VALLEY FORGE, Pa. — PJM’s Eric Hsia told attendees at last week’s Market Implementation Committee meeting that the RTO plans to salvage the non-compensation portions of its proposal to revise its regulation market that FERC rejected last month. (See FERC Rejects PJM Regulation Plan, Calls Tech Conference.)

PJM had filed for approval of revisions that included four interdependent components. The commission denied the proposal outright because it would have paid units a formula rate that didn’t specifically compensate for the actual amount of regulation work they provided, but its order didn’t address the other three components. Hsia said PJM plans to ask FERC to reconsider those components separately as the RTO determines how to address the commission’s issues with its compensation plan. He confirmed that PJM wouldn’t change the language describing the three components in its reconsideration request.

Direct Energy’s Marji Philips asked if PJM plans to consolidate its regulation signals into a single signal as FERC pointed out in its order is the process that all other grid operators follow. Hsia said the RTO is considering that option.

VOM Proposal

Stakeholders endorsed proposed revisions for how operations and maintenance costs are recovered that would allow “major” maintenance to be included in variable operations and maintenance (VOM) calculations. Both PJM’s and a default proposal received overwhelming support. The RTO’s proposal received 169 votes in favor, or 75%, and 57 opposed. The default package received 178 votes in favor, or 81%, and 43 votes opposed.

A follow-up vote found that 71% of voters preferred one of the packages over the status quo. The revisions will impact how units calculate their cost-based offers and have implications for other market and operational issues, such as frequency response. (See PJM SHs Debate Frequency Response Rules.)

The Independent Market Monitor’s Catherine Tyler provided context for the Monitor’s proposal, which would have replaced “incremental” with “short-run marginal” in the Operating Agreement and assumed that all maintenance and labor costs are included in a unit’s capacity offer. It fell well short of the votes needed, receiving 11% favorability, or 24 votes out of 224.

“The cost-based offer should be set at a competitive level, and that is short-run marginal cost,” Tyler said.

She said that while every unit provides a cost-based offer, which is only applied if the unit fails its market power test, it isn’t used frequently because price-based offers are often lower than cost-based ones, which she said is a particular concern when cost-based offers are overstated. A unit has incentive to pad cost-based offers because it provides more room to adjust price-based offers when the unit fails its market power test.

PJM’s Gary Helm said the quadrennial analysis of how unit-type net cost of new entry (CONE) is determined will evaluate both including and excluding major maintenance from the VOM calculation. PJM hired the Brattle Group to do the review, which will be presented later this month and is slated for filing for approval at FERC on Aug. 1.

The last review in 2014 became mired in infighting at FERC over details in the engineering portion of how costs could be determined.

FES Bankruptcy

PJM staff did not offer any specific comment on FirstEnergy Solutions’ bankruptcy announcement and plans to shutter its three nuclear facilities, but they agreed to field stakeholder questions on the issue.

Stu Bresler, senior vice president of markets and operations, confirmed that the plants’ “must-offer requirement is retained” absent an exemption. Because the period for seeking such an exemption has closed, it would require a FERC waiver granting it.

CFO Suzanne Daugherty said, “PJM is still ready for June 1,” referring to the target date for Ohio Valley Electric Corp.’s integration into the RTO. But she said staff would accommodate a delay if requested. She said that all PJM members are in compliance with credit requirements but clarified that any without investment-grade ratings wouldn’t be eligible for unsecured credit.

It remains unclear how the deactivations will impact prices.

“I can’t imagine the analysis resulting in any other [locational deliverability area] model than what’s already been modeled,” Bresler said. But Monitor Joe Bowring said he can’t tell if an additional LDA would clear the Base Residual Auction above the RTO-wide capacity price unless it’s modeled in the auction.

SOM Revisions

Bowring announced that several calculations have been revised in the IMM’s annual State of the Market Report that paint a less rosy picture for nuclear facilities than originally thought. (See IMM Report Says PJM Prices Sufficient.)

The Monitor revised its calculations on forward-looking profitability for nuclear plants, reducing the numbers by tens of millions of dollars. It now predicts a revenue shortfall of $11 million this year for the Perry generating station, which is one of the facilities FES plans to close, instead of the previous $500,000 profit. Perry also overtook Three Mile Island, which Exelon has threatened to close, for the grimmest long-term outlook, expected to hemorrhage $79.5 million in 2020 alone.

Exelon’s Dresden facility in Illinois overtook the company’s Limerick facility near Philadelphia as the plant with the best outlook, with about $58.8 million in profit expected for 2020.

Nodal Mapping

Stakeholders are working on several initiatives involving financial transmission rights.

Proposed revisions to address the nodal remapping issue are expected at the May MIC meeting to target a Sept. 1 effective date that coincides with the 2018 LMP bus modeling likely for mid-September, PJM’s Brian Chmielewski said.

The revisions are in response to concerns highlighted by Direct Energy about replacing nodes where FTRs begin or end and are terminated based on changes in load, generation or system topology. When that happens, an “electrically equivalent” node must be identified to replace the terminated one, but stakeholders who have experienced that issue have been unsatisfied. The proposal would create a “dummy” pricing node at the same location as the terminated one where only “sell” bids would be allowed. After all connected FTRs are sold or expire, the node would be terminated. The same process would work for incremental auction revenue rights.

Long-Term FTR

PJM also plans to bring a proposal to the May MIC meeting for addressing long-term FTRs, with a target effective date by June 1 in time for the 2020/23 auction, Chmielewski said. PJM’s plan would eliminate the current “year all” offering, leaving only the one-year options that are one, two or three years in the future.

PJM said interest was low in the “year all” option that included all three years and eliminating it would improve FTR software performance. The proposal would also limit ARR modeling. Instead of including all planning period ARRs as fixed injections and withdrawals, it would only include those that cleared based on the annual model with all transmission outages removed. Chmielewski said the plan better represents the residual capability on the system and preserves capability for ARR holders in the subsequent annual allocation.

— Rory D. Sweeney