Adequacy Analysis Approved Despite Concerns

WILMINGTON, Del. — Members at last week’s Markets and Reliability Committee meeting approved PJM’s proposed revisions to adjust the methodology for developing the capacity model for winter peak weeks, despite strong dissent from stakeholders concerned about how the modifications might affect capacity procurement.

PJM’s Patricio Rocha-Garrido said the theoretical approach used by the RTO’s PRISM modeling software to derive aggregate outage levels during the winter peak week is not representative of actual aggregate historical outage levels because it relies on historical outage data at the individual unit level rather than the aggregate level.

To “better account for the risk caused by the volume of concurrent [outages] observed historically during this week,” the changes to Manual 20 create a “cumulative capacity outage probability table” using the historical forced outage data aggregated across the RTO. Planned outages will be based on the average historical planned outages aggregated across the RTO. (See “Winter Modeling Changes,” PJM PC/TEAC Briefs: May 3, 2018.)

However, several stakeholders expressed concern that the changes would reduce the potential for using seasonal resources.

“Given the summer-dominated loss-of-load-expectation, it is my takeaway that this change isn’t really going to have a measurable impact on the installed reserve margin,” Old Dominion Electric Cooperative’s Mike Cocco said. “However, if FERC orders changes to PJM’s annual capacity construct in response to several FERC [Federal Power Act Section] 206 complaints, then these Manual 20 changes potentially would have an effect by limiting the ability of seasonal capacity market resources to contribute. I would say there’s been a fundamental design change in [Capacity Performance], and I wouldn’t personally put so much focus on historical data but be looking at developing projections based on the design changes.”

“The challenge is making assumptions for the future; the only anchor point we have is the past,” Rocha-Garrido said.

“I believe that the assumption that planned outages is not a PJM-controllable level is not correct. It implies that PJM does not have control of planned outages,” CPower’s Bruce Campbell said.

He explained that lowering the expectations of units’ availability in the winter increases the overall procurement of annual resources, which means there would be less opportunity for seasonal resources to fill in the difference between the baseline amount of always-available resources and seasonal peak demands.

Carl Johnson, who represents the PJM Public Power Coalition, said he would be requesting a review for next year’s analysis of the model’s sensitivities and incorporating a different set of assumptions about how CP resources should be operating.

Some generation owners defended the revisions as necessary.

“We do need to do this. We cannot ignore it,” said Calpine’s David “Scarp” Scarpignato, who said he’s seen windmills in Texas stop working when the weather gets too cold.

Despite the concerns, stakeholders overwhelmingly endorsed the changes with 4.56 in favor and 0.44 opposed in a sector-weighted vote. The threshold for endorsement was 3.33.

The vote came on the same day PJM released a study analyzing the first year of partial implementation of CP in delivery year 2016/17 compared to the previous 2015/16 delivery year, which found that generator performance has improved since implementing CP even though the model has not been extensively tested by the extreme weather it was designed to address.

Unrelated to the MRC, Robbie Orvis of the clean energy consulting firm Energy Innovation, tweeted his own takeaways from the analysis. He noted the report’s acknowledgement of poor performance from coal-fired units during the January cold snap known as the “bomb cyclone.”

“Coal and oil Capacity Performance resources did not perform as well as their non-Capacity Performance counterparts during the cold snap. Understanding the source of this issue requires some additional analysis,” the report said. “Both coal and oil Capacity Performance resources showed no improvement in forced outage rates from the polar vortex to the cold snap.”

PJM said in the report that owners of coal-fired resources are making “major equipment overhauls and upgrades to ensure the longevity of these resources,” winterizing equipment to prevent icing and freezing, and “performing routine testing and inspections to ensure the quality of their equipment.”

Trust in Short Supply

A routine agenda item about cleaning up PJM’s governing documents turned into an impromptu stakeholder referendum on the RTO’s trustworthiness when stakeholders refused staff’s request for authority to file similarly innocuous revisions for FERC approval without stakeholder endorsement.

Members endorsed revisions to the Tariff to clarify cross references with the Operating Agreement and Reliability Assurance Agreement, but they drew the line when staff asked for stakeholders’ consent to file such non-substantive revisions in the future without having to bring them for an endorsement vote. Members allowed that staff wouldn’t need to make a presentation on the revisions but demanded they be on the consent agenda so stakeholders can review the changes.

American Municipal Power’s Steve Lieberman repeated his concerns that PJM was not affording the members sufficient time to review proposed changes to the governing documents and was shocked that the RTO’s response to that criticism was to seek the approval to make future non-substantive changes without prior member approval. Lieberman called into question whether the changes would be deemed non-substantive from a stakeholder perspective even if considered as such by PJM.

“Accidents have been made in the past, and sometimes we catch them for you,” Johnson added.

The reaction prompted Vince Duane, PJM’s general counsel, to weigh in uncharacteristically, saying he was “disappointed” given that members often complain they are overwhelmed by the slow pace of the stakeholder process and the extreme time commitments necessary to meaningfully engage in it.

“If you can’t trust us to make clerical changes … we’ve got a long way to go, and I don’t like the future at all,” he said.

Variable Operations & Maintenance Packages

Voting on whether to allow units to add certain variable costs in their cost-based offers derailed after American Electric Power asked to make several friendly amendments to its own proposal.

The proposed changes were a combination of proposals made by AEP and PJM that would allow units to include variable maintenance costs in cost-based energy offers as part of variable operations and maintenance (VOM). The package was endorsed at the Market Implementation Committee earlier this month. (See “Accounting for Maintenance Costs in Cost-Based Offers,” PJM Market Implementation Committee Briefs: June 6, 2018.)

The revisions appeared to be an effort to ensure the proposal is the first option to be voted on related to the matter. With the revisions, the proposal much more closely resembled a proposal brought for consideration at the meeting by Rockland Electric Co., which had previously expressed interest in a largely unpopular proposal from the Independent Market Monitor that eliminated all maintenance costs from energy offers. While RECO’s proposal was not as strict, it eliminated some double counting that the PJM/AEP proposal overlooked.

Because the proposal had been endorsed by the lower committee, AEP was no longer allowed to revise it, so it had to offer “friendly amendments” that required endorsement from the membership to be included in the proposal. When some stakeholders balked at being asked to consider last-minute amendments, others suggested the vote be deferred to a later meeting to give everyone a chance to review the changes.

PJM pushed members to commit to voting on the changes at the July MRC, explaining that the outcome affects the quadrennial review of the variable resource requirement curve in capacity auctions, which must be finalized in August. NRG Energy’s Neal Fitch questioned that argument, saying the parameters are cemented in August but the actual calculations don’t happen until January.

“I remain unconvinced that they’re tied together,” he said.

AMP’s Ed Tatum echoed that, saying the MRC “does have the ability to make changes to VOM as it sees fit,” irrespective of any “urgency” PJM desires to put on the timeline.

Stakeholders eventually agreed to defer the vote to the August MRC meeting, maintaining the current voting sequence for the proposals and declining to remand it to the MIC.

Waiting to make the revisions until after the quadrennial review is finalized will mean that these variable costs continue to be included in the cost of new entry calculation that is part of the foundation of PJM’s capacity auction for the next four years. Any subsequent changes that would include them in the VOM component of energy offers would mean that generators could be paid for those costs in both the energy and capacity markets until the VRR can be revised again in four years.

Credit and Default

Staff announced two member issues that will impact market participant accounts.

On Thursday, PJM declared GreenHat Energy in payment default for failing to pay its weekly invoice from June 5 of $1.2 million. The RTO will liquidate the financial transmission rights portfolio GreenHat defaulted on by bidding the balance of the 2018/19 positions into the auction that opens on July 16. Any remaining positions that aren’t liquidated there will be offered into the Aug. 16 auction.

Positions for 2019/20 and 2020/21 will be offered into the long-term FTR auction on Sept. 4. Those that aren’t liquidated will be offered into the Dec. 3 long-term auction.

The net loss or gain on these liquidated positions will be added to the actual unpaid net charges or net credits that accumulate on these positions prior to being liquidated and will be included in the total default amount that will be allocated to PJM’s members. Staff said they can’t estimate the amount of the default allocation assessment but believe it is likely to be “in the tens of millions of dollars.”

PJM will calculate each member’s estimated default allocation assessment percentage that will be applicable to GreenHat’s default after the June 2018 month-end invoices are issued on July 9, which staff hope to post by July 13. Staff said they will pursue “reasonable avenues of collection of GreenHat’s default amounts” and that any money recovered would be allocated back to members that are charged a default allocation.

Staff stressed that they have made revisions to the credit policy that they estimated would have created a $60 million credit requirement for GreenHat to acquire its portfolio had they been in place at the time. Stakeholders are also considering additional revisions to the credit policy. (See “DC Energy FTR Credit Policy Complaint to FERC,” PJM Market Implementation Committee Briefs: June 6, 2018.)

Staff also outlined a plan for allocating funds disgorged by PSEG Energy Resources and Trade as part of a FERC enforcement settlement. The more than $31 million — $26,905,736 plus interest of $4,494,264 — will be allocated as a negative operating reserve charge to market participants that received operating reserve charges during the period covered by the settlement. (See PSEG to Pay $39.4M to Settle FERC Investigation.)

The allocations will be made using a formula “consistent with the methodology utilized to allocate the original PSEG operating reserve credits” and staff hope to have the allocations credited by either June or July.

Stakeholder Process Revisions

During the Members Committee meeting, Chairman Mike Borgatti of Gabel Associates detailed several different initiatives to consider revising the stakeholder process, which had been a source of confusion.

First, he outlined an “academic” exercise being performed by Christina Simeone at the University of Pennsylvania’s Kleinman Center for Energy Policy. Earlier last week, Simeone sent a letter to the committee explaining that her Aug. 2 workshop is outside the stakeholder process and had been planned prior to the announcement at May’s committee meeting of similar initiatives within the stakeholder process. Simeone said she invited approximately 20 undisclosed PJM stakeholders that formed a “representative sample” of the membership and that “increasing the number of invitees risks distorting the representative sample and inhibiting in-depth group dialogue.” The chosen few will discuss “data analysis pertaining to PJM governance trends,” receive a presentation on the topic from Pennsylvania State University researchers and consider “a mock FERC-proposed rule on governance.”

Borgatti offered no endorsement of the workshop.

“I don’t control what Christina does. PJM doesn’t. I didn’t tell her I think this is a good idea,” he said. “In my opinion, this is exactly what it states to be: It’s an academic exercise.”

He assured members that the workshop wouldn’t be used to redesign the stakeholder process without their involvement and input.

PJM CEO Andy Ott echoed that view.

“I don’t believe her scholarship has any direct impact on what we’re going to do here,” he said.

The initiative within PJM will begin with a half-day discussion in late July to consider “target-rich opportunities to improve our process,” Borgatti said. He said the goal won’t be to fix any problems identified, but rather to decide whether they’re worth pursuing. The goal of the July session is to develop a recommended path forward that could be voted on at a future MC meeting.

Ott said he is aware of concerns about the stakeholder process and a “resignation” that nothing can be done to improve it.

“I think that feeling may not be the best situation,” he said.

“On the thorny issues, I think we do have opportunities to do better,” Tatum said, adding that collaboration will require opponents to not “immediately dig in their heels” and instead move forward without “preconceived notions.”

Stakeholders Approve Manual, Operational Changes

Stakeholders endorsed by acclamation several manual revisions and other operational changes:

• Manual 11: Energy & Ancillary Services Market Operations. Revisions developed to modify how the RTO estimates the synchronized reserve maximums for Tier 1 units in response to stakeholder concerns about significant overestimations. (See “Synch Reserve Changes,” PJM Operating Committee Briefs: May 1, 2018.)
• Manual 6: Changes to address replacing terminated nodes that are part of FTR paths. These are changes to the manual only, so they will go into effect without a vote at the MC. (See “Modeling Node Changes,” PJM Market Implementation Committee Briefs: May 2, 2018.)
• Revisions to the confidentiality provisions of the OA to specify that PJM may share member confidential information with reliability entities in addition to NERC. (See “Stakeholders Approve Changes to Manuals, Operations,” PJM Markets and Reliability Committee Briefs: May 24, 2018.)
• Changes to the long-term FTR auction construct to correct current processes that allow participants to obtain the rights to congestion on transmission paths before the owners of the underlying auction revenue rights. The Monitor reiterated its opinion that the revisions are positive but don’t go far enough. (See “Long-term FTRs Undercut Annual FTRs,” PJM Market Implementation Committee Briefs: June 6, 2018.)

— Rory D. Sweeney