1st Read on 2nd Phase of CIFP Manual Revisions

VALLEY FORGE, Pa. — PJM presented stakeholders with proposed manual revisions to implement a requirement that dual-fuel generators must offer schedules with both of their fuels into the energy market during the winter, as well as changes to the operational and seasonal testing for capacity resources.

The proposal is the second package of manual updates to conform with tariff revisions approved by FERC in January 2024 as part of PJM’s Critical Issue Fast Path (CIFP) capacity market rework (ER24-99). (See “Stakeholders Endorse Manual Revisions to Implement CIFP Changes to Capacity Market,” PJM MIC Briefs: May 1, 2024.)

The dual-fuel requirement would be added to Manual 11 and specify that combustion turbines and combined cycle committed as dual-fuel capacity resources offer their alternative fuel into the energy market during the winter or follow outage reporting requirements.

The summer/winter capability testing requirements in Manual 18 would be redefined to focus on whether a resource participating in the capacity market or a fixed resource requirement plan is able to output its daily installed capacity (ICAP) minus the 95th percentile hourly seasonal net output. A resource that has a daily ICAP value exceeding the tested capability during that season would be subject to shortfall charges until it is able to test to a greater capability.

Changes to Manuals 14, 18, and 28 would allow PJM to subject capacity resources to up to two operational tests in the summer and winter. Intermittent resources, including the variable component of a hybrid resource, would be exempt from both testing requirements.

The penalty rate for failing either of the tests also would be changed to be determined by multiplying the daily deficiency rate, ICAP shortfall and accredited unforced capacity (AUCAP) factor; the status quo uses the equivalent demand forced outage rate (EFORd) instead of the AUCAP factor.

The committee will vote on the changes at its meeting in February, with a vote by the Markets and Reliability Committee in April.

PJM Presents Changes to Black Start Compensation

PJM’s Glen Boyle presented a proposal to revise how generators providing black start service are compensated to remove the net cost of new entry (CONE) as an input.

The RTO would instead use a fixed rate derived from the average RTO-wide net CONE values over the past five years, coming out to $272.62/MW-day. That would be multiplied by the unit capacity and varying multipliers depending on resource classification to arrive at the black start service cost, which is one component of the base formula rate that determines compensation. The fixed rate would be reevaluated every five years as part of the holistic review of the service. Boyle said PJM is trying to break the tie between black start revenues and net CONE.

The proposal is set to be voted on by the MIC on Feb. 5, followed by the MRC on March 19.

The net CONE component has come under scrutiny after PJM presented planning parameters for the 2026/27 Base Residual Auction, scheduled for July, which saw net CONE values fall to zero in some zones. One of several pending filings PJM submitted to FERC in December would revert a change in the reference resource that net CONE is based on from a CC generator back to a CT unit. (See PJM MIC Briefs: Dec. 4, 2024.)

While using the status quo formula for the 2025/26 delivery year would result in decreasing black start revenues across all zones — an overall 22.73% decrease and exceeding 50% in one area — the proposal would result in compensation remaining nearly equal to the previous year’s.

Calpine’s David “Scarp” Scarpignato said he does not see a link between net CONE and black start service and added that he appreciates the straightforward nature of PJM’s approach.

Independent Market Monitor Joe Bowring said the proposal appears to be an arbitrary change that would perpetuate the use of what he called an irrelevant metric — net CONE — in compensating black start units. He proposed that black start resources be compensated for the cost of providing black start plus an incentive rather than net CONE. He questioned why net CONE should be subject to escalator given that it depends on net revenues, which vary from year to year.

Bowring also said the original rationale for the PJM proposal is no longer true as it based its proposal on the basis that net CONE would be zero in multiple locational deliverability areas (LDAs) because it was planning to use a CC as the reference unit.

“While the gross CONE of a CC is higher than that of a CT, the net CONE of a CT is higher than the net CONE of a CC. There are no LDAs with negative net CONE,” Bowring said.

Discussions Continue on Demand Response Availability Window

Stakeholders continued to weigh in on PJM’s proposal to eliminate the demand response availability window and instead model the resource class as being available in all hours, following arguments from curtailment service providers that there is unrecognized potential for consumers to reduce their load any time of day. (See “PJM Proposes Changes to Demand Response Availability Window,” PJM MIC Briefs: Oct. 9, 2024.)

The prospect of a wider availability window became especially significant for DR in the wake of PJM’s redesigned risk modeling paradigm, which FERC approved in January 2024. That shifted the focus to winter, when reliability risks are more dispersed across the day, from a few peak hours in the summer.

PJM’s Pat Bruno said the proposal would build a specific load profile for DR in light of analysis that found that program participants have a different average load profile from general load.

When determining the winter peak load (WPL) for the resource class, Bruno said adding up the peak load for each participant would overstate capability because consumers’ load could peak in different hours. Instead, the proposal would measure the WPL across five winter coincident peak (WCP) days at the 8 to 9 p.m. hour, as that is when overall class capability most coincides with system peak load. Because both profiles may change over time, this would be reevaluated regularly.

Aggregate average hourly DR load profiles also would be created across the five WCP days for use in the effective load-carrying capability (ELCC) analysis driving risk modeling and resource accreditation. The average would be at its lowest between 1 and 4 a.m., when DR would be modeled at 63% of its maximum reduction capability.

ELCC ratings for DR could increase by about 20%, with values also increasing for resources that perform better in the summer. Ratings for storage could increase between 8 and 10%, depending on the duration of the resource, and thermal and storage could see more modest boosts. Onshore and offshore wind values would fall by 2% and 4%, respectively. System reliability risk as a whole would shift toward the summer by about 4%.

Because individual consumer load profiles can vary, Bruno said there is less correlated outage risk, and the impact of changing the amount of DR that participates in the auction has less of a marginal impact than for other resources.

Bowring said that PJM’s asserted increase in the ELCC value for DR ignored the fact that DR had underperformed during the December 2022 winter storm.