By Rory D. Sweeney

WILMINGTON, Del. — Still unable to reach consensus on the specifics of what to study, PJM members balked again last week at a request from a coalition of demand-side stakeholders to revisit the Capacity Performance construct.

By the end of the lengthy discussion at the Markets and Reliability Committee meeting Thursday, American Municipal Power’s Ed Tatum, who has represented the coalition in committee discussions, admitted he was at his wit’s end.

“I’m getting ready to curl up on the floor into a ball and roll around,” he said.

But even without the coalition’s initiative, stakeholders had plenty of capacity-related issues to discuss at last week’s MRC meeting, debating underperformance rules, seasonal capacity and pseudo-ties. They also began considering another look at ways to limit capacity auction arbitrage.

Tatum’s coalition continued to struggle with the scope of its proposed issue charge. The current issue charge suggests it is states’ public-policy actions that might upset the delicately balanced CP market. (See Review of PJM Capacity Market Put on Hold.)

However, John Farber of the Delaware Public Service Commission urged that the issue not be framed that way. “The existential threat is not with states, but possibly [to] customers who have to pay the eventual costs,” he said.

Some stakeholders pushed for adding more topics to those listed, while others said they opposed broadening the scope. Susan Bruce, an attorney who represents the PJM Industrial Customer Coalition, said the proposal needs to be broad enough to cover more than just capacity market impacts but narrow to the extent that PJMICC isn’t interested in talking about alternatives to RPM.

“I appreciate the dilemma,” she said.

EnerNOC’s Katie Guerry requested that the proposal’s language be more accommodating toward change rather than defensive. “Why don’t we set up a more productive process where we can work toward solutions?” she asked.

Both Bruce and Exelon’s Jason Barker said they would attempt to edit the proposal into something they could support, but “I’m not sure how to address that or to modify the current statement,” Barker conceded.

“What I’m hearing today is, ‘let’s re-broaden the discussion, at least to start.’ … I don’t understand what people want. Do they want to have a broad discussion and narrow it?” asked Jeff Whitehead, whose Direct Energy is a sponsor of the proposal. “It’s a pretty big ask of this group to have us find the right scope of this discussion before we start the work. One of the main issues here is defining what are these public policies that impact the wholesale market.”

Tatum said his goal is to find the CP version of the Serenity Prayer: a construct that can change what’s within its authority to change, accept what it can’t change and know the difference.

The lack of consensus caused frustration among the proposal’s sponsors. PJM’s Dave Anders, the committee’s secretary, suggested a separate informational meeting on the topic, but none of the sponsors actively supported the idea.

“I personally don’t see a need for an informational meeting,” said Steve Lieberman of Old Dominion Electric Cooperative. He said it would be “surprising” if there were new perspectives on the proposal than the ones that had already spoken up.

“Frankly, if we don’t want to talk about this, let’s stop talking about it,” Whitehead said.

Carl Johnson of the PJM Public Power Coalition, which also sponsored the proposal, reminded everyone that ignoring the issue wouldn’t make it go away. “If we don’t have this conversation, it’s going to happen without us,” he said.

Farber, who had registered the first concern with the proposal, nonetheless expressed support for it, saying the committee was “letting the perfect be the enemy of the good” and that he didn’t want to see it succumb to “paralysis by analysis.”

Stakeholders acknowledged that the current proposal was “substantially different” from past iterations. Tatum said he needed to confer with the coalition before deciding the next step.

Stakeholders not Quite Done with Seasonal Capacity

Stakeholders balked at PJM’s suggestion to sunset the Seasonal Capacity Resources Senior Task Force, saying there is more work to be done despite the RTO’s announcement Oct. 19 that its Board of Managers will file a “facilitated aggregation” proposal with FERC. (See PJM to Seek FERC OK for Seasonal Capacity Proposal.)

While stakeholders praised the job PJM’s Scott Baker has done steering the task force, they derided the RTO’s handling of the issue. PJM’s proposal was one of five voted on by the task force in September, but it received only 32% support.

CPower’s Bruce Campbell said he was “very disappointed in PJM’s actions in … pre-empting a viable discussion.” Guerry explained that the reason some stakeholders were upset is because the RTO’s action was contrary to stakeholders’ “expectation of the rules and how the process was supposed to play out.”

Barker, however, commended PJM’s leadership on the issue. “Let’s sunset it and move on,” he said.

Bruce suggested a “quick hibernation,” as when it announced the planned filing, PJM had noted that there were additional pieces of the structure to work out.

The indignation with PJM transitioned to the next discussion, in which Whitehead presented to the committee his proposal from the task force. His “substantive but simple” proposal would allow base capacity to participate in the auction for another year to allow enough time to fully consider the topic, he said.

“It’s our view that the board decision unfortunately wasn’t informed by some of these critical pieces of the stakeholder process,” he said.

Seasonal resource owners were only able to address the differences between forecasted peak loads in summer and winter “at kind of a cursory level,” he said. PJM has experienced colder periods than the 2014 polar vortex on which much of the capacity decision-making is based, he said. Its top winter peak-load day occurred in February 2015.

“I’m not sure it continues to make sense to continue to make reliability procurement decisions based on one year’s experience,” he said. “It doesn’t make a lot of sense that we would buy capacity to run somebody’s air conditioner in January.”

While Farber said the additional transition year was “critical,” Howard Haas of Monitoring Analytics, PJM’s Independent Market Monitor, objected to the proposed extension. Barker said the polar vortex highlighted issues that further investigation of a new seasonal-capacity construct might not address. “We need to be mindful of the nature of the winter constraints that we saw,” he said.

“I’m not disputing that this needs to be studied. That’s actually what I’m asking,” Whitehead said.

Later in the meeting, James Wilson of Wilson Energy Economics proposed a problem statement and issue charge to review PJM’s procedures for evaluating winter-capacity needs. “I don’t think it calls for a lot of changes, mainly just a few updates,” Wilson said. “It was really never much of a topic. … Winter capacity matters, we’ve learned.”

PJM’s Stu Bresler indicated that the FERC filing will likely occur prior to November’s MRC meeting. Because the task force sunset, the base capacity extension and the winter resource analysis proposals were presented as first reads, none will be voted on until that meeting — presumably after PJM has made its filing.

Underperformance Changes Would Weaken CP, Says PJM, Monitor

Asked to develop proposals for two CP issues, the Underperformance Risk Management Senior Task Force was only able to find consensus to endorse one.

The task force was charged with analyzing PJM’s pseudo-ties and flowgates to determine the impacts of integrating external CP resources. Of the four options proposed, the highest approval that any package reached was 38%. However, 78% preferred a change over the status quo.

PJM’s Rebecca Carroll said feedback is being collected from stakeholders through a new nonbinding poll, the results of which will be available this week. The group expects to review results and determine next steps at its Nov. 10 meeting.

The task force was also assigned to review underperformance rules. The endorsed package — which received nearly 55% approval — will be put up for a sector-weighted vote at the November MRC.

It would make several changes to Manual 18: PJM Capacity Market and Attachment DD of the Tariff including:

• Basing the nonperformance penalty on the highest Base Residual Auction clearing price in any locational deliverability area instead of net cost of new entry;
• Allowing underperforming units to find replacement megawatts from over-performing units in the same performance assessment hour area. Under current rules, such transfers are allowed only within the same capacity account with PJM;
• Adding a new mechanism for transferring the replacement megawatts; and
• Adjusting the stop-loss provision from annual to monthly.

Howard Haas of Monitoring Analytics, PJM’s Independent Market Monitor, was quick to register his objection to the proposal. “We think it’s going to weaken the product to the point where it no longer incents performance,” he said.

Others agreed, including Barker, PJM Public Power Coalition’s Johnson and the RTO itself.

“PJM cannot find itself in a position to support this package” Bresler said, explaining that it’s “too far down” the slope of not requiring CP units to perform at the exact time they’re needed, which the existing construct was specifically designed to do.

The proposal did have some champions, though, including Talen Energy’s Tom Hyzinski and John Horstmann of the Dayton Power and Light Company. Horstmann said adding a monthly stop-loss provides protections for the supplier and ultimately reliability because a monthly limit would provide generators with incentives to perform throughout the delivery year. Additionally, basing penalties on net CONE creates inconsistent penalty rates across differing LDAs, he said, and disproportionately penalizes the lowest-priced capacity with the highest percentage loss of revenue for a PAH penalty. Hyzinski said there are many other incentives to perform that keep the proposed changes from diluting CP.

Later in the meeting, Barry Trayers of CitiGroup Energy proposed another Manual 18 revision to eliminate a prohibition on how early a capacity obligation replacement can be made. Trayers’ proposal was followed by a friendly amendment from PJM that refined the language of the proposed rule change. The proposal will be brought back at November’s MRC for a vote. No one voiced any concerns about how the separate replacement changes would integrate.

Buy High, Sell Low?

Stakeholders would consider anew the price differences between the BRA and incremental auctions under a problem statement proposed by Whitehead.

Whitehead said the stark differences between the BRA clearing prices and the lower IA prices raises the potential for abuse. Noting that load is receiving cents on the dollar on excess capacity released by PJM in the later auctions, he proposed investigating whether IA prices yield reasonable and accurate results and revise policies if they don’t.

Citing results from recent auctions, Whitehead highlighted the disparity that creates an incentive to sell during the BRA and buy back during the IA at much lower prices.

Other stakeholders agreed. Calpine’s David “Scarp” Scarpignato said the structural issues between the two auctions “[create] a lot of speculation.”

For all but one delivery year between 2012/13 and 2016/17, the third IA auction clearing price has been a fraction — between 8 and 20% — of the BRA price.

The only time the IA price exceeded the BRA was 2015/16, when PJM did not sell back excess capacity in the IA.

Whitehead also noted that PJM’s excess sales have resulted in much larger reductions in the capacity acquired than in the cost savings to load. “In essence, load gets a lot less reliability in exchange for a negligible reduction in capacity cost,” the problem statement says. “Load should be appropriately compensated for the resulting reliability reduction, in consideration of the fact that, among other benefits, capacity in excess of the PJM’s planning targets can have value in a tail reliability event.”

The issue is not a new one. In 2013-14, stakeholders wrestled with ways to eliminate what some called “arbitrage opportunities” between the BRA and IAs. The effort ended in May 2014, after FERC rejected a plan to curb speculation in the auction, saying it created undue barriers to entry. (See PJM Wins on DR, Loses on Arbitrage Fix in Late FERC Rulings.)

The commission ordered a Section 206 proceeding and technical conference to explore the issue further (EL14-48) but did not schedule the conference after PJM asked the commission to defer action while it developed CP.