Questions Remain as PJM Continues Push for Price Formation Revisions

PHILADELPHIA — Stakeholders hoping to influence PJM’s plans for revising its price formation methodology had better move quickly. RTO staff unveiled their problem statement and issue charge on the topic at last week’s Markets and Reliability Committee meeting and hope to have it approved at the next one on Dec. 21.

“If you are going to follow up … please do so soon,” PJM’s Stu Bresler said of the proposal, which would create a senior task force “investigating energy and reserve price formation enhancements [to] … more transparently reveal the true cost of meeting system reliability needs.”

PJM has set up an email — price_formation@pjm.com — to compile comments on the proposal.

In advance of a decision looming at FERC to provide price supports for nuclear and coal-fired units, PJM has been campaigning for support of an alternative. It would remove the prohibition on letting inflexible generators — often large coal and nuclear plants — be the price-setting marginal unit in its real-time and day-ahead energy markets. It would also factor in start-up and no-load costs, which are currently set aside.

PJM says these “simplifications” were used during the development of LMPs to reduce the time necessary to successfully dispatch the system. Large inflexible units are often dispatched despite clearing prices that are below their offers and receive uplift payments that compensate them for their costs. Out-of-market uplift payments have been a source of stakeholder frustration for years. (See PJM MRC OKs Uplift Solution over Financial Marketers’ Opposition.)

“From the initial implementation of locational marginal pricing, given that it is an optimization … we made some simplifying assumptions up front,” Bresler said.

PJM’s plan wouldn’t eliminate uplift and calls for making additional lost opportunity cost (LOC) payments for flexible units with lower offer prices to reduce their output to balance load and generation. But the RTO argues that the reduced uplift and LOC payments combined would be a fraction of the current uplift payments.

Still, stakeholders have been cautious to endorse the plan and asked that it not be rushed into implementation.

James Wilson of Wilson Energy Economics, who consults with several consumer advocates within PJM’s footprint, said the RTO’s proposed timeline for completing the task force before the fourth quarter of 2018 is too ambitious.

Joe Bowring, PJM’s Independent Market Monitor, echoed that.

“This is a massive change. There’s no reason to not have thought it through carefully,” he said, listing other market components beyond the energy and reserve prices that would be “impacted” by the change, including financial transmission rights and rules for Capacity Performance, market-power mitigation and uplift.

“I ask you to get stakeholder input and consider other options,” said Greg Poulos, the executive director of the Consumer Advocates of the PJM States (CAPS).

Bob O’Connell of Panda Power Funds asked PJM to “reserve judgments” about what causes and solutions the task force could discuss.

“Impairing flexibility because of the way we’re paying suppliers, that’s something we need to talk about,” he said.

Gabel Associates’ Mike Borgatti requested education for market participants to update their modeling assumptions.

Susan Bruce, who represents the PJM Industrial Customer Coalition, asked that load receive “fair notice” of the changes and a way to measure what the impact will be. “We have a lot of load that’s locked in because of low energy prices,” she said.

DER Charter Endorsed

After several contentious discussions at previous MRC meetings, members endorsed by acclamation the charter for the Distributed Energy Resources Subcommittee, which will consolidate PJM’s efforts on DER.

The charter had been contentious because of an addition that required all rules to “adhere to all pertinent jurisdictions” and regulators. Some stakeholders saw it as stating fact, while others were concerned it could be used to stifle discussion.

Bruce asked the group to be “extremely cautious” and that its proposals could result in costly requirements for “people who are not represented in this effort because they have chosen not to be in the PJM markets.”

PRD Rules Deferred

Stakeholders voted to defer a planned vote on new rules for price-responsive demand (PRD) pending the deliberations of the recently formed Summer-Only Demand Response Senior Task Force.

The RTO wants to change the PRD rules to comply with its CP requirements. PJM’s Pete Langbein attempted to characterize it as “just another [supply-side] option that would be out there that folks could elect to choose.” But state representatives complained that the proposed changes fail to acknowledge PRD’s value.

“It’s not a capacity product. It’s a mechanism to refine the load forecast,” said Morris Schreim of the Maryland Public Service Commission. “It’s not competing with supply.”

He argued against a change in the PRD rules that would “close the door” on solutions in the task force and suggested tabling the vote pending the outcome of the task force. Gregory Carmean, executive director of the Organization of PJM States Inc. (OPSI), agreed with Schreim that “it is time to take a pause,” saying it’s “hard to reconcile” the RTO’s justifications.

Langbein clarified that PRD displaces resources, either generation or demand response, with year-round capacity on a one-for-one basis. “That is the reality,” he said.

Calpine’s David “Scarp” Scarpignato called PRD “inferior” to generation in the context of CP and urged a vote. Waiting will make it harder to adjust the rules later as companies make decisions based on the current rules, he said. “We need this in place for the next [Base Residual Auction].”

EnerNOC’s Katie Guerry said it’s “alarmist” and “unproductive” suggest that all DR on the system would convert to PRD without the rule changes and said she was “looking forward to analyzing the opportunities” through the task force.

“Please participate in that process regardless of what sector you’re in,” she said, because that is where she sees any “real solution” being developed for summer-only DR that can no longer qualify as a capacity resource.

The deferral passed with just enough votes to clear the two-thirds threshold, receiving a 3.44 score (out of 5) in a sector-weighted vote.

Stakeholders Have Questions Before Approving MOPR-Ex

The Monitor will hold a question-and-answer session Tuesday to address stakeholder concerns on its proposed revisions to the capacity construct. The changes to the minimum offer price rule (MOPR) are expected to be brought to a vote at the Dec. 21 MRC meeting.

The IMM’s proposal was the only one to receive more than 50% approval in a poll of the Capacity Construct/Public Policy Senior Task Force, which has been meeting throughout the year to address concerns about market distortions from subsidized generators. The proposal would extend the MOPR to cover all units indefinitely, though it would include several exemptions.

Bowring said the proposal is meant to create an incentive for subsidized units “not to exist in the first place.” He fielded enough questions that stakeholders asked for a separate forum before voting. Jason Barker of Exelon, which had submitted its own proposal to the task force, questioned Bowring’s contention that the proposal is nondiscriminatory.

“Why do you think it’s appropriate to allow an overbuild?” he asked of one of the rule exemptions.

“I hear the point, and you’re right,” Bowring responded. “Let us think about that; it’s a good point.”

“You don’t have an answer to that? We’re going to have to vote on this,” Barker pressed.

“You’re not going to have to vote today,” Bowring replied. “We’ll have something out well ahead of the vote.”

PJM agreed to shorten its Dec. 12 Operating Committee meeting to make time for the Q&A.

Stakeholders Move Incremental Auction Proposal

For the second time in three months, no proposal from the Incremental Auction Senior Task Force received enough support to be proposed at the MRC, a fact that American Municipal Power’s Steve Lieberman argued should preclude PJM from automatically bringing its proposal for MRC review, even if it was just seven votes shy of the threshold at the task force. But Exelon’s Sharon Midgley moved for a vote on PJM’s Proposal A” and Bruce seconded it. The proposal received a first read and will be voted on at the next MRC.

“This is a compromise … but it’s all in the interest to try to get something before FERC so the issue of excess capacity and the sellback can get addressed, favorably for load,” Bruce said.

CPower’s Bruce Campbell argued the proposal doesn’t maximize the value of IA returns for load and said he was prepared to back another proposal “if others are interested,” but he received no support.

Other Voting Results

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

• Manual 11: Energy & Ancillary Services; Manual 18: PJM Capacity Market; Manual 27: Open Access Transmission Tariff Accounting; Manual 28: Operating Agreement Accounting; and Manual 29: Billing. The revisions implement PJM’s transition to five-minute settlements under FERC Order 825.
• 2018 day-ahead scheduling reserve (DASR) requirement. The final DASR calculation dropped to 5.28%, which was even lower than PJM’s preliminary estimates in October. The 2017 DASR was 5.48%. PJM attributed the year-over-year drop to reductions in average seasonal load forecast errors and the forced-outage rate. (See “DASR Requirement Drops Again,” PJM Operating Committee Briefs: Oct. 10, 2017.)
• Tariff and Operating Agreement revisions to modify credit requirements for regulation and FTRs:
  • Regulation credits are accrued daily and billed monthly, while energy charges are accrued daily and billed weekly. Although the regulation-only resources’ credits are much greater than the charges, the weekly bills for charges create a credit requirement, even though the much larger credit is due to the provider at the end of the month. Daily regulation credits will now be included in weekly instead of monthly activity for calculating credit requirements. The change will apply to all resources, not just regulation-only resources.
  • FTR credit requirements for prevailing paths currently are based on weighted historical congestion on those paths, but transmission system upgrades can reduce congestion, decreasing the value of prevailing-flow FTRs. PROMOD simulation results will now be incorporated into the FTR credit calculator prior to the bid window to incorporate consideration of major upgrades and reduce default exposure to PJM’s members. (See “Give Them Some Credit,” PJM Market Implementation Committee Briefs: Oct. 11, 2017.)

Members Committee

Stakeholders Endorse Consent Agenda

Stakeholders endorsed by acclamation the committee’s consent agenda along with several other OA and Tariff changes:

• OA revisions associated with PJM sharing of restoration planning generator data with transmission owners. (See “TOs to Receive Confidential Generation Data for System Restoration,” PJM Operating Committee Briefs: Sept. 12, 2017.)
• Tariff revisions related to a proposed change in credit requirements for regulation resources. (See “Other Voting Results” above.)
• Tariff revisions to FTR credit requirements to reduce exposure posed by congestion changes resulting from major transmission upgrades. (See “Other Voting Results” above.)

Nominees Approved

Members elected new representatives to the Finance Committee, sector whips and the Members Committee vice chair for 2018. It is the Transmission Owners sector’s year to choose a vice chair, and Chuck Dugan of the East Kentucky Power Cooperative was nominated.

— Rory D. Sweeney