FERC Denies Rehearing of PJM’s Minimum Offer Price Rule but the Issue Remains Far from Settled

May 11, 2020

By Kurt R. Rempe, Fredrikson & Byron and Rao Konidena, Rakon Energy LLC

The Federal Energy Regulatory Commission (FERC) recently issued two orders, available here and here, denying rehearing and providing additional clarification of its new Minimum Offer Price Rule (MOPR). The MOPR stems from a 2016 complaint by a group of merchant generators, lead by Calpine Corporation, that state-subsidized electric generation resources are artificially depressing the capacity market clearing price in the PJM Interconnection (PJM) competitive capacity market. In the PJM capacity market, suppliers offer to be available to provide power and receive capacity payments for that availability regardless of whether they are called upon to provide energy. FERC granted the complaint and implemented a paper hearing to establish a revised MOPR based on stakeholder input that applies to new and existing resources receiving out-of-market payments, regardless of resource type.

The paper hearing culminated in a December 2019 FERC order that directs PJM to expand its existing MOPR from covering new natural gas-fired and combined cycle generators to also covering renewable and low- or zero-carbon resources that receive or are entitled to receive “state subsidies.” FERC broadly defined state subsidies to include any financial benefit from a state or local government or electric cooperative (e.g., zero-emission credits, renewable energy credits (RECs) that are used to comply with renewable portfolio standards programs and state tax abatements). Federal tax credits are not included in the definition. Generators that receive state subsidies, and are not otherwise exempt from the MOPR, must bid into the capacity auction at the net cost of new entry for new resources and the net avoidable cost rate for existing resources, each as defined in the order. FERC concluded that this is required to prevent these resources from offering their capacity at a level that would unfairly drive down the price received by other suppliers participating in the capacity auction. As clarified in the latest orders, the exemptions apply to existing self-supply, demand response, storage and energy efficiency resources as well as resources participating in renewable portfolio standards programs, provided that in each case they have prior to the December 2019 FERC order successfully cleared an annual or incremental capacity auction, have executed an Interconnection Construction Service Agreement, Interconnection Service Agreement, Interim Interconnection Service Agreement or Wholesale Market Participating Agreement, or have any of these unexecuted agreements filed by PJM with FERC. Suppliers that do not qualify for these grandfathering exemptions can submit below-floor bids if they are able to demonstrate that their actual costs are lower than the applicable MOPR price floor through a resource specific review process approved by the Independent Market Monitor, or if they certify annually that they will elect to forgo accepting any state subsidies. The grandfathering exemptions put existing renewable suppliers on an equal footing with “unsubsidized” suppliers but do not apply to nuclear generators.

The latest FERC orders denied rehearing and rejected state jurisdictional arguments that it was intruding on state prerogatives to determine energy resource mix and new generation. FERC also dismissed arguments that the price floor under the new MOPR will prevent new renewable resources from clearing the market, stating that if the state-subsidized resource is not able to clear the capacity market it means that it is not economic without the subsidy. On a positive note, FERC clarified that corporate/voluntary RECs are not state subsidies. However, Commissioner Glick lambasted the order in his dissent arguing that it was “illegal, illogical and truly bad policy.” He also stated that the order “makes clear that voluntary RECs are not out of the woods yet” pointing to footnotes in the order indicating that FERC may revisit this issue in the future and find that these RECs distort the capacity market.

As far as next steps, FERC directed that PJM submit a supplemental compliance filing to the April order by June 1 and it has yet to act on the compliance filing that PJM submitted in March to the December 2019 order. As a result, it is unlikely that PJM will be able to conduct the next Base Residual Auction (BRA) for the 2022-23 delivery years until early next year. After that, PJM stated in its March 2020 compliance filing that it plans to conduct BRAs every six months to get back on schedule.

The MOPR raises a host of issues that are far from settled. Petitions for review are pending before the U.S. Courts of Appeals for the District of Columbia Circuit and the Seventh Circuit. Given the scope of the orders, it may ultimately be decided by the U.S. Supreme Court. As this works through the courts, stakeholders will have to navigate an uncertain environment and negotiate deals with a finger to the wind to predict how this will play out. The appeals do not stay the FERC order, which means there is a chance that the results of future PJM capacity auctions could be overturned retroactively if the courts find that FERC was arbitrary and capricious and overstepped into state jurisdictional territory by sweeping in nearly all state policy tools used to determine their resource mix and encourage the deployment of renewable resources. If the MOPR is upheld, independent power producers may look to locate projects in markets outside of PJM. Capacity payments in other RTOs/ISOs can be much richer than PJM, as indicated by Michigan’s $250 per MW-day capacity prices in the 2020-21 planning year. In addition, states that support renewables could potentially require that their utilities withdraw from RTO/ISOs that have mandatory capacity markets (PJM, ISO-NE and NYISO). Withdrawals will likely place significant costs on ratepayers from market exit fees as well as transmission project costs from PJM’s Regional Transmission Expansion Plan (RTEP) or any other preexisting obligations under the tariff. Withdrawals will also lead to more protracted litigation similar to the hard-fought dispute over whether Duke Energy and FirstEnergy were responsible for costs to construct multi-value projects when they left MISO. Moreover, the composition of the Commission will change if Trump is not reelected. A democratic lead Commission will almost certainly chip away at the MOPR if not overturn it entirely.

Rao Konidena focuses on providing policy and testimony support, business development and training in wholesale energy markets.

Kurt Rempe advises clients on tax, regulatory and commercial issues related to the development, financing, purchase and sale of energy projects