Stakeholders Endorse Manual Revisions Conforming to New FERC Requirements

VALLEY FORGE, Pa. — The PJM Markets and Reliability Committee endorsed revisions of Manual 14B to align with new language in NERC’s TPL-001-5.1 standard during its July 26 meeting. The changes aim to establish new transmission system performance requirements. (See “Stakeholders Endorse Quick Fix Manual Revisions to Conform to NERC Standards,” PJM PC/TEAC Briefs: July 11, 2023.)

The new language increases the requirements for PJM’s spare equipment standards, creates a new threshold for new outages to be included in the planning horizon and expands the technologies considered part of a component protection system.

The previous NERC standard required that RTOs include outages longer than six months in their planning horizon, which was changed to leave the rationale up to the organizations. PJM proposed looking at upgrades to 230-kV or higher rated equipment or outages that would last longer than five days.

The proposed spare equipment standard would involve PJM reaching out to asset owners to inquire about their policies for maintaining spare equipment to replace any failures that could take a year or two to replace. If those owners don’t maintain an inventory, PJM would conduct a study to evaluate the impact of that equipment failing.

The changes were brought before the July Planning Committee meeting as a quick fix proposal, which allows for a problem statement, issue charge and solution to be brought concurrently and voted on in the same meeting. The manual changes were effective immediately following MRC endorsement.

PJM and Monitor Present Generation Deactivation Issue Charge

PJM’s Paul McGlynn gave a first read of a problem statement and issue charge being drafted in collaboration with the Independent Market Monitor that would investigate increasing the deadline for generators to notify PJM of plans to deactivate, the compensation for generation owners that agree to continue operating facilities beyond the desired deactivation and the triggers offering a generator a reliability-must-run (RMR) contract.

Possible changes to capacity market rules and cost allocation for RMR contracts are out-of-scope in the issue charge. McGlynn said a new senior task force reporting to the MRC is the envisioned route for engaging in the discussion given the number of areas that deactivations impact, including planning, markets and operations.

The only reason PJM currently can provide for seeking an RMR is transmission reliability criteria, but McGlynn said there may be other reasons it wishes to keep a generator operating. The primary rationale the RTO envisions is losing reliability parameters such as black start when a generator goes offline.

Monitor Joe Bowring said the current rules create a lot of confusion and uncertainty, which results in resources being wasted on proceedings. “The rules need to be clarified,” he said.

Vistra’s Erik Heinle questioned if there would be a limiting principal in how long an RMR contract could run for, adding that it could take a long time to replace the black start service provided by a given generator while also discouraging other resources interested in investing to provide that service.

“Before we go down this route, we need to be careful to think of where we may end up,” he said. “We need to be careful of what signals we’re sending to the market.”

McGlynn said PJM’s goal is to keep RMR contracts as limited in use and duration as possible.

“Nobody wins when there’s an RMR. In general, the generators — they’ve already made the decision to deactivate, they want to deactivate it,” he said.

Bowring said he’s concerned about broadening the scope of RMR and believes it should be as narrow as possible but is willing to discuss options.

Dominion’s Jim Davis questioned if part of the rationale for re-evaluating how RMR contracts function is to slow the pace of retirements or make it take longer for them to exit the market. He said the company would not support any changes that could hinder generators’ ability to retire and that one of the purposes of a functional capacity market is to send price signals, including for retirement.

“Ultimately, the decision to retire a resource belongs to the resource owner and that decision is partially made to redirect capital,” he said.

McGlynn said the intent is to look at the process after the decision to retire has been made and support that determination. Senior Vice President of Market Services Stu Bresler added that the longer notice period for deactivation requests is meant to ensure the grid is prepared for resources to go offline.

Susan Bruce, of the PJM Industrial Customers Coalition, said it’s important RMR doesn’t become more attractive than market participation for some resources. She supported discussion of additional triggers for opening an RMR contract and said it also may be prudent to make capacity market changes in scope, given the large changes being considered in the Critical Issue Fast Path (CIFP) process and elsewhere.

Stakeholders also questioned if the voluntary nature of RMR contracts would be in scope, to which McGlynn said his understanding is that PJM can’t force generators to continue operating. Bresler said the issue charge doesn’t explicitly preclude having that discussion but that it may be a question for FERC to decide if PJM has the authority.

Paul Sotkiewicz, president of E-Cubed Policy Associates, said he believes not explicitly ruling out discussion of permitting RMR contracts to maintain resource adequacy is “extremely dangerous” and should be out of scope. The capacity market has its own backstop and RMR should be focused on transmission needs, he said.

Several stakeholders also questioned if the complexity of the topic may not lend itself to the “CBIR Lite” (Consensus Based Issue Resolution) process.

PJM Seeks Stakeholder Process on Reserve Certainty

PJM’s Donnie Bielak presented a wide-spanning issue charge and problem statement on reserve certainty, with several immediate, medium-term and long-term goals for stakeholders to consider in a proposed new senior task force. PJM has seen a decline in the response rate for reserve deployments since the two tiers of reserves were consolidated in a reserve market overhaul implemented Oct. 1. That resulted in PJM increasing the synchronized reserve requirement by 30% this year, overriding stakeholder objections. Bielak said it’s likely nobody was happy with that outcome, and the goal of the new issue charge is to find better permanent solutions. (See “Stakeholders Reject PJM Synch Reserve Manual Change; RTO Overrides,” PJM MRC/MC Briefs: May 31, 2023.)

The seven key work activities include reserve performance and penalties, aligning the offer structure with fuel procurement, how resources are deployed and PJM’s target reserve procurement. The proposed timeline for immediate need topics, such as performance and penalties, is to have a solution within a year, while the long-term need to incentivize resource flexibility to match grid needs is set for three to five years.

Heinle said he’s concerned such a wide range of topics could lead to the task force becoming directionless, a fate he said befell the resource adequacy senior task force before it was converted to the CIFP process with a tight turnaround mandated by the Board of Managers. He suggested that finding ways of keeping the work focused on specific areas would help prevent the process from outrunning stakeholders’ best intentions.

Sotkiewicz said he believes more education on the impact of the reserve market changes implemented in October is needed and that the lower response rate could stem from a software or design issue in the new system. He said prices are decreasing leading up to a spin event, which is the opposite of what should be happening. He said PJM rhetoric about generators underperforming and the possibility of enforcement actions has been unhelpful.

“I think there’s something actually much more systemic here that requires more investigation and education … for members to understand that,” he said.

Bruce said more analysis is needed to understand the dynamics of how the increasing number of inverter-based resources on the grid impacts reserves and what their contribution looks like. More education also is necessary to understand what is driving the lower performance. She said she worries if that is not established, it could lead to consumers spending more money on reserves to shore up the issue.

“The solution cannot be let’s just have customers pay more for reserves. Because if we don’t understand what the problem is … that’s just throwing money at the problem,” she said.

Bowring said the issue charge is too broad and should be broken into smaller stakeholder processes. He said he believes synchronized reserves’ failure to respond in recent months has to do with communications and training.

First Read on Peak Market Activity Credit Activity Proposal Expected in August

The Risk Management Committee (RMC) has finalized a slate of packages it plans to vote on during its August meeting, which will be followed by a first read at the MRC during its Aug. 24 meeting. Thomas Zadlo, RMC chair, said PJM is exploring ways of expediting a vote at the RMC to either hold a same-day vote in August following the first read or use other accelerated stakeholder actions to allow the proposal to be implemented in time for winter.

Constellation’s Adrien Ford said the company supports any acceleration that can be found while still respecting the need for appropriate document review.

Proposed changes include introducing minimum exposure and minimum transfer amounts, setting maximum amounts that can be invoiced over given timeframes and changing how collateral shortfalls and surpluses are calculated.

Other MRC Discussions:

• • Several state consumer advocates objected to or abstained from endorsing revisions to Manual 13 stemming from its periodic review, which Gregory Poulos, executive director of the Consumer Advocates of the PJM States, said was due to dissatisfaction that the review of the manual did not take into account how emergency notifications and public messaging performed during the December 2022 winter storm. The changes were approved by acclamation as part of the consent agenda.
  • PJM presented a first read of proposed revisions to Manual 13 to include essential actions in NERC’s cold weather preparations for extreme events. Changes focus on the amount of detail needed in member load-shed plans.

Members Committee Endorses IROL-CIP Cost Recovery

The Members Committee voted to endorse a PJM-sponsored proposal to create a cost-recovery mechanism to allow generators to recoup expenses incurred by making upgrades after being designated critical to the derivation of an interconnected reliability operating limit (IROL) under NERC’s critical infrastructure protection (CIP) standards. The acclamation vote had six objections and 11 abstentions. (See “MRC Endorses IROL-CIP Cost Recovery,” PJM MRC/MC Briefs: June 22, 2023.)

PJM’s Darrell Frogg, who presented to the MC Wednesday, has compared the cost-of-service payment structure in the proposal to the cost-recovery structure for black start service, with generators submitting their costs to the RTO and Monitor to review and costs allocated to market participants.

The proposal was opposed by the Monitor, who presented a competing proposal in the Operating Committee, on the grounds the costs should be included in generators’ market offers and it could become a slippery slope to new non-market cost-of-service structures for other services, a concern he returned to Wednesday. He argued there is no explanation for what differentiates IROL-CIP-related costs from other services generators include in their offers.

Bruce said some industrial customers abstained from the vote over concerns the process PJM uses to select IROL-CIP facilities may lead to increased costs if PJM designates one generator, it makes the requisite upgrades and then PJM shifts the designation to a different resource. She said the “heartache” isn’t with having to pay for reliability upgrades, but rather with cost minimization.

Poulos said some advocates who abstained from the MRC vote switched to being in opposition because of a concern the proposal turns away from using markets and toward a less transparent cost-of-service approach.

PJM Assistant General Counsel Thomas DeVita said he believes the proposal included a healthy balance between allowing generators to recover costs while protecting consumers. He said costs incurred before the critical designation or those that would have been made regardless can’t be included and the proposal also includes provisions to avoid double counting.

“We have some very significant and serious protections built in for customers,” he said.