Markets and Reliability Committee
Stakeholders Endorse Changes to Generator Deactivation Requirements
VALLEY FORGE, Pa. — The PJM Markets and Reliability Committee and Members Committee endorsed a proposal to rework the RTO’s rules around generation deactivations, including a longer notification period, changes to components of the deactivation avoidable cost credit and adding transparency to the process. (See “First Read on Extended Notification Requirement for Deactivating Generation, Changes to Compensation,” PJM MRC/MC Briefs: Dec. 18, 2024.)
The proposal would increase the advance notice a generation owner must provide PJM ahead of bringing a unit offline from three months to one year. The status quo deadlines for owners to file for exemptions from the requirement that they offer their resources into the capacity market if they intend to deactivate would remain unchanged. The PJM proposal was supported by the Deactivation Enhancement Senior Task Force (DESTF) in October 2024, winning out over alternatives from the Independent Market Monitor and Calpine, as well as a separate proposal by the RTO.
The longer gap was sought to provide PJM with more time to conduct studies to identify any transmission violations that may be caused by a unit going offline and to make it more feasible for other resources or market participants to mitigate those issues rather than relying on costly reliability-must-run (RMR) agreements.
Paul Sotkiewicz, president of E-Cubed Policy Associates, said the longer deadline, paired with a compressed Base Residual Auction (BRA) schedule, would prevent generation owners from being able to tell if their resources would be able to provide capacity in a delivery year before making the decision to deactivate. Given accelerating load growth and generation retirements, he said the proposal could imperil PJM’s efforts to maintain resource adequacy.
“We believe that runs counter to the reliability of the system,” he said.
The proposal also would increase the deadlines for all resources, Sotkiewicz argued, when only a few require RMR agreements.
PJM Executive Vice President of Market Services and Strategy Stu Bresler said the submission of a deactivation notification does not prevent a generation owner from offering that unit into the capacity market and withdrawing the request if it clears. He acknowledged, however, there could be staffing issues associated with that dynamic.
Sotkiewicz responded that there are financing and debt issues associated with the determination to bring a unit offline that complicate the ability to undo the decision. It also would increase the administrative burden for PJM staff if resources are submitting and withdrawing deactivation notices that must be studied.
“That’s not helping PJM because you’re ripsawing the system around in terms of planning,” he said.
The proposal also would revise one of the two compensation mechanisms for resources operating on RMR agreements: the deactivation avoidable cost credit. It would remove the $2 million limit on project investments that can be recompensed, limit the annual adder on those investments to 10%, and remove a trigger that causes the credit to be paid through the daily deficiency rate rather than the deactivation avoidable cost rate (DACR) when the DACR and multiplier is greater than the deficiency rate.
The changes to transparency would increase the amount of information published around responses to deactivation notifications, market power determinations, details of RMR agreements and the estimated RMR revenue allocation zonal rate. PJM’s Chantal Hendrzak said stakeholders have requested more transparency to understand the going-forward costs of RMR agreements.
Susan Bruce, representing the PJM Industrial Customer Coalition, said the proposal is an improvement from a consumer perspective, albeit a minor one. She said the ICC supports the changes in a goodwill gesture with the hope that deeper changes to how RMR agreements are used will be pursued in the second phase of the DESTF’s work. The end product of those efforts should consider the permanent design of the capacity market, with three-year forward auctions, and the current reality where auctions are held months in advance of their corresponding delivery year.
“There is a need for thinking about some of those issues, both within the world that we live in now, where we are dealing with things in a whack-a-mole fashion and an accelerated auction timeline. But we also need to think about a time when we have a three-year forward” market, she said. “There is a place here for pragmatism, as well as creating certainty for this fragmented piece.”
Monitor Joe Bowring argued PJM’s proposal would not adequately address issues with RMR compensation; would not require RMR resources to document their actual costs; did not require a review of the need for and level of those costs; and should have required the notice be provided one year ahead of the BRA corresponding to the delivery year in which the unit would retire.
Bowring said that under the normal capacity market timing, retiring resources have had to provide notice more than three years ahead of the relevant delivery year. The proposal also lacks provisions for addressing circumstances where RMR units underperform and would fail to address the inclusion of RMR resources in capacity auctions, he argued.
Widened Scope for ELCC Issue Charge Approved
Stakeholders endorsed adding a key work activity (KWA) to an issue charge focused on how PJM’s effective load-carrying capability (ELCC) framework feeds into resource accreditation and the amount of capacity it may offer.
The additional KWA seeks to “explore potential reforms that may provide greater certainty in ELCC accreditation and/or allow market participants to better manage potential changes in ELCC accreditation between the time of the BRA and the final ELCC values determined for a delivery year.”
The paragraph added to the issue charge was revised during the meeting to include other relevant planning parameters to allow the work to also consider impacts to the stability of financial transmission rights.
The discussion was sparked by rising load growth in the preliminary 2025 Load Forecast, particularly in the winter, leading PJM to consider revising the ELCC values of resources participating in the third 2025/26 Incremental Auction, as well as the installed reserve margin (IRM) and forecast pool requirement (FPR) for the auction.
Mike Cocco, of Old Dominion Electric Cooperative, said the change is warranted to address the risk capacity providers face if their accreditation shifts after the BRA, forcing them to buy capacity in the IAs or face deficiency charges.
E-Cubed’s Sotkiewicz said the issue demonstrates that PJM needs to stop moving items through the stakeholder process without doing the analysis and full stakeholder discussion, because there have repeatedly been unintended consequences. “We need to think things through very clearly, and we are not learning the lesson,” he said.
The overall issue charge also seeks to provide capacity sellers with more certainty around how changes to their resources will affect accreditation and improve the investment signals sent by accreditation. Other KWAs include education about the historical data included in ELCC, key design principles and criteria for accreditation, alternative methods and inputs that can be used in the marginal ELCC framework, and developing proposals to revise ELCC.
The issue charge aims to have governing document revisions filed with FERC in the first quarter so the changes can be implemented for the 2026/27 BRA, scheduled for July. The work is being conducted by PJM’s ELCC Senior Task Force, which also is considering a handful of issue charges brought by LS Power to evaluate the transparency and functionality of the framework. (See “Discussions on CETL Shifted to ELCC Task Force,” PJM MRC/MC Briefs: Dec. 18, 2024.)
Revised Incremental Auction Parameters Endorsed
The committee endorsed revised ELCC ratings and a lower FPR value for the third 2025/26 IA, reflecting a shifting resource mix and performance data pushing risk toward the winter.
The endorsement is advisory to the PJM Board of Managers’ decision on whether to approve the figures.
Most resource types saw their ratings stay flat or within 1% of the ratings used during the BRA, but offshore and onshore wind saw theirs increase by 3% and 2%, respectively. Storage ratings decreased most sharply for four-hour batteries, with the impact muted the longer the duration, and landfill gas intermittent generation decreased by 3%.
The available installed capacity decreased from 191,693 MW to 188,920 MW, causing the FPR proposed for the IA to fall from 0.9387 to 0.938. The IRM and capacity benefit of ties would remain the same.
The class rating changes were in line with a shift toward winter risk, which accounts for 87.8% of expected unserved energy (EUE) risk under the proposal, up from 86.9% in the BRA. The changes were less substantial than values PJM had presented to the Planning Committee earlier in January, as the RTO decided not to continue using preliminary data from the 2025 Load Forecast in the proposal. The original values saw 96.2% of EUE risk concentrated in the winter, driving sharper changes in ratings and auction parameters.
PJM’s Andrew Gledhill told the MRC that the 2025 Load Forecast would be used for the capacity emergency transfer objective and reliability requirement, but not the ELCC class ratings. (See “Stakeholders Discuss Revised IRM and FPR Values for 3rd Incremental Auction,” PJM PC/TEAC Briefs: Jan. 7, 2025.)
PJM CEO Manu Asthana said there are improvements to be made to how ELCC models extreme weather and performance data. While load forecasting tends to look at 50/50 cases, it’s the 90/10 case that is driving the risk modeling, particularly the January 1994 cold wave. He said PJM is considering how the edges of the data are reflected in its modeling.
E-Cubed’s Sotkiewicz said that raises questions of whether reliability risks are being driven by historical data or PJM’s selection of which data to include. He also argued that the impact of the load forecast on accreditation has created a dynamic where demand is determining the amount of available supply, running contrary to economic principles. “If our accreditation is affected by the load forecast … then this is a modeling that is not working,” he said.
Sophia Dossin, of Middle River Power, said there is a broader gap around being able to hedge capacity market risk, particularly around the prospect of changing accreditation.
Performance Strong During Record Winter Peak
PJM Director Operations Planning Dave Souder said there was excellent coordination between the RTO and its transmission and generation members as it set a new winter peak load of 145 GW on Jan. 22 as a winter storm brought freezing temperatures across the footprint. (See related story, PJM Sets Record Winter Peak Load.)
Several emergency procedures and alerts were announced ahead of the storm, including maximum generation and load management alerts, some of which remained in place until the end of the storm Jan. 23. Souder said two other days exceeded 140 GW during the storm, and it was possible two of the top five winter peaks were set that week.
Based on unit start-up requirements, low ambient operating temperature limits and historical performance, Souder said about 50 GW of resources were determined to be at risk going into the storm, leading PJM to preschedule resources and avoid cycling them on and off.
Rebecca Stadelmeyer, of Gabel Associates, said the lack of coordination between the electric and gas sectors was on display during this storm and must continue to be a focus of stakeholder efforts. She noted that scheduling fuel over long holiday weekends was one of the core focuses of efforts following the December 2022 Winter Storm Elliott, and generators reported significant losses over the Martin Luther King Jr. Day weekend after procuring packages of fuel that ultimately was not consumed. (See “Stakeholders Endorse Revised Proposal to Align Energy, Gas Schedules,” PJM MRC/MC Briefs: June 27, 2024.)
“It doesn’t seem to be changing anytime soon,” she said of the gas industry’s rules for fuel procurement.
PJM Senior Vice President of Operations Mike Bryson said it’s an issue the RTO must “wrestle with” because the long weekends remain a challenge for dispatchers and generators.
PJM’s Bresler said emergency procedures continue to not be fully reflected in market prices, which is part of the issues being addressed by the Reserve Certainty Senior Task Force.
Other Committee Business
Stakeholders deferred action on revisions to Manual 14H: New Service Requests Cycle Process that PJM said would clarify the site control requirements for projects in the interconnection queue. The RTO argues the language is necessary to create a clear set of rules to apply to all generation projects, but developers argue the proposal is too onerous and would require holding onto unneeded land to comply. (See “Vote on Site Control Requirements Deferred,” PJM MRC/MC Briefs: Dec. 18, 2024.)
PJM’s Kevin Hatch presented a first read on revisions to Manual 13: Emergency Operations to establish a new procedure for wildfires. Staff meteorologists would evaluate and discuss wildfire risks with transmission and generation owners, conduct future and real-time studies to identify transmission assets that may need to be taken out of service and coordinate with TOs to cancel future transmission maintenance and bring offline assets back into operation as needed. TOs would be responsible for monitoring red flag warnings and high risk conditions, notifying PJM of lines that may need to be de-energized, and re-evaluate the ratings of any facilities impacted by wildfires.
PJM’s Ben Miller presented revisions to Manual 40: Training and Certification drafted through the document’s periodic review. The proposal would update references to reflect organizational changes and clarify how members should respond to PJM data verification requests. It is set to go for an endorsement vote on Feb. 20.
Members Committee
Stakeholders Endorse Process for Proposals Rejected by FERC
The MC endorsed revisions to Manual 34: PJM Stakeholder Process to create a pathway for considering how to proceed after FERC rejects a member-endorsed proposal.
The language states that within 90 days of FERC rejecting a filing, PJM may present the order to a senior standing committee and recommend next steps. The presentation may be made on the RTO’s own initiative or following a stakeholder request. The discussion may include changes to the proposal that could be made, restarting the stakeholder process or following a new path.
