by Roger D. Stark and Daniel R. Simon, Ballard Spahr LLP
A cascade of litigation reveals the contentious issues faced by states trying to develop generation facilities within regional transmission organization-administered capacity markets. Such litigation highlights the significant risks and uncertainties project developers face in working with states trying to develop new generating capacity.
State Actions: The LCAPP Statute and Maryland RFP
PJM Interconnection operates a forward capacity market called the Reliability Price Model (RPM) that is designed to contract a one-year term of reliable electric capacity three years in advance. New Jersey and Maryland have long complained that the RPM fails to provide the long-term revenue certainty necessary to attract new generation in those states.
Now these two states are aiming to attract new generating capacity by launching new initiatives. New Jersey Gov. Chris Christie signed controversial legislation in January 2011 that created a long-term capacity agreement pilot program (LCAPP) to encourage the development of 2,000 MW of new natural gas-fired electric generation facilities in that state. More recently, the Maryland Public Service Commission (PSC) ordered each of the state’s electric distribution companies to issue a request for proposals (RFP) for up to 1,500 MW in natural gas-fired generation in that state. Both programs contemplate:
- Contracts that pay subsidized minimum long-term capacity prices likely to be higher than those currently available from the PJM market, and
- A requirement that participating generators must “clear” (have their bids selected by) the PJM capacity market to receive long-term capacity pricing under the applicable program.
Maryland Gov. Martin O’Malley proposed after the RFP issued that it should allow bids from projects using renewable energy resources, that it require an “apples-to-apples” price comparison among competing resources including renewables, and that it allow bids for utility-owned generation. Thus, the RFP initiative may extend to procurement of renewable resources, which in some cases also might be subject to mitigation under the PJM tariff.
PJM’s Minimum Offer Price Rule
The RPM contains a minimum offer price rule (MOPR) that includes a minimum offer screen designed to prevent the exercise of buyer market power by requiring all new resources to offer capacity at competitive and economic prices. The MOPR allows PJM to mitigate a bid (i.e., revise it upward) if the MOPR analysis shows the bid is uneconomically low, a level currently set at 90 percent of the “net cost of new entry” for natural gas-fired resources.
The requirement in LCAPP and the Maryland RFP that participating generators clear PJM’s capacity market has focused increased attention on the application and scope of the MOPR. Previously, PJM applied the MOPR only for the resource’s first delivery year. Thus, a participating generator’s bid could fail to clear its first capacity year auction (i.e., the MOPR price screen could mitigate its bid to a level above the clearing price), but then could bid zero and clear the auction the next year. The MOPR previously did not apply to certain new resources developed in response to a state mandate to resolve a projected shortfall.
In New Jersey, a group of incumbent generators—and PJM itself—raised concerns that new generation projects selected under the LCAPP might, after one year of mitigation, use zero bids to clear the capacity market for its second and subsequent years of capacity eligibility without economic justification under the RPM construct. If that occurred, they argued, capacity market prices would be artificially and unjustly depressed and incumbent generators would incur losses resulting from a form of buyer-side market manipulation. To avoid this, PJM and the incumbent generators asked the Federal Energy Regulatory Commission (FERC) to approve specific changes to the MOPR.
Litigation in New Jersey, FERC
The incumbent generators filed suit to challenge the constitutionality of the LCAPP statute in federal court in New Jersey. The case raises important questions about states’ rights, interstate commerce, federal pre-emption and the scope of FERC’s statutory authority. Because of its similarity to the LCAPP program, the Maryland RFP could face similar legal or regulatory challenges.
By contrast, litigation at FERC has focused on technical aspects of the MOPR. In a series of MOPR orders, the commission generally accepted with conditions the MOPR amendments proposed by PJM and declined to implement more aggressive proposals submitted by LCAPP opponents. FERC concluded that the MOPR must be applied to new generation until it clears a capacity auction at least once on its own economic merits. According to FERC, this approach will avoid the scenario where a new resource satisfies the MOPR by simply failing to clear the auction for its first eligible capacity delivery year, and thereafter submits uneconomic bids not subject to the MOPR that clear the market, thereby depressing capacity revenues for other market participants. FERC did, however, allow PJM to include a unit-specific review process whereby a new resource could avoid mitigation by demonstrating that its bid is economic because its actual “cost of new entry” would allow it to be competitive if it were required to rely on PJM market revenues.
Numerous parties have appealed the MOPR orders to the 3rd and D.C. Circuit Courts of Appeals.
The MOPR orders and related litigation raise numerous legal and policy questions. For instance, if New Jersey’s LCAPP is invalidated by the federal courts, the ability of states to incentivize construction of new resources (absent higher capacity market clearing prices) could be limited severely. Similarly, a federal court of appeals could reverse FERC’s MOPR orders, which might lead to additional changes to the PJM capacity market rules.
Regardless whether the LCAPP and MOPR orders survive on appeal, several questions remain:
1. How can states lawfully encourage the construction of new generation if capacity market clearing prices remain low? States traditionally have exercised broad discretion to encourage the construction of new generation capacity. Vertically integrated utilities, for instance, often build new generation pursuant to integrated resource plans approved by or opined on by state utility commissions. FERC has vowed not to interfere with state and local policies for development of new capacity but has said it must act when state-subsidized entries artificially depress market price signals. Thus, the extent to which states can encourage new resources to be financed and constructed while RPM clearing prices remain low is unclear.
2. When is a state economic development program subject to mitigation? It remains unclear which state economic incentives are subject to mitigation. In contrast with the MOPR orders, FERC concluded in an analogous case that capacity bids benefiting from New York real estate tax incentives were not subject to mitigation because the tax incentive was granted “as of right” and was not discretionary. Some observers have concluded that FERC’s explanation amounts to a distinction without a difference. More guidance is needed. The final determination on this issue could affect many state programs providing economic development subsidies to attract new generation and could portend momentous changes in the federal and state regulatory balance.
3. Will PJM accept a different pricing methodology to justify bids below the new MOPR price screen? The MOPR orders state that the price screen uses a “nominal levelized” analysis and that new resources submitting unit-specific data need not use the nominal levelized analysis. It is unclear, however, how much flexibility this approach might provide. For example, would it allow a new resource to avoid mitigation by using “back-loaded” financing structures to arrive at a bid below the MOPR screen?
4. What is the test for determining whether a particular renewable resource other than wind or solar is permitted to “zero bid” in an RTO capacity auction? The MOPR orders expressly allow wind and solar projects to zero bid without becoming subject to mitigation based on FERC’s conclusion that neither type of project lends itself to market manipulation. That leaves the rest of the renewable energy project universe (e.g., hydroelectric, geothermal and biomass) wondering whether it can zero bid without being subject to mitigation.
5. Will a longer capacity term address states’ concerns? To incentivize new generating capacity, PJM’s stakeholders have expressed interest in developing a voluntary long-term auction within the RPM. PJM has outlined a proposal for such auctions to occur one month before the current base residual auction for a capacity obligation, which also would obtain capacity three years in advance. Instead of a one-year term, the capacity commitment could be for three-, five- or seven-year terms. Longer capacity obligations anticipate needs further in advance and provide a steady stream of capacity revenues for a longer period. This construct might make financing a new project easier, and PJM has committed to pursuing development of this approach for implementation before May 2013. The voluntary nature of the plan, however, raises questions about PJM’s commitment to the initiative.
Litigation involves risks, and risks often reveal opportunities. In assessing the controversies regarding LCAPP and the Maryland RFP, project sponsors must be mindful of the risks associated with developing projects within organized capacity markets as they seek profitable opportunities to develop new generating capacity.
Roger D. Stark is a partner in Ballard Spahr’s business and finance department and focuses his practices on energy and project finance. Reach him at 202-661-7620 or firstname.lastname@example.org.
Daniel R. Simon is a partner in Ballard Spahr’s business and finance department and a member of the Energy and Project Finance Group and the Climate Change and Sustainability Initiative. Reach him at 202-661-2212 or email@example.com.