WILMINGTON, Del. — Has the door for revising PJM’s Capacity Performance calculations been opened too far? Some stakeholders fear so after members at last week’s Markets and Reliability Committee meeting endorsed revisions to an issue charge for an initiative examining the calculation of the balancing ratio used in setting capacity offer caps.

Originally, the market seller offer cap (MSOC) equation was out of scope in the inquiry being conducted by the Market Implementation Committee and members were only focused on how to determine the balancing ratio.

The balancing ratio needs to be addressed because it is currently based on the number of performance assessment intervals PJM experienced in the past three years, and it can’t be determined if there are no such events. That became a reality this year, requiring PJM to reuse last year’s as a stopgap until a new calculation is developed. (See “Stopgap Balancing Ratio OK’d Despite Questions,” PJM MRC/MC Briefs 10-26-17.)

Beyond the balancing ratio, the issue charge also allows for evaluating how many assessment intervals are assumed in calculating the nonperformance charge rate. The current assumption is 30 intervals per year, which some stakeholders have argued is too high.

But Joe Bowring, PJM’s Independent Market Monitor, pointed out that changes to the nonperformance charge can affect the MSOC, so the MIC needs the latitude to consider changes to it as well. It’s important to maintain the consistent relationship between the nonperformance charge rate and the MSOC, said PJM’s Pat Bruno, who was presenting the proposal.

“We can’t keep the equation ‘net [cost of new entry] times B’ as the default offer cap out of scope with this issue charge because any changes we make with the nonperformance charge rate may impact that default offer cap equation,” he said.

Exelon’s Jason Barker questioned that position, arguing that FERC approved the specific MSOC equation — the net CONE for a unit’s technology class multiplied by the balancing ratio. He said all the necessary assessment-interval changes can be made while keeping “the FERC-approved tether to net CONE” by ensuring the interval calculation remains consistent throughout the formulas, a point on which Bruno agreed.

Barker said that — and not a potential wholesale re-evaluation of the MSOC — is what he believed stakeholders were agreeing to when they approved the issue charge. Other stakeholders agreed.

“I don’t think there’s anything in the issue charge as it stands now that would prevent us from completely changing the nonperformance charge rate,” Bruno acknowledged.

But Bowring argued there’s nothing “magical” about the current MSOC and that FERC approved the logic through which the equation was developed.

“You have to address this additional question if all of these issues are at play, which they are at the moment,” he said.

Barker said he couldn’t endorse the widened scope and encouraged others to vote against it as well.

Other stakeholders voiced concerns about the potential effect on other market mechanics, but Barker’s lobbying fell short. The proposal was endorsed with five objections and one abstention.

Offer Cap Walk Back Stalled

PJM’s hope to return to previous language over energy market offer caps was dashed after stakeholders agreed with Bowring that the previous rules also weren’t correct.

Members approved the current Manual 11 language at the October 2017 MRC to comply with FERC Order 831. PJM staff subsequently discovered the revisions restrict market-based offers to $1,000/MWh, contradicting language in the Operating Agreement. The proposal would have reverted to previous rules that market-based incremental energy offers may not exceed $1,000/MWh unless the cost-based incremental energy offer is greater than that amount. In that case, the market-based incremental energy offer is capped at the lesser of the cost-based incremental energy offer or $2,000/MWh.

The current proposal was pushed through PJM’s stakeholder process unusually quickly, with a first reading at the Members Committee webinar just three days before the MRC meeting. PJM’s Rami Dirani said the quick turnaround was necessary to maintain consistency because the order became effective on April 12. He described the return to the prior language as “very straightforward,” but Bowring disagreed.

“It doesn’t strike me as being so straightforward,” he said, noting that the previous rules didn’t address PJM’s obligation to verify cost-based offers ex ante — based on forecasts — and ensure that price-based offers not exceed cost-based offers of more than $1,000.

Carl Johnson, representing the PJM Public Power Coalition, noted that many Manual 11 changes were being discussed in October, “so maybe it just slipped our focus. But I thought we knew what we were doing then, and it’s clear from reading the manual language that we didn’t.”

The changes were originally made to reduce complexity, Dirani said.

“The inclination would be to spend a little more time on this rather than move another … rule that is not right,” Johnson said.

Other stakeholders agreed.

Calpine’s David “Scarp” Scarpignato asked that PJM return with some comparison of potential rule changes.

“I need to know more than just the mechanics,” he said.

“I’m sure it seems simple; you’re going back to previous language. So I’m sure it felt simple, but it has obviously led to further questions,” said Adrien Ford with Old Dominion Electric Cooperative.

Staff agreed to send the issue back to the MIC for discussion but said they aimed to get feedback in time to have a proposal prepared for a vote at next month’s MRC.

Price Formation Reshuffle

PJM’s Adam Keech outlined staff’s plan to address energy market price formation changes in accordance with the Board of Managers’ request that stakeholders break the issue into pieces so that less controversial changes can be implemented sooner. The board made its request in a letter April 11. (See PJM Board Seeks Reserve Pricing Changes for Winter.)

The plan breaks potential changes into short-, mid- and long-term goals that correspond with the board’s request that some reserve market changes be ready for implementation by next winter and that other energy market changes be prepared for next spring.y

In the short term, PJM plans to focus on the synchronized reserve market, dynamic reserve zone modeling, simplifying the operating reserve demand curve (ORDC) and fast-start pricing if FERC approves the proposal PJM has already filed.

The mid-term topics for the first quarter of 2019 would include developing a 30-minute reserve product, along with additional revisions to the ORDC and fast-start pricing.

The long-term plan would extend the implementation of integer relaxation and look to add shortage pricing to the day-ahead market.

“My interpretation of the discussions [at the most recent meeting of the Energy Price Formation Senior Task Force] was there were no objections to moving forward with that,” Keech said.

Greg Poulos, the executive director of the Consumer Advocates of the PJM States, said his members don’t necessarily see the need to make these changes, “but we are aligned with the goals” of analyzing the situation to see if any changes are warranted.

The consumer advocates are particularly interested in cost-impact analyses, he said.

Stakeholders OK Manual, Operating Agreement Changes

Members approved changes to Manual 12: Balancing Operations to incorporate rules approved by FERC in November regarding reviews required for approval of pseudo-tied generators. The changes were endorsed with two objections and three abstentions. (See “External Capacity,” PJM PC/TEAC Briefs: March 8, 2018.)

Stakeholders also endorsed unanimously several manual revisions and other operational changes:

• Manual 14A: New Services Request Process. The revisions clarify language to match existing procedures and add language to describe in detail system impact study (SIS) and interconnection feasibility study analyses. In January, a FERC administrative law judge issued an initial decision finding that PJM’s process is unjust and unreasonable because of a lack of transparency (EL15-79). On Feb. 20, PJM filed a brief on exceptions challenging the ruling. (See FERC Judge Faults PJM, TOs on Transmission Upgrade Process.)
• Manual 14B: Regional Transmission Planning Process. The revisions are the result of a periodic review that identified several administrative changes, including a revision to the generator deliverability procedure and adding the Ohio Valley Electric Corp. to the western region study area definition. (See “Transformer Consideration Changed for Gen Deliverability,” PJM PC/TEAC Briefs: March 8, 2018.)
• Manual 28: Operating Agreement Accounting. The revisions address changes to comply with FERC Order 825 implementing five-minute settlements. Also makes a technical correction for the revenue data used to calculate settlements for generation resources. (See “Order 825 Implementation Moves Forward,” PJM Market Implementation Committee Briefs.)
• Revisions to the Operating Committee charter to replace the term “spinning reserve” with “synchronized reserves” to match the language in PJM manuals.

— Rory D. Sweeney