Renewables and PJM capacity auctions

Renewables and PJM capacity auctions

February 10, 2020 | By Robert Shapiro in Washington, DC

The Federal Energy Regulatory Commission is likely to hold a rehearing of its controversial decision in late December to require renewable energy and nuclear generators bidding into PJM capacity auctions to bid a minimum offer price.

Four states have threatened to withdraw from PJM and the New England ISO if the order stands.

Many parties, including PJM, have filed substantial rehearing requests. Any rehearing order on the merits would not be issued before the end of February at the earliest and will probably take longer given the number and complexity of the issues.

PJM has still not held its 2019 capacity auction, and the 2020 auction is expected to be delayed. The auctions are for capacity to be supplied three years in the future.

FERC currently operates with only three commissioners. There are two vacancies. It needs at least three to conduct business. Bernard McNamee, one of the remaining three commissioners, said in January that he will leave at the end of June, but he said he would remain until his replacement is confirmed. At least two of the three commissioners must agree on the approach to the capacity auctions.

The December order imposing a minimum offer price has generated significant public opposition from nearly every segment of the non-fossil-fueled resource stakeholders, including renewable power developers, states that have substantial clean energy policies or nuclear power or offshore wind incentives, and ratepayer advocates.

There seems little doubt that the order, if implemented as written, will have the effect, if not the intent, of increasing the costs to ratepayers in PJM states that provide and are committed to provide and maintain significant climate change-related incentives and increase the likelihood of dispatch of coal-fired generation.

Whether it will significantly slow development of renewable energy in the region is less clear, as that may depend on how individual states respond to the capacity market impacts from the order.

PJM is the section of the US utility grid that covers 13 states and the District of Columbia from Pennsylvania, New Jersey, Maryland and Delaware west through the rust belt to parts of Illinois and Michigan.

Minimum offer price

PJM holds annual auctions, known as the base residual auctions or BRAs, to set the capacity prices and the capacity commitments for projects that are lucky enough to be selected in the auction for a future delivery year, typically three years ahead.

There are also intermediate annual auctions, called incremental auctions, that permit PJM and existing or potential suppliers to buy and sell capacity committed in a particular BRA delivery year.

Projects that are subject to the minimum price offer rules, or MOPR, have to offer that minimum price in the auction and run the risk of being shut out of selection if the clearing price is lower than the MOPR.

As a general matter, the order requires bidders that qualify for a state subsidy on a project to bid a minimum offer price in each annual PJM capacity auction, subject to very limited exceptions.

The prior PJM rules included a minimum price rule or MOPR requirement, but only for new gas-fired resources. For the first time, in addition to new gas-fired resources, renewable energy projects, capacity storage projects, demand-side resources and energy efficiency resources qualifying for state subsidies will have to bid a minimum offer price in each capacity auction.

Also, for the first time, all existing projects with such subsidies will have to clear the market each year under the new default rate as well. Previously, new projects subject to the MOPR requirement had to clear in only one auction and then were deemed existing projects and were permanently exempted from the MOPR requirements thereafter.

Further, for the first time, “self-supply resources” will have to meet the MOPR requirement, subject to very limited exceptions. “Self-supply resources” are generating facilities belonging to vertically integrated utilities, electric cooperatives and municipal entities that the utility uses to supply electricity to its own retail customers.

In addition, the minimum offer price will now be higher than before. It will be set for new projects at 100% of the net cost of new entry or “Net CONE,” rather than at 90% of Net CONE. This will create a higher hurdle for subsidized projects (and gas-fired projects) to be selected for capacity in the capacity auction. The Net CONE is based on a levelized single year of revenues needed to recover capital and fixed costs of a new combustion turbine, adjusted for variable operating costs, net of expected revenues for energy and ancillary services.

If the clearing price in the annual auction is determined to be below the resource’s MOPR bid, that resource will not receive any capacity payment.

State subsidies that subject a generating facility to the requirement to bid a minimum offer price are very broadly defined and would include, among other things, both state mandatory and voluntary renewable energy credit (REC) programs, subsidized demand side and capacity storage resources, as well as zero emission credit programs subsidizing certain nuclear plants and OREC or offshore renewable energy credits for offshore wind projects.

PJM wanted to limit the MOPR requirements to projects above 20 megawatts in size on the ground that small projects would not have a material effect on the market. However, FERC rejected any minimum size threshold for application of the MOPR to projects that qualify for state subsidies.

FERC directed PJM to make a compliance filing by late March implementing the various changes ordered by the commission as well as providing support for a number of such changes.

In the meantime, dozens of intervenors filed petitions for a rehearing of the FERC order. The intervenors include PJM, which asked for more time to implement the MOPR order and the many requests for clarification and rehearing of many aspects of the order from other intervenors.

Some aspects of the FERC order will probably be clarified or revised on rehearing and necessitate an additional filing by PJM if the original compliance deadline is not extended.

The process will take time to play out fully.

After FERC decides whether to hold a rehearing, it will issue another order. If that order in any way modifies the prior order, then the revised order will also be subject to rehearing. The FERC orders will almost certainly be challenged in a US court of appeals. While the appeals will not prevent the base residual auctions from going forward based on the orders, there is a risk that that the outcomes of those BRAs could be undermined by an adverse ruling by the appeals court on review, which could take more than a year to decide the challenges.

The auction that was supposed to have taken place in 2019 will now be rescheduled, but further delays are possible.

FERC directed PJM to propose a new schedule to set commitments for the 2019 BRA, meaning the June 1, 2022-to-May 31, 2023 delivery year, and for the 2020 BRA, which would establish commitments for the June 1, 2023-to-2024 delivery year. The 2019 BRA was supposed to have occurred in May 2019, three years in advance of initial delivery, and the 2020 BRA is supposed to be held in May 2020, which will not happen.

Several major resource providers are urging FERC to delay any PJM auction until FERC clarifies its December order, which could push the next auctions into 2021, although the 2019 BRA would need to address the delivery year starting June 1, 2022 and the 2020 BRA would need to address the delivery year starting June 1, 2023.

State subsidy defined

FERC adopted a broad definition of a state subsidy that will require a project to bid a minimum offer price.

The term means “[a] direct or indirect payment, concession, rebate, subsidy, non-bypassable consumer charge, or other financial benefit that is (1) a result of any action, mandated process, or sponsored process of a state government, a political subdivision or agency of a state, or an electric cooperative formed pursuant to state law, and that (2) is derived from or connected to the procurement of (a) electricity or electric generation capacity sold at wholesale in interstate commerce, or (b) an attribute of the generation process for electricity or electric generation capacity sold at wholesale in interstate commerce, or (3) will support the construction, development, or operation of a new or existing capacity resource, or (4) could have the effect of allowing a resource to clear in any PJM capacity auction.”

This definition is in marked contrast to the narrower definition that PJM wanted.

PJM wanted only a “material subsidy” to require a generator to bid a minimum offer price. FERC completely eliminated the materiality component, making any incentive, from 5¢ to $5 million, enough to trigger a minimum offer requirement.

The FERC definition is too vague. PJM will have a hard time figuring out whether some bidders are subject to it. For example, what is the universe of “indirect payments . . . or other financial benefit that . . .(3) will support the construction, development or operation of a new or existing capacity resource or (4) could have the effect of allowing a resource to clear in any PJM capacity auction”?

FERC said its “concern is with those forms of State Subsidies that are not federally preempted, but nonetheless are most nearly ‘directed at’ or tethered to the new entry or continued operation of generating capacity” in the PJM market.

The word “tethered” is a loaded reference, as it was the same word used by the US Supreme Court in the Hughes v. Talen decision. In Talen, the Supreme Court invalidated a state-mandated contract because it required the developer to clear the PJM capacity auction in order to receive the fixed payment under the contract. The PJM capacity tariff is a wholesale rate. FERC has exclusive jurisdiction over wholesale rates. Therefore, the state contract was “preempted” by federal law, the court said. (For more information, see “Supreme Court Nixes Two PPAs” in the June 2016 NewsWire.)

The contract was a so-called contract for differences, in which the contract price was netted against payments received by the seller from the PJM capacity market. The Supreme Court said its decision was a limited one that permits states to take action to encourage production of new or clean generation through measures “untethered to a generator’s wholesale market participation.”

Lawyers have debated what “untethered” means. FERC has taken that vague pronouncement about federal preemption, and compounded the ambiguity further, by expressly stating that a minimum offer price by bidders who qualify for state subsidies that, unlike the contract in Talen, may not be federally preempted, but are nonetheless “tethered” to the wholesale market participation.

FERC clearly had in mind projects that qualify for renewable energy credits or RECS under state renewable portfolio standards. RECS are a creature of state law, not federal law.

FERC said it could not rule out that “voluntary REC arrangements . . . [that] are not associated with a state-mandated or sponsored procurement process” would also require a bidder to bid a minimum offer price.

Its argument is that RECs sold to a third party could later be resold to a utility under a state RPS obligation.

This suggests that even corporate PPAs could be captured by the state subsidy definition, even though the corporate buyer has no legal obligation under state law to purchase RECs and the generator cannot benefit from the RECs that are transferred to the corporate buyer. Presumably a commitment by the buyer to retain or retire the RECs once transferred to the buyer would convince FERC that no state subsidy is involved. But the mere assertion by FERC that a REC sale to a corporate buyer with no state REC requirement and therefore literally no state subsidy could nonetheless cause a renewable project to trigger the MOPR rule strongly supports the dissent by Commissioner Richard Glick that FERC is targeting renewable projects in order to favor fossil-fuel projects in the PJM market.

FERC considered and rejected adding to the MOPR any federal subsidies that can give a project a competitive advantage in the PJM capacity auction. The reason is that federal subsidies are a product of federal law, and FERC has no authority to nullify the effect of a federal law, it said. However, the Glick dissent points out, there is a logical inconsistency between the argument made by FERC in support of the state-subsidized MOPR requirement and the argument for excluding the federally-subsidized projects: since FERC argued that its orders mitigating the effects of state subsidies did not prevent states from applying those subsidies, a FERC order that would mitigate the impact of federal subsidies would not prevent the federal government from applying those subsidies either.

It will ultimately be up to the US court of appeals to decide whether this federal-versus-state rationale for the dividing line on subsidies is legally supportable.

FERC also excluded from the state subsidy definition any generic industrial development and local siting support because FERC assumed these state benefits would be available to “all businesses.”


Three types of renewable generators are exempted from the need to bid a minimum offer price.

The obligation does not apply to any project that successfully cleared an annual or incremental PJM auction before FERC issued the MOPR order on December 19, 2019.

It does not apply to a project that signed or filed an interconnection construction service agreement with PJM before December 19.

It does not apply where a bidder qualifying for a state subsidy persuades FERC to grant it a competitive exemption by committing not to use the state subsidy.

But if a new resource gets a competitive exemption in the first year and later uses the state subsidy, then it will be barred from participating in the future capacity market for up to 20 years.

This draconian outcome can be avoided under something called a “unit specific exemption.” The exemption permits an individual project to apply to the PJM market monitor to offer a lower-than-MOPR price if it can show that its expected costs and revenues are low enough to justify a bid below the MOPR level. FERC directed PJM to give a better explanation of the methodology and standards that will be applied when assessing claims by bidders that the net costs of a project should allow a bid below the MOPR price.

Richard Glick said in dissent that he expects most projects to apply for the unit specific exemption to reduce their minimum bid price below the MOPR rate. He said this will effectively convert the PJM capacity market from one relying on competitive market forces, as originally intended, to one that is based on administratively determined cost-of-service rates established by the market monitor.

A substantial percentage of state-subsidized renewable resources, capacity storage and demand resources may still find it possible to finance projects without counting on capacity revenues from PJM.

However, at some point, the effective exclusion from the capacity market may end up causing states to have to offer more state support to reach renewable energy goals.

In addition, by maintaining currently uneconomic capacity in PJM by placing a high barrier for new resources and thus failing to account for the capacity attributes of renewable, storage and demand resources, retail ratepayers that bear the cost of state subsidies for those resources will also bear significant additional costs under the PJM tariff. PJM requires all utilities and other retail electricity suppliers to obtain capacity commitments to meet projected retail demand. By excluding the capacity value of operating state-subsidized resources in PJM and including other resources to fill that perceived demand, retail ratepayers will have to pay more. FERC did not provide any analysis of the potential rate impacts of its decision.

Existing resources

For existing state-subsidized resources, which are planned resources subject to the MOPR that have cleared the PJM auction, in subsequent auctions they will need to offer a minimum or default price, but one that is lower than the initial MOPR for planned resources.

The default price has been labeled the “net avoidable cost rate” or NCR. The NCR will vary by resource type. It is an estimate of how much revenue the resource requires, in excess of energy and ancillary services revenues, in order to provide capacity in a given year.

PJM is required to come up with value for each resource type for each year in its compliance filing. In his dissent, Commissioner Glick argues (as did the PJM market monitor, which has to evaluate these costs, in its comments to the commission) that it is illogical to permit existing revenue resources to bid a different minimum rate than new, planned resources because their respective resource costs and revenues will not materially differ from one another.

Net CONE, the MOPR for new resources, is a leveled annual value for a 20-year operating period, and this value therefore should not change from year one to year two. However, setting a minimum price at the lower NCR level in subsequent years will make it easier for existing state-subsidized resources to clear the market if they can get past the initial MOPR-required hurdle.

State exits

Several states with extensive climate-change agendas have indicated that they are evaluating whether to direct their in-state utilities to exit the PJM capacity market altogether.

Under the existing PJM rules, which are not being modified, a utility or other retail supplier that has an obligation to serve a designated service territory at retail can avoid participation in the PJM capacity market in a delivery year if it demonstrates a commitment to serve all of its customers’ capacity demand with non-PJM capacity and also remove its entire system load from PJM market for the applicable delivery year.

This opt-out option is called the “fixed resource requirement,” or FRR. The utility would avoid any capacity obligation in PJM and avoid any PJM capacity reliability charge associated with a shortfall in capacity requirements.

The interstate interrelationships among most utilities in the PJM market would make any state withdrawal extremely complicated to accomplish. The mere fact that some states are evaluating the option shows the extent of concern and dissatisfaction with the FERC’s actions.