A decision handed down by the Federal Energy Regulatory Commission (FERC) on a seemingly obscure issue in one regional power market threatens to have far ranging impact on the cost of electricity, the future of state policy, and the ability for advanced energy to compete – and win, as it has been doing – in the marketplace. FERC’s policy change is purportedly intended to address the “price suppression” in competitive wholesale power markets allegedly caused by resources that are supported by state policies like renewable portfolio standards (RPS) and zero emission credit (ZEC) policies. But what FERC’s decision will actually do is limit the ability of advanced energy resources to participate in the nation’s largest electricity market, force customers from New Jersey to Ohio to pay twice for the generating capacity they need, steer funds to existing coal and natural gas power plants that are otherwise redundant, and undermine state policies that are explicitly intended to promote advanced energy deployment. How it will do so is complicated, but potentially devastating to the advanced energy economy that has been steadily growing in the United States.
First, some background. PJM Interconnection, the regional grid operator serving 13 mostly mid-Atlantic states, operates a capacity auction to ensure the region has enough energy resources for reliability purposes. These auctions are held for a one-year period three years in the future. For example, a PJM capacity auction held in May 2020 would procure capacity for the June 2023 to June 2024 delivery year. In general, PJM’s capacity market has historically allowed resources flexibility in how they construct a capacity offer price, including allowing resources to submit low or zero price offers, with all resources that “clear” the market getting paid the highest amount bid by the clearing resources.
However, since its inception, PJM’s capacity market has also included a limited “Minimum Offer Price Rule” (MOPR), which sets a floor price for bids from certain resources. MOPR was originally a narrow rule intended to prevent market manipulation by participants who both pay for capacity purchased in the capacity market and sell capacity (such as large utility holding companies who are load-serving entities paying capacity market charges). Absent the MOPR, these participants could over-build generation and offer it into the capacity market at artificially low prices, with the goal of lowering overall market prices enough to reduce their total capacity payments.. The original MOPR prevented this type of gaming of the market.
For the past several years, existing traditional generators in PJM (generally existing natural gas and coal) have claimed that capacity market prices were being suppressed by the participation of resources that receive revenues under state policy programs, specifically states that enacted Zero Emission Credit policies to compensate nuclear power plants for their emission-free attributes. They asserted that these resources are able to bid artificially low prices in the PJM capacity market because they are guaranteed revenues by state policies, and that these low offers suppress the prices paid to all the power plants that cleared the auctions. These generators eventually filed a complaint at FERC seeking expansion of the MOPR to apply it to more resources receiving revenues under state policy programs. After years of back and forth between PJM and FERC, the Commission finally issued its Order on the PJM MOPR last month.
The December 19 Order requires PJM to expand the application of the MOPR to all new and some existing capacity resources that receive or are eligible to receive “State Subsidies,” unless an exemption applies. FERC defines such State Subsidies broadly, as a direct or indirect payment supported by a state policy that could impact wholesale market prices. This expansive definition appears to sweep in nearly all state policies developed to date to encourage deployment of advanced energy technologies, namely Renewable Portfolio Standards, Energy Efficiency Resource Standards, Renewable Energy Certificate markets, clean energy standards, procurement mandates and targets (including those included in a utility Integrated Resource Plan), and other tools that incentivize investment in these technologies for meeting electric power needs.
FERC justifies this sweeping expansion of PJM’s MOPR on the grounds that all resource and technology types can “impact the competitiveness of the capacity market and the resource adequacy it was designed to address.” FERC specifically rejects PJM’s proposal to exclude energy efficiency resources, explicitly stating that demand response, energy storage, and unspecified “emerging technology” should all be subject to MOPR.
This expansion also includes self-supplied capacity resources owned by vertically integrated utilities and voluntary transactions that include RECs (i.e., corporate procurement of renewable energy), while rejecting a “materiality” threshold, which would have excluded (1) capacity resources of 20 MW or smaller, and (2) capacity resources that receive a subsidy that amounts to 1% or less of their actual or anticipated total revenues from energy, capacity, and ancillary services markets.
FERC exempts from the expanded MOPR most existing resources, including renewable energy, energy efficiency, and the like. The exception is nuclear, with existing power plants now subject to the MOPR. But the MOPR would apply to all of the wider range resources developed and entering into the market going forward.
The December 19 Order directs PJM to establish individual offer floor prices for all types of capacity resource. Here is AEE’s roundup on how advanced energy can expect to be treated:
Wind and Solar: These resources will be required to offer at a floor price equal to Net Cost of New Entry. While PJM must develop and file a precise floor price in compliance with the December 19 Order, PJM’s earlier filings with FERC identified offer floors of $2,489/MW-day for onshore wind, $4,327/MW-day for offshore wind, and $387/MW-day for solar. With recent capacity market clearing prices ranging from $80/MW-day to $220/MW-day, these estimates suggest a significant risk that new wind and solar capacity will not clear in the market.
Demand Response: FERC distinguished between two types of demand response: generation-backed demand response (e.g., demand response supported by behind the meter generation) and non-generation-backed demand response. For generation-backed demand response, FERC appears to require PJM to develop offer floors equal to 100% of the Net CONE for the type of behind-the-meter generation used by the particular demand response resource. For non-generation-backed demand response, FERC accepted PJM’s proposal to determine the offer floor price based on the average of the last three years of demand response offers in the capacity market.
Energy Efficiency: FERC’s Order notes that determining the Net CONE for energy efficiency is difficult. Instead, FERC directs that on compliance, PJM instead “establish objective measurement and verification requirements for new energy efficiency offers and to limit such offers to the verifiable level of savings.” This directive addresses only the amount of capacity new energy efficiency resources may offer and leaves significant uncertainty regarding the offer floor price that will be applied.
FERC provides no additional guidance on how the offer floor price for energy storage capacity should be calculated. As to “emerging technology,” FERC simply requires PJM to develop and file offer floors for “new technologies as they emerge.”
In the proceeding leading up to the new Order, AEE, the Advanced Energy Buyers Group, and others had asked FERC to make clear that voluntary corporate purchases of advanced energy are excluded from the MOPR. FERC did not grant this request. Rather, as noted above, the Order includes “voluntary REC arrangements, meaning those not associated with a state-mandated or state- sponsored procurement process.”
The ruling leaves several questions about how MOPR may impact voluntary purchases, given the variety of contracting structures used to facilitate such transactions. Read together, the rulings suggest that the direct purchase of advanced energy, where the buyer holds and retires any RECs or similar revenue-generating instruments created by the project (rather than selling them in a secondary market), is the structure that is most assured of avoiding application of the MOPR.
So what happens now? We can expect several actions to take place in the coming weeks and months. First, numerous parties, including AEE, will seek rehearing and prepare for judicial review. In the meantime, FERC required PJM to submit a compliance plan within 90 days of the Order’s filing.
The far-reaching nature of this Order will likely bring responses from states as well as other RTOs/ISOs. States with significant state policies supporting existing nuclear power plants, including Illinois, New Jersey, and Ohio, as well as states with existing and emerging clean energy goals, like Maryland and Virginia, are likely to move aggressively to contest FERC’s order and seek alternatives to avoid its impacts. Likewise, both ISO-New England and the New York ISO use a capacity market structures similar to PJM’s. That means the December 19 Order sets a precedent that could be repeated in those markets.
Ultimately, FERC’s major policy change escalates the ongoing clash between state climate and clean energy policies and FERC-regulated wholesale markets. Unless reversed on rehearing or appeal, FERC’s ruling risks excluding advanced energy resources encouraged by state policies from the PJM wholesale market, increasing consumer costs and undermining the state’s valid exercise of their authority to determine the generation mix used to serve retail customers. Rather than attempting to coordinate federal wholesale markets with state energy policies, FERC’s decision to broadly apply MOPR to effectively nullify the impact of state clean energy policies amplifies the need for new wholesale market constructs that better balance valid state energy policy goals with the need to ensure just and reasonable wholesale rates under the Federal Power Act.
For years, AEE has made the case that advanced energy resources face barriers within existing wholesale markets. AEE has also praised FERC for its efforts to remove some of these barriers, as in its 2018 Order 841 requiring regional grid operators to allow energy storage resources to compete in wholesale markets. Unfortunately, in its December Order, FERC has erected a new, and potentially devastating, barrier to advanced energy.
Forcing advanced energy resources to bid at prices that may not reflect their actual economics creates the risk that they will be arbitrarily forced out of PJM’s capacity auction and locked out of the ability to receive capacity market revenues. This result also forces consumers to buy duplicative capacity through the capacity market, raising their costs. More broadly, this FERC ruling undermines pro-advanced energy state policies by potentially depriving these resources of capacity market revenues and boosting such revenues for existing coal and natural gas power plants not subject to the MOPR. AEE will work with allies to fight this latest barrier to fair competition in the nation’s wholesale electricity markets.
For more details and analysis, download AEE’s primer, “Understanding FERC’s ‘Minimum Offer Price Rule’ Order,” by clicking below.