Markets and Reliability Committee

Additional Reserves Needed?

Moments after stakeholders approved the charter for the Energy Price Formation Senior Task Force (EPFSTF) without comment at last week’s Markets and Reliability Committee, PJM moved to revise the issue charge on which it’s based to also address concerns about insufficient secondary reserves.

“The topic of potential new reserve products has been raised in our discussion around energy price formation,” PJM’s Dave Anders explained. “We realized that it would really be beneficial for the Operating Committee to provide some input to those considerations around reserve products.”

The EPFSTF decided that the first step is for the OC to define the “reliability-related aspects” that need to be addressed so they can be incorporated into the market-structure changes the task force is contemplating. To include that, they recommended adding a “key work activity” to the task force’s issue charge and assigning it to the OC.

The initial proposal tasked the OC with identifying the factors a 30-minute real-time product should have and how it would interact with synchronized reserves. However, stakeholders — led by the Independent Market Monitor Joe Bowring — eventually replaced that with a more generalized task to analyze secondary reserves and any “interdependencies” it would have with primary reserves.

Calpine’s David “Scarp” Scarpignato asked that the discussion include any reserve requirement changes that would interact with the reliability assessment and commitment (RAC) process and the day-ahead and real-time markets. Anders said the language had been added to the EPFSTF’s charter.

PJM’s Dave Souder said the reserve considerations are an extension of the gas-electric coordination and pipeline-contingency initiative that he has been leading since late last year. He said he plans to “set aside an hour” at each monthly OC meeting to create a recommendation on the appropriate inputs and what revisions might need to happen in real time. (See “Resilience Update,” PJM Operating Committee Briefs: March 6, 2018.)

“I think it’s within our purview at the OC to see if we have reliability need, and we can recommend that the product be developed, but how that’s developed would be through the [EPFSTF],” Souder said. “There may be times where the gas contingency is larger than our largest 30-minute requirement. Under those conditions, we may need to ensure we have sufficient 30-minute reserves.”

Congestion Overlap

Stakeholders endorsed the second phase of an initiative with MISO to address overlapping congestion. The first phase was filed with FERC in December, but PJM had to respond to a deficiency notice in January and it was not approved by the proposed March 1 implementation date. With the endorsement of the second phase, staff hope that both phases can be approved for implementation by June 1, PJM’s Tim Horger said.

The proposal addresses the potential for pseudo-tied resources to pay twice for congestion charges as their energy crosses the market borders. The first phase eliminated the charges, and the second phase allows hedging of potential congestion charges through day-ahead transactions, auction revenue rights and financial transmission rights. Owners will be refunded or charged for deviations between day-ahead submittals and real-time operations. (See MISO, PJM Pursue Pseudo-Tie Double-Charge Relief.)

Generation Transfer

Concerns with PJM’s proposed deadlines for notifying the RTO of generation transfers are being ironed out, PJM’s Rebecca Stadelmeyer said. A vote on the issue was deferred at February’s MRC meeting because some generation owners felt PJM’s timeline was too onerous. (See “Generators Hesitate on Ownership Transfer Rules,” PJM Markets and Reliability Committee Briefs: Feb. 22, 2018.)

Stadelmeyer said stakeholders have sent in redlines, and a group of generation owners, coordinated by GT Power Group’s Dave Pratzon, are engaged on the issue.

“It definitely appears PJM and the generator owners are coming to a mutual understanding,” she said.

The group has another call scheduled for March 28.

Stakeholders Approve Variety of Actions

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

• Manual 1: Control Center and Data Exchange Requirements. The revisions were developed as part of a periodic review and encompass real-time system monitoring and communication requirements, including external resources.
• Manual 3A: Energy Management System (EMS) Model Updates and Quality Assurance (QA). The revisions were developed to implement new NERC standards for transmission owners to monitor and report the quality of its real-time assessments in intervals of at most 30 minutes.
• Manual 14A: New Services Request Process and Manual 14E: Additional Information for Upgrade and Transmission Interconnection Projects. Revisions developed to implement previously approved revisions to PJM’s transmission service and upgrade requests. (See “Transmission Issues,” PJM PC/TEAC Briefs: Feb. 8, 2018.)
• Manual 33: Administrative Services for PJM Interconnection Agreement. Revisions developed as part of a comprehensive periodic review to clarify and streamline language.
• Manual 37: Reliability Coordination. Revisions developed to clarify language and simplify references to NERC standards.

Members Committee

Overlapping Congestion Endorsed Through Consent Agenda

The Tariff and OA revisions to address the overlapping congestion issue were added to the consent agenda, which stakeholders endorsed by acclamation without comment.

The issue was brought for a vote at both committees on the same day because stakeholders agreed to that arrangement when they deferred the vote at February’s MRC. The dual vote allows PJM to maintain its preferred timeline for filing and implementation.

Monitor Recommends Redrawing Market Lines

Monitor Bowring believes the lines that define regional price separations within the RTO in the capacity market are antiquated and that price separation should be dynamic based on the actual characteristics of the market. He discussed the recommendation while briefing members on the 2017 State of the Market report. (See IMM Report Says PJM Prices Sufficient.)

Bowring’s thoughts on redefining locational deliverability areas (LDAs) in the capacity market came in response to a question from Ruth Ann Price of the Delaware Division of the Public Advocate. She had asked him to expound on his recommendation that LDA definitions be dynamic and market based.

“We think that it should be based on a nodal definition so that the price separation is a function of the actual transmission characteristics of the system as well as the relative offer prices of the system,” Bowring said. “LDAs are arbitrary lines … [that are] almost without exception the old-fashioned transmission zones. There’s no reason to believe that those are the right way to have prices separate.”

He said the first step to addressing the issue is modeling every LDA to see if any prices separate. He said he hasn’t done the analysis to determine how many LDAs would price separately, but that he would investigate it.

Bowring said another “work in progress” is examining the nature of the competition to provide transmission upgrades and expansions.

— Rory D. Sweeney