PJM capacity, grid reliability and PURPA

PJM capacity, grid reliability and PURPA

August 08, 2019 | By Robert Shapiro in Washington, DC

Several major issues that affect large segments of the power industry remain on the Federal Energy Regulatory Commission agenda as it heads into the fall.

These include the re-establishment of capacity auctions for the PJM capacity market, the evaluation of system reliability issues for various regional transmission organizations in the interstate markets, and a re-evaluation of how the Public Utility Regulatory Policies Act of 1978 (or PURPA) is implemented.

All three subjects have the potential to affect the extent to which renewable energy versus fossil fuels are used to generate US electricity.

PJM Capacity Market

PJM, the largest regional transmission organization in the United States, runs an annual capacity auction to buy capacity to meet the power needs of its 13 state regional markets. PJM operates the electricity grid from the mid-Atlantic states all the way to parts of Illinois and Michigan.

The auctions are run three years in advance of delivery.

The auctions are conducted in a manner that is supposed to provide appropriate market signals to encourage new capacity when reserves are tight and to discourage new capacity when there is excess capacity in the market.

However, with the increasing volume of renewable energy that relies on federal tax credits and the increasing subsidization of large, operating nuclear plants within PJM, PJM proposed in 2018 to revise the auction rules — beginning with the 2019 auction for capacity to be provided in the 2022-2023 delivery year — to mitigate the price-depressing impact from having so much subsidized capacity bid into the auctions.

FERC agreed with PJM in June 2018 that its existing rules were no longer "just and reasonable" due to the subsidies, but it rejected PJM's specific proposals to revise its capacity rules. Instead, FERC, in a three-to-two decision along party lines (with the two Democrats dissenting), came up with its own "tentative" revised plan and then invited interested parties to comment on that plan and to respond to a set of questions.

Many parties commented and many, including PJM, came up with different proposed plans. FERC has not acted on any proposal since then.

When PJM realized that FERC would be delaying its decision, PJM asked and received permission from FERC to delay its scheduled 2019 auction from May to August 2019. When FERC still had not acted by March 2019, PJM decided to go ahead with the auction in August anyway, and proposed to follow both the pre-existing PJM auction rules that had been in place before PJM had requested their modification, as well as FERC's tentative new proposal.

Many objections were filed. On July 25, 2019, FERC directed PJM not to run its 2019 auction in August. FERC appeared to recognize the difficulty in deciding whether an auction run under rules that it had already determined to be unjust and unreasonable could lead to just and reasonable results. It concluded that the auction must be delayed "until the Commission establishes a replacement rate" because it would "provide greater certainty to the market than conducting the auction under existing rules."

There is no deadline for FERC to act. Although FERC recognized the importance of sending price signals significantly in advance of delivery to allow developers and existing operators to make intelligent investment decisions, it has provided no timetable and no inkling of the direction it may take.

A further complication is that, of the five commissioners that voted on the original June 2018 order, only two remain. One is a Republican who voted for it, and one is a Democrat who voted against it. The third commissioner, Bernard McNamee, was confirmed in December 2018, was a lobbyist for the coal industry and was widely believed to be a moving force behind the unsuccessful US Department of Energy direction to FERC in 2017 to subsidize coal and nuclear plant operations in the regional transmission organizations over other sources of power, which would have severely disrupted the operation of the competitive markets.


Under the former PJM tariff for capacity before the 2018 proposed changes, certain new generators that had not yet participated and cleared in a PJM capacity auction would have to offer a minimum price to supply capacity in their first delivery year. The requirement to bid a minimum price is known as the "minimum offer price rule" or MOPR. Existing market participants were not subject to the MOPR under the old rules.

 Under the old rules, the MOPR requirement applied only for the first auction. If a new generator's bid clears once in an auction, then in subsequent years it would not be subject to a minimum offer price requirement. Also, under the old rules, the MOPR requirement did not apply to unsubsidized gas projects that meet certain exemption tests, to renewable generators, to anyone offering demand-side reduction or to existing capacity suppliers. However, the MOPR did apply to state-subsidized new gas-fired generation.

In the proposal that FERC rejected in June 2018, PJM said that the existing rules were no longer viable in light of the distorting effects of state subsidies and offered two alternative plans and asked FERC to choose which one it preferred. While FERC agreed with PJM that the existing approach was no longer just and unreasonable, FERC also decided that both of PJM's proposed tariff revisions were unjust and unreasonable, as well. It then offered its own "preliminary" proposal to change the existing PJM capacity MOPR rule in two ways.

First, it directed PJM to expand the MOPR to create a replacement minimum offer rate for all existing and new generating plants, regardless of resource type, with few exceptions.

Absent such a requirement to bid at a minimum price, existing generators and all new price-subsidized renewable generators and nuclear plants could offer capacity as "price takers," meaning that each could offer a zero price that is guaranteed to clear the auction and still receive the auction's market clearing price. With FERC's proposal, on the other hand, there is a risk that such generators will have to offer prices at levels that will not clear the auction and, therefore, receive no capacity payments.

FERC fully recognized that its proposal would mean that the MOPR would apply not only to unsubsidized generators, but also to subsidized generators.

It recognized that by holding subsidized resources to the MOPR standard, some ratepayers may be obligated to pay for capacity twice — "both through the state programs providing out-of-market support and through the capacity market." This could happen if such a generator's bid did not clear in the auction. FERC said the courts have recognized this risk, but that the courts have found the risk is reasonable given that states retain the right to pursue their own generation policy goals.

However, to mitigate the risk of double payment, FERC proposed a second change to the MOPR rule, called the "fixed resource requirement" or the FRR alternative option.

This option would allow, on a case-by-case basis, a utility or other load-serving entity with specific generation that was receiving out-of-market state support to choose to remove that generation from the PJM capacity market along with a commensurate amount of load, for some period of time.

In setting the proceeding for a paper hearing, FERC also asked interested parties to address a number of important open issues. The issues included the following.

First, what should be considered an out-of-market subsidy? PJM had proposed to define such subsidies broadly to include any market payments, concessions, rebates or subsidies received directly or indirectly from any government entity, or received in any state-sponsored or state-mandated processes, that are connected to construction, development, operation or clearing of the capacity in any capacity auction

But PJM wanted to exclude a laundry list of items from the definition. It wanted to exclude subsidies that promote general industrial development in an area. It would also exclude subsidies that encourage a power plant to be put in one county or locality rather than another one. Federal tax credits and other tax benefits that are available to eligible generators regardless of location would also be ignored.

Second, FERC asked for advice on what categories of generators should be exempted from bidding under the MOPR.

Third, it asked whether federal sources of out-of-market support should be addressed by the commission action.

Fourth, it asked how long generators receiving out of-market support who choose the resource specific FRR alternative should be required to remain outside of the auction.


In her dissenting opinion, Commissioner Cheryl LeFleur (who left the commission after her term expired in August) would have been willing to work with PJM's proposal, with some modifications to protect resources under state renewable portfolio standards, or have PJM consider a new construct approved by FERC in March 2018. The new construct was ISO-New England's modification to its MOPR for its capacity auction market, known as "competitive auctions with sponsored policy resources," or CASPR, also designed to mitigate the impacts of subsidized resources on competitive market prices.

Under CASPR, ISO-New England maintained its current MOPR rule that applied to new resources. Then it would conduct a second-stage or substitution auction. The capacity price to be paid to all cleared bids would be determined by the first auction results. But in a second, substitution auction, existing generators that made successful bids to supply capacity in the first auction were permitted to offer to retire their capacity in the second substitution auction at a certain price.

Any state-sponsored resources whose bids did not clear in the first auction would be allowed to bid in the substitute auction to acquire the capacity from those existing resources that offer to retire their capacity in the substitute auction. This was expected to allow retiring existing capacity to receive a somewhat lower than capacity-clearing price to exit the capacity market permanently and also allow new state-supported generators to obtain rights to supply capacity at the market-clearing price.

ISO-New England ran a successful 2019 auction under the CASPR method.

Many interested parties filed comments about FERC's preliminary replacement auction plan for PJM, with some simply responding to FERC's questions, still others supporting FERC's plan or offering their own alternative proposals, and others arguing not to change the existing auction rules.

For its part, PJM offered yet another alternative. Under this revised alternative, PJM offered revised MOPR rules and a "resource carve-out" replacement that it claimed was consistent with FERC's tentative suggested approach. FERC has not indicated in what direction it is headed ultimately.

Although it was assumed that, following the untimely death of the Chairman McIntyre in January 2019 and the expiration of Commissioner LaFleur's term in August, President Trump would simultaneously appoint a Republican and a Democrat to fill FERC's two open seats (out of a full quota of five) to speed approval of the nominations through Congress, it now appears that Trump may leave the open seats unfilled; the commission has two Republicans and one Democrat and can act with a quorum of three commissioners.

No one believes that PJM will be left in a position that would prevent any capacity auction in advance of the 2022-2023 delivery year. However, at this point, unless the FERC decides to reverse itself and determine that the current rules were in fact just and reasonable (as the two dissenting Democrats would have ruled in 2018) but would be revised beginning with the 2020 auction for the 2023-2024 delivery year, the results of the 2019 auction process, whenever it occurs, will have a legal cloud over them. A FERC decision is not likely to be forthcoming for the next several months. That decision will itself be subject to a rehearing, and will take several more months for reconsideration and a final decision. Even if FERC denies a rehearing on its final order, that decision would be subject to appellate court challenge, which could take a year or more to resolve.

Moreover, continued uncertainty over a ruling governing the 2019 auction rules will inevitably add to uncertainty over their application in the 2020 auction in light of the expected litigation over the eventual 2019 auction decision.

Grid Resilience

The commission will be considering whether additional steps need to be taken by the various regional transmission organizations (or RTOs) to bolster resiliency of the US electricity grid.

FERC undertook this initiative in response to a proposal by the Trump administration in the fall of 2017 to have FERC order all the regional transmission organizations other than ERCOT, which is not subject to FERC jurisdiction, to pay generators with 90-day fuel supply inventories on site a price for electricity that guarantees them full recovery of operating costs and a return on investment.

The transparent purpose was to force FERC to subsidize uneconomic coal and nuclear plants that have fuel storage on-site to the disadvantage of natural gas and renewable energy projects, which have no need for on-site storage. The Trump administration argued that the policy was needed for system reliability. (For more detail, see "FERC Directed to Favor Coal and Nuclear" in the September 2017 NewsWire and "Halting Coal and Nuclear Retirements" in the June 2018 NewsWire.)

FERC unanimously rejected the proposal in January 2018, but initiated a new proceeding that required the RTOs to provide their views of what bulk power system resilience means and requires, and how each system assesses whether its system is resilient. FERC would then assess the information received and decide whether any additional commission action is needed. The commission expressly recognized that the issue of resilience extends beyond the RTOs, including utilities in non-RTO systems, as well as distribution system reliability and modernization, which are areas beyond the commission's jurisdiction. The docket contains several dozen questions about the definition of resilience and requires an explanation how each system addresses resilience and reliability issues.

The various RTOs provided comments to FERC, as did many other segments of the power industry. Many parties also filed reply comments.

The commission has not responded to these comments despite the fact that it has been many months since the comments were filed. The most recent comments filed concerned efforts by certain groups to get Commissioner McNamee to recuse himself from the docket in light of his history in spearheading the unsuccessful DOE initiative to subsidize coal and nuclear plants. Commissioner McNamee has said that he will not do so.

Meanwhile, the various RTOs have been continually undertaking their own evaluations of their systems' grid resiliency. In particular, both ISO-New England and PJM have been analyzing fuel security resilience in their respective regions. ISO-New England has recently found that the difficulty in siting and completing the construction and operation of new natural gas pipelines is causing stress on system reliability, particularly on the coldest winter days where existing pipeline curtailments occur and fuel switching is required.

ISO-New England made a filing at FERC in March 2019 to implement, beginning with the winder of 2023-24, a program to provide incremental compensation to resources that maintain inventoried energy during cold periods when winter energy security is most stressed. ISO-New England had previously received approval to retain and compensate Mystic gas-fired generating units that would otherwise have retired because of the need for fuel security. But FERC wanted ISO-New England to propose a tariff amendment to address future retention of units to address fuel security concerns. That tariff became effective on August 6, 2019 because FERC failed to act on the filing, claiming that it lacked quorum .

It is unclear when FERC expects to make public an evaluation of the responses on grid resiliency or, following such an evaluation, whether FERC will direct any of the RTOs to take steps that they are not already taking to ensure that the regional systems remain reliable and resilient.

The specific problems with siting of gas pipelines in New England and the consequent fuel constraints in the winter appear to be creating the most significant issues, and the recent efforts by ISO-New England to address these concerns in its current filing may become a vehicle for their resolution.


The Public Utility Regulatory Policies Act of 1978, called PURPA, is a federal law that requires all types of utilities (public, private, regulated and unregulated) to buy electricity from renewable energy generators up to 80 megawatts in size at the "avoided cost" the utility would otherwise pay to purchase or generate the electricity itself.

PURPA also greatly reduces the utility regulatory burdens on renewable generators.

PURPA has been amended several times over the years, although the basic FERC rules implementing the statute have largely remained in place. A unique feature of the statute is that while FERC issues implementing rules under PURPA, certain of the federal rules must be implemented by state utility commissions, and the state commissions are given wide latitude in their implementation.

Following a request from Congressional oversight committees more than two years ago, FERC undertook to re-visit its PURPA rules, opening a notice of inquiry and asking a series of questions concerning the existing rules.

The importance of the PURPA rules has diminished nationally over time. This is primarily due to the fact that 30 states have passed their own laws requiring their state utilities to meet a renewable portfolio standard (or RPS), which has led to purchases of greater amounts of renewable power, better pricing and larger projects than PURPA would afford developers.

In addition, FERC found that utilities operating in competitive markets served by RTOs do not have to buy power from PURPA projects (known as "qualifying facilities" or QFs) if the projects exceed 20 megawatts in size. Accordingly, it is primarily in the sections of the country in which there are no RTOs and limited or no RPS standards (principally in the northwest and southeastern US) that PURPA still has relevance.

In its notice of inquiry, FERC sought and received comments on a number of issues. These are whether there should be a mandatory purchase obligation for utilities in organized markets for projects up to 20 megawatts, a FERC rule that limits a utility's ability to curtail QF power, assessments of the current avoided cost methodologies approved by the state commissions, a standard that would trigger a utility's obligation to purchase the electricity at its avoided cost, and whether developers should be able to treat related facilities that are more than a mile apart as separate QFs to stay under the size limits — the so-called "one-mile rule." By far the most contentious issue is the one-mile rule, which allows developers to break, for example, a 160-MW project that would not qualify under PURPA into two 80-MW QF projects in a single location as long all the turbines from one of the projects were a least a mile away from the turbines for the other project.

FERC has given no indication how or when it is going to handle this re-examination of the PURPA rules, and there has been no major effort by the utility industry to undo the statute or the rules, particularly in light of the latitude given to state commissions that can limit or kill potential QF projects through state implementation of PURPA. But there have been periodic statements issued from time to time by a few utilities and congressmen hostile to PURPA that seek FERC's attention to this investigation. A re-evaluation by a Republican-controlled FERC is a distinct possibility.