By Rory D. Sweeney

VALLEY FORGE, Pa. — If FERC hoped to receive a consensus proposal from PJM stakeholders on how to revise the RTO’s capacity market, it may be disappointed.

PJM staff unveiled a new proposal at a special session of the Markets and Reliability Committee on Wednesday and were careful to differentiate it from the fixed resource requirement (FRR) FERC suggested in its rejection of the RTO’s previous “jump ball” proposal. (See FERC Orders PJM Capacity Market Revamp.)

The RTO calls the proposed construct the Resource-specific Carve Out, or ReCO, because it would start with a subsidized generation resource exiting the capacity market with a corresponding amount of load rather than the FRR’s inverse situation of a designated amount of load exiting the capacity market with a corresponding resource.

The same three FERC staff members who attended PJM’s last meeting on the issue returned on Wednesday. At the previous meeting, the RTO provided a general overview of its plan and offered representatives of four other proposals time to outline their approaches. (See PJM Stakeholders Search for Capacity Rules FERC Will OK.)

FERC staff are uninvolved in the commission’s decision on the topic and were only there to offer insight.

Whether PJM accepts it is another question.

Matthew Estes, a FERC attorney, advised consolidating the different aspects of several FRR-like proposals, including PJM’s, into a single filing. He highlighted proposals developed by Exelon and a coalition of environmental organizations.

“Try to come up with a proposal that includes as much agreement as possible, or at least filling in the holes,” Estes said, adding that PJM should consider filing a comparison of the proposals. “I think it would be helpful to the parties and the commission to see where there can be consensus and still disagreement.”

But Craig Glazer, PJM’s federal liaison, wasn’t optimistic.

“Is there commonality? I’m guessing there isn’t that much,” he said, noting that the order requires a response from PJM directly, not a stakeholder-endorsed proposal. “The purpose of this [meeting] was to give PJM’s thoughts.”

PJM’s ReCO proposal would define a minimum offer price rule (MOPR) in its annual Base Residual Auctions, how resources would become subject to the rule and what options those resources have to exit the capacity market instead of accepting the MOPR. The proposal focuses on removing price-suppressing impacts of resources offering into the auctions at rates that have been subsidized by other out-of-market payments, such as state programs for renewable or zero-emission generation.

ReCO, RECO, RICO

Whatever the final proposal is, it’s likely the name won’t remain. James Wilson of Wilson Energy Economics noted that PJM already has a RECO acronym for Rockland Electric Co., and Exelon’s Jason Barker pointed out the pronunciation suggests the federal Racketeer Influenced and Corrupt Organizations Act (RICO).

“We have it in the notes to change the name,” PJM’s Adam Keech said.

Glazer emphasized that it’s “not [an] open-ended” option for resources to choose to avoid a must-offer requirement, but a “narrowly carved right” for states to offer subsidies without requiring ratepayers to pay twice for capacity.

Resources would be subject to mitigation through the MOPR if they are at least 20 MW and receiving out-of-market revenues that are at least 1% of actual or anticipated market revenues. Outside payments from any federal program adopted prior to March 21, 2016 — the date set by FERC back to which companies would be eligible for refunds in a 2016 complaint that Calpine and Eastern Generation joined on how the existing MOPR handles subsidized resources (EL16-49) — would be exempt. Federal subsidies after that would have to include “a clear statement of congressional intent” to not be subject to the MOPR.

Those parameters set off a series of stakeholder concerns. Tangibl’s Ken Foladare suggested increasing the 1% threshold so as to not be “trip[ped] up” unintentionally by combinations of state and local programs that aren’t targeting wholesale power markets. Others asked why the date of the Calpine complaint was the cutoff and whether making exemptions for federal programs was discriminatory against state programs.

Glazer said PJM made room for federal programs because it is federally regulated and that it set the cutoff so that staff do not “have to romp through the tax code” to infer Congress’ intent for older programs that likely did not contemplate current legal issues. It would create “an administrative nightmare” and “we’ll never get anything done,” he said, and neither would FERC.

“I’m not sure they wanted to be in the middle of endless fights over the tax code,” he said.

PJM counsel Jen Tribulski said staff “didn’t feel that we needed to draw that same line in the sand” for state programs.

Several stakeholders asked for clarification of PJM’s position on how it would handle programs promulgated by federal agencies that don’t regulate the RTO, such as the Department of Energy, which has been considering ways to subsidize ailing coal and nuclear facilities. Glazer said PJM would accept a program “to the extent that it is legal and it applies to us,” but he declined to wade in farther.

“That’s your legal argument,” he said of stakeholder positions on what should apply to PJM. “Save it for court.”

MOPR Exemptions

Another area of contention was the number of MOPR exemptions PJM is considering. Beyond federal programs, the proposal would also exempt resources listed in PJM’s Tariff as self-supply for public power and vertically integrated entities prior to July 7, 2017 — the date the D.C. Circuit Court of Appeals remanded back to FERC its 2013 order on the RTO’s MOPR. (See PJM Stakeholders Split on Request to OK MOPR Compromise.)

New resources would be subject to net short/long criteria that would look at the owner’s full portfolio to determine whether, in aggregate, its resource fleet exceeds thresholds of having either too much or not enough generation to supply its load. New units that are determined to have exceeded the thresholds would be subject to the MOPR.

Barker asked why PJM plans to apply the MOPR to units that receive state payments for externalities the RTO’s markets aren’t valuing, such as Illinois’ zero-emissions credits and New Jersey’s nuclear diversity certificates for nuclear generators.

“We’re not chasing intent,” Glazer said. “They all have a distorted effect on the market.”

Barker called it “very convenient” that PJM would “hide behind” FERC’s directive for a MOPR with “few to no exemptions” to avoid discussing state programs after it had already outlined several other exemptions.

“It sounds like if there is an attribute that’s not priced by this market, it sounds like you just don’t want that to be considered,” he said.

Glazer called it a “debate that’s beyond the economic regulator and beyond us.”

PJM’s Stu Bresler said the reason is because “the subsidy is directly aimed at a resource to produce electricity” and if the unit can clear the auction without the subsidy it “has no fear of being MOPRed.”

Barker also challenged the details of PJM’s proposal to apply the MOPR to resources that exit the capacity market through ReCO but decide to return after the subsidy that made it eligible for ReCO expires. The applicable MOPR would include any project investment that occurred during the time frame when the subsidy was received.

DR

Under the plan, existing demand response resources would have a MOPR floor of $0/MWh, but planned DR would have a floor of the average offer price for planned DR from the previous three BRAs. Until those data become available, the floor would be based on the average offer price for DR from those BRAs. Keech said that planned DR would likely be considered as customers added that hadn’t participated previously.

Eric Matheson with the Pennsylvania Public Utility Commission warned that might create barriers to entry if the previous offers were exceptionally high.

What Load?

ReCO would work by allowing resources receiving an “actionable subsidy” subject to a MOPR to exit the capacity auction along with a corresponding amount of load. While both the load and the resource would be included for the purposes of clearing the auction, the resource wouldn’t receive any revenue. That money would instead be allocated as a pro rata credit back to all PJM load in the state subsidizing the resource on the basis of such loads’ locational reliability charges.

Such resources would be subject to PJM’s Capacity Performance requirements, but staff said that the resource and the load aren’t required to be located in the same area.

“I don’t know that we’ve come up a reason why that matters quite yet,” Keech said.

Vistra Energy’s Arnie Quinn said it could result in undesirable cost shifting.

“There’s a physical element and there’s a financial element. You’ve honored the physical element, but you haven’t honored the locational pricing,” he said.

Joe Bowring, PJM’s Independent Market Monitor, agreed that it “does not make sense to have load and supply in separate locations.”

FirstEnergy’s Jim Benchek said the cost-allocation portion of the ReCO plan “makes sense” because there will be multiple auctions — the BRA and three subsequent Incremental Auctions — along with states with multiple zones to determine a final price to credit back to ratepayers. The final zonal capacity price is never the same as the BRA or IA prices, he said.

Matheson said it will be important for state regulators to have a role in the crediting process and determination.

Other Ideas

Keech confirmed that PJM doesn’t plan to pursue an approach similar to the Competitive Auctions with Sponsored Resources construct recently approved for ISO-NE.

“I’m not here to tell you it can’t be [implemented],” Keech said. “I’m just going to tell you that we’re not going to pursue it as part of this proceeding. … That doesn’t mean that we can’t discuss it sometime down the road in some other stakeholder proceeding.”

That decision was endorsed by Wilson, who said CASPR is “a very, very complicated process, resulting in very complex rules that to do something that’s really quite modest.”

However, Keech said PJM is still contemplating whether its initial idea for a two-phase auction that eliminates subsidized offers will work in combination with the MOPR or ReCO. It is also looking at a “diversity load adder” to ensure load remains in the capacity market to account for the diversity of PJM’s generation fleet.

FERC’s Emma Nicholson said that “the commission did contemplate that this is a major rule change,” so it “could envision some timing issues” with implementation and that “transition mechanisms might be necessary.”

Next Steps

Staff are planning another session on the topic on Sept. 11 and said they would consider how to address Estes’ suggestion of combining the FRR-related proposals. Susan Bruce, who represents the PJM Industrial Customers Coalition, asked that staff announce as early as possible if they plan to develop a comparison matrix to submit to FERC so stakeholders have time to provide input.

“I think we’re treading on unusual grounds here,” she said.