VALLEY FORGE, Pa. — PJM doesn’t plan to contest a FERC ruling that may have contributed to the increase in demand response clearing in last week’s Base Residual Auction, Senior Vice President of Operations and Markets Stu Bresler told Thursday’s Markets and Reliability Committee meeting.

On May 8, the commission rejected rule changes PJM developed to discourage market participants from selling capacity in the BRA and buying back their obligations at lower prices in Incremental Auctions, a practice that has led to concerns that arbitrageurs are offering capacity they have no intention of providing. The Independent Market Monitor says DR providers disproportionately replace BRA commitments in the IA. (See FERC Closes Book on PJM’s ‘Paper Capacity’ Concerns.)

“At this point, PJM does not intend to seek rehearing,” Bresler said, noting FERC’s “strongly worded” rejection of the filing to revise IA rules, which also terminated a related Section 206 proceeding.

PJM plans to allow the 30-day rehearing window to expire and then meet with FERC to discuss the RTO’s next steps, he said. FERC staff had told PJM that they wouldn’t entertain a prefiling meeting on the IA revisions because of the outstanding 206 proceeding on the issue. By letting both expire, Bresler said he believes FERC will be willing again to discuss the issue.

“We do intend to bring this back to stakeholders about how to move forward,” he said. “We think a discussion with FERC would be very valuable.”

FERC’s May 8 ruling may have played a role in why more DR cleared as annual resources in the BRA for delivery year 2021-22. DR offered into the auction increased almost 21% to 11,887 MW, nearly 94% of which cleared. Of the 11,126 MW of DR that cleared — up 3,305 MW from last year — 96% cleared as annual Capacity Performance and 452 MW cleared as summer-only resources that were aggregated with other products to meet CP’s requirement for year-round commitment. (See Capacity Prices Jump in Most of PJM.)

DR participants have complained that they can’t receive a capacity commitment because they struggle to meet CP’s year-round requirement and have requested seasonal products. But several MRC members speculated they might have been more emboldened to take the risk because FERC’s decision ensured at least one outlet remains. PJM’s IA revisions were meant to close a loophole that allows market participants to receive higher prices for supply obligations in the BRA and pay less in subsequent IAs to offload those commitments.

VOM Remanded

Stakeholders at last week’s MRC meeting were spared an expected showdown on variable operations and maintenance (VOM) cost accounting after Rockland Electric’s Brian Wilkie indicated an interest in deferring the vote. The idea ended up being motioned and seconded by others, but stakeholders were happy to endorse it and return the issue to the Market Implementation Committee.

Monitor Joe Bowring was prepared to make a presentation in defense of his proposal on the issue, but stakeholders preferred to address it at the lower committee, where the proposal earlier failed to receive an endorsement to be considered at the MRC. (See “VOM Proposal,” PJM Market Implementation Committee Briefs: April 4, 2018.)

Offer Cap Revisions Stalled Again

Two sets of changes to Manual 11: Energy & Ancillary Services Market Operations were approved by acclamation, but a third set dealing with offer caps was sent back to the MIC for additional review.

The approved changes focused on bidding and unit-parameter submissions. The first set includes conforming changes regarding bidding locations for virtual transactions. The second set expands the window for when generators can make intraday offers. (See “Intraday Offers,” PJM Market Implementation Committee Briefs: May 2, 2018.)

The revisions returned to the MIC were developed to ensure consistency between the manual and Operating Agreement regarding price-based offers over $1,000/MWh. The change was necessitated by FERC Order 831, which required RTOs and ISOs to raise their hard caps for verified cost-based incremental energy offers to $2,000/MWh. (See “Offer Cap Resolution,” PJM Market Implementation Committee Briefs: May 2, 2018.)

PJM’s Susan Kenney said the discrepancies occurred because the Order 831 compliance filings failed to appropriately update the Tariff and OA, so the manual’s $1,000/MWh cap conflicts with the OA, which permits price-based offers to exceed $1,000/MWh if they are less than a verified cost-based offer. As an immediate fix, PJM is proposing capping all offers at $1,000/MWh by default and allowing higher offers to submit a request for verification. The system will be automated once the capability has been developed.

For price-based offers, PJM is “strongly” suggesting operators allow a “switch to cost” option that excludes price schedules from dispatch. Otherwise, they can request the ability to submit price-based offers in line with verified cost-based offers, but they are then on the hook to ensure price-based offers at each segment remain compliant with verified cost-based offer caps.

The Monitor argues the solution should be holistic to include a full implementation in PJM’s offer submission software and related manual changes. Until then, PJM should seek an exception from FERC to use the revised “switch to cost” method, which includes the $1,000/MWh cap, the Monitor said.

Last month, Manual 11 revisions to correct inconsistencies with PJM’s governing documents regarding offer caps failed to receive MRC endorsement and were sent back to the MIC as well.

Long-term FTRs

PJM and the Monitor presented members with separate proposals to revise the long-term financial transmission rights market.

The proposals are meant to correct current processes that allow participants in the long-term FTR market to obtain the rights to congestion on transmission paths before the owners of the underlying auction revenue rights. Both proposals would do away with the “year all” product in the market and only offer annual products for each of the next three years.

PJM’s proposal would model all ARRs that clear in the annual model as fixed injections and withdrawals in the long-term auction model. Any transmission outages that would impact the ARRs would be removed. PJM argues this would accurately represent any residual capability left on the system.

The Monitor’s proposal would set the residual capability for the auction at zero and require all prevailing-flow capability to be generated from counterflow FTRs. The Monitor’s Howard Haas argued this would eliminate the risk of any overallocation between the long-term auction and annual auctions and establishes counterparties in the market.

“We think it’s going a little too far,” PJM’s Tim Horger said of the Monitor’s proposal.

“We think PJM’s going in the right direction … but it does not go far enough,” Haas said in response.

Horger said he was interested in seeing what the “true capability” is in the long-term model.

Members will be asked to endorse one of the proposals at the June MRC.

Stakeholders Approve Changes to Manuals, Operations

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

• Manual 36: System Restoration. Revisions developed as part of the manual’s annual review; includes clarifications regarding synchro-check relays, blocking governors and black start generators.
• Manual 3: Transmission Operations. Biannual review to update operating procedures. Revisions update remedial action schemes, sectionalizing schemes and definitions for the Cleveland and Eastern interfaces; designate voltage limits for Ohio Valley Electric Corp.’s impending integration; add language regarding reactive reserve check submittals; and clarify notes on load shed activity.
• Manual 14A: New Services Request Process. Annual review. Revisions developed to introduce the Queue Point software for submitting data for feasibility and system impact studies.
• Manual 7: Protection Standards. Revisions developed by the Relay Subcommittee to add clarity, update terms and add reliability requirements.
• Manual 14D: Generator Operational Requirements. Revisions developed to define procedures and notification deadlines for transferring ownership of generation resources. (See “Gens Get Commercial Realities into Gen Transfer Processes,” PJM Operating Committee Briefs: May 1, 2018.)
• OA revisions allowing PJM to share member confidential information with the Eastern Interconnect Data Sharing Network (EIDSN) in addition to NERC and other reliability entities. EIDSN was created in 2014 to develop industry tools that NERC has decided it no longer wants to create and maintain.

— Rory D. Sweeney