The PJM Market Implementation Committee on Wednesday endorsed an initiative to update the RTO’s business rules to accommodate co-located generation and energy storage hybrid resources.

The issue charge passed unanimously by acclamation and is set to be overseen by the proposed Distributed Energy Resource and Inverter-based Resources Subcommittee (DIRS).

Scott Baker, PJM business solutions engineer, provided a first read of the problem statement and issue charge for the effort, which will define how current requirements for solar parks, solar resources, intermittent resources and energy storage resources do and do not apply to generation-battery hybrids.

The focus of discussions will initially be centered on solar-battery resources, which represent more than 95% of the more than 10,000 MW of hybrids in the PJM interconnection queue. But the issue charge allows for investigation of other hybrid resources like wind-battery, gas-battery or any other combination. Baker said that as a result of stakeholder feedback at the Markets and Reliability Committee, the issue charge calls for the subcommittee to begin work in July and report its findings and proposed solutions to the MIC by the end of 2020. (See “Action on Hybrid Resource Initiative Deferred on Venue Question,” PJM MRC Briefs: April 30, 2020.)

Baker said the solar-battery hybrid issue assignment was intentionally left blank because the MIC is also discussing the consolidation and creation of the DIRS. He provided the first read of the charter for the new subcommittee and a proposal to sunset the Intermittent Resources Subcommittee (IRS). The IRS originated as the Intermittent Resources Working Group (IRWG) in 2008 to address issues regarding operations and reliability, energy markets, capacity markets and interconnections.

Baker said that although DIRS would operate under the MIC, stakeholders requested that the subcommittee also coordinate with the Planning and Operating committees. Baker said many of the issues discussed at DIRS could affect both markets and operations.

PJM will seek endorsement of the new subcommittee at the next MIC meeting on July 8.

PRD Credits Disposition

Sharon Midgley of Exelon provided a first read of the problem statement and issue charge addressing the price-responsive demand (PRD) credits disposition. The issue calls for the MIC to review the market design to determine if the current load-serving entity PRD credits are appropriate and to explore alternative allocations.

PRD providers represent retail customers that have the capability to reduce load in response to prices. Midgley said current PJM settlement rules do not address electric distribution companies (EDCs) or curtailment service providers (CSPs) that do not have direct responsibility for serving retail load but otherwise meet the eligibility requirements of a PRD provider.

All revenues associated with PRD are credited to the LSE for the area, Midgley said, meaning some market participants are paid for PRD service that an EDC or CSP is supplying while performance penalties stay with the PRD provider.

The committee will vote on the issue charge endorsement at its July meeting. The work effort is expected to take six to nine months, with changes implemented in advance of the 2021/22 delivery year.

Performance Assessment Interval Settlements

Danielle Croop of PJM conducted a first read of a problem statement and issue charge to increase transparency in settlement calculations for nonperformance charges, including ancillary service accounting and the determination of scheduled megawatts. It will also include provisions to make language for energy-only and demand response resources parallel with that of generation resources.

In March, PJM released a report on performance assessment interval (PAI) settlements as an addendum to its review of the Oct. 1-2, 2019, performance assessment event, when an abnormal heat wave led to emergency procedures and the first call on DR resources in more than five years. (See PJM, Stakeholders Baffled by DR event.)

The incident resulted in $8.2 million in nonperformance charges. Bonus payments averaged $32.89/MW-interval, with the average amount of megawatts eligible for bonuses during the event being 9,706.

In her presentation, Croop said PJM staff found the settlement calculations for the Oct. 1-2 emergency event lacked transparency. A market notice was posted on PJM’s capacity market webpage detailing how the RTO settled the charges and credits.

Croop said the RTO will seek stakeholder input on business rules not described in detail in the governing documents. The initiative will memorialize the business rules in the appropriate agreements and manuals without changing the substance of Capacity Performance rules.

Independent Market Monitor Joe Bowring said he disagreed with some of PJM’s proposed language changes, calling it “subjective” and difficult to interpret. Bowring said some of the proposed rules may not be consistent with CP.

“We want to make sure the end result is that this process works properly,” Bowring said.

The MIC will vote on the issue charge approval at its July meeting.

FERC Transmission Orders

PJM’s Ray Fernandez provided updates at both the MIC and the June 2 Planning Committee meeting on the cost allocation impacts of two recent FERC orders requiring resettlement.

In the first order, FERC ruled that PJM must rebill parties to reverse incorrect cost assignments of Form 715 transmission projects. The costs, which had been allocated 100% to the zone of the host transmission owner, have been spread more widely, reflecting the projects’ regional benefits. (See FERC Stands Firm on Form 715 Assessments.)

PJM found 44 projects impacted by the order, including 33 in the PSEG zone and 11 in the Dominion zone.

Dominion Energy will collect almost $28.5 million in refunds from two dozen other transmission zones, led by American Electric Power and Commonwealth Edison, which will be billed more than $4 million each, according to an estimate posted by PJM on May 27.

Public Service Electric and Gas is owed $53.2 million from five companies, led by Linden VFT ($19 million), Neptune ($15.2 million) and Consolidated Edison ($13.2 million). PJM cautioned that the revised cost assignments could change based on FERC rulings or additional review by the RTO.

In the second order, FERC ruled that two merchant transmission operators in New Jersey are still liable for some cost allocations under PJM’s Regional Transmission Expansion Plan (RTEP) despite converting from firm to non-firm service after the cancellation of the Con Ed-PSEG “wheel” in 2017 (ER18-680). (See FERC Rejects Cost Formula for NJ Merchant Tx.)

Linden and Hudson Transmission Partners (HTP) own merchant transmission facilities that carried power into New York City as part of the wheel, in which 1,000 MW were exported from upstate New York to PJM through PSE&G facilities in northern New Jersey, and then exported to the city. Con Ed and PSE&G canceled the agreement in April 2017, prompting HTP and Linden to convert their firm transmission withdrawal rights (TWRs) to non-firm TWRs.

HTP would be billed $24.1 million and Linden $5.7 million under PJM’s resettlement estimate. PSE&G is the biggest beneficiary, due $22.9 million.

Linden, Long Island Power Authority, Neptune and the New York Power Authority (NYPA) made requests for a rehearing to FERC, Fernandez said. Linden and NYPA also requested settlement relief if FERC does not grant a rehearing request by delaying billing until January 2021 and to allow for a 12-month settlement period in equal installments from Jan. 1, 2021, through Dec. 31, 2021.