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.
Prior to 1999, Maryland utilized a vertically integrated model of electric energy regulation. A single electric utility (such as BGE or Pepco) 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
Plaintiffs
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
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.
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.
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., 273 U.S. 83, 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."
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.
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 subchapter and subchapter III of this chapter,"
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").
Niagara Mohawk Power Corp. v. F.E.R.C., 452 F.3d 822, 824 (D.C.Cir.2006).
"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:
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;
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"
In the 1970's and 1980's, significant "[t]echnological 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
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-i.e., 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 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 5:6-6:1 (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 constitute an RTO, an entity has to satisfy certain requirements and have its proposal approved by FERC. A FERC-approved 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
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").
As an RTO:
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.
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 controller[] 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."
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
The PJM Markets are run pursuant to FERC-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
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
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."
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
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:
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[,] 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.
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
"Capacity," as used herein to refer to a product,
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://www1.eere.energy.gov/femp/pdfs/primer.pdf).
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.
Pursuant to the RAA with PJM, each LSE must satisfy certain "Capacity Obligations."
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:
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).
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.
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.
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.
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.
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.
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.
Total MW-Days
Available at
Generator MW-Day Bid Price Bid Each Price
L 500 $0 500
G 700 $0 1,200
J 800 $0 2,000
F 500 $10 2,500
M 500 $25 3,000
Etc.
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. 11(PM) at 101:20-102:1 (Kahal). The following reflects six years of BRA clearing prices:
Market Clearing Price
PJM SWMAAC Southwest MAAC
(charted as Mid-Atlantic Area Mid-Atlantic Area
Delivery Year "RTO") Council Council
2007/2008 $ 40.80 $188.54 $ 40.80
2008/2009 $111.92 $210.11 $111.92
2009/2010 $102.04 $237.33 $191.32
2010/2011 $174.29 $174.29 $174.29
2011/2012 $110.00 $110.00 $110.00
2012/2013 $ 16.46 $133.37 $133.37
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.
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
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 Pepco. The portions of Maryland not in SWMAAC are in the Eastern Mid-Atlantic Area Council ("EMAAC"), 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 EMAAC 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.
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. Plaintiff's expert, Professor Willig, opined that higher capacity prices in an LDA encourage projects to be developed in that area because the RPM
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.
Maryland has, as have various other states, abandoned the vertical integration model of electric energy regulation.
Before the restructuring of 1999, Maryland's electric utilities (such as BGE and Pepco) 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).
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
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").
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,
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 in Maryland have a choice to buy electric service from the default local utility or from an alternative supplier. Tr. Mar. 5(AM) at 45:3-47:19 (Nazarian). The sale of electricity supplied by the default local utility is called Standard Offer Service ("SOS"). The PSC regulates the SOS procurement process, which is conducted by the Maryland EDCs, and the rate the EDCs may charge customers for SOS. See id. at 44:2-45:23. If a Maryland customer chooses an alternative supplier, that transaction is a matter of contract and is not regulated by the PSC. See id. at 46:16-24, 48:10-18. Since Maryland's energy market is deregulated,
In mid-2000, the Maryland General Assembly and the PSC 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. For instance, in "the summer of 2006, the General Assembly convened a special session to pass legislation that would mitigate a proposed 72% rate increase on residential ratepayers [in the] BGE" territory, the largest utility territory in Maryland. P.391 (2007 PSC Interim Report) at 5.
These concerns, which took the form of several legislative and regulatory actions, eventually culminated in the issuance of the Generation Order at issue.
In May 2007, the Maryland General Assembly signed into law Senate Bill 400, calling for the PSC to study re-regulatory options and the availability of adequate generation and transmission assets in the state and to also provide the General Assembly with interim and final reports
In December 2007, the PSC filed its interim report with the General Assembly that "offer[ed its] recommendations and analysis regarding options for `re-regulating' Maryland's electricity markets and for obtaining new generation and transmission resources" in Maryland. P.391 (2007 PSC Interim Report) at 1. In the interim report, the PSC explained that "Maryland faces a critical shortage of electricity capacity... because Maryland sits in a highly congested portion of the regional electric transmission system (which makes it difficult to bring more power in) and because we use more electricity than is generated here." Id. To respond to this problem, the PSC advised that Maryland could "add more capacity, either through new generation or transmission, or ... reduce the amount of electricity [it] use[s]." Id.
Describing the wholesale and retail markets as "structured ostensibly to create price incentives for new generation or transmission," the PSC noted that the wholesale markets had not responded to Maryland's needs and opined that those markets were unlikely to respond in the immediate future to the state's "looming capacity shortage." Id. According to the PSC, "capacity shortages and transmission constraints" in Maryland caused consumers to "pay much higher than average
Ultimately, after reviewing reports presented by two groups of consultants, the PSC concluded that "[t]he analyses by [the consultants] combine to create a compelling case for directing utilities in the state to enter into long-term contracts to induce the supply of new electricity in Maryland. This is a `re-regulation' option that we believe should be pursued and that we intend to pursue." Id. at 41. The PSC believed this option would maintain the reliability of the transmission grid and obtain the best possible prices for Maryland ratepayers. Tr. Mar. 5(AM) at 64:5-11 (Nazarian).
In the summer of 2007, PJM began warning the PSC about a potential capacity shortfall in Maryland for the following year. In November 2008, the PSC issued an order in Case No. 9149, referred to as the "Gap RFP Proceeding," to address "a [`potential'] gap between the anticipated need [for electricity] in the summers going forward based on load forecasts and the known resources available to serve that need" in response to PJM's representation of a "potential delay in a transmission line project" known as the TrAIL Line. Tr. Mar. 5(AM) at 74:10-76:19 (Nazarian). Seeking new demand response resources that would bid as capacity resources into the BRA, the PSC ordered the four Maryland EDCs to issue Requests for Proposals ("Gap RFPs"). P.345 (PSC Order in Case No. 9149) at 7. In exchange for the demand response resources bidding into the BRA, the PSC offered the EDCs contracts for differences that apparently guaranteed the suppliers a fixed revenue stream for the demand response, irrespective of the market clearing price in the BRA. The Gap RFPs yielded 600 MW of demand response.
On December 10, 2008, the PSC provided its final report to the Maryland General Assembly. See generally P.582 (2008 PSC Final Report). In the report, the PSC stated that in addition to reliability measures already underway, the PSC would "undertake a new investigation in 2009 to determine whether[,] and on what terms[,] to direct or solicit the construction of one or more new power plants in Maryland." Id. at 2. Former PSC Chairman Nazarian testified that although the PSC had intended to open a proceeding for the particular purpose of addressing that issue, it never opened such a case. Trial Tr. Mar. 5, 2013(AM) at 78:22-81:-23 (Nazarian). Instead, the PSC commenced a proceeding related to inducing new generation in Maryland — Case No. 9214. It is this proceeding that led to the PSC's issuing the Generation Order.
In PSC Case No. 9117, a case unrelated to the Generation Order, CPV filed a motion to intervene and "strongly urge[d] the [PSC] to encourage policies that promote and direct long-term (10 to 15 years) PPAs [Purchase Power Agreements] from in-state generation to serve Maryland's load."
In its filings in Case No. 9117, CPV asserted its belief in the necessity of having state-sponsored long-term financing to move forward with its Charles County project because "traditional commercial banks no longer are willing to finance the types of risks they might once have undertaken; nor will they be willing to rely on third party consultant reports estimating a project's potential revenue stream in a particular wholesale market." P.14 (2009 CPV Motion) at 22. CPV explained that "RPM's conditional three-year commitment period is simply insufficient to allow new baseload [sic] generation to be financed [because] the RPM is too short-term, too volatile, and too fraught with continued regulatory uncertainty to provide lenders with anything close to the certainty of a fixed revenue stream required for financing." Id. at 24. CPV went on to note that "given RPM's purpose to provide an accurate price signal to new generation, the FERC rejected" proposed changes to RPM that would extend the commitment period. See id. at 24-25.
Instead of granting CPV's request for a state-sponsored financing contract specifically for CPV's Charles County project, in September 2009 the PSC opened a separate proceeding, Case No. 9214, which implemented the competitive bid process that eventually resulted in the Generation Order, and eventually awarded the contract for differences to CPV for its Charles County project. Tr. Mar. 5(AM) at 85:13-86:20 (Nazarian).
On September 29, 2009, the PSC initiated Case No. 9214 and directed "[t]hat any proposals for new Maryland-located electric generating facilities ... be filed by December 11, 2009." P.35 (PSC Order No. 82936) at 3-4.
On December 29, 2010, the PSC issued for comment a draft Request for Proposals for Generation Capacity Resources Under Long-Term Contract (the "Draft RFP"). See generally P.13 (2010 Draft RFP). The Draft RFP solicited up to 1,800 MW of capacity, energy, and ancillary services from generation resources. The PSC invited all interested parties to review the Draft RFP and provide comments.
The Draft RFP differed in several respects from the RFP ultimately issued by the PSC. For example, the Draft RFP solicited proposals from all types of generation resources and permitted bids from existing facilities that would uprate, or expand, their existing generation capacity. With respect to locational requirements, the Draft RFP required "[t]he proposed Generation Capacity Resource [to] be interconnected to the System such that the [resource's] output may be infed to a node east of the Western Interface and deliverable to Maryland east of the Western Interface avoiding likely transmission congestion." Id. at 15. Using this locational definition, it was possible for a generation
In the summer of 2011, the PSC engaged Boston Pacific Company, Inc. ("Boston Pacific") to perform consultation work in connection with the Draft RFP. Tr. Mar. 5(AM) at 100:20-102:1 (Nazarian). On August 12, 2011,
Regarding the reliability concern in Maryland, Boston Pacific observed that conditions had improved since 2008 when the PSC provided its final report to the Maryland General Assembly illustrating scenarios in which there could be a generation shortfall in Maryland. For example, many of the scenarios posited to the General Assembly in 2008 related to a failure on the part of PJM to secure the construction of the Trans-Allegheny Interstate Line ("TrAIL Line"). Id. at 1-2, 15. But, as Boston Pacific pointed out, PJM had come through and the TrAIL Line had gone into service in May 2011 "providing more transmission support for the [Maryland] region." Id.
Boston Pacific also explained that load growth in Maryland had declined, reducing pressure on the transmission system, and that demand response resources had materially increased, due in part to the Gap RFPs. Id. However, Boston Pacific identified "several key risk factors that could rapidly change Maryland's future [energy] supply needs." Id. at 2. Specifically, Boston Pacific noted:
Id. at 2, 17-27.
Boston Pacific identified two alternatives for the PSC to respond to reliability concerns: (1) take more time to evaluate the risks identified by Boston Pacific or (2) issue a request for proposals "targeted to address and mitigate the key risks" identified by the company. Id. at 3, 27. Boston Pacific advised the second option if the PSC "believes ... that the current risks to reliability are great enough to justify immediate action, and that RPM will not bring new generation to the State." Id. at 3. If the PSC decided on the second option to issue a request for proposals, Boston Pacific suggested several modifications to the Draft RFP "[t]o effectively mitigate the [reliability] risks" faced by Maryland. See id. at 3-5. Boston Pacific advised:
Id. at 4; see id. at 30-31.
On December 8, 2011, the PSC issued the Amended Request for Proposals for New Generation to be Issued by Maryland Electric Distribution Companies (the "RFP"), which ordered each Maryland EDC to issue an attached request for proposals.
According to the PSC, the RFP's purpose was "to ensure the continued, long-term reliability of the electricity supply to Maryland customers by mitigating key risks faced by the State." Id. at 1. Such risks, as listed in the RFP, included the risks identified by Boston Pacific, as well as "the risk that RPM will not attract enough new capacity to address these risks effectively, whatever the level of need turns out to be." See id. at 2-3. According to the PSC, "RPM has failed to attract new generation in the State to mitigate these longer-term reliability concerns, and RPM's signal remains unable to anchor the financing new generation development requires." Id. at 3. Consequently, the PSC concluded that, "[a]lthough [it] appreciates PJM's role in planning regional transmission solutions, ... [b]ecause market forces have not produced new generation in our region," the PSC may need to order the construction of new generation to "satisfy the long-term anticipated demand in Maryland" for electric supply. Id. at 3-4.
The PSC set a deadline of January 20, 2012 for proposals from interested parties for the construction and operation of new generation resource(s) to be submitted pursuant to the requirements detailed in the RFP. In exchange for building and operating the generation resource, the PSC offered the selected supplier a long-term contract for differences with three Maryland EDCs, which would provide the supplier with a guaranteed revenue stream based upon the supplier's wholesale energy and capacity sales into the PJM Markets. The PSC stated that it would select "the bid(s) that produces the lowest-cost solution for ratepayers when accounting for risk." Id. at 16. The PSC explicitly reserved the right to reject all proposals submitted in response to the RFP.
In the RFP, the PSC sought proposals to build and operate a particular type of generation resource in a particular location. Specifically, the PSC only solicited proposals for:
Pursuant to the structure employed by the RFP,
As outlined in the RFP, the compensation structure for any supplier chosen by the PSC to construct and operate a new generation resource in SWMAAC would be governed by a long-term contract for differences ("CfD"). The RFP provided that, after selecting a supplier, the PSC would direct or order one or more of the Maryland EDCs to enter into the CfD with the supplier. The CfD contained compensation provisions that enabled the selected supplier to receive its proposed "contract price" for each unit of energy and capacity sold to PJM in the PJM Markets up to a ceiling amount. See generally id.; id., Attachment 1 (CfD Settlement Example); id., Attachment 8 (Sample CfD).
The terms of the RFP required each submitted proposal to contain "the total pricing provisions for the Capacity and Energy produced by the Generation Capacity Resource over the contract term." See P.2 (2011 RFP) at 10-11. The RFP and its attachments contained detailed explanations of the parameters for submission of the contract price.
At trial, CPV explained its "method" for reaching the proposed contract price. CPV assessed the costs of all of its obligations surrounding its proposed project, including: construction of its facility; fixed operating costs going forward, such as labor, property taxes, and maintenance; raising capital to finance the construction; and a reasonable rate of return to CPV. CPV then applied those assessments to a financial model to determine the annual revenue requirements necessary to construct and operate its proposed generation resource. Tr. Mar. 7(AM) at 122:15-123:19 (Knight). That annual revenue requirement served as the basis for CPV's requested contract price presented in $/MW-day of unforced capacity and $/MWh.
As discussed in detail infra, under the CfD the actual revenue received by the supplier for its sale of energy and capacity in the PJM Markets is compared to what the supplier would have received for those sales had the contract prices been controlling, and any difference is settled between the supplier and the EDC(s). If the contract prices are higher than the market prices, the EDC(s) pays the difference to
In response to the RFP, the PSC received seven bids, including a proposal from CPV for the construction and operation of a power plant in Charles County, Maryland. On April 12, 2012, after evaluation of the bids, the PSC issued the Generation Order directing BGE, Pepco and Delmarva (the "Maryland EDCs") "to enter into a Contract for Differences with CPV ... under which CPV will construct a 661 megawatt (MW) natural gas-fired combined-cycle generation plant in Waldorf in Charles County, Maryland, with a commercial operation date of June 1, 2015. P.44 (Generation Order) at 7.
The PSC determined that CPV's bid provided "the best price for [Maryland] SOS ratepayers, with the average impact to residential SOS ratepayers projected to be a credit of $0.49/month over the entire life of the contract." Id. at 26. The PSC also ordered that the Maryland EDCs required to enter into the CfD with CPV should recover their costs from all Maryland SOS ratepayers, not just those ratepayers in the SWMAAC zone. Id. at 26-27.
In the Generation Order, the PSC provided a summary of the comments it received from various interested parties with respect to moving forward with the RFP. Specifically, the Maryland EDCs opposed proceeding with the RFP on the grounds "that customers would be `burdened' with additional costs for unneeded and uneconomic generation." See id. at 10-12. With respect to the Plaintiffs, PPL opposed the RFP on the grounds that "it is not necessary because the competitive market is working to create reserve margins above 20% through 2015, and trends indicate demand is declining." Id. at 13-14. Similarly, PSEG "assert[ed] that proceeding with the RFP will interfere with the proper functioning of the wholesale competitive market." Id. at 14. The PSC rejected these concerns along with the contention that demand needs could be satisfied by the RPM and the BRA, stating:
Id. at 22-23.
Commercial Power Ventures Maryland ("CPV") and its affiliates develop natural
In 2006, CPV began planning the project to build its Charles County Facility (the "Facility"). Tr. Mar. 7(PM) at 87:3-10 (Egan). As discussed supra, CPV was of the opinion that it needed a long-term price contract, or its equivalent, to finance the construction and development of the Facility. Id. at 89:6-18. In about 2008, after exploring options in the open market to no avail, CPV began pursuing the procurement of a long-term contract from the State of Maryland, and in 2009 it formally requested such a contract from the PSC. Id. at 88:9-15. As discussed herein, on April 12, 2012, the PSC issued the Generation Order selecting CPV's generation proposal and awarding CPV the CfD. As of the time of bench trial, CPV has stated that it would not move forward with construction of the Facility without the CfD. Id. at 89:15-18, 93:21-94:1.
In the spring of 2012, CPV bid 661 MW-days of capacity from its yet-to-be-built Facility into the BRA. Tr. Mar. 7(AM) at 104:19-107:22 (Knight). Because it involved a new generation resource, CPV's bid was subject to the MOPR, which FERC had recently modified in 2011. The MOPR, as it existed in 2012, placed a floor on CPV's bid into the BRA that precluded CPV from bidding zero and acting as a price taker. Pursuant to the MOPR, CPV could not bid less than 90% of Net CONE (Cost of New Entry)
PJM Interconnection, L.L.C., 137 FERC ¶ 61,145, at *4 (2011).
On March 7, 2012, CPV filed a unit-specific MOPR exception proposing a bid floor of $13.95/MW-day. See generally D.173 (CPV MOPR Exception Request). Pursuant to PJM's tariff, PJM must review a submitted unit-specific exception "to determine if it's consistent with competitive cost-based fixed nominal levelized [CONE]." Tr. Mar. 7(AM) at 96:12-97:23 (Knight). PJM's independent market monitor made the initial determination that CPV's unit-specific costs precluded it from bidding below $136.87/MW-day. See id. at 98:15-103:23. On April 10, 2012, CPV requested a separate determination from PJM. One month later, on April 20, 2012, PJM approved a bid floor of $96.13/MW-day for CPV because the offer was "`consistent with the competitive, cost-based,
In accordance with PJM's unit-specific determination, CPV submitted a bid into the 2012 BRA of $96.13/MW-day for the amount of 661 MW for the delivery year 2015/2016. In SWMAAC and MAAC, the market clearing price for the 2012 BRA was $167.46/MW-day. Hence, CPV cleared the BRA. After the 2012 BRA results were released, PJM performed a sensitivity analysis. See Tr. Mar. 4(PM) at 22:23-24, 24:23-24 (Carretta). In the sensitivity analysis, PJM calculated that if the offered supply of capacity had been decreased in SWMAAC by 750 MW from the bottom of the supply stack or curve, the resulting clearing price for capacity in SWMAAC would have been $195.00/MW-day instead of $167.46/MW-day. See id. at 24:23-25:6; Tr. Mar. 5(PM) at 135:13-140:6 (Cudwadie).
The Supremacy Clause of the United States Constitution renders federal law "the supreme Law of the Land." U.S. Const. art. VI, cl. 2. "The Supremacy Clause is grounded in the allocation of power between federal and state governments..." Md. Pest Control Ass'n v. Montgomery Cnty., Md., 884 F.2d 160, 162 (4th Cir.1989) (per curiam). Rooted in the Supremacy Clause and its recognition of a hierarchy of federal and state power is the doctrine of preemption. See Gade v. Nat'l Solid Wastes Mgmt. Ass'n, 505 U.S. 88, 108, 112 S.Ct. 2374, 120 L.Ed.2d 73 (1992). Pursuant to the doctrine of preemption, "[i]t is a familiar and well-established principle that the Supremacy Clause invalidates state laws that `interfere with, or are contrary to,' federal law." Hillsborough Cnty., Fla. v. Automated Med. Labs., Inc., 471 U.S. 707, 712-13, 105 S.Ct. 2371, 85 L.Ed.2d 714 (1985) (internal citation omitted) (quoting Gibbons v. Ogden, 22 U.S. 1, 211, 9 Wheat. 1, 6 L.Ed. 23 (1824)). Accordingly, the doctrine of preemption is a limitation on state power stemming from the recognition in the U.S. Constitution of a dual system of government where the national government reigns supreme. See Anderson v. Sara Lee Corp., 508 F.3d 181, 191 (4th Cir.2007) (explaining that "`federal statutes and regulations properly enacted and promulgated can nullify conflicting state or local actions'") (citation omitted).
Preemption of state action through federal law can occur as the result of: (1) "the Constitution itself," (2) "a valid act of Congress," and/or (3) "regulations duly promulgated by a federal agency." City of Charleston, S.C. v. A Fisherman's Best, Inc., 310 F.3d 155, 168-69 (4th Cir. 2002). "Yet `[c]onsideration under the Supremacy Clause starts with the basic assumption that Congress did not intend to displace state law.'" S. Blasting Servs., Inc. v. Wilkes Cnty., N.C., 288 F.3d 584, 589-90 (4th Cir.2002) (quoting Maryland v. Louisiana, 451 U.S. 725, 746, 101 S.Ct. 2114, 68 L.Ed.2d 576 (1981)). This presumption (of a lack of congressional intent to displace state law) is strongest when "Congress has `legislate[d] ... in a field which the States have traditionally occupied.'" Medtronic, Inc. v. Lohr, 518 U.S. 470, 485, 116 S.Ct. 2240, 135 L.Ed.2d 700 (1996) (alteration in original) (citation omitted). "[A]n `assumption' of nonpre-emption is not triggered when [a] State regulates in an area where there has been a history of significant federal presence." United States v. Locke, 529 U.S. 89, 108, 120 S.Ct. 1135, 146 L.Ed.2d 69 (2000).
Plaintiffs contend that the Generation Order impermissibly invades a field occupied exclusively by FERC — the regulation of wholesale energy and capacity sales, including the price at which such sales are made — because the Generation Order sets the wholesale price received by CPV for its capacity and energy sales into the PJM Markets. Defendants assert that the Generation Order falls within the area of electric energy regulation not only traditionally occupied by the states, but also explicitly reserved to the states in the Federal Power Act ("FPA").
As discussed supra, preemption of state law may be express, i.e., explicitly provided for by the federal statue in question, or implied. See Morales v. Trans World Airlines, Inc., 504 U.S. 374, 383, 112 S.Ct. 2031, 119 L.Ed.2d 157 (1992). One type of implied preemption is field preemption. Field preemption occurs "where Congress has legislated comprehensively, thus occupying an entire field of regulation." La. Pub. Serv. Comm'n v. F.C.C., 476 U.S. 355, 368, 106 S.Ct. 1890, 90 L.Ed.2d 369 (1986). Thus, "state law is [field] pre-empted where it regulates conduct in a field that Congress intended the Federal Government to occupy exclusively." English v. Gen. Elec. Co., 496 U.S. 72, 79, 110 S.Ct. 2270, 110 L.Ed.2d 65 (1990).
The congressional intent essential for a field preemption claim can be found in
English, 496 U.S. at 79, 110 S.Ct. 2270 (alterations in original) (quoting Rice v. Santa Fe Elevator Corp., 331 U.S. 218, 230, 67 S.Ct. 1146, 91 L.Ed. 1447 (1947)). Generally speaking, "if Congress evidences an intent to occupy a given field, any state law falling within that field is preempted." Silkwood v. Kerr-McGee Corp., 464 U.S. 238, 248, 104 S.Ct. 615, 78 L.Ed.2d 443 (1984); Pac. Gas & Elec. Co. v. State Energy Res. Conservation & Dev. Comm'n, 461 U.S. 190, 212, 103 S.Ct. 1713, 75 L.Ed.2d 752 (1983).
Accordingly, assessment of Plaintiffs' field preemption claim requires a determination of whether Congress intended the federal government to regulate exclusively the field of wholesale energy and capacity sales and, if so, whether the Generation Order can be said to have regulated in that field.
By enacting the FPA and other related laws, Congress created a division between federal and state authority within the broad field of electric energy regulation. As discussed supra, this division was somewhat necessitated by the Supreme Court's holding in 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 the FPA, Congress declared:
16 U.S.C. § 824(a).
In line with this dual federal/state regulatory regime, pursuant to the FPA, FERC has jurisdiction over "the transmission of electric energy in interstate commerce and ... the sale of electric energy at wholesale in interstate commerce,"
Though it creates a federal role, the FPA explicitly "preserve[d] state jurisdiction" over certain areas of the electric energy regulation field, including, but not limited to, regulation concerning the siting and construction of physical facilities used for the generation of electric energy.
The preservation of state authority in a carved-out area within a broader federal regulatory field does not eliminate the exclusive federal jurisdiction over the balance of the field. See generally Pac. Gas & Elec. Co. v. State Energy Res. Conservation & Dev. Comm'n, 461 U.S. 190, 212, 103 S.Ct. 1713, 75 L.Ed.2d 752 (1983) (explaining that "the federal government has occupied the entire field of nuclear safety concerns, except the limited powers expressly ceded to the states"). Indeed, structuring a statutory scheme so as to divide state and federal authority within one regulatory realm could be viewed as indicating that Congress intended the "federal side" of the field to be regulated exclusively by the federal government.
In regard to electric energy regulation, through the FPA Congress vested FERC with authority over wholesale electric energy prices. The FPA provides that:
16 U.S.C. § 824d(a). A "public utility" is defined as "any person who owns or operates facilities subject to the jurisdiction of the Commission." Id. § 824(e). A power plant that engages in wholesale electric energy sales and interstate transmission would fall within the definition of a public utility.
To ensure the just and reasonableness of wholesale electric energy rates, the FPA implements a regulatory framework that vests FERC with authority to determine
Wholesale electric energy rates include energy prices as well as capacity prices, which "are a large component of wholesale rates." See Miss. Indus. v. F.E.R.C., 808 F.2d 1525, 1541 (D.C.Cir.1987), vacated in part on other grounds, 822 F.2d 1104 (D.C.Cir.1987); see also Entergy La., Inc. v. La. Pub. Serv. Comm'n, 539 U.S. 39, 43, n. 1, 123 S.Ct. 2050, 156 L.Ed.2d 34 (2003) ("Where, as here public utilities share capacity, the allocation of costs of maintaining capacity and generating power constitutes `the sale of electric energy at wholesale in interstate commerce.'" (quoting § 824(b)(1))).
As stated by the Supreme Court:
Miss. Power & Light, 487 U.S. at 371, 374, 108 S.Ct. 2428 (alteration in original) (quoting Nantahala Power & Light Co. v. Thornburg, 476 U.S. 953, 960, 957, 106 S.Ct. 2349, 90 L.Ed.2d 943 (1986) (noting that FERC "has exclusive jurisdiction over wholesale power rates")); Ark. La. Gas Co. v. Hall, 453 U.S. 571, 580-82, 101 S.Ct. 2925, 69 L.Ed.2d 856 (1981) (finding that state breach-of-contract claim was preempted by FERC's exclusive jurisdiction on the grounds that the state court's interpretation of terms could interfere with FERC rates); see also Pub. Util. Dist. No. 1 of Snohomish Cnty. v. Dynegy Power Mktg., Inc., 384 F.3d 756, 758 (9th Cir.2004) (acknowledging FERC's "exclusive jurisdiction over interstate sales of wholesale electricity"); Appalachian Power Co. v. Pub. Serv. Comm'n of W. Va., 812 F.2d 898, 902 (4th Cir.1987) ("FERC's jurisdiction over interstate wholesale rates is exclusive.").
Accordingly, it appears well accepted that Congress intended to use the FPA to give FERC exclusive jurisdiction over setting wholesale electric energy and capacity
Plaintiffs contend that the PSC has impermissibly regulated in the field of wholesale electric energy price setting because the Generation Order effectively sets the price received by CPV for its wholesale energy and capacity sales to PJM in the PJM Markets. Defendants contend the Generation Order does not "set wholesale prices" because it is a purely financial arrangement that secured the construction and development of a new generation facility in Maryland.
Defendants take the position that the Court cannot, or at least should not, construe the PSC's regulatory action in connection with the Generation Order as invading the exclusive field of FERC because the Order sought to secure the construction of a generation facility, an act within the jurisdiction reserved to the states under the FPA.
The Court agrees with Defendants' position that the FPA preserved states' jurisdiction over certain direct regulation of physical generation facilities. For instance, it appears that the states hold the authority to do the following: (1) take regulatory action to require existing generation facilities to retire; (2) limit the type or amount of generation facilities constructed in the state; (3) promote certain environmentally desired types of generation facilities; and (4) determine the siting or location of a new generation facility within the state. See 16 U.S.C. § 824(b)(1); Conn. Dep't of Pub. Util. Control v. F.E.R.C., 569 F.3d 477, 481 (D.C.Cir.2009). The Court can accept Defendants' position that FERC and/or PJM cannot directly order the construction of a new generation facility, let alone require or direct a state to permit such construction to occur within its borders. See Tr. Mar. 5(PM) at 21:1-14, 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). The Court also can accept the position that the State of Maryland has a legitimate interest and federally permissible role in securing an adequate supply of electric energy for Maryland residents in the present and in the future. See 16 U.S.C. § 824o(i); Md.Code Ann., Pub. Util. § 5-101(a).
Yet after a generator physically comes into existence and operation and participates in the wholesale electric energy market, the prices or rates received by that generator in exchange for wholesale energy and capacity sales are within the sole purview of the federal government. While Maryland may retain traditional state authority to regulate the development, location, and type of power plants within its borders, the scope of Maryland's power is necessarily limited by FERC's exclusive authority to set wholesale energy and capacity prices under, inter alia, the Supremacy Clause and the field preemption doctrine. Based on this principle, Maryland cannot secure the development of a
Defendants maintain that the Generation Order cannot be field preempted because states may take a variety of actions to incentivize the development of generation facilities that affect wholesale energy and capacity prices without infringing on FERC's jurisdiction. The Court does not doubt that state action that promotes the development of power plants contemplated to participate in the wholesale energy market would not be field preempted merely because the action — by increasing the supply of available energy and capacity — affects wholesale energy and capacity prices in the PJM Markets. Indeed, Plaintiffs do not contend that the Generation Order is field preempted solely because it will have an effect on wholesale prices. Rather, Plaintiffs assert that the Generation Order is field preempted because it seeks to secure new generation by setting or establishing the prices to be received by CPV for its wholesale energy and capacity sales in the PJM Markets for the next twenty (20) years.
Therefore, the Court rejects Defendants' position that because the Generation Order sought to accomplish an objective within the purview of state jurisdiction contemplated by the FPA, the Order cannot be held to be field preempted. It is the means by which the PSC sought to secure a new generation facility that Plaintiffs challenge as field preempted, not the securing of the facility itself or the purpose for taking action to do so. Consequently, the fact that the Generation Order secured the construction of a generation facility capable of serving the electric energy needs of Maryland is not determinative of the field preemption issue. The Court must assess whether the compensation mechanism, the CfD, impermissibly set wholesale prices for CPV's energy and capacity sales into the PJM Markets.
The price or rate received by CPV or by any generation resource within the PJM region for energy and capacity sales to PJM in the PJM Markets is regulated exclusively by FERC under the FPA. PJM sets the prices received by generators for sales into the PJM Markets through market-based auction processes that are filed with, and approved by, FERC. The heart of the parties' dispute relates to whether the PSC has effectively "set the wholesale prices" that CPV will receive for its energy and capacity sales into the PJM Markets by issuing the Generation Order, which requires the Maryland EDCs to enter into the CfD with CPV. In essence, the CfD permits CPV ultimately to recover its proposed "contract price" — accepted and approved by the PSC in the Generation Order — for energy and capacity sales into the PJM Markets.
Allegedly impermissible wholesale rate setting by a state usually occurs with respect to the demand side of the energy
Pursuant to the CfD, CPV agreed to, inter alia:
P.2 (2011 RFP), Attachment 8 (Sample CfD) at 18, 19, 32, 33.
Under the compensation scheme outlined in the CfD, CPV is guaranteed to receive the "contract price" for each unit of energy and capacity it sells to PJM in the PJM Markets up to a ceiling quantity of 661 MW. The contract price is a dollar figure assigned to a unit of energy and capacity.
The following chart, using completely hypothetical numbers, illustrates the compensation mechanism employed by the CfD:
Energy Capacity Total ($)
Total Units Sold to
PJM in PJM Markets in 200049 300050
One Month by CPV
Contract Price per Unit 10051 120
Market Price per Unit 5052 7553
CPV Market Revenue
(Units Sold * $100,000.00 $225,000.00 $325,000.00
Market Price)
Contract Payment
Stream (Units Sold * $200,000.00 $360,000.00 $560,000.00
Contract Price)
Payment from EDC to CPV: $100,000.00 $135,000.00 $235,000.00
Payment from CPV to EDC: $0 $0 $0
Accordingly, the Court finds that the Generation Order, through the CfD, establishes the price ultimately received by CPV for its actual physical energy and capacity sales to PJM in the PJM Markets. However, under field preemption principles, the PSC is impotent to take regulatory action to establish the price for wholesale energy and capacity sales. FERC has exclusive domain in that field and has fixed the price for wholesale energy and capacity sales in the PJM Markets as the market-based rate produced by the auction processes approved by FERC and utilized by PJM.
Defendants assert that despite the fact that the CfD's compensation mechanism provides CPV with the contract price for its actual capacity and energy sales to PJM in the PJM Markets, the Court cannot consider the Generation Order field preempted because the Order is a mere financing arrangement outside the jurisdiction of FERC. According to Defendants, the contract price represents CPV's "revenue requirements ... to construct a power plant," and therefore, any payments between the EDCs and CPV are in return for CPV's construction of a generation facility and not for the sale of energy and capacity. Defs.' Post-Trial Br. [Document 146] at 19-20, 22.
The evidence established that CPV formulated the contract price it submitted in response to the RFP based upon, inter alia, the cost of constructing the proposed Charles County Facility. But, the financial considerations taken into account by CPV when computing the contract price go beyond recouping the costs for physically constructing a generation facility. Mr. Knight, a representative of CPV, testified that CPV formulated the contract price submitted to the PSC based upon its calculation of the annual revenue requirement necessary for CPV to construct the facility, operate the facility going forward, and receive a reasonable return on the project. Tr. Mar. 7(AM) at 122:15-123:19 (Knight). Indeed, evidence was presented that the same types of financial concerns or factors are taken into account by an existing generation resource when formulating the price at which it is willing to bid into the BRA. See id. at 129:5-130:7. As Mr. Knight explained, the CfD exchanged the "unknown or variable energy prices" received in the PJM Markets for the fixed contract price, and, from CPV's perspective, all CPV needed to know was that the contract price plus the minor profit it estimated from ancillary services "covers our total costs on a forward going basis." Id. at 124:16-21. The evidence establishes that the contract price represents a fixed revenue stream for actual energy and capacity sales into the PJM Markets that replaces the non-fixed wholesale market revenue that CPV would otherwise depend
Based on the foregoing, the Court finds that the market revenue for wholesale energy and capacity sales into the PJM Markets and the contract price under the CfD serve basically the same goal: incoming revenue that enables CPV's facility to exist, operate, and dispatch electric energy into the PJM region. Consequently, the variables used by CPV to configure the contract price submitted to and accepted by the PSC in the Generation Order do not support Defendants' position that the CfD is limited to a financing arrangement outside the reach of FERC and is therefore incapable being field preempted.
The CfD is not a purely financial contract, financial hedging agreement, or swap agreement,
See id. at 63:14-65:25.
Though swap agreements refer to "buying" and "selling," those terms are used in
Participants in the energy industry may enter into swap agreements as a financial hedge for actual energy transactions conducted independently with third parties in the market. Id. at 67:6-9, 68:24-69:16. Thus, a party intending to purchase energy can guarantee that it will cost $40 per unit by entering into a swap transaction. If the actual market price is $42, the party pays $42 for the energy but receives $2 from the hedge transaction, making its net cost $40 per unit. If the actual market price is $38, the party will pay $38 for the energy but an additional $2 to the other side of the hedge transaction, also making its net cost $40 per unit. Payment under the swap agreement is not conditioned upon actual physical sales or deliveries into the energy market. Id. at 69:22-70:13. As a result, the swap agreement on its own has no contractual effect or relation to the swap parties' behavior in the market upon which the deal is based because the swap agreement is not a real sale of a tangible product.
The Court agrees with Mr. Cudwadie that the CfD is critically distinguishable from a swap or similar agreement and cannot be categorized as a "purely financial arrangement" as that term is commonly understood in the energy industry. Unlike the swap agreement described above, the CfD: (1) obligates CPV to construct and operate the generation Facility; (2) requires CPV to participate and offer that Facility's output into the PJM Markets; (3) dictates the manner in which CPV participates in the PJM Markets, (4) mandates a financial settlement only if CPV clears the BRA in any given year; and (5) determines the amount of settlement based on CPV's physical energy and capacity sales into the PJM Markets. See id. at 94:12-98:14. Indeed, because the CfD requires CPV to bid and clear the BRA at a price different from the amount that CPV will actually receive, the CfD directly affects the market price. Accordingly, the Court finds that the CfD does not constitute a pure financial contract of the type used by participants in the energy market for hedging purposes. Consequently, the Court rejects Defendants' position that the CfD is not field preempted because it amounts to a non-FERC jurisdictional financial swap agreement.
First, the compensation scheme orchestrated by the PSC in the CfD renders payment directly contingent upon CPV's clearing capacity in the BRA. If CPV does not clear any capacity in the annual BRA, then it gets nothing under the CfD. Specifically, "[n]o Monthly Payment shall be provided during any period in which [CPV] has not been selected to provide capacity in PJM's BRA." P.2 (2011 RFP), Attachment 8 (Sample CfD) at 37. Even if CPV constructs and operates the Charles County Facility, CPV will receive no payment under the compensation scheme if it does not clear capacity in the BRA. Yet, a power plant that does not clear the BRA may still sell its electric energy to PJM in the PJM Wholesale Energy Market. See Tr. Mar. 8(AM) at 13:19-14:2 (Willig). The clearing pre-condition in the CfD rewards CPV for clearing the BRA because CPV only obtains the contract price for wholesale energy and capacity sales into the PJM Markets if the CPV bid clears. Thus, the Court finds that the CfD's payment scheme compensates CPV, in part, for making wholesale capacity sales to PJM in the PJM Wholesale Capacity Market.
A second illustration of how the contract price compensates CPV for its wholesale energy and capacity sales into the PJM Markets is provided by the way in which monthly settlements are calculated under the CfD. If CPV clears the BRA, the pricing terms in the CfD are linked directly to the quantity of energy and capacity sold from the CPV Facility into the PJM Markets. Mar. 7(PM) at 11:11-13:3, 16:20-17:7 (Knight). As discussed supra, CPV is compensated based upon how much capacity and energy it actually sells to PJM in the PJM Markets up to a ceiling figure. As Mr. Cudwadie testified, "to get paid [CPV] ha[s] to clear the auction. That same type of principle applies to the energy market as well. If they're going to get payment under the contract, they must clear megawatts in the energy market." Tr. Mar. 4(PM) at 98:4-8 (Cudwadie).
The Generation Order, the 2011 Amended RFP, and the CfD contain other representations that rebut the notion that the CfD does not compensate CPV for wholesale energy and capacity sales. For instance, the CfD provides that the Maryland EDCs "shall not pay for Capacity and Energy that PJM deems was not made available up to the performance standards required by PJM Agreements and PJM Tariff." See P.2 (2011 RFP), Attachment 8 (Sample CfD) at 38. The CfD obligates CPV to bid its 661 MW of the Facility only into the PJM Markets. See id. at 32. However, wholesale energy and capacity sales may occur through bilateral contracts
Defendants assert that the Generation Order is outside the purview of the FERC-regulated field because the CfD is not an agreement for the physical delivery or sale of energy and capacity between CPV and the Maryland EDCs.
Defendants contend that Plaintiffs' field preemption claim is moot because
CPV filed an application with FERC pursuant to Section 205 of the FPA on November 8, 2012 (and amended the application on December 4, 2012) seeking, inter alia, "authorization to make market-based wholesale sales of energy, capacity, and ancillary services pursuant to [an attached] market-based rate tariff." P.611 (CPV FERC Application for Market-Based Rate Authorization) at 1. On February 1, 2013, FERC approved CPV's market-based rate tariff (the "MBR Tariff"). Defendants assert that if "the CfD were a contract within FERC's jurisdiction, that contract is now authorized by FERC and controlled by the MBR Tariff [and] any complaint by Plaintiffs regarding the CfD ... would have to be directed to FERC, and not this Court."
"[Market-based rate t]ariffs, instead of setting forth rate schedules or rate-fixing contracts, simply state that the seller will enter into freely negotiated contracts with purchasers." Morgan Stanley, 554 U.S. at 537, 128 S.Ct. 2733. Contracts entered into under market-based rate tariffs need not be filed immediately with FERC. Instead, the wholesale seller must file quarterly reports summarizing the contracts into which it has entered. Id. A market-based rate tariff authorizes a seller to enter into bilateral transactions "for resale of electric energy, capacity, or ancillary services at market-based rates." See 18 C.F.R. § 35.36(b); Tr. Mar. 4(AM) at 40:2-9 (Alessandrini) (explaining that market-based rate authority gives a seller "the ability to buy and sell electricity with two willing counter-parties at arm's length and at market-based rates"). However, "FERC will grant approval of a market-based tariff only if a utility demonstrates that it lacks or has adequately mitigated market power, lacks the capacity to erect other barriers to entry, and has avoided giving preferences to its affiliates." Morgan Stanley, 554 U.S. at 537, 128 S.Ct. 2733.
As a result of its MBR Tariff, CPV has FERC approval to sell electric energy, capacity, or ancillary services at wholesale through freely negotiated contracts with purchasers, including wholesale sales made to PJM in the PJM Markets. See Tr. Mar. 7(PM) at 5:4-8 (Knight) (explaining that CPV would be required to obtain market-based rate authority from FERC prior to making the sales required under the CfD to PJM). Of course, the MBR Tariff would affect only those transactions that are subject to FERC's jurisdiction.
In CPV's application for market-based rate authorization, it provided in a footnote that:
P.611 (CPV FERC Application for Market-Based Rate Authorization) at 4 n. 7 (internal citations omitted). In its order authorizing CPV's MBR Tariff, FERC referenced CPV's above-quoted representation, but did not address the CfD as part of the proceeding for market-based rate authority, limiting its discussion to whether CPV had horizontal or vertical market power. CPV Shore, LLC, 142 FERC ¶ 61,081, at *7-10 (2013). FERC has not passed judgment, one way or another, on the reasonableness or fairness of the terms of CfD, whether the CfD is a "FERC-jurisdictional" contract, or any other potential issue within its regulatory jurisdiction.
Defendants contend that a finding in favor of Plaintiffs on the field preemption claim means that FERC would have jurisdiction over the CfD and, since CPV has been granted its MBR Tariff, the only forum to debate the enforceability of the CfD is FERC. The Court does not agree.
Even if the MBR Tariff granted by FERC authorized CPV, in the first instance, to enter into the CfD with the Maryland EDCs, thereby rendering any dispute over the CfD within the primary jurisdiction of FERC, such an authorization would not by extension preclude this Court from granting relief to Plaintiffs on a field preemption claim against the Maryland PSC. Plaintiffs' Complaint seeks relief enjoining the PSC from enforcing the Generation Order, which includes the requirement that the Maryland EDCs enter into the CfD with CPV. In this action, Plaintiffs have not directly challenged the CfD (i.e., the ability of the Maryland EDCs and CPV to enter into the CfD absent state directive). Plaintiffs do not seek relief against CPV and do not assert that CPV has engaged in an unlawful practice in connection with the CfD. Contrary to the situation in Pub. Util. Dist. No. 1 of Snohomish Cnty. v. Dynegy Power Mktg., Inc., 384 F.3d 756, 761 (9th Cir.2004),
Plaintiffs have challenged the Maryland PSC's ability under the Supremacy Clause to issue the Generation Order, which directed market participants to enter into the CfD with CPV. While the Court's finding that the Generation Order is field preempted raises the implication that the CfD, standing by itself, is a FERC-jurisdictional contract as opposed to a purely financial arrangement that is generally considered outside the purview of FERC, such an implication does not strip this Court of jurisdiction to decide the constitutionality of the PSC's regulatory actions and to enjoin enforcement of an unconstitutional state action.
When it issued the Generation Order, the PSC sought "to ensure the continued,
In the Generation Order, the PSC directed the Maryland EDCs to enter into the CfD with CPV. Under the CfD, CPV is guaranteed to receive the contract price — an out-of-market price set by the PSC — for its actual wholesale energy and capacity sales up to 661 MW in the PJM Markets. Based on the evidence presented at trial as discussed herein, the Court finds that the Generation Order sets or establishes the ultimate price received by CPV for these wholesale energy and capacity sales. The doctrine of field preemption forecloses state regulation in a field occupied entirely by the federal government, even if the state's purpose is admirable or the state regulation does not conflict with achievement of the federal scheme. See Arizona v. United States, ___ U.S. ___, 132 S.Ct. 2492, 2502, 183 L.Ed.2d 351 (2012). Where Congress intended FERC alone to regulate wholesale energy and capacity prices, and this Court has found the Generation Order sets or establishes the wholesale energy and capacity prices to be received by CPV for its sales into the PJM Markets, the PSC has encroached upon an exclusive federal field. In line with the principles of the Supremacy Clause, the Generation Order cannot stand.
The Court finds that the Generation Order is field preempted and, therefore, is unconstitutional as a violation of the Supremacy Clause.
Conflict preemption exists "where state law `stands as an obstacle to the accomplishment and execution of the [Congress'] full purposes and objectives.'" Freightliner Corp. v. Myrick, 514 U.S. 280, 287, 115 S.Ct. 1483, 131 L.Ed.2d 385 (1995) (alteration in original) (quoting Hines v. Davidowitz, 312 U.S. 52, 68, 61 S.Ct. 399, 85 L.Ed. 581 (1941)). The Court's decision that the Generation Order violates the Supremacy Clause because it is field preempted, renders moot the question of whether the Order would also be held to violate the Supremacy Clause because it is conflict preempted.
The Court will not undertake an academic exercise to hypothecate the findings that it would have made in a decision holding that the Generation Order is not field preempted and then hypothecate what would have been this Court's conflict preemption decision with those findings substituted for those actually made.
Accordingly, the Court simply will note that there are reasonably debatable issues as to whether the Generation Order violated the Supremacy Clause by virtue of conflict, as well as field, preemption.
As discussed herein, the Court does not accept any of Defendants' plethora of contentions that would prevent consideration of the merits of Plaintiffs' dormant Commerce Clause claim. However, on consideration of the ultimate issue, the Court does not find that the Generation Order violates the dormant Commerce Clause.
The enumerated powers delegated to Congress by the United States Constitution include the power "[t]o regulate Commerce with foreign Nations, and among the several States, and with the Indian Tribes." U.S. Const. art. I, § 8, cl. 3. "Although the Commerce Clause is phrased merely as a grant of authority to Congress ... it is well established that the Clause also embodies a negative command forbidding the States to discriminate against interstate trade." Associated Indus. of Mo. v. Lohman, 511 U.S. 641, 646, 114 S.Ct. 1815, 128 L.Ed.2d 639 (1994). This negative aspect of the Commerce Clause, or dormant Commerce Clause, prohibits economic protectionism ("that is, regulatory measures designed to benefit in-state economic interests by burdening out-of-state competitors") on part of the States. See New Energy Co. of Ind. v. Limbach, 486 U.S. 269, 271, 273, 108 S.Ct. 1803, 100 L.Ed.2d 302 (1988) (invalidating under the dormant Commerce Clause a statute that provided a tax credit for sales of ethanol produced in Ohio but not for sales of ethanol produced in certain other states). Such state economic protectionism "violates the principle of the unitary national market by handicapping out-of-state competitors." W. Lynn Creamery, Inc. v. Healy, 512 U.S. 186, 193, 114 S.Ct. 2205, 129 L.Ed.2d 157 (1994).
In any dormant Commerce Clause challenge to state action, a court must determine as a preliminary matter whether the state's actions are of the type subject to the strictures of the dormant Commerce Clause. If the state's actions are not exempted from the Commerce Clause, then the court must determine whether the state has affirmatively discriminated against interstate commerce or, though regulating evenhandedly, has unduly burdened interstate commerce. See Maine v. Taylor, 477 U.S. 131, 138, 106 S.Ct. 2440, 91 L.Ed.2d 110 (1986); McBurney v. Young, 667 F.3d 454, 468 (4th Cir. 2012), aff'd, ___ U.S. ___, 133 S.Ct. 1709, 185 L.Ed.2d 758 (2013). Affirmative discrimination
Defendants contend that the PSC's challenged actions are not covered by the strictures of the dormant Commerce Clause. Defendants contend that in connection with issuing the Generation Order, the PSC operated without Commerce Clause confinement because: (1) state spending or subsidization to advance a legitimate public purpose operates outside the Commerce Clause; (2) the PSC acted as a market participant in the new generation market; and/or (3) Congress has expressly authorized states to discriminate against interstate commerce in the siting of generation facilities.
Defendants urge the Court to hold that the dormant Commerce Clause does not apply to the PSC's actions because, by ultimately requiring Maryland ratepayers to shoulder the financial burden of the CfD, the PSC has merely spent money to subsidize the construction of a power plant in order to advance a legitimate public purpose. See Defs.' Post-Trial Br. [Document 146], at 43-45. In essence, Defendants request this Court to recognize a sweeping exception to the dormant Commerce Clause that would permit a state or local government to discriminate against interstate commerce so long as that government's actions can be categorized as spending or subsidization to advance a legitimate public purpose. For the reasons stated herein, the Court declines to do so.
Defendants' spending and subsidy contentions are separable into two distinct categories: (1) state or local spending on any matter and (2) administration of state or local subsidies or subsidy programs provided to private business. In their posttrial briefing, Defendants treat state spending generally and state administration of a subsidy program as a single class of state action wholly outside the Commerce Clause. Yet, a state subsidy is a sub-set that falls under the much broader umbrella of state or local spending.
Relying on several Supreme Court cases addressing the market participant exception
The Supreme Court jurisprudence relied upon by the Defendants does not demonstrate a separate and categorical dormant Commerce Clause exception for state activity pigeonholed as spending money to advance public health, safety, or welfare. Rather, those decisions indicate a recognition that (1) in certain instances, when a state or local government spends its own revenues, that government may be considered a market participant free to operate without Commerce Clause hindrance (White v. Mass. Council of Const. Emp'rs, Inc., 460 U.S. 204, 103 S.Ct. 1042, 75 L.Ed.2d 1 (1983); Reeves, Inc. v. Stake, 447 U.S. 429, 100 S.Ct. 2271, 65 L.Ed.2d 244 (1980)) and that (2) in certain instances a state's favoring or benefiting a government or public entity while treating all private companies without distinction does not discriminate against interstate commerce (Dep't of Revenue of Ky. v. Davis, 553 U.S. 328, 128 S.Ct. 1801, 170 L.Ed.2d 685 (2008); United Haulers Ass'n, Inc. v. Oneida-Herkimer Solid Waste Mgmt. Auth., 550 U.S. 330, 127 S.Ct. 1786, 167 L.Ed.2d 655 (2007)).
Specifically, in White the Supreme Court held that "[]nsofar as the city [of Boston] expended only its own funds in entering into construction contracts [to which the city was a signatory] for public projects, it was a market participant,"
Accordingly, the Supreme Court has by no means made clear that when a state or local government spends money to advance a legitimate public purpose it is free to discriminate against interstate commerce or is considered not to discriminate against interstate commerce. Further, the PSC's actions at issue herein are entirely distinguishable from the actions at issue in the aforementioned cases. Here, the PSC is not: (1) spending its own funds to construct a power plant; (2) entering into a contract to which it is a signatory for the construction of a power plant; (3) owning or operating a power plant; (4) creating a clearly public entity that will own and operate a power plant; and/or (5) issuing bonds to generate state revenue to fund a power plant. To the contrary, the PSC procured a market actor, CPV, to construct, own, and operate a private facility in the interstate energy market and then used its regulatory authority to order other market actors, and ultimately Maryland ratepayers, to provide the Facility with financial backing.
Additionally, the Court does not find any basis for recognizing the general "spending exception" advocated by Defendants. Such an exception would endorse a formalistic approach to the Commerce Clause, long discouraged by the Supreme Court. See W. Lynn Creamery, 512 U.S. at 201, 114 S.Ct. 2205. As the Supreme Court pointed out in the not-too-distant past: "The commerce clause forbids discrimination, whether forthright or ingenious. In each case it is our duty to determine whether the statute under attack, whatever its name may be, will in its practical operation work discrimination against interstate commerce." Best & Co., Inc. v. Maxwell, 311 U.S. 454, 455-56, 61 S.Ct. 334, 85 L.Ed. 275 (1940). In addition to its reluctance in fashioning exemptions that place form over substance, the Supreme Court has flatly cast aside any notion that a state may regulate in a manner that discriminates or burdens interstate commerce so long as it acts for a legitimate public purpose. See, e.g., Or. Waste Sys., Inc. v. Dep't of Envtl. Quality of State of Or., 511 U.S. 93, 100, 114 S.Ct. 1345, 128 L.Ed.2d 13 (1994) (explaining the "purpose of, or justification for, a law has no bearing on whether it is facially discriminatory"); Dean Milk Co. v. City of Madison, 340 U.S. 349, 354, 71 S.Ct. 295, 95 L.Ed. 329 (1951).
Whether any particular state spending activity is subject to, or passes muster under, the dormant Commerce Clause will depend on the nature and contours of that particular scheme. The Court will, therefore, address Plaintiffs' claim that the specific actions taken by the PSC implicate and violate the dormant Commerce Clause.
Defendants contend that the PSC's actions amount to a constitutionally permissible subsidy program not subject to dormant Commerce Clause scrutiny. Plaintiffs assert that the Supreme Court has never explicitly addressed the constitutionality of subsidy programs in connection with the dormant Commerce Clause and that, in any event, the PSC has not directly subsidized anything.
The Supreme Court has yet to decide whether or not state or local government subsidy programs are categorically outside the dormant Commerce Clause. See Camps Newfound/Owatonna, Inc. v. Town of Harrison, Me., 520 U.S. 564, 589, 117 S.Ct. 1590, 137 L.Ed.2d 852 (1997) (explaining that there was no need to address the permissibility of a state subsidy under the dormant Commerce Clause because the law at issue was a tax exemption, which, although having the same effect as subsidy, is constitutionally distinct under Supreme Court jurisprudence); W. Lynn Creamery, 512 U.S. at 199 n. 15, 114 S.Ct. 2205. However, the Supreme Court has made several statements with respect to subsidies and the dormant Commerce Clause. For instance, in W. Lynn Creamery, the Supreme Court stated in dicta that "[a] pure subsidy funded out of general revenue ordinarily imposes no burden on interstate commerce, but merely assists local business." 512 U.S. at 198-99, 114 S.Ct. 2205 (holding that a pricing program consisting of a subsidy and a nondiscriminatory tax on all dairy farmers violated the dormant Commerce Clause because the tax was effectively imposed only on out-of-state dairy farmers). In a case involving a discriminatory tax scheme, the Supreme Court stated that:
At most, the Supreme Court's statements regarding subsidies suggest that a "pure [state or local government] subsidy funded out of general revenue" or "direct subsidization of domestic industry" by a state or local government is generally permissible under the Commerce Clause.
In the instant case, the PSC is not directly funding or providing pecuniary aid to a domestic business through general taxes, municipal bonds, or some other
Accordingly, the Court finds the PSC's actions cannot be characterized as a direct subsidization of the construction and operation of a local generation facility, irrespective of whether direct subsidies would be permissible under the Commerce Clause.
Defendants assert that the PSC, on behalf of the Maryland ratepayers, is a "financier" of a new generation facility and thus should be considered a market participant in the market for new generation facilities whose actions are therefore not subject to the dormant Commerce Clause. Plaintiffs assert the market participant doctrine is inapplicable because the PSC is not buying or selling anything in the new generation market.
The market participant exception permits a state to discriminate against interstate commerce and prefer its own citizens when it acts as a participant in the market, and not as a regulator. See Hughes v. Alexandria Scrap Corp., 426 U.S. 794, 802, 809-10, 96 S.Ct. 2488, 49 L.Ed.2d 220 (1976) (finding that a law giving "Maryland processors an advantage over ... non-Maryland processors in the competition for bounty-eligible hulks" was not subject to the dormant Commerce Clause where Maryland had acted as a market participant in using state monies to create and fund the "bounties" and concluding that the state was free to favor its own citizens in receiving such bounties). The Supreme Court has explained that the market participant exception makes "good sense" because "the Commerce Clause responds principally to state taxes and regulatory measures impeding free private trade in the national marketplace. There is no indication of a constitutional plan to limit the ability of the States themselves to operate freely in the free market."
Under the Generation Order and the CfD, the PSC is not buying, selling, or directly paying for anything in the new generation resource market. The CfD requires the generation facility to sell its energy and capacity to PJM in the PJM Markets. As the evidence at trial demonstrated, PJM sells the energy and capacity that it purchases from generation resources to LSEs within the PJM region, including the Maryland EDCs, who then resell the energy and capacity to Maryland end-use customers. With respect to "payment," the PSC is not a signatory to the CfD; that compensation scheme is between the generation facility and the Maryland EDCs. The EDCs have PSC authorization to pass on losses and gains under the CfD to Maryland ratepayers who pay the EDCs for retail electric sales. Under this scheme, the PSC is not acting as a proprietor or even directly participating in the free market or in a market it created, and therefore is not entitled to be treated as a private actor procuring a new generation facility for purposes of the Commerce Clause. Cf. Brooks v. Vassar, 462 F.3d 341, 357 (4th Cir.2006) (finding that where Virginia elected to sell alcohol from state-owned and state-operated stores, it was a participant in the alcohol retail market and therefore could elect not to sell out-of-state wines at its stores without dormant Commerce Clause concerns). Rather, as the face of the RFP makes clear, the PSC is acting as a regulator of electric distribution companies. See P.2 (2011 RFP) at 1 n. 1 (citing regulatory authority relied upon by PSC in issuing the RFP). The fact that this regulatory action may have the "effect of subsidizing" the operation and construction of a local generation facility, "does not transform it into a form of state participation in the free market." New Energy, 486 U.S. at 277, 108 S.Ct. 1803.
Accordingly, the Court finds the PSC's actions do not fall within the market participant exception.
Defendants assert that the PSC's actions cannot give rise to a dormant Commerce Clause claim because Congress expressly authorized the states to regulate freely the siting of generation facilities within each respective state in Section 201(b)(1) of the Federal Power Act. 16 U.S.C. § 824(b)(1). Plaintiffs contend that Defendants have failed to meet their burden of demonstrating a clear intent on behalf of Congress to permit states to discriminate against interstate commerce.
In exercising its authority under the Commerce Clause,
Section 201(b)(1) of the FPA provides, inter alia, that FERC "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." 16 U.S.C. § 824(b)(1). In examining the particular part of Section 201(b)(1) that references states' existing lawful authority over hydroelectric energy, the Supreme Court concluded that "§ 201(b) simply saves from pre-emption under Part II of the Federal Power Act such state authority as was otherwise `lawful'" and that "[n]othing in the legislative history or language of the statute evinces a congressional intent `to alter the limits of state power otherwise imposed by the Commerce Clause.'" New Eng. Power Co. v. New Hampshire, 455 U.S. 331, 341, 102 S.Ct. 1096, 71 L.Ed.2d 188 (1982) (citation omitted). As later recognized by the Supreme Court: "Our decisions have uniformly subjected Commerce Clause cases implicating the Federal Power Act to scrutiny on the merits." Wyoming, 502 U.S. at 458, 112 S.Ct. 789.
The Court finds Defendants have failed to demonstrate a clear and unambiguous intent on behalf of Congress to permit states to discriminate against interstate commerce in connection with the siting of generation facilities within a state.
The Court has found that the PSC's actions challenged by Plaintiffs do not fall within an established or recognized "exception" to the dormant Commerce Clause. As a result, "the Commerce Clause stands as constitutional limitation on the means by which [the PSC] can constitutionally seek to achieve [its] goal" of incentivizing the development and operation of a private local generation facility. See Bacchus Imports, 468 U.S. at 271, 104 S.Ct. 3049.
Plaintiffs bear the burden to demonstrate that the Generation Order "`discriminates [against interstate commerce] facially, in its practical effect, or in its purpose.'" Yamaha Motor Corp., 401 F.3d at 567 (alteration in original) (citation omitted). If Plaintiffs make such a showing, then the Generation Order will be struck down unless Defendants demonstrate "both that the statute `serves a legitimate local purpose [unrelated to economic protectionism],' and that this purpose could not be served well by available nondiscriminatory means." Maine, 477 U.S. at 138, 106 S.Ct. 2440 (citation omitted). However, if Plaintiffs demonstrate that the Generation Order "amounts to simple economic protectionism, a `virtually per se rule of invalidity' has [been] applied" by the Supreme Court. See Wyoming, 502 U.S. at 454-55, 112 S.Ct. 789 (1992) (citation omitted).
The fact that the locational requirement is defined as "SWMAAC," which includes the District of Columbia and only part of Maryland, does not "insulate" the Generation Order from Plaintiffs' contention that by virtue of the locational restriction in the RFP, the PSC affirmatively discriminated against interstate commerce. See C & A Carbone, 511 U.S. at 391, 114 S.Ct. 1677
The Court finds that there was little, if any, realistic possibility that the generation facility in question would be located in the District of Columbia. Mr. Massey testified that about 98% of SWMAAC geographically is within Maryland. Tr. Mar. 6(AM) at 37:16-18 (Massey). In addition, evidence as to the availability of useable sites in the District of Columbia, established a high degree of improbability — if not impossibility — that an acceptable facility could be located there. Moreover, the RFP required any proposal to include a "[d]escription of the reliability and direct economic benefits to Maryland ratepayers as a result of the Generation Capacity Resource" and provided that in scoring bids, 2.5% of the non-price score consisted of the "benefits to the State of Maryland." P.2 (2011 RFP) RFP at 10, 14-15 (emphasis added). In any event, even if the facility realistically could have been located in the District of Columbia rather than Maryland, this fact would have no bearing on the affirmative discrimination claim.
The Court finds that the PSC's regulatory action would be repugnant to the dormant Commerce Clause if it discriminates against economic interests outside a particular zone of the PJM region.
Plaintiffs assert that the evidence establishes that the Generation Order discriminates against interstate commerce on its face and in its practical effect. Plaintiffs contend that the SWMAAC locational requirement treats in-state and out-ofstate economic interests differently, "the former benefitting from exclusive rights to participate in the RFP and the latter precluded from participation."
The dormant Commerce Clause "prevents a State from `jeopardizing the welfare of the Nation as a whole' by `plac[ing] burdens on the flow of commerce across its borders that commerce wholly within those borders would not bear.'" Am. Trucking Ass'ns, Inc. v. Mich. Pub. Serv. Comm'n, 545 U.S. 429, 433, 125 S.Ct. 2419, 162 L.Ed.2d 407 (2005) (alteration in original) (citation omitted). Precluding this type of state action enforces the principle that "[t]he mere fact of nonresidence should not foreclose a producer in one State from access to markets in other States." Granholm v. Heald, 544 U.S. 460, 472, 125 S.Ct. 1885, 161 L.Ed.2d 796
H.P. Hood & Sons, Inc. v. Du Mond, 336 U.S. 525, 539, 69 S.Ct. 657, 93 L.Ed. 865 (1949).
Discrimination for purposes of the dormant Commerce Clause "simply means differential treatment of in-state and out-ofstate economic interests that benefits the former and burdens the latter." Or. Waste Sys., 511 U.S. at 99-100, 114 S.Ct. 1345 (holding that a greater surcharge on disposal of in-state waste than on disposal of out-of-state waste facially discriminated against interstate commerce). For instance, states may not "provid[e] a direct commercial advantage to local business." Nw. States Portland Cement Co. v. Minnesota, 358 U.S. 450, 458, 79 S.Ct. 357, 3 L.Ed.2d 421 (1959). "Permitting the individual States to enact laws that favor local enterprises at the expense of out-of-state businesses `would invite a multiplication of preferential trade areas destructive' of the free trade which the Clause protects." Boston Stock Exch. v. State Tax Comm'n, 429 U.S. 318, 329, 97 S.Ct. 599, 50 L.Ed.2d 514 (1977) (citation omitted). The Supreme Court has considered states to have impermissibly favored in-state economic interests over out-of-state economic interests by: (1) providing only tax credits for in-state sales of products actually produced in-state, New Energy, 486 U.S. at 271, 108 S.Ct. 1803; (2) precluding out-of-state producers from shipping products directly to in-state consumers, Granholm, 544 U.S. at 473-74, 125 S.Ct. 1885; and (3) giving property tax exemptions to in-state entities that primarily serve state residents but not to instate entities that principally serve interstate clientele, Camps Newfound/Owatonna, 520 U.S. at 576-77, 117 S.Ct. 1590.
The Court finds that Plaintiffs have failed to prove that the SWMAAC locational requirement is facially discriminatory for purposes of the dormant Commerce Clause.
Though the PSC has exercised its regulatory power to create and sustain another competitor in the wholesale energy market through indirect subsidization, the fact that the PSC limited its financial backing to a yet-to-built facility in SWMAAC does not equate to affirmative discrimination against interstate commerce or out-of-state economic interests within the meaning of the dormant Commerce Clause. See generally McBurney, 667 F.3d at 469 (explaining that the dormant Commerce Clause "`does not purport to ... protect the participants in intrastate or interstate markets, nor the participants' chosen way of doing business'" (alteration in original) (citation omitted)).
Relying on Alliance for Clean Coal v. Miller, 44 F.3d 591 (7th Cir.1995), Plaintiffs assert the SWMAAC "locational requirement discriminates against out-of-state commerce [because] it effectively displaces imported power with locally produced power." Pls.' Post-Trial Br. [Document 144] at 64. However, the Seventh Circuit's decision in Alliance for Clean Coal does not stand for the broad proposition that displacing imported energy discriminates against interstate commerce. In Alliance for Clean Coal, Illinois passed a law that, while not compelling all in-state coal burning generators to burn high-sulfur coal mined in Illinois, implemented several statutory mechanisms
Furthermore, the evidence does not support the claim that the Generation Order will discriminatorily displace imported power. The Generation Order will add
The Court does not find persuasive Plaintiffs' position that the SWMAAC locational restriction discriminates against interstate commerce because it requires economic activity to take place in-state to the exclusion of out-of-state sources of the same activity. As discussed supra, the Generation Order does not impose any hindrance on the ability of market participants to buy and sell wholesale energy and related products in the PJM region. Therefore, the existence of a facility in Maryland does not operate to the exclusion of generation facilities outside of SWMAAC, which are still free to supply electric energy to Maryland EDCs through the PJM Markets or bilateral transactions. The decisions relied upon by Plaintiffs in support of their position are inapposite. For instance, in Tri-M Grp., LLC v. Sharp, the Third Circuit struck down a residency requirement as facially discriminatory under the dormant Commerce Clause because the regulatory scheme required a contractor to set up and maintain a permanent office location in the state to be eligible to pay lower apprentice wage rates for work done on in-state public projects. 638 F.3d 406, 412, 413 (3d Cir.2011). The Third Circuit explained this type of in-state presence requirement "forces out-of-state contractors ... to `surrender whatever competitive advantages they may possess' by burdening them with expenditures for a new local operation, or with the payment of increased wages on their contracts." See id. at 427-28. Here, the Generation Order does not require any out-of-state competitor to establish a physical presence in SWMAAC or Maryland to supply electric energy to Maryland residents.
Accordingly, the Court finds that the Plaintiffs have failed to demonstrate that the Generation Order discriminates against interstate commerce either facially, in its practical effect, or in its purpose as a consequence of the SWMAAC locational requirement in the RFP.
Plaintiffs contend that the Generation Order imposes a significant burden on interstate commerce and that there is no evidence in the record demonstrating that the Order was needed to maintain reliability in Maryland. Defendants maintain that Plaintiffs have failed to meet
State action that does not affirmatively discriminate against interstate commerce may nonetheless violate the dormant Commerce Clause if it places an undue burden on interstate commerce. See Yamaha Motor Corp., 401 F.3d at 567. The Supreme Court has noted:
Huron Portland Cement Co. v. City of Detroit, Mich., 362 U.S. 440, 443-44, 80 S.Ct. 813, 4 L.Ed.2d 852 (1960) (alteration in original).
To determine whether state action burdens interstate commerce in violation of the dormant Commerce Clause, courts apply the Pike undue burden balancing test:
Pike v. Bruce Church, Inc., 397 U.S. 137, 142, 90 S.Ct. 844, 25 L.Ed.2d 174 (1970) (internal citation omitted). The undue burden test is less scrutinizing than the test for affirmatively discriminatory state actions. See Yamaha Motor Corp., 401 F.3d at 567.
As discussed herein, Maryland has a legitimate interest in ensuring that Maryland residents have available to them an adequate and reliable supply of electric energy. Presumably,
Even if the Generation Order could be viewed as placing or imposing some burden on interstate commerce, the burden would be de minimis, and thus, not clearly excessive in relation to the benefits to Maryland. The soundness of the PSC's reasoning in choosing to limit the RFP to generators physically located within SWMAAC can, like the rationale for most regulatory actions, be the subject of reasonable debate. However, the rationale reflected in the Generation Order and related materials is not so irrational as to be
Accordingly, the Court finds that Plaintiffs have failed to demonstrate that the Generation Order, as a consequence of the SWMAAC locational requirement in the RFP, imposes an undue burden on interstate commerce that is clearly excessive in relation to the putative local benefits.
In Count III, Plaintiffs claim that the PSC deprived them of their federal statutory rights protected by 42 U.S.C. § 1983. To the extent that Plaintiffs have not abandoned that claim, the Court finds it meritless because the Fourth Circuit has "held that the Supremacy Clause is not a source of substantive individual rights that could support an action brought pursuant to Section 1983." Md. Pest Control Ass'n v. Montgomery Cnty., Md., 884 F.2d 160, 162-63 (4th Cir.1989) (per curiam).
For the reasons set forth herein, the Court decides that:
TERM/ACRONYM DEFINITION
PSC Maryland Public Service Commission
Order/Generation Order Order No. 84815 issued by the PSC on April 12, 2012
EDCs Electric Distribution Companies
CfD Contract for Differences entered into by CPV and the
Maryland EDCs pursuant to the Generation Order
FPA Federal Power Act
FERC Federal Energy Regulatory Commission
RTO Regional Transmission Organization
PJM region 13 states and the District of Columbia
PJM PJM Interconnection, LLC
LSE Load Serving Entity, an entity that has state or local authority
to sell electric energy to end-use customers located within the
PJM region
RAA Reliability Assurance Agreement
BRA Base Residual Auction
RPM Reliability Price Model
RTEP Regional Transmission Expansion Plan
FRR Fixed Resource Requirement Alternative
Uprate Action taken by an existing generation facility to expand its
generation capacity
TrAIL Trans-Allegheny Interstate Line, a transmission line
constructed and placed into service by PJM
EQR Electronic Quarterly Report, pursuant to a FERC requirement,
entities that have market-based rate tariffs are required
to file on a quarterly basis a report of all the transactions and
contracts entered into that are subject to the jurisdiction of FERC. Tr. Mar. 7(AM) at 114:16-115:8 (Knight). MOPR Minimum Offer Price Rule PJM Tariff The Open Access Transmission Tariff pursuant to which PJM operates
The named Defendants are the Commissioners of the PSC, sued in their official capacities, Douglas R.M. Nazarian, Harold Williams, Lawrence Brenner, Kelly Speakes-Backman, and Kevin Hughes. On January 8, 2013, after Plaintiffs filed the instant suit, Douglas R.M. Nazarian was appointed to the Maryland Court of Special Appeals.
PJM Interconnection, LLC, 132 FERC ¶ 61,173, 61,870 (2010).
P.2 (2011 RFP), Attachment 8 (Sample CfD) at 35.
