Fuel Cost Policy Updates for Manual 15

The Market Implementation Committee endorsed an issue charge to evaluate whether revisions to Manual 15: Cost Development Guidelines are warranted to preclude market sellers from inflating cost-based offers by using inaccurate fuel cost estimates from affiliated suppliers. The issue charge passed with 81.9% support. (See “Fuel Cost Policy Issue Charge,” PJM MIC Tackles Issue Charges, Problem Statements.)

PJM’s David Hauske said the issue charge would memorialize the RTO’s existing practices around approving fuel cost policies.

Joel Romero Luna, an analyst with the Independent Market Monitor, said all of the currently approved fuel cost policies meet the changes contemplated by the issue charge.

Stakeholders questioned how the definition of “affiliate” used in the issue charge might interact with the tariff-defined term. PJM Associate General Counsel Chen Lu said “affiliate” was lowercased intentionally to avoid tying it to the governing document definition.

Manager of Stakeholder Process and Engagement Michele Greening said PJM can revise the issue charge to allow for changes to the governing documents if necessary.

Monitor Reminder for Reviewing Fuel Cost Policies

The Monitor presented a reminder that market participants with fuel cost policies expiring in November 2026 should review the compliance of their policies and update them if needed. Those who fail to extend their policies will be required to submit a new one and either submit cost-based offers priced at zero or use PJM’s temporary cost offer method in the meantime.

PJM Proposes Performance Penalties for Non-emergency Load Management

PJM presented a proposal to assess performance penalties against demand response (DR) resources that do not meet their obligations during a non-emergency load management deployment.

Curtailment service providers (CSPs) that do not meet their obligations would be subject to a penalty rate set at half the charge for capacity resources that fail to respond during a performance assessment interval (PAI), which would be approximately $1,150/MWh for the 2027/28 delivery year. The additional penalties would count toward the annual stop-loss limit capping the amount of capacity performance penalties a resource can be assigned in a delivery year.

PJM’s Pete Langbein said the revenues collected from the penalties would be allocated to load-serving entities (LSEs) as a bonus on the logic that they purchased the capacity CSPs are expected to provide.

According to the problem statement brought by PJM, there were six deployments in the summer of 2025 totaling 30 hours, with a weighted average performance of 67%.

“This is significantly lower than in prior years and much lower than the overall test results of 103% for the [2024/25] DY. PJM expects to dispatch load management (and/or PRD will be required to respond) more frequently in the future due to lower reserve margins,” PJM wrote.

Voltus presented a non-performance penalty based on the IESO market design, which would set charges at the shortfall measured in unforced capacity (UCAP) times the daily capacity rate and a non-performance factor based on event duration. A portion of the penalties would go to overperforming CSPs, and the remainder would be allocated to consumers.

Auction Report Correction

PJM has reposted its report on the 2027/28 Base Residual Auction (BRA) to correct two errors related to the installed reserve margin (IRM).

Langbein said a rounding error on the pool-wide accreditation factor led to the IRM accreditation being understated at 14.4%. The report has been updated to correct that value at 14.9%. (See PJM Capacity Auction Clears at Max Price, Falls Short of Reliability Requirement.)

The report’s executive summary also did not account for price-responsive demand (PRD) when discussing the reserve margin.

PJM Presents Issue Charge on Storage Participation in Energy and Ancillary Service Markets

PJM’s Danielle Croop presented a problem statement and issue charge to expand the capability of the RTO’s energy storage resource (ESR) participation model to account for state of charge, opportunity costs and other participation rules for the energy and ancillary service markets.

Both documents note that PJM has an obligation under FERC Order 841 to incorporate state of charge in storage dispatching in 2026, a gap the RTO wrote can lead to infeasible dispatch instructions.

The problem statement argues a closer look at the ESR model is necessary due to the amount of storage under development in PJM.

“As of November 2025, PJM’s interconnection queue has over 3.5 GW of energy storage under construction, ~1.2 GW in transition cycle 1 and over 9 GW in transition cycle 2. Even if only a portion of these projects become operational, PJM can expect a significant increase in battery storage on its system. As its penetration grows, PJM needs to ensure that its market rules can effectively manage these limited-duration resources,” PJM wrote.

Croop said other RTOs have integrated large amounts of storage in their markets, creating an opportunity for PJM to review other market design elements and their success, such as how storage resources are required to submit offers and their parameters.

The issue charge lists market rules that may be part of the discussion as including “energy must-offer rules, intraday offer rules, uplift eligibility and resource parameters.” It also would open the conversation to whether hybrid resources should be included.

Croop told RTO Insider the energy market must-offer requirement for storage resources is not as cut and dried as for traditional resources. They are required to offer their full capability, measured in UCAP, into the market.

Responding to questions around peak shaving adjustments and load forecasting, Croop said the issue charge is narrowly focused on storage participation in the energy and ancillary service markets. While those are issues worth talking about, that should come with a dedicated issue charge.

Flexible Resource Issue Charge Endorsed

Stakeholders endorsed by acclamation an issue charge seeking to rework the definition of flexible resources, with the aim of reducing instances where resources committed in the day-ahead market on flexible parameters cannot be dispatched on other schedules in the real-time market. (See “1st Read on Flexible Resource Definition Clarification Issue Charge,” PJM MIC Tackles Issue Charges, Problem Statements.)

Flexible resources typically are held offline until committed by PJM or the resource owner self-schedules, with lost opportunity cost (LOC) credits paid to compensate the owner for real-time profits that were missed out on. The flexible definition pertains to resources that can start up within two hours and run for two or fewer hours, known as 2×2 parameters.

If a flexible resource changes either its start time or minimum run time to be longer than three hours, it becomes ineligible for LOC credits and cannot be evaluated by intermediate term (IT) SCED. The issue charge aims to address instances where a flexible offer is not needed, and other inflexible schedules could allow the resource to operate.

PJM’s Susan Kenney gave an example of a resource committed on a flexible schedule in the day-ahead market and which is offer capped due to a market power determination owing to a transmission constraint. If that constraint does not materialize, IT SCED would not be able to consider any of the resource’s other offers with inflexible parameters.

She said PJM has solutions in mind and expects the issue can be addressed within a few months, leading to the issue charge being brought through under the CBIR Lite pathway, which offers a more streamlined stakeholder process.

Stakeholders Endorse Quick Fix on Offline Resource LOC Eligibility

The MIC endorsed by acclamation a quick fix proposal to tighten when secondary reserves are eligible for LOC credits. The quick fix pathway allows for an issue charge to be brought concurrent with a proposed solution. (See PJM MIC Tackles Issue Charges, Problem Statements.)

The proposal addresses instances in which offline resources, which are supposed to be ineligible for LOC, are viewed as being online by settlement calculations and made eligible for credits.

PJM’s Suzanne Coyne said the issue arises due to a discrepancy between settlement and how real-time (RT) SCED determines if a resource is offline. The dispatch software considers a resource offline if it is not operating when assigned a commitment, while the settlement side focuses on whether the unit was operating at the start of that commitment. If the resource begins ramping up between the time it is dispatched and the start of its commitment, it can improperly be considered eligible for LOC credits.

If endorsed by the Markets and Reliability Committee at its Feb. 19 meeting, implementation could begin in March, Coyne said.