 65 Fed.Reg. 810, 811 (Jan. 6, 2000). According to FERC, despite Order No. 888, opportunities still existed “for transmission owners to unduly discriminate in the operation of their transmission systems so as to favor their own or their affiliates’ power marketing activities,” which could in turn impede competitive electricity markets. Id. at 817. In 2000, FERC issued Order No. 2000 requiring “utilities that own, operate, or control interstate transmission facilities either to file a proposal to participate in an RTO or to describe their efforts toward joining one.” Me. Pub. Utils. Comm’n v. F.E.R.C., 454 F.3d 278, 280 (D.C.Cir.2006); 18 C.F.R. § 35.34(a). FERC’s stated purpose entailed “promoting efficiency and reliability in the operation and planning of the electric transmission grid and ensuring non-discrimination in the provision of electric transmission services.” 18 C.F.R. § 35.34(a). FERC defined the required functions of any formed RTO as including, inter alia: (1) “employing] a transmission pricing system that will promote efficient use and expansion of transmission and generation facilities” and (2) “ensuring] the development and operation of market mechanisms to manage transmission congestion.” Id. § 35.34(k)(l)-(2). An RTO “manage[s] all the accounting for the energy that’s put in and taken out” of the transmission system it oversees, “operate[s] all the different pricing and biding mechanisms that fall under those wholesale market structures,” and operates and plans the regional transmission system within its area. Tr. Mar. 5(AM) at 126:20-127:18 (Nazarian). To constitute an RTO, an entity has to satisfy certain requirements and have its proposal approved by FERC. A FERCapproved RTO operates pursuant to tariffs filed with, and approved by, FERC. See Tr. Mar. 5(AM) at 126:22-127:6 (Nazarian). Presently, “[RTOs] exist in about two-thirds of the country” and are thus responsible for “about two-thirds of the load” or power consumption in the United States. Tr. Mar. 6(AM) at 19:21-20:16 (Massey). As relevant hereto, all of Maryland is part of an RTO formed in 2002, operated and administered by PJM Interconnected, LLC. C. PJM Interconnected, LLC (“PJM”) After issuance of Order No. 2000, PJM organized itself into an RTO, receiving full RTO status from FERC in December 2002. Although PJM operates as an RTO under the control of FERC, PJM is a private entity with 750 members or stakeholders, including “parties that own facilities, or buy or sell power in the PJM region.” Tr. Mar. 6(PM) at 11:16-12:3 (Wodyka); see also P.606 (PSC Order No. 81423) at 42. PJM’s members include “power generators, transmission owners, distributors, marketers, and large consumers.” P.606 (PSC Order No. 81423) at 42. States are not members or stakeholders of PJM. See id. The PJM area encompasses the District of Columbia and all or parts of 13 states (collectively the “PJM region”). The PJM region, i.e., PJM’s geographic footprint, consists of about 18 interconnected transmission zones. A transmission zone is the area or territory in which a particular utility, such as Baltimore Gas & Electric (“BGE”), owns transmission lines or resources. A transmission zone generally mirrors the utility’s historical service territory, discussed supra. See Pis.’ Dem. 16. The PJM region has an aggregate population of approximately 60 million people, covers 214,000 square miles, and includes 1,365 electric generators that are connected to PJM’s regional transmission system. P.516 (PJM — At a Glance) at 3; Pis.’ Dem. 16. As an RTO: PJM is responsible for the coordination and operation of the electric power system across the entire PJM footprint. They also then design and administer competitive markets to support the operations and activities within the, again, PJM RTO region. And finally they do ... resource adequacy planning to ensure that appropriate generation and transmission resources are available to serve the load requirements across the PJM region. And they do this in a way that they try to ensure the safety and reliability of all the activities that occur in the PJM footprint. Tr. Mar. 6(PM) at 10:25-11:10 (Wodyka). As a FERC-approved RTO, PJM carries out its responsibilities under FERC’s jurisdiction and pursuant to FERC-approved tariffs, including the Open Access Transmission Tariff (the “PJM Tariff’), which governs broadly how PJM operates the regional transmission system in the PJM region. P.516 (PJM — At a Glance) at 4. Additionally, PJM executes its duties through agreements with other parties that are filed with, and approved by, FERC, including the Transmission Owners Agreement (“TOA”), the Reliability Assurance Agreement (“RAA”), and the Operating Agreement. Tr. Mar. 6(PM) at 25:5-19 (Wodyka); P.516 (PJM — At a Glance) at 4. 1. PJM’s Operation of the Bulk-Power System and Transmission Planning One aspect of PJM’s duties as an RTO is the day-to-day operation and maintenance of the bulk electric power system “to ensure reliability of electricity delivery across the [PJM] region.” Tr. Mar. 4(AM) at 37:20-38:16 (Alessandrini). Thus, PJM operates and maintains a regional interconnected transmission system and power grid that spans the PJM footprint, enabling electric energy to be dispatched and delivered to various points across the PJM region. See PJM Interconnection, LLC, 132 FERC ¶ 61,173, 61,869-70 (2010); see also Tr. Mar. 5(AM) at 127:7-18 (Nazarian). PJM can be thought of as analogous to an “air traffic controlled ] of the power grid” because it “monitors and coordinates ... electric generators, ... high-voltage transmission lines, ... substations,” and the flow of electric energy therein on a day-to-day basis. P.516 (PJM — At a Glance) at 1. PJM is responsible for planning for the regional transmission system it oversees to ensure resource adequacy and future system reliability. To that end, PJM evaluates whether, and to what extent, new transmission resources or improvements to existing transmission resources “are necessary to meet the requirements of the load in the future.” Tr. Mar. 4(AM) at 38:12-16 (Alessandrini). For example, “PJM conducts a long-range Regional Transmission Expansion Planning (RTEP) process that identifies what changes and additional to the grid are needed to ensure reliability and the successful operation of the wholesale markets.” P.516 (PJM — At a Glance) at 2; see also Tr. Mar. 6(AM) at 20:21-24 (Massey). The RTEP includes long-term planning studies that look “into the future as far as 15 years ... to evaluate the performance of the transmission as well as the generation system that’s going to be able to reliably serve load in the long run.” Tr. Mar. 6(PM) at 22:10-21 (Wodyka). 2. PJM-Administered Wholesale Electricity Markets In addition to managing the physical flow of electric energy across the interstate transmission system within the PJM region and planning for improvements to ensure infrastructure reliability, PJM administers three wholesale markets in which electric energy products are sold by capacity resources to PJM and then resold by PJM to Load Serving Entities (“LSEs”) according to prices set in each of the respective markets. Only two of these markets, the energy market and the capacity market, are pertinent to the instant case. The third wholesale market, the ancillary services market, is not. Therefore, the term “PJM Markets” as used herein refers to the energy and capacity markets collectively and excludes the ancillary services market. The PJM Markets are run pursuant to PERC-approved tariffs and are the mechanisms that PJM uses to set or determine the price at which energy and capacity are to be bought and sold within its territory. Transactions on the PJM Markets are not the only permissible FERC-regulated wholesale transactions. Private parties can buy and sell wholesale energy, capacity, and ancillary services outside the PJM Markets and thus outside the prices set by PJM in such markets. See OPC’s Post-Trial Br. [Document 140] at 21. For instance, subject to FERC rules, a capacity resource, such as a generation facility, may sell energy and capacity directly to an LSE through a bilateral contract at a price determined by the parties, not set by PJM through its market-based mechanisms. See Tr. Mar. 5(AM) at 16:21-17:9 (Nazarian). Irrespective of the transactional means used by an LSE to procure energy for resale to end-use customers, the costs incurred by the LSE for wholesale purchases are passed on to end-use customers through the retail rate charged by the LSE. See Miss. Power & Light Co. v. Miss. ex rel. Moore, 487 U.S. 354, 372, 108 S.Ct. 2428, 101 L.Ed.2d 322 (1988) (“States may not bar regulated utilities from passing through to retail consumers FERCmandated wholesale rates.”). Thus, an increase in wholesale rates tends to result in a corresponding increase in retail rates, a. PJM Wholesale Energy Market The PJM wholesale energy market is a market in which wholesale electric energy generated by power plants is bought and sold to meet present load demand within the PJM region (the “PJM Energy Market”). In the PJM Energy Market, generation resources sell energy to PJM that is generated and delivered into PJM’s interconnected power grid by the generator. LSEs then purchase that energy from PJM to deliver and resell it to end-use customers, thereby satisfying load or customer demand for electricity at any point in time. Tr. Mar. 4(AM) at 23:16-24, 37:20-38:6 (Alessandrini). Because generators sell their energy to PJM, and LSEs purchase that energy from PJM and receive delivery through PJM’s interstate grids and transmission systems, there is no direct sale of energy from a generator to a particular LSE. Thus, the PJM Energy Market is composed of two separate sub-markets — day-ahead and real-time. In the day-ahead sub-market, generation facilities bid into an energy market for energy delivery in the next twenty-four hours; in the real-time sub-market, generation resources bid into a market for delivery in the next hour. See Tr. Mar. 6(AM) at 18:4-19:12 (Massey). With respect to setting the price of energy in the PJM Energy Market, PJM uses a system called “Locational Marginal Pricing [ (‘LMP’) ], which is the economic dispatch and price setting of energy.” Tr. Mar. 4(AM) at 24:22-24 (Alessandrini). The concept of LMP is that it “reflects the value of the energy at the specific location and time it is delivered” and “takes into account the effect of actual operating conditions on the transmission system in determining the price of electricity at different locations in the PJM territory.” P.516 (PJM — At a Glance) at 11. LMP may result in different prices for energy in different zones or locations within the PJM region. These “[e]nergy prices vary across the PJM footprint according to a number of factors that differentiate energy prices at different points within the system.” P.391 (2007 PSC Interim Report) at 17; see also Tr. Mar. 4(AM) at 114:11-25 (Alessandrini). LMP for energy is “volatile” because “it depends on the value of that energy, where it’s produced, at the time it’s produced, and what the weather and other conditions are.” Tr. Mar. 5(PM) at 65:21-66:6 (Nazarian). Concerning the prices received by power plants for energy sold into the PJM Energy Market, generation facilities across the PJM region have the ability to bid electric energy into the PJM Energy Market at a bid price. PJM, as the operator of the power grid, dispatches that energy to meet load demand by taking generation bids in ascending order of cost (ie., beginning with the lowest cost generation and ending with the highest cost generation) “until the electric load is satisfied.” P.391 (2007 PSC Interim Report) at 17. The highest cost generation (that is, the cost at the point at which the load demand is satisfied) “set[s] the clearing price for all [generators] operating in the zone,” and the resulting price is the LMP received by those generation resources. Id. One factor that influences LMPs significantly is the extent, or lack, of transmission capability into a state or region [because w]hen transmission lines are ‘congested’ or ‘constrained,’ ie., they cannot carry the lower cost electricity to meet demand, PJM must dispatch more expensive generation located in the constrained zone, which increases LMPs. Id. That is, if lower cost generation cannot be dispatched to serve load in a particular zone due to limitations in transporting the energy, PJM “skips” it and dispatches higher cost generation, which results in “congestion costs” and higher LMPs paid by the purchasing LSE and corresponding increases in the retail energy rates for the end-use customers served by the LSE. See id. at 17-18; see also Tr. Mar. 4(AM) at 116:6-118:1 (Alessandrini); Tr. Mar. 8(AM) at 93:20-94:19 (Willig). Thus, higher LMPs provide higher revenues to generation facilities. According to PJM, the LMP pricing model: give[s] price signals that encourage new generation sources to locate in areas where they will receive higher prices. It signals large new users to locate where they can buy lower-cost power. It also encourages the construction of new transmission facilities in areas where congestion is common, in order to reduce the financial impact of congestion on electricity prices. P.516 (PJM — At a Glance) at 11; see also Tr. Mar. 8(AM) at 94:16-19 (Willig) (“If the LMPs are different at ... two points, it means there’s ... differential value to resources located at those two points.”). The Maryland Public Service Commission (“PSC”) has opined that LMPs do not work as intended, in part because they “have not yielded adequate new generation inside Maryland’s transmission constraints.” P.391 (2007 PSC Interim Report) at 18-19. The PSC noted that as a “result[J Marylanders have paid and will continue to pay higher prices than others in the PJM region due to our higher LMPs, but no new material generation has been built in recent years.” Id. at 19. b. PJM Wholesale Capacity Market PJM administers a wholesale capacity market (the “PJM Capacity Market”), which is a forward market where a product called “capacity” is sold by a capacity resource to PJM and then resold by PJM to LSEs. Capacity resources include generators that will increase the energy supply and users that will reduce the energy demand. LSEs purchase capacity to meet their capacity obligations under certain FERC-filed agreements with PJM. As in the PJM Energy Market, capacity resources sell capacity to PJM; there is no direct sale of capacity from a capacity resource to a particular LSE. PJM sets the price for capacity bought and sold in the PJM Capacity Market through application of the Reliability Pricing Model (“RPM”). The RPM establishes an annual Base Residual Auction (“BRA”) through which PJM procures capacity from capacity resources “for a particular ‘power year’ ” three years after the auction. That is, capacity bid in the 2012 BRA will be made available for the 2015/2016 power year. The BRA determines the market clearing price, which is the price that PJM will pay for all capacity that clears the BRA. P.391 (2007 PSC Interim Report) at 19. Generally speaking, increases in capacity prices lead to increases in the retail rates paid by end-use customers. (i) “Capacity” “Capacity,” as used herein to refer to a product, is a standby commitment made by a capacity resource to either produce electric energy or to consume less electric energy at a time in the future when called upon by PJM to do so. See Conn. Dep’t of Pub. Util. Control v. F.E.R.C., 569 F.3d 477, 479 (D.C.Cir.2009). “In a capacity market, in contrast to a wholesale energy market, an electricity provider purchases from a generator an option to buy a quantity of energy, rather than purchasing the energy itself.” NRG Power Mktg., LLC v. Me. Pub. Utils. Comm’n, 558 U.S. 165, 168, 130 S.Ct. 693, 175 L.Ed.2d 642 (2010). Accordingly, the purchase of capacity is the purchase of a capacity resource’s availability either to supply energy into PJM’s interconnected transmission grid or to reduce the demand for electric energy on the transmission system at some defined future time. Tr. Mar. 8(AM) at 11:11-12:21 (Willig). A purchase of capacity is not a purchase of actual electric energy, but is instead a purchase of a resource capable of producing, or reducing demand for, electric energy in the transmission system when requested. Id. Capacity resources take various forms. The most typical form is generation capacity, which is a generation resource’s commitment to generate actual electric energy into the transmission system operated by PJM that can then be dispatched to serve load at some future point, if and when called upon to do so. See id. at 11:11-18. Any type of power plant (e.g., nuclear, natural gas, coal, wind farm, solar) is a generation resource. Capacity resources can also take the form of demand reduction or energy efficient programs. Unlike generation resources that take place on the energy supply side of the market, “demand response” programs occur on the energy demand side of the market and represent a commitment by an LSE to reduce the demand for energy on the transmission system when called upon to do so. The ability of an LSE to reduce demand generally involves an agreement by end-use customers to reduce demand during peak periods at the request of the LSE in return for compensation. Under the RPM, generation and demand reduction resources bid into the BRA as “capacity.” “Capacity is an important concept in the energy market due to the substantial deviations between maximum energy demand and minimum energy demand.” PPL Energyplus, LLC v. Solomon, No. 11-745, 2012 WL 4506528, at *1 (D.N.J. Sept. 28, 2012) (citing U.S. Dep’t of Energy, A Primer on Electric Utilities, Deregulation, and Restructuring of U.S. Electricity Markets, at A.4 (2002), http://wwwl.eere. energy.gov/femp/pdfs/primer.pdf). The purchase and sale of capacity ensures that at any given time there are adequate resources capable of supplying energy to serve forecasted load, as well as a reserve margin to meet exigent circumstances, such as an unexpectedly high demand or the failure of a generator. See Tr. Mar. 8(AM) at 11:4-12:7 (Willig). As explained by Professor Willig: If there is capacity in the market, and there is need for the energy, then that capacity is utilized, the physical cast is turned on. However, sometimes capacity is available, but it’s not actually used. If the capacity isn’t there, then it can’t be used, but if it’s there, then it could be used if it’s needed. Id. at 12:8-14. In addition to the general benefits of ensuring an adequate amount of capacity to satisfy load demand, a capacity market benefits capacity resources because capacity sales are a source of revenue. In particular, a generator that clears capacity in the BRA run by PJM in a year (for example, 2012) will have a fixed stream of revenue for one-year period three years in the future (for example, from 2015 to 2016). This fixed stream of revenue is significant because it can enable the generator to obtain current financing essential to its ability to deliver capacity in the future. (ii) Capacity Obligations Within the PJM Region Pursuant to the RAA with PJM, each LSE must satisfy certain “Capacity Obligations.” See P.76 (PJM RAA Agt.) at 34. The RAA’s stated purpose is “to ensure that adequate Capacity Resources ... will be planned and made available to provide reliable service to loads within the PJM Region.” Id. at 23. To effect this purpose, the RAA sets forth a comprehensive process pursuant to which PJM determines the total amount of generating capacity needed within the PJM region and, based on that calculation, creates capacity obligations for each LSE. See id. at 90-115. To determine the total amount of capacity needed in a future delivery year, PJM calculates the “amount of capacity needed to meet the forecasted load” and adds to it “reserves adequate to provide for the unavailability of Generation Capacity Resources, load forecasting uncertainty, and planned and maintenance outages.” See id. at 34. The reserve margin is computed as a percentage and applied to the load forecasts to determine the total amount of capacity required to serve reliably the forecasted load in the PJM region. Tr. Mar. 6(PM) at 33:7-34:17 (Wodyka). Once PJM determines the total amount of capacity needed, it divides responsibility for procuring that amount among the LSEs within the PJM region. Id. at 25:24-32:9. Capacity obligations can be satisfied by generation or demand resources, as discussed infra. An LSE can satisfy its capacity obligations by a combination of the following actions: 1. Designating its own generation or demand resources; 2. Entering into a bilateral contract with a capacity resource with the parties to the agreement determining the price for capacity; and/or 3. Being assigned capacity in the BRA, PJM’s annual capacity auction, which determines the price for capacity through application of the RPM. P.516 (PJM — At a Glance) at 9-10. In lieu of the above actions, an LSE may elect the Fixed Resource Requirement (“FRR”) under the PJM Tariff. Pursuant to the FRR, the LSE, in essence, removes its load or energy demand from PJM. To use the FRR option, the LSE must demonstrate that it can satisfy its share of the total capacity obligation through individual bilateral agreements with capacity resources or through the generation of electricity from its own facilities. Tr. Mar. 4(AM) at 82:2-20, 124:22-125:15 (Alessandrini); Tr. Mar. 6(PM) at 16:19-24 (Wodyka). (iii) PJM’s FERC-approved RPM In 2006, FERC adopted and approved PJM’s RPM for operating a wholesale capacity market and implementing a competitive capacity auction process. The RPM sets forth the terms and conditions governing the sale and delivery of capacity through the annual BRA including the manner by which capacity is offered into the auction, how the clearing price of capacity is determined, how capacity resources are paid for cleared capacity, and the penalties for failure to deliver capacity that clears the auction. Tr. Mar. 4(AM) at 32:12-13, 37:23-38:2 (Alessandrini); Tr. Mar. 4(PM) at 8:16-17 (Carretta); Tr. Mar. 4(PM) at 104:25-106:16 (Cudwadie). Ultimately, the RPM encompasses the method by which PJM sets the price of capacity that is offered into and clears the BRA. In each BRA, PJM seeks to procure a target capacity reserve level for the RTO in a least cost manner while also taking into account locational constraints. PJM is the buyer in the BRA, and the capacity resource is the seller. To sell successfully capacity to PJM in the BRA, a capacity resource must bid or offer an amount of capacity at a price, and the bid must be partially or fully selected in or clear the BRA. When a capacity bid clears the BRA, the seller becomes obligated to sell the cleared amount of capacity to PJM at the market clearing price. The market clearing price is determined in reference to all of the capacity bids (and the corresponding bid prices) submitted in the BRA. See Tr. Mar. 8(AM) at 16:22-17:5 (Willig). As discussed in more detail infra, the market clearing price is the bid price at which demand, as determined by PJM, is fully supplied. All resources that offer capacity in the BRA at or below the market clearing price generally will clear the BRA and, as a result, receive the market clearing price for the offered capacity. See id. at 16:9-17:5. (1) Bidding in the BRA To bid into the BRA, a capacity resource must submit an offer consisting of: (1) an amount of capacity the bidder is willing to sell for one year to be delivered beginning three years after the BRA and (2) a bid price for the amount of capacity offered. Id. at 29:9-11. Capacity is measured and offered in megawatt-days (“MW-day”), and the bid price is a dollar amount per MW-day (“$/MW-day”). See id. at 29:9-12. For instance, a power plant that bids 100 MW-days of capacity at $25 into the 2012 BRA, is offering its availability to deliver up to 100 MW of electric energy each day for one year beginning in 2015 (three years after the auction), at a minimum price of $25/MW-day. See generally Tr. Mar. 7(AM) at 138:19-139:9 (Knight). Hence, if the power plant’s bid clears the BRA in its entirety, the power plant will receive that year’s clearing price — which may be more than $25/MW-day — for 100 MW-days of capacity during the delivery year beginning in 2015. A capacity resource generally may select whatever price it wishes in $/MW-day when bidding capacity into the BRA, subject only to the Minimum Offer Price Rule (“MOPR”) and a bid ceiling or cap. For example, if a generator is considering an uprate to an existing generation resource that would increase the amount of energy it can output into PJM’s interconnected grid, thus increasing its capacity, the generator may price its bid into the BRA at an amount sufficient to recover the uprate costs not gained back through anticipated energy sale revenue. See id. at 129:21-131:5. If the generator clears the BRA at that price, it will go forward with the uprate, but if it does not clear, it will not. See id. at 129:9-130:7; see also Tr. Mar. 8(AM) at 15:15-17:5 (Willig) (describing a “well-functioning” capacity market as discouraging uneconomic development). However, bidding or bid prices are not necessarily connected directly to an immediate development decision. They may instead be chosen by virtue of the view that getting anything for capacity is better than nothing. That is, an existing capacity resource not subject to the MOPR can bid into the BRA at $0/MW-day. This is referred to as “price taking.” See Tr. Mar. 7(PM) at 68:3-19 (Knight). PJM has reported that in some BRAs, 80% of the participants bid zero. Id. at 68:19. A bid of $0/MW-day ensures that the offered capacity will clear the BRA and will yield a payment more than zero, unless every bidder bids zero. A price taker will accept whatever the market clearing price happens to be in that BRA. See Mar. 7(AM) at 140:23-41:23 (Knight). New capacity resources bidding into the BRA are subject to the MOPR, found in the PJM Tariff. The MOPR has been in place since establishment of the RPM in 2006, but its form has varied. See id. at 91:20-22. In essence, the MOPR subjects new generation resources to a minimum bid amount “to ensure that ... new plant generating resources ... bid[ ] their competitive cost-based fixed nominal net cost of new entry if it was to rely purely on PJM market revenues alone,” and thereby precludes new generators from acting as price takers. Id. at 92:1-4. (2) Determining the Market Clearing Price and Clearing Capacity in the BRA After all capacity offers are submitted into the BRA, PJM must determine: (1) which offers will successfully sell into, or clear, the BRA and (2) the single price that PJM will pay for the cleared capacity (the “market clearing price”). Broadly speaking, PJM makes these determinations by taking the capacity bids, in ascending price order, until a pre-determined capacity demand amount is fulfilled. The price of the bid that fulfills the demand amount sets the market clearing price for everyone. Every bid at, or below, the market clearing price clears the BRA, and every bid above the market clearing price does not. Explanation of the RPM framework and establishment of a market clearing price in any given BRA can be illustrated by the simplified hypothetical provided by Plaintiffs’ witnesses: 1. In a BRA, PJM receives a number of capacity bids at a variety of prices and amounts. The bids are submitted in a sealed fashion so that initially, only PJM knows what each capacity resource bid into the BRA. 2. Every capacity bid submitted is stacked in ascending order of price, lowest priced bid at the bottom and highest priced bid at the top. Once the bids are stacked in price order, one can tell the total MW-Days available at each bid price by adding up the MW-day amount of each bid preceding any particular price: 1. A graph can be created in which, in ascending order, the x-axis is MW and the y-axis is Price ($MW-Day). PJM uses the bids stacked in price order to create a “supply curve” and plots that supply curve on the graph. With just the supply curve plotted, one can see that at the price of $25/MW-day on the y-axis, the BRA generated bids totaling 3,000 MW, represented on the x-axis. Stated differently, there are 3,000 MW of capacity bid into the BRA willing to accept $25/MW-day or less for the capacity. 4. Next, PJM configures a Variable Resource Requirement curve (“VRR Curve” or “demand curve”), representing the total amount of capacity in MW that PJM has determined must be procured through the BRA to adequately supply forecasted load within the PJM region for the one-year period three years following the BRA. 5. The demand curve, generally a vertical line, is plotted on the graph at the appropriate amount of MW on the x-axis. The demand curve then intersects with the supply curve of stacked bids when the aggregate amount of capacity offered is equal to the demand in MW established by PJM. The point at which the supply curve intersects with the demand curve is the market clearing price and the market clearing amount of capacity. This is illustrated by the demonstrative submitted by Plaintiffs: 6. As illustrated above, if the demand is determined to be 8,000 MW, the market clearing price would be $150/ MW-day. This means that all capacity offered at or below that price clears the BRA. Every bidder whose capacity cleared the BRA will be paid the clearing price of $150/MW-day. As a result, even the generators that bid $0 for their capacity will receive $150/MW-day. Tr. Mar. 8(AM) at 28:24-38:24 (Willig). If a generation resource successfully clears capacity in the BRA, PJM rules require the generator to offer the electric energy generated in the PJM Energy Market. Since the market clearing price in any BRA is entirely dependent on the bid prices received by PJM from capacity resources (again, which for existing resources can be $0), the price is volatile and difficult — if not impossible-to predict with a reasonable degree of reliability. See Tr. Mar. 8(AM) at 76:19-22 (Willig); Tr. Mar. 11(AM) at 32:8-12 (Roach); Tr. Mar. ll(PM) at 101:20-102:1 (Kahal). The following reflects six years of BRA clearing prices: See D.34 (2015/2016 RPM BRA Results). (3) Locational Deliverability Areas (“LDAs”) and Price Separation in the BRA In theory, the BRA could establish one uniform market clearing price based on one model supply and demand curve for the entire PJM region. However, in practice the process is significantly more complicated. When procuring capacity through the BRA, PJM recognizes that not all locations are equally situated. Transmission constraints exist that make importing energy and capacity into certain areas within the PJM region more difficult than importing into other areas. A “transmission constraint” is a limitation on the ability of the transmission system or infrastructure effectively and reliably to transport electric energy from one point to another point within the PJM region. See Tr. Mar. 8(AM) at 94:6-95:8 (Willig). PJM employs several indicators and standards to alert whether and where transmission constraints exist and the consequences, affects, and severity of any such constraints. In the context of the PJM Capacity Market, to take locational transmission constraints into account, PJM models certain areas as Locational Deliverability Areas (“LDAs”) for purposes of the BRA. An area or zone is modeled as an LDA if “the amount of transmission import capability into [that] area” from the rest of the RTO (the Capacity Emergency Transport Limit (“CETL”)) falls below a target ratio with the level of capacity needed to import power to meet reliability requirements under the Capacity Emergency Transfer Objective (“CETO”). P.42 (2011 Boston Pacific Evaluation of Draft RFP) at 16. “The lower the ratio, the ‘tighter’ supply line into the area. If the CETL/CETO ratio is less than 1.15, then the area must be modeled as a separate zone in RPM.” Id. Being modeled as an LDA neither precludes generators outside the LDA from supplying electric energy into the LDA, nor necessarily affects the ability of generators outside the LDA to enter into bilateral agreements for energy and/or capacity with LSEs within an LDA. See Tr. Mar. 4(PM) at 115:16-117:6 (Cudwadie). Once an area or zone is modeled as an LDA, it functions as a separate capacity market with a separate supply and demand curve and a separate market clearing price from the balance of the PJM footprint. That is, there are “separate supply stacks and separate reliability needs ... considered by the PJM” in the BRA process for an LDA. See Tr. Mar. 8(AM) at 93:15-19 (Willig). Since LDAs function as a separate capacity market for purposes of the BRA, the market clearing price for an LDA may be different from the price for the rest of the RTO. When the market clearing price for an LDA is different from the balance of the PJM footprint the phenomenon is referred to as “price separation.” See Tr. Mar. 4(PM) at 113:23-114:1 (Cudwadie). Price separation occurs because each LDA has a separate target capacity reserve level and a maximum limit on the amount of capacity that it can import from resources located outside of the LDA. See id. at 114:1-115:15, 119:2-122:23. As a result of the import limitation, a lower-priced capacity resource located outside the LDA may be “skipped” or excluded from the stack of bids used by PJM to create the supply curve. This occurs because the LDA has reached its import limit so that even though the outside resource is the next bid in price order PJM will not select it to meet the capacity needs within the LDA. See Tr. Mar. 8(AM) at 94:2-22 (Willig). Where lower-cost capacity resources outside of the LDA are excluded due to the import limitation, PJM must then select more expensive capacity resources located within the LDA to fulfill the LDA’s capacity target level. See Tr. Mar. 4(PM) at 113:23-115:15, 119:8-122:15 (Cudwadie). When an LDA reaches its import limitation before the LDA’s capacity needs are met and PJM is forced to select more expensive capacity bids from within the LDA, the LDA’s market clearing price will separate from the rest of PJM because the last capacity bid selected — a more expensive resource within the LDA — sets the LDA price at a level higher than the RTO clearing price. See id. Within the PJM region, the Mid-Atlantic Area Council (“MAAC”) is modeled as an LDA. The Southwest Mid-Atlantic Area Council (“SWMAAC”) is a sub-LDA within MAAC. See Tr. Mar. 4(PM) at 27:6-10 (Carretta). SWMAAC includes part of Maryland and the District of Columbia; about 98% of SWMAAC is within Maryland. Tr. Mar. 6(AM) at 37:15-18 (Massey). SWMAAC includes the transmission systems of BGE and Pepeo. The portions of Maryland not in SWMAAC are in the Eastern Mid-Atlantic Area Council (“EM-AAC”), a sub-LDA that includes parts of Delaware, Pennsylvania, and New Jersey. Tr. Mar. 5, 2013(AM) at 106:15-18 (Nazarian). In the BRA conducted for the 2015/2016 delivery year, the market clearing price in all of MAAC (including EM-AAC and SWMAAC) was $167.46/MW-day, and the market clearing price in the rest of PJM was $136.00/MW-day. D.34 (2015/2016 RPM BRA Results). For the 2010/2011, 2011/2012, 2012/2013, and 2015/2016 delivery years, the market clearing price for SWMAAC did not separate from the rest of MAAC, even in years when MAAC separated from the balance of the PJM footprint. Id. (iv) Price Signals FERC has described the PJM Capacity Market as “provid[ing] long-term price signals to attract needed investment in the PJM region through a competitive auction process three years in advance.” PJM Interconnection, LLC, 132 FERC ¶ 61,173, 61,870 (2010). PJM identifies the RPM system as a means of providing “incentives that are designed to stimulate investment both in maintaining existing generation and in encouraging the development of new sources of capacity — not just generating plants, but demand response and energy efficiency programs as well.” P.516 (PJM — At a Glance) at 8. Plaintiffs submitted expert testimony to explain in an economic sense how the capacity prices set in the PJM Capacity Market through the RPM send price signals to market participants capable of inducing investment in generation development. Plaintiffs expert, Professor Willig, opined that higher capacity prices in an LDA encourage projects to be developed in that area because the RPM “reflects] the locational impact on need and on cost” of electric energy. Tr. Mar. 8(AM) at 95:9-24, 99:5-20 (Willig). According to Professor Willig, because the RPM is configured to create a positive correlation between transmission constraint and price, higher prices indicate greater difficulties in importing energy into an LDA, which signals to the market a need for capacity development and/or signals to PJM a need for transmission planning. Id. at 98:6-99:20. This is because constraint on the transmission system can be eased by additional capacity resources in the right location and/or new or expanded transmission lines to that location. Id. As Professor Willig concluded, a decrease in constraint, either by additional capacity or by a transmission-related solution, “will tend to bring pricing closer, because when prices are closer, it’s because there’s less constraints between their areas.” Id. at 99:5-9. The PSC has stated that the RPM “ha[s] failed to attract new generation in [Maryland] to mitigate these longer-term reliability concerns,” and that “RPM’s signal remains unable to anchor the financing new generation development requires.” P.2 (2011 RFP) at 3. D. Maryland’s Regulation of Electric Energy Maryland has, as have various other states, abandoned the vertical integration model of electric energy regulation. 1. Pre-Restructuring Vertical Integration Before the restructuring of 1999, Maryland’s electric utilities (such as BGE and Pepeo) were vertically integrated and predominately regulated by the Maryland PSC, except insofar as the utilities engaged in wholesale transactions, which were regulated by FERC. Tr. Mar. 5(AM) at 40:23-41:18 (Nazarian). Even then, however, Maryland’s utilities imported approximately 30% of the electric energy resold to end-use customers from generation resources outside the state in wholesale transactions. Id. at 50:6-51:24. Under the vertically integrated structure, the PSC generally retained authority to “regulate[] the distribution, transmission and generation rates” that Maryland utilities charged to rate payers. P.606 (PSC Order No. 81423) at 33. The rates charged by Maryland utilities to end-use customers were determined by the PSC through cost-of-service principles. That is, the PSC set rates that “w[ould] result in an operating income to the [utility] that yields, after reasonable deduction for ... expenses and reserves, a reasonable return on the fair value of the [utility]’s property used and useful in providing service to the public.” Id. at 33-34; P.391 (2007 PSC Interim Report) at 10. Because the Maryland utilities primarily sold electric energy generated by their own power plants to users in retail transactions, the PSC effectively determined— through its rate making authority — whether new or additional generation resources would be built in Maryland. Generation development by a Maryland utility would be financed through rate increases, which required approval by the PSC. See P.162 (2009 Nazarian Presentation) at slide 10. Additionally, in pre-restructured Maryland, ratepayers had no choice as to their electric utility supplier; they purchased electricity from whichever utility’s service territory in which they were located. See Tr. Mar. 5(AM) at 43:12-23, 44:21-24 (Nazarian). 2. 1999 Maryland Restructures In 1999, the Maryland General Assembly passed the Electric Customer Choice and Competition Act (the “1999 Act”), which restructured, or deregulated, Maryland’s electric energy market. See Md. Code Ann., Pub. Util. § 7-504, et seq. “The premise of the 1999 Act was that electric consumers would benefit more from a competitive market for their electricity rather than being captive to a single utility that had a monopoly on their electricity service.” P.606 (PSC Order No. 81423) at 36. The 1999 Act put this premise into effect by removing generating assets from the control and ownership of the Maryland utilities and requiring the utilities to provide Standard Offer Service, discussed in more detail infra, to their customers. Post-restructuring, the PSC remains an agency empowered by the State of Maryland to assure “safe, adequate, reasonable, and proper [electric] service.” Md.Code Ann., Pub. Util. § 5-101(a). In addition to regulating the procurement of electric energy by the Maryland Electric Distribution Companies (the “EDCs” or “Maryland EDCs”) for Maryland residents, the PSC administers a streamlined “process by which transmission and generating facilities are sited and ... approve[d]” for construction in Maryland. P.606 (PSC Order No. 81423) at 42. However, the PSC does not evaluate the need for new generation stations in Maryland. Rather, that need is determined by the marketplace. Tr. Mar. 5(AM) at 58:18-59:5 (Nazarian) (noting the “residual authority [of the PSC] to order new generation in anticipation of a long-term demand in the state”). a. Separation of Generation Assets The 1999 Act separated the Maryland “utilities’ [Maryland-located] generating assets from their distribution and transmission functions” by transferring ownership of those generation assets to other companies that owned and operated the power plants. P.391 (2007 PSC Interim Report) at 10; see also Md.Code Ann., Pub. Util. § 7-504(3); Tr. Mar. 5(AM) at 42:13-18 (Nazarian). This separation effectively forced Maryland utilities, now referred to as EDCs, to purchase electric energy at wholesale, thereby engaging in federally regulated energy transactions. Since the EDCs no longer owned generation assets or power plants, “electricity previously subject to traditional rate-of-return regulation (in which the PSC set the utility’s profit through a state regulatory proceeding) would now be purchased by local [EDCs] in the federally regulated wholesale electricity market” for purposes of re-selling that electricity to end-use customers. P.391 (2007 PSC Interim Report) at 10. Consequently, Maryland EDCs now rely on the wholesale energy market regulated by FERC to purchase the electric energy that they ultimately sell to end-use customers. See P.606 (PSC Order No. 81423) at 37. By virtue of having to purchase energy at wholesale, the Maryland EDCs (and correspondingly Maryland ratepayers) are financially affected by wholesale prices set by the PJM Markets. b. Standard Offer Service Maryland’s restructuring not only required local utilities to divest themselves of ownership of power-generating facilities, but also allowed Maryland electricity consumers to choose their electric energy supplier. Electricity customers