On December 18, 2019, the Federal Energy Regulatory Commission (FERC) issued an order directing the PJM regional transmission organization (RTO) to expand its Minimum Offer Price Rule (MOPR) as a move to address subsidies to electric power generation resources by states, with certain exemptions. FERC stated that it acted "to protect the competitive capacity market administered by PJM" by requiring PJM to expand its MOPR to apply to any new or existing power generation resource that receives, or is entitled to receive, a state subsidy, unless a FERC-determined exemption applies. FERC initiated a hearing under section 206 of the Federal Power Act (FPA) to make its determination that PJM's Open Access to Transmission Tariff was "unjust and unreasonable," since it did not account for the effect of these subsidies.
RTOs and independent system operators (ISOs) manage the electric transmission systems and the competitive wholesale electric energy markets, under FERC's oversight. RTOs essentially operate as a broker between generation companies that bid to sell power into the wholesale markets, and distribution companies that submit bids to buy power from the markets. To ensure the reliability and timeliness of these transactions, RTOs generally run several markets (including a capacity market) to ensure that enough generation is available to reliably meet peak power demands. Therefore, the dispatch of power plants essentially involves two stages, encompassing the planned commitment of generation to meet projected RTO system demand, and the dispatch of additional or alternative capacity in real time.
In recent years, several states have criticized various aspects of the performance of the competitive markets, especially in areas with transmission congestion (i.e., "load pockets") where high prices for electricity persist. Several proposals, in New Jersey and Maryland in particular, to subsidize generation in these load pockets and opposition to these proposals from energy marketers eventually led to the 2016 Supreme Court decision in Hughes v. Talen Energy Marketing. The Supreme Court decision held that Maryland's program to encourage development of in-state generation was preempted by FERC's exclusive jurisdiction over interstate wholesale electricity rates under 16 U.S.C. §824.
Forward capacity markets are used in some RTOs to ensure that sufficient generation will be available years in the future. As these markets developed, some participants and observers raised concerns that new generators could undermine competitiveness by submitting artificially low bids. In response, some RTOs, including PJM, added the regulatory concept of "Cost of New Entry"(CONE) to represent the estimated cost of building and connecting a reference power plant (typically, a natural gas-fired combustion turbine serving peak loads) to the grid in a particular location. Net CONE represents the revenue a new power generating plant (i.e., a resource) would need to make in the capacity market in its first year, net of other market revenues and CONE.
With declining wholesale electricity prices caused by a combination of flat demand and the entry of low-cost generators (using natural gas, wind, and solar), many coal-fired and nuclear power plants face closure as their operating costs are higher than prices in the wholesale markets. Some states in RTOs have attempted to provide subsidies to help certain types of generation remain competitive, sometimes citing their reliability attributes. Other states in RTOs have sought to "reregulate" certain types of generation, by removing them from the competitive markets.
CONE values are also used to help provide a screen for possible exercise of "buyer-side" market power under an RTO MOPR. Subsidized resources can potentially become "price takers," if such resources have a power purchase agreement or receive some other price subsidy. MOPRs provide a process for RTOs to determine whether low bids from new projects are consistent with a project's costs, and are not, therefore, anticompetitive. MOPRs require new resources to offer at, or above, a floor price (equal to the net CONE for the asset generator type and location), and therefore prevent an artificial depression of capacity market prices.
In 2017, some generators filed a complaint about PJM's market rules arguing that nuclear subsidies and renewable portfolio standard requirements were acting to suppress capacity market prices. Alternatively, some observers argue that the real problem for PJM's capacity market is oversupply. In response to the generators' complaint, PJM filed two market reform proposals at FERC with the first approach comprised of a two-stage annual auction, with capacity commitments determined in stage one of the auction and the clearing price set separately in stage two (capacity repricing). PJM's second approach would have expanded the MOPR to apply to offers from some subsidized resources, subject to certain proposed exemptions (i.e., MOPR-Ex).
FERC rejected PJM's approaches, finding that out-of-market payments threaten the competitiveness of PJM's capacity market, and directed PJM to expand the MOPR to apply to all new or existing resource that can or does receive a state subsidy, unless an exemption applies.
Arguably, at the heart of the debate is a state's authority under the Federal Power Act over in-state generation facilities (16 U.S.C. §§791a–825r), as opposed to FERC's exclusive authority over sales in interstate wholesale electricity markets (16 U.S.C. §824). FERC has ordered PJM to submit a compliance filing by April 2020. There are a number of pending requests for rehearing or clarification of the FERC PJM MOPR order, including a rehearing request from PJM. Some point out that FERC does not consider the relative effect of a subsidy on a potential bid, or have a minimum size of a resource for the MOPR to apply. Existing resources are largely exempted from FERC's order, including those with state subsidies. FERC's order could require future state-subsidized resources to use the MOPR, thus limiting their ability to submit lower-priced bids. In the near term, FERC's order, if implemented, would mostly affect new resources that qualify under state renewable portfolio standards. The capacity market accounts for about 20% of the wholesale price of electricity in PJM, meaning that the loss of capacity market revenues may lead renewable developers to increase their prices.