How state-sponsored planning can fit with FERC’s capacity markets.
Craig R. Roach, Frank Mossburg, and Vincent Musco are, respectively, president, managing director, and project director at Boston Pacific Company, Inc., a consulting firm specializing in the electricity and natural gas businesses. Roach was an expert witness in the two federal court cases referenced here, and Boston Pacific managed the Maryland Capacity RFP.
Two cases decided recently in federal court have reignited the long-standing debate over the jurisdictional boundary between federal and state regulation of the electricity business.1 The plaintiffs in both cases argued that because the Federal Energy Regulatory Commission (FERC) had created a capacity market within the PJM regional transmission organization, the states were preempted from playing their traditional role in resource planning. In a companion argument, they claimed such state action would unduly restrict interstate commerce.
The judges in the two U.S. District Courts in Maryland and New Jersey – the two states that were defendants – each ruled in favor of the plaintiffs on the preemption issue. They declared that the efforts of the two states to procure new generation to serve their ratepayers violated the Supremacy Clause of the U.S. Constitution. Our purpose in this article isn’t to analyze or to critique the judges’ decisions; each was thorough and well explained from a legal standpoint. Nor do we speculate on the future of the new generation projects procured by these two state programs. Instead, our purpose is to explain the potential negative policy implications of these rulings going forward.
Preempting the states is a bad idea. Let’s consider four reasons, founded in public policy and economics.
First, only the states have authority under the Federal Power Act to order the construction of new generation capacity to mitigate long-term risks. Such risks include delays in building major transmission facilities, sudden and substantial retirements of existing power plants (often in the face of new environmental regulations), abrupt changes in load (especially as we come out of the Great Recession), the need to accommodate intermittent generation by solar and wind facilities, and the failure of the PJM capacity market to attract a diversified portfolio of resources in transmission-constrained areas. It would be dangerous to take that authority away from the states in the face of these significant risks.
Second, if the logic of the plaintiffs’ arguments is carried forward it could wipe away a broad swath of state programs. The logic is that states are preempted when their programs “affect” or alternatively “set” prices in wholesale markets. The latter argument was what both judges accepted in ruling that the Supremacy Clause had been violated.2 Yet since almost any state program will affect supply or demand, all could be said to “affect” wholesale prices. Moreover, the policy structures of the Maryland and New Jersey programs that were challenged by the plaintiffs were no different from many other widely accepted state programs that also happen to “set” prices. The policy structure is first to say that the state wants more of a certain kind of resource, then to offer a price guarantee to ensure that resource gets built, and to insulate the builder from the volatility of short-term prices in FERC-approved markets.
Third, the short-term products solicited in the FERC-approved capacity market are fundamentally different from the long-term products solicited through state-run competitive procurements. The PJM capacity market asks for a one-year commitment only, while Maryland and New Jersey were asking for 15 years or more. Plus, the states were requiring that bidders build new generation facilities and that their prices be fixed (in part) for that 15-(plus)-year term. Different products mean different markets, but the two can coexist. Short-term and long-term markets coexist in many businesses despite the fact that one market may affect the price in the other market; the short-term housing rental and long-term housing sale markets offer a good analogy, as do short and long-term bond markets.
Fourth, states are responding appropriately to FERC’s market design. If interstate commerce is influenced in any way, it’s the result of the locational pricing required by FERC, not the alleged parochial interests of the states. In FERC’s capacity market, when transmission constraints or other constraints are binding, the capacity market is balkanized, meaning that different locations have different prices. FERC intended that new generation be built in higher-priced locations – that’s exactly what the states in these cases were doing. To do otherwise would put ratepayers at risk, paying for capacity for which they get no benefit because FERC rules could make it undeliverable. (Neither judge found that the state had violated the Commerce Clause.)3
The bottom line is that a federal-state partnership is the right policy, not federal preemption, as was argued by the plaintiffs in these two cases. Render unto FERC what is FERC’s: the short-term capacity market. And render unto states what is theirs: a long-term capacity procurement tied to resource planning. Short-term and long-term markets can and do coexist and benefit one another. As to potential harm, FERC should remain free to protect its market from uneconomic entry, as it has done already. Moreover, by leaving long-term resource planning to the states, America gets the diversified portfolio of resources it needs. That diversity happens naturally because the states differ in their assessments of the uncertainties the nation faces and in their resource preferences.
But with these two decisions standing in the way, we risk endangering our claim to a truly diversified portfolio of resources.
The Programs and their Aims
The cases in question both centered on states taking action to ensure construction of new generating capacity.
The first case comes from New Jersey, where, in early 2011, out of concern for the lack of new generation in the region, the state legislature created the Long-term Capacity Agreement Pilot Program or LCAPP.4 This program offered long-term (up to 15 years) capacity price guarantees to developers who would build new base-load or mid-merit generating plants. The price guarantee would be used to attract financing for the project and, in return, the developer would construct and operate its plant, selling all of its capacity and energy into the PJM wholesale markets for the duration of the guarantee.
The guarantee took the form of a swap on the price of capacity as set by PJM’s annual capacity auction called the Reliability Pricing Model or RPM. New Jersey ratepayers would guarantee a fixed capacity price to the developer, and, in return, would receive the RPM capacity revenue. These amounts were netted against each other, so the actual money that changed hands would simply equal the difference between the two prices. If the RPM price was higher than the guaranteed fixed price, ratepayers would receive the difference from the developer. If it was lower, they’d pay the difference to the developer. To implement the LCAPP, the New Jersey Board of Public Utilities (BPU) held a competitive procurement in which developers were invited to submit proposals, including a required fixed price for their capacity. The BPU then invited the three lowest-cost bids to sign 15-year swap agreements, each representing a new natural-gas-fired combined cycle facility amounting to about 1,948 MW of new capacity in total.5
The second case began in Maryland, where, in late 2011, the Maryland Public Service Commission (PSC), with concerns similar to those in New Jersey, had issued a “Request for Proposals for Generation Capacity Resources Under Long-Term Contract” (the Long-Term RFP).6 This RFP was open only to new natural gas-fired plants willing to locate in PJM’s Southwest MAAC Locational Deliverability Area (LDA), which includes the service territories of Baltimore Gas & Electric and Pepco. Developers had to construct a new plant and sell into the PJM capacity and energy markets. In return they’d receive a long-term (15-year or more) price guarantee. The price guarantee was slightly different from that offered in New Jersey. In the Maryland RFP, developers proposed a price equal to the total revenue requirement needed per year to build the plant, from which would be subtracted capacity market revenues and profits made from the sale of energy. Again, the actual payments made to or by ratepayers would be the difference between the developer’s guaranteed price and the market revenues received. The PSC issued the RFP and received competing proposals, and ultimately selected the single, lowest-cost proposal to sign to a 20-year agreement for a 661 MW natural gas-fired combined cycle plant.7
The plaintiffs in the New Jersey and Maryland cases included a group of parties, consisting of owners of existing generation and electric distribution companies, who brought claims in a number of different venues. Here, however, we focus only on the two suits in U.S. District Court.8
The plaintiffs claimed that the new supply created by these programs would cause them harm by lowering the prices they receive for capacity and energy from PJM markets. This claim was founded on two primary arguments, each centered on the issue of federal preemption.
First, they argued that the state-sponsored programs were unlawful under the Supremacy Clause because the FERC has “occupied the field” of wholesale energy and capacity sales by creating markets for both, and that, given these FERC markets, states are preempted. The plaintiffs said the Maryland and New Jersey programs were unlawful specifically because they’d “affect” the price of wholesale capacity and energy in FERC markets.9 The plaintiffs further refined this claim to contend that the programs actually “set” the wholesale price for capacity and energy by replacing the federal rate with a state-determined price.10 Second, they argued that these programs were unlawful under the Commerce Clause because they either explicitly (in Maryland) or implicitly (in New Jersey) restricted suppliers to certain geographical areas.11
In each case, in wholly separate decisions, the district court judges ruled in favor of the plaintiffs on the issue of the Supremacy Clause.12 In Maryland, the judge found that the Maryland procurement violated the Supremacy Clause of the U.S. Constitution because it “set” prices for sales of wholesale capacity and energy,13 and in New Jersey, the judge concluded the same.14 We will leave it to others to weigh these arguments from a legal standpoint. However, from our view as experts in economics and public policy, the arguments made by plaintiffs were unfounded and could have negative consequences for a host of state actions. Below we detail our four major concerns.
States Face Long-Term Risks
Our first concern is that states will lose their long-held authority to order the construction of new generation – authority that no one else has under the Federal Power Act, including FERC.15 To understand why a state, even one that participates in a broader wholesale market like PJM, might order the construction of new generation, it helps to understand the real-world long-term risks that states face. These include the risks of: a) delayed transmission construction; b) large-scale generation retirements; c) abrupt changes in load forecasts, and d) the need to accommodate increased renewable generation.
Maryland and New Jersey face many of the same risks. Both states rely heavily on imports of energy to meet their needs and, as such, are very much at risk for delays in the construction of new transmission lines. In fact, the motivation for Maryland’s Long-Term RFP occurred back in 2007 when PJM officials warned the state that a delay in the construction of two major lines (the TrAIL and PATH lines) could put the state at risk for shortfalls of up to 1,500 MW by 2012.16 The TrAIL line eventually was energized in 2011, but the PATH line was cancelled by PJM.17 New Jersey faced a similar situation. In 2009, PJM officials warned the state of reliability criteria violations by 2012 if a new transmission line (the Susquehanna-Roseland line) wasn’t completed by 2012.18 Officials from Public Service Electric & Gas raised the possibility of brown-outs or rolling black-outs if the line wasn’t completed on time.19 Due to permitting issues, the line was delayed, and is now due to be in service by 2015.20
Second, both states rely on an aging fleet of generators at risk for retirement. New Jersey is expecting about 3,100 MW to retire by the middle of 2015; this represents about 18 percent of the existing capacity in the state.21 These retirements are driven by age and environmental restrictions. About 68 percent of these announced retirements in New Jersey are called High Energy Demand Day or HEDD units – older generators that have restricted operating ability because of environmental performance.22 (See Figure 1.) Maryland gets about 60 percent of its in-state generation from coal-fired units, and roughly two-thirds of Maryland’s capacity is more than 30 years old.23
Third, both states are subject to swings in load forecasts that can be quite substantial. For example, the Maryland state-wide forecast peak demand for the year 2015 dropped more than 1,300 MW – nearly the size of three new combined cycle plants – between the years 2009 and 2010. Between 2010 and 2011, the peak forecast for the same year increased 452 MW – about the size of a new combined cycle plant.24 These swings are more problematic when we consider that it takes at least three years to construct a new base or mid-merit power plant.
Fourth, both states have aggressive renewable portfolio standards. These standards have brought forth – and will continue to bring forth – a great deal of intermittent resources whose varying levels of electric generation must be accommodated by other power plants; new natural gas-fired combined cycle plants are considered to be the best to provide such accommodation. Renewables can cause reliability problems, too. For example, in 2011 PJM found that 28,500 MW of renewable resources must be added to the system to meet RPS obligations by 2020,25 and that such additions could move up the first occurrence of NERC thermal criteria violations for the transmission system by as many as five years.26
We note that neither state has experienced major reliability problems thus far – mostly due to the recession, which significantly reduced demand, but also due to operational changes made by PJM.27 Nonetheless, when decision-makers hear about blackouts in one year, and then are told not to worry the next, it doesn’t give them comfort. Commissioners, as decision-makers, don’t think that a significantly changed forecast means the forecast is getting more accurate. Instead, they see changing forecasts as indicative of the uncertainty of the future. In other words, changing forecasts don’t remove risk for a decision-maker, they reveal risk.
In addition, we note that the judge in the Maryland case did affirm the state’s right to regulate the development, type and location of new generation within its boundaries.28 However, at the same time the judge noted that the state couldn’t regulate or “set” the prices ultimately received by the generation for sales of its products on the wholesale market.29 The problem with this restriction arises when power plants must be financed by long-term contracts that guarantee or set the ultimate price received for sales of capacity and energy – or are similarly guaranteed a set amount of cost recovery through rate-base treatment. Without the ability to guarantee a stream of revenue, states can’t guarantee that new generation will receive the financing needed and, therefore, can’t guarantee that new generation actually will be built.
Capacity Markets Serve the Short Term
PJM’s energy and capacity markets haven’t brought forth the diversified portfolio of resources needed to mitigate these four risks in transmission-constrained areas. Despite relatively high capacity prices in both Maryland and New Jersey, PJM’s capacity market had brought little new generation at the time of the state decisions, leading instead to a possible overreliance on limited resources such as demand-side measures.
PJM’s capacity market (the RPM) is designed to send locational price signals as an incentive to generators to locate in transmission-constrained areas. Both states have seen capacity prices that are significantly higher than in the rest of the PJM RTO. From the start of RPM until the issuance of the Long-Term RFP, the average price for SWMAAC capacity had been $177.04/MW-day, as compared to $88.65/MW-day in the rest of the RTO.31 (See Figure 2.) This price premium was supposed to serve as incentive for new generators to build in constrained areas. However, when Maryland made its decision to issue the Long-Term RFP, it had seen only 242 MW of new generation selected in RPM since 2006, and that was fully offset by 788 MW of retirements.32 (See Figure 3.) At the time of the LCAPP decision, New Jersey had seen only about 534 MW of new generation made available through RPM.33 (See Figure 4.)
In contrast, over the same time frame the RPM has attracted a large number of other resources to Maryland and New Jersey that are operationally limited. Since RPM began in New Jersey, about 75 percent of new resources offered in the state have been either demand-response or withdrawn or cancelled retirements.34 In Maryland, when the decision was made to issue the Long-Term RFP, about 1,800 MW of new demand response had cleared in the RPM auction.35 Such operationally limited resources aren’t sufficient to mitigate the long-term risks noted above.
Demand response, for example, has a limited ability to contribute. For example, what PJM terms “limited” demand response only has to show up for a maximum of 60 hours per year;36 in addition, it commits for just one year through RPM, and there’s no guarantee that it will show up in subsequent years. Similarly, many units are categorized as deferred retirements are older units, such as the New Jersey HEDD units; these can run for only a limited time due to environmental restrictions and will have to be shut down in the near future.37 New generation, by contrast, can operate nearly around the clock and, once built, will be around for decades.
States are still responsible for assuring reliability; it’s state commissions that field the (rightfully) angry calls from ratepayers when the lights go out. Given that, with so much uncertainty, it makes a great deal of sense for a state commissioner to turn to a solution based on getting steel in the ground – that is, ordering new generation to be built, as only states can do.
Other Endangered State Programs
Our second concern with the plaintiff’s preemption argument is that it could wipe away a broad array of state programs, many of which might not appear threatened by these two decisions at first blush.
The plaintiffs in the two cases each argued that states can’t undertake any program which a) “affects” prices in a federal market; or b) “sets” a price for sales into a federal market by substituting a state rate for a federal rate. The latter argument is what the judges in both cases cited as the basis for finding that these programs violated the Supremacy Clause.38 To see why this is such a dangerous argument, we need to step back and see how state policies really work. Typically, a state will say, ‘a) I want more of that kind of resource to pursue a particular policy goal; b) here is a guaranteed revenue stream to ensure the chosen resource gets built; and c) while that resource may participate in PJM markets, it receives its guaranteed revenue stream regardless of wholesale market prices.’
This formulation appears again and again in many types of state programs. For example, many states that have deregulated to allow retail choice offer full-requirements service for ratepayers who choose not to choose a competitive electricity supplier.39 This service goes by many names, including “standard offer” and “provider of last resort” service. To select providers of this service, each state will have a competitive procurement in which wholesale bidders offer to serve a percentage of customer needs for a fixed price over several years. Even though these sales are often called sales for resale, state commissions approve the design of the procurement and the selection of winning bidders. Just as in the New Jersey LCAPP and Maryland’s Long-Term RFP, winning bidders can “affect” prices in PJM markets, and in the plaintiff’s logic, “set” a fixed price to be paid no matter what the wholesale PJM price may be. We are concerned that the outcome in the federal court cases could put all of these state efforts at risk.
Another example can also be found in Maryland. In 2008, as part of its response to PJM’s warnings about the transmission construction delays noted above, the Maryland PSC conducted a procurement for demand response that had many of the same characteristics as the Long-Term RFP.40 They invited just a single technology – demand-response products – required them to be located in Maryland, and offered a price guarantee to bidders via a contract for differences. Almost 400 MW of demand response was secured.41 We aren’t aware of objections by FERC or PJM to this procurement.
Connecticut offers a third example. In 2007, the Connecticut Commission, concerned that New England capacity market prices had been at the cap of $14,000/MW-month, issued a procurement for new, in-state capacity that was almost identical to the procurements at issue here.42 It invited bids for peaking capacity that must be located in Connecticut. Winning bidders had to sign a contract to build a new plant and sell into wholesale markets, turning over all their revenues in exchange for a price guarantee. The procurement resulted in three new peaking facilities being built, about 500 MW of new capacity.43 Again, we aren’t aware of any objections.
A fourth example is the use of renewable portfolio standards, or RPS. Twenty-nine states and the District of Columbia have RPS44 that dictate how much of the electricity supply must be generated by specific technologies. These jurisdictions encourage compliance with RPS through the use of renewable energy credits (RECs), which are given to renewable resources for generating power. RECs in effect set a price floor for renewable supply. What’s more, many states have long-term procurements for renewable supply which provide the type of long-term price guarantees that were offered in the Maryland and New Jersey procurements being challenged by the plaintiffs.
Lastly, a fifth example can be found in traditionally-regulated states that supply the PJM market. For example, in Virginia, Dominion received approval from the Virginia Corporation Commission to construct a new combined cycle facility (the Warren County facility). Dominion was guaranteed a traditional cost recovery, but it will sell into PJM wholesale markets and will credit any market revenue it earns back to ratepayers.45
All of these programs “affect” market prices by affecting supply and demand. All in whole or in part operate to “set” prices, in the plaintiff’s terminology, by offering a fixed revenue stream that insulates the resource from wholesale market prices. If this is no longer allowed, all these programs could be at risk for preemption. In addition, these programs often specify that a “local” product must be offered. For example, the Maryland “Gap” RFP and the Connecticut RFP required in-state location to ensure that the state ratepayers get what they were paying for.
Different Products, Different Programs
Our third concern with the plaintiff’s argument is that it fails to reflect the fact that what the commissions in Maryland and New Jersey are asking for is a different product than that procured in FERC’s wholesale markets. The PJM capacity market asks that a resource be available for one year, three years in the future, so a short-term product is being procured. In sharp contrast, both states are asking for a long-term product with a 15-to-20-year commitment. Moreover, these states ask a lot more from developers who must also actually construct a new power plant, operate that power plant, and offer that plant’s energy and capacity into wholesale markets for those 15 to 20 years.
Since these state programs are asking for a fundamentally different product, they’re creating a different market than FERC – a long-term capacity market tied to resource planning. It’s unreasonable to think that only the short-term market can exist, since short and long-term markets coexist everywhere. For example, in the housing market, there are renters and buyers. These are two different product markets. Buying a house is a long-term product. The buyer gets a guaranteed place to live and a guaranteed price in the form of a mortgage payment. The buyer, however, takes on the added risk of upkeep and a long-term financial commitment. Renting is a short-term product; a place to live isn’t guaranteed beyond the rental contract and neither is the price, and the risks of long-term ownership aren’t taken on. These markets are separate despite the fact that they “affect” each other. Buying a house that was a rental decreases the supply of houses for rent and could increase rental prices. Building too many houses for the long-term buying market could force a crash in the rental market if the new supply is converted into rentals. Despite this, no economist would propose shutting down the house-buying market to preserve a higher-priced rental market.
Wholesale markets are FERC’s jurisdiction, but FERC realizes that state programs can coexist with wholesale markets and has taken measures to protect its wholesale markets. The key protection for the RPM market is the Minimum Offer Price Rule or MOPR. FERC itself has said the MOPR acts to “reconcile” state actions with FERC markets.46 The MOPR scans new resources for below-cost bidding (or uneconomic entry). In practice, it sets a floor price for new gas-fired resources offering into RPM. Individual bidders may submit cheaper bids, but those bids must be reviewed by PJM and the Independent Market Monitor who will review the offers and determine whether or not they’re permissible and based on legitimate costs and revenue projections. The Maryland winning bidder’s unit and two of the New Jersey winning bidder’s units underwent this MOPR cost-review process and were selected to provide capacity in the 2015 and 2016 RPM Auction.
Acting on Price Signals
Our final concern with the plaintiff’s argument is that, by claiming that states can’t have locational requirements or preferences in a procurement, it ignores the fact that states are simply responding to FERC’s wholesale market design. With electricity, resources in one geographic location can’t serve everywhere at every moment because of constraints on the transmission system. PJM wholesale energy and capacity markets acknowledge this in their market design. When an area becomes constrained, it balkanizes; it has a separate price from other areas and, more importantly, new supply outside the constrained area can’t serve load in that constrained area. Because of this, it makes sense for state programs to ask for in-state supply so as to avoid paying for a resource from which ratepayers might not receive benefit. Otherwise, a state may end up paying twice for capacity; first, for the resource it selected in the competitive state-run RFP, and second, for the same amount of capacity from the PJM market.
An example might help illustrate how a state, if it ignores PJM’s locational price signals, could end up paying twice for capacity. Consider a scenario in which Maryland holds an RFP for new capacity and awards a contract for differences to a generator located in Maryland. The contract for differences price is $200/MW-day. Then assume that Maryland is a region within PJM that’s “constrained,” meaning it can’t import incremental capacity from outside due to transmission constraints, and that the clearing price for capacity in Maryland is $180/MW-day. Under the contract for differences, the Maryland ratepayers would pay the generator $20/MW-day and purchase capacity from PJM at $180/MW-day.
Now assume, in the alternative, that the winning bidder is located in western Pennsylvania, outside of the constrained region, where the clearing price for capacity is $120/MW-day. Under this scenario Maryland ratepayers again would have to cover the rest of the guaranteed contract for differences price, now $80/MW-day. In addition, because of constraints, the capacity of the western Pennsylvania generator isn’t actually serving Maryland load under PJM rules. Since the new generation is no longer in Maryland, the area must turn to higher-cost resources, raising the clearing price for capacity in Maryland to $195/MW-day. Thus, Maryland ratepayers pay a total of $275 – the $80 payment under the contract for differences plus the $195 capacity price. In this scenario the Maryland ratepayers pay for a resource in Pennsylvania that they don’t see the benefit of. This result could have been avoided simply by requiring the resource to locate in Maryland.
States must be allowed to respond to the PJM and FERC rules that create the incentive to locate capacity where it’s needed most so the states can avoid forcing its ratepayers to pay too much for capacity. The states are only playing by the rules that FERC created.
While the courts have, for now, accepted the plaintiff’s arguments, we hope that all parties will understand the risks that states face. States are in the best position to judge the risk tolerance of their ratepayers and each state can make its own assessment of how much to pay to mitigate the risks it faces.
States of course will take different paths. Massachusetts – faced with circumstances similar to those in Maryland and New Jersey – recently decided not to conduct a long-term capacity procurement.47 More broadly, because of such difference among states, allowing the states to use long-run capacity procurements tied to resource planning will ultimately give America what it needs most: a diversified portfolio of resources to address the major uncertainties we face going forward as a nation.
1. “Memorandum of Decision,” Case 1:12-cv-01286MJG, In the U.S. District Court for the District of Maryland, Sept. 30, 2013; “Memorandum,” Civil Action No. 11-745, In the U.S. District Court for the District of New Jersey, Oct. 11, 2013.
2. “Memorandum of Decision,” Case 1:12-cv-01286MJG, In the U.S. District Court for the District of Maryland, Sept. 30, 2013, 111-112; “Memorandum,” Civil Action No. 11-745, In the U.S. District Court for the District of New Jersey, Oct. 11, 2013, 54.
3. “Memorandum of Decision,” Case 1:12-cv-01286MJG, In the U.S. District Court for the District of Maryland, Sept. 30, 2013, 113; “Memorandum,” Civil Action No. 11-745, In the U.S. District Court for the District of New Jersey, Oct. 11, 2013, 64-65.
6. “Notice of Approval of Request for Proposals for New Generation to be Issued by Maryland Electric Distribution Companies,” In the Matter of Whether New Generating Facilities Are Needed to Meet Long-Term Demand for Standard Offer Service (Case No. 9214), Maryland Public Service Commission, Sept. 29, 2011.
7. Maryland Public Service Commission, “Order No. 84815,” In the Matter of Whether New Generating Facilities Are Needed to Meet Long-Term Demand for Standard Offer Service (Case No. 9214), April 12, 2012 (published by Public Utilities Reports at 297 PUR4th 336).
8. “Complaint for Declaratory and Injunctive Relief,” Case 1:12-cv-01286MJG, In the U.S. District Court for the District of Maryland, April 27, 2012; “Complaint for Declaratory and Injunctive Relief,” Case 3:11-cv-00745, In the U.S. District Court for the District of New Jersey, Feb. 9, 2011.
9. “Complaint for Declaratory and Injunctive Relief,” Case 1:12-cv-01286MJG, In the U.S. District Court for the District of Maryland, April 27, 2012, pp. 5-6, 30-31; “Complaint for Declaratory and Injunctive Relief,” Case 3:11-cv-00745, In the U.S. District Court for the District of New Jersey, Feb. 9, 2011, pp. 3-6, 25-27, 30.
11. “Complaint for Declaratory and Injunctive Relief,” Case 1:12-cv-01286MJG, In the U.S. District Court for the District of Maryland, April 27, 2012, 34-36; “Complaint for Declaratory and Injunctive Relief,” Case 3:11-cv-00745, In the U.S. District Court for the District of New Jersey, Feb. 9, 2011, 31-33.
12. “Memorandum of Decision,” Case 1:12-cv-01286MJG, In the U.S. District Court for the District of Maryland, Sept. 30, 2013, 147; “Memorandum,” Civil Action No. 11-745, In the U.S. District Court for the District of New Jersey, Oct. 11, 2013, 65.
15. “Memorandum of Decision,” Case 1:12-cv-01286MJG, In the U.S. District Court for the District of Maryland, Sept. 30, 2013, 8; “Memorandum,” Civil Action No. 11-745, In the U.S. District Court for the District of New Jersey, Oct. 11, 2013, 14-15.
16. “Report on the Evaluation of a Draft Request for Proposals for Generating Capacity Resources Under Long-Term Contract,” In the Matter of Whether New Generating Facilities Are Needed to Meet Long-Term Demand for Standard Offer Service (Case No. 9214), Boston Pacific Company, Jan. 23, 2012, 1-2.
17. “2010 Regional Transmission Expansion Plan Executive Summary,” PJM Interconnection, Feb. 28, 2011, 5 & 12; PJM Interconnection, L.L.C., “Comments,” In the Matter of Whether New Generating Facilities Are Needed to Meet Long-Term Demand for Standard Offer Service (Case No. 9214), Jan. 13, 2012.
18. “Pre-filed Direct Testimony of Steven R. Herling on Behalf of Public Service Electric and Gas Company in Support of Susquehanna-Roseland Transmission Line Project,” In the Matter of the Petition of Public Service Electric and Gas Company for a Determination Pursuant to the Provisions of N.J.S.A. 40:55D-19 (Docket No. EM09010035), Jan. 12, 2009, 4.
19. PSE&G warned New Jersey of blackouts if Susquehanna-Roseland wasn’t built on time: “If the [Susquehanna-Roseland] Project is not placed into service in 2012 … there will be overloads on critical circuits in the region, and PJM and the transmission owners may need to implement emergency operating procedures, such as reducing transmission system voltages (‘brown-outs’) or implementing rolling black-outs for network transmission service customers, in order to manage operating conditions.” See Pre-filed Direct Testimony of Esam A.F. Khadr on Behalf of Public Service Electric and Gas Company in Support of Susquehanna-Roseland Transmission Line Project, In the Matter of the Petition of Public Service Electric and Gas Company for a Determination Pursuant to the Provisions of N.J.S.A. 40:55D-19 (Docket No. EM09010035), Jan. 12, 2009, 22.
21. “Future Deactivations,” PJM Interconnection, last modified July 26, 2013; “2014/2015 RPM Resource Model,” PJM Interconnection, Jan. 31, 2011; “2012 Quarterly State of the Market Report: January through September,” PJM Interconnection, Nov. 15, 2012, p. 226, sec. 11, tables 11-14; “2012 Regional Transmission Expansion Plan Report,” PJM Interconnection, Feb. 28, 2013, Book Five, sec. 8.
22. “Future Deactivations,” PJM Interconnection, last modified July 26, 2013; “2014/2015 RPM Resource Model,” PJM Interconnection, Jan. 31, 2011; PJM Interconnection, “2012 Quarterly State of the Market Report: January through September,” p. 226, sec. 11, tables 11-14.; “2012 Regional Transmission Expansion Plan Report,” PJM Interconnection, Feb. 28, 2013, Book Five, sec. 8.
23. “Report on the Evaluation of a Draft Request for Proposals for Generating Capacity Resources Under Long-Term Contract,” In the Matter of Whether New Generating Facilities Are Needed to Meet Long-Term Demand for Standard Offer Service (Case No. 9214), Boston Pacific Company, Jan. 23, 2012.
24. “Report on the Evaluation of a Draft Request for Proposals for Generating Capacity Resources Under Long-Term Contract,” In the Matter of Whether New Generating Facilities Are Needed to Meet Long-Term Demand for Standard Offer Service (Case No. 9214), Boston Pacific Company, Jan. 23, 2012, p. 20, table 7.
28. “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.” “Memorandum of Decision,” Case 1:12-cv-01286MJG, In the U.S. District Court for the District of Maryland, Sept. 30, 2013, 84.
29. “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.” “Memorandum of Decision,” Case 1:12-cv-01286MJG, In the U.S. District Court for the District of Maryland, Sept. 30, 2013, 112.
32. “Report on the Evaluation of a Draft Request for Proposals for Generating Capacity Resources Under Long-Term Contract,” In the Matter of Whether New Generating Facilities Are Needed to Meet Long-Term Demand for Standard Offer Service (Case No. 9214), Boston Pacific Company, Jan. 23, 2012, p. 9, table 3.
33. “Comments of PJM Interconnection, L.L.C.,” In the Matter of the Board’s Investigation of Capacity Procurement Transmission Planning (Docket No. EO11050309), PJM Interconnection, June 17, 2011, 13.
34. “Comments of PJM Interconnection, L.L.C.,” In the Matter of the Board’s Investigation of Capacity Procurement Transmission Planning (Docket No. EO11050309), PJM Interconnection, June 17, 2011, 13.
35. “Report on the Evaluation of a Draft Request for Proposals for Generating Capacity Resources Under Long-Term Contract,” In the Matter of Whether New Generating Facilities Are Needed to Meet Long-Term Demand for Standard Offer Service (Case No. 9214), Boston Pacific Company, Jan. 23, 2012, p. 9, table 3.
37. New Jersey Department of Environmental Project, Division of Air Quality, Control and Prohibition of Air Pollution by Volatile Organic Compounds and Oxides of Nitrogen (R. 2009 d.137), March 26, 2009.
38. “Memorandum of Decision,” Case 1:12-cv-01286MJG, In the U.S. District Court for the District of Maryland, Sept. 30, 2013, 111-112; “Memorandum,” Civil Action No. 11-745, In the U.S. District Court for the District of New Jersey, Oct. 11, 2013, 54.
39. Maryland Standard Offer Service, FirstEnergy and Duke Energy Ohio’s Standard Offer Service, Delmarva Power and Light’s Standard Offer Service, Pepco’s District of Columbia Standard Offer Service; and PPL’s, MetEd’s and PennElec’s Provider of Last Resort.
40. “Commission Staff Report and Recommended Gap RFP to be Issued by Maryland Investor Owned Utilities,” In the Matter of the Investigation of the Process and Criteria for Use in Development of Request for Proposal by the Maryland Investor-Owned Utilities for New Generation to Alleviate Potential Short-Term Reliability Problems in the State of Maryland (Case No. 9149), Maryland Public Service Commission, Dec. 22, 2008.
41. “Memorandum from Kevin Mosier – Data Request,” In the Matter of the Investigation of the Process and Criteria for Use in Development of Request for Proposal by the Maryland Investor-Owned Utilities for New Generation to Alleviate Potential Short-Term Reliability Problems in the State of Maryland (Case No. 9149), March 2, 2009; Maryland Public Service Commission, “Order No. 82511,” In the Matter of the Investigation of the Process and Criteria for Use in Development of Request for Proposal by the Maryland Investor-Owned Utilities for New Generation to Alleviate Potential Short-Term Reliability Problems in the State of Maryland (Case No. 9149), Maryland Public Service Commission, March 11, 2009.
42. DPUC Investigation of the Process and Criteria for Use in Implementing Section 50 of Public Act 07-242-Peaking Generation,” Connecticut Department of Public Utility Control, Decision, Dec. 14, 2007.
45. For approval and certification of the proposed Warren County Power Station electric generation and related transmission facilities under § § 56-580 D, 56-265.2, and 56.46.1 of the Code of Virginia and for approval of a rate adjustment clause, designated as Rider W, under §56-585.1 A 6 of Code of Virginia (Case No. PUE-2011-00042), Commonwealth of Virginia State Corporation Commission, Final Order, Feb. 2, 2012 (published by Public Utilities Reports at 296 PUR4th 148).
46. FERC has made it clear that it believes markets under its jurisdiction can coexist with states’ long-term procurements: “We believe that the MOPR that we accept subject to modification in this proceeding, including the unit-specific review process proposed in PJM’s compliance filing, serves to reconcile the tension that has arisen between policies enacted by states and localities that seek to construct specific resources, and our statutory obligation to ensure the justness and the reasonableness of the prices determined in the RPM.” See: “Order on Compliance Filing, Rehearing, and Technical Conference,” 137 FERC ¶ 61,145, Nov. 17, 2011, ¶ 4.
47. “D.P.U. 12-77,” Investigation by the Department of Public Utilities on its own motion into the need for additional capacity in NEMA//Boston within the next ten years, pursuant to Chapter 209, Section 40 of the Acts of 2012 “An Act Relative to Competitively Priced Electricity in the Commonwealth” and pursuant to G.L.c. 164§ 76, Massachusetts Department of Public Utilities, March 15, 2013.