MARKETS AND RELIABILITY COMMITTEE

Stakeholders Endorse Changes to Accounting of Demand Response in Load Forecasts

VALLEY FORGE, Pa. — The Markets and Reliability Committee endorsed by acclamation a quick fix proposal to account for errors in the availability of load management when calculating the unrestricted peak loads component of the load forecast. (See “First Read on Quick Fix for Revising Load Drop Estimate Inputs,” PJM MRC/MC Briefs: Nov. 21, 2024.) 

PJM’s Andrew Gledhill explained that when PJM incorporates hourly load data in the forecast, it produces estimated load drops that intend to determine what load would have been if not for load management deployments. In some instances, however, emergency conditions may be initiated at times when consumers participating in DR programs already have reduced demand. 

He gave the example of the December 2022 Winter Storm Elliott, which saw several blocks of performance assessment intervals (PAIs) declared around Christmas — including during night-time hours — when industrial and commercial DR customers were operating at reduced capacity independent of grid conditions. (See PJM Recounts Emergency Conditions, Actions in Elliott Report.) 

The revisions to Manual 19: Load Forecasting and Analysis, modify two paragraphs to grant PJM flexibility in identifying when the standard load drop estimates may be inaccurate and to apply alternatives. The language also would clarify how the estimates are used in producing the annual forecasts. 

Several stakeholders argued the language was overly broad and more detail would be needed on what methodologies PJM would use and transparency for stakeholders on when they are invoked. Gledhill said there is no one-size-fits-all and PJM prefers to keep its options open-ended. 

Calpine’s David “Scarp” Scarpignato and Gabel’s Rebecca Stadelmeyer offered amendments to the language that would direct PJM to present stakeholders with information should it use the discretion the revisions would offer. Gledhill accepted such an amendment.

Vote on Site Control Requirements Deferred

Stakeholders voted to delay action on revisions to Manual 14H: New Service Requests Cycle Process, which would codify PJM’s interpretation of the site control rules for planned resources in the interconnection queue. Several developers have called PJM’s interpretation overly strict and argued it would require them to retain unnecessary land. (See “Stakeholders Endorse Quick-fix Revisions to Site Control Manual Requirements,” PJM PC/TEAC Briefs: Dec. 3, 2024.) 

EDF Renewables Director of Transmission Policy Emma Nix said delaying would allow manual revisions to be informed by a complaint filed by the American Clean Power Association, Solar Energy Industries Association and Advanced Energy United, which argues PJM’s interpretation of the site control rules in the tariff do not conform to its language and would present unnecessary development costs (EL25-22). Nix motioned to have the item removed from the MRC’s consent agenda. 

PJM’s Jason Shoemaker said the application window for Transition Cycle 2 closed Dec. 17 and staff seeks to implement the language quickly to provide developers with clarity on the rules. He added that the vote would not be an end to the RTO’s ongoing conversations with developers on site control requirements. 

“These developers need to have some understanding of how their projects are going to be moved through the process,” he said. “We’d like to see the vote go forward today because it does impact our developers today.” 

The revisions would allow parcels to be removed from a project so long as it continues to meet the minimum acreage and energy output listed in the project application. Land could be added to a project at Decision Point 1 so long as either it is adjacent to the site, or evidence of easements is provided. If the energy output is reduced, the land requirements also correspondingly would go down. 

The revisions would seek to clarify language stating there are no specific site control evidentiary requirements associated with Decision Point 2 to specify that “site control must be maintained throughout the cycle process.” A note also would be added stating that parcels can be added similarly to DP1, with the caveat that a one-year term would be imposed from the end of Phase 2 of the relevant study cycle. 

No additions would be permitted at the final Decision Point 3, but reductions would be allowed so long as the acreage-per-megawatt and evidentiary requirements continue to be met. Once a generator interconnection agreement is signed, any site control changes would require a necessary study agreement (NSA) to determine permissibility. 

The revisions also would correct Exhibit 10 in the manual, which inadvertently used a diagram from another exhibit when describing how generators interconnect to existing transmission substations.

Discussions on CETL Shifted to ELCC Task Force

The committee endorsed a change to an issue charge to charge the newly formed Effective Load Carrying Capability Senior Task Force (ELCC STF) with addressing a “disconnect” between PJM’s winter-focused accreditation and the use of summer peaks when calculating zonal capacity emergency transfer limits (CETL). (See “Stakeholders Endorse LS Power Issue Charge on CETL,” PJM PC/TEAC Briefs: Nov. 6, 2024.) 

Endorsed by the Planning Committee on Nov. 6, the issue charge originally assigned the work to the PC. But ELCC STF Chair Michele Greening said PJM staff found there is a lot of synergy between the CETL discussions and the other two topics the task force is addressing, both on substance and timelines. 

The task force also is in the early phases of working on issue charges addressing the transparency of the ELCC model and how it is used to determine resource accreditation. Both were approved by the MRC during its Oct. 30 meeting. 

The revisions to the CETL issue charge also extended the work timeline to target a FERC filing in May 2025, rather than the first quarter of 2024. 

First Read on Extended Notification Requirement for Deactivating Generation, Changes to Compensation

PJM’s Chantal Hendrzak presented a first read on proposed changes to PJM’s rules for deactivating resources, extending the notification they must provide PJM before they can go offline, increasing the amount of data that is posted publicly and revamping the compensation for units that enter reliability-must-run (RMR) agreements. (See PJM Stakeholders Delay Vote on Generator Deactivation Rules.) 

The tariff revisions would require generation owners to provide 12 months’ notice ahead of their desired deactivation date, in addition to the existing must-offer exception deadlines on units that would not participate in the capacity market. PJM would publish publicly the estimated RMR revenue allocation zonal rate for zones that would be affected by an RMR agreement; postings also would be expanded to include Independent Market Monitor determinations on market power, deactivation response letters and RMR agreement notifications. 

The $2 million cap on project investments that can be included in the deactivation avoidable cost rate (DACR) would be eliminated and the scaling element of the yearly adder on investments would be shifted to a static 10%. A provision that replaces the DACR with the daily deficiency rate if the DACR and multiplier are greater than the deficiency rate also would be removed. 

The proposal is one of three the Deactivation Enhancement Senior Task Force (DESTF) voted on in October, carrying 69% support and winning out over a second PJM-sponsored package with fewer changes to compensation and a proposal from the Monitor that would have limited RMR agreements to five years and required stakeholder notification of agreements at least a year in advance.

Several Manual Revisions Endorsed

PJM’s Ryan Nice presented a slate of revisions to Manual 1: Control Center and Data Exchange Requirements, expanding its backup and emergency communication modes, as well as changes drafted through the document’s periodic review. The committee is set to vote on endorsement at its Jan. 23 meeting.  

He said the AltSCADA communication process allows inter-control center communications (ICCP) links to be transmitted between PJM and transmission owners using simple spreadsheet files in the event that default SCADA software is offline, such as through a cyberattack. The changes also include an expansion of the RTO’s read-only mode that prevents ICCP data from being edited during planned maintenance windows where the risk of incorrect data being submitted is increased. 

The periodic review changes include updating definitions to be clearer and more consistent with other manuals. 

PJM’s Liem Hoang presented a set of revisions to Manual 38: Operations Planning, to include information about the Operational Planning Analysis used in the Day-ahead Market and specify that CEII access is necessary to review the analysis. The language is set to be considered by the Operating Committee on Jan. 9 and the MRC on Jan. 23, with immediate implementation if approved.  

PJM’s Susan Kenney presented a set of revisions to Manuals 27 and 29 to remove outdated references, make grammatical corrections and add a description of how the non-zone network load responsibility is assigned to network customers in Manual 27. The MRC is set to vote on the changes Jan. 23. 

MEMBERS COMMITTEE

Sector Representatives and MC Vice Chair Elected

The Members Committee voted to elect representatives to serve on the Finance Committee for its 2025 term, sector whips and named Steve Kirk of NextEra Energy Marketing to serve as MC vice chair. American Municipal Power’s Lynn Horning will be chair of the committee. 

The new sector representatives on the Finance Committee will be: Susan Bruce, of the PJM Industrial Customers Coalition, representing end use customers; Jeff Whitehead, of Eastern Generation, representing generation owners; Steve Kirk, representing other suppliers; and Laura Yovanovich, of PPL Utilities, representing transmission owners. 

The sector whips for 2025 will be: 

• • John Rohrbach, of the Southern Maryland Electric Cooperative (SMECO), for the electric distributor sector. 

• • Greg Poulos, of the Consumer Advocates of the PJM States (CAPS), for the end use customer sector. 

• • David “Scarp” Scarpignato, of Calpine, for the generation owner sector. 

• • Sean Chang, of Shell Energy North America, for the other supplier sector. 

• • Jim Davis, of Virginia Electric & Power Co., for the transmission owner sector. 

PJM Presents Manual Language Detailing Process After FERC Rejection of Stakeholder Packages

PJM presented a first read on a proposal to revise Manual 34: PJM Stakeholder Process to establish a standardized path for PJM to follow when FERC rejects a stakeholder-endorsed proposal. The language is set to be voted on during the committee’s Jan. 23 meeting, with AMP and the Delaware Division of the Public Advocate intending to move and second the motion. 

Acting on its own accord or stakeholder request, PJM could hold a presentation within 90 days of the order on the commission’s rejection and recommend how to proceed. The proceeding discussion would include all possible stakeholder options, such as restarting the stakeholder process, identifying changes that could be made, new proposals or any other decision decided the senior standing committee agrees on. 

Greening said the manual is currently silent on how PJM and stakeholders should proceed after the commission rejects a proposal, leading to instances where there was disagreement on next steps. One such instance followed FERC denying a proposal to implement multi-schedule modeling by using a formula to select energy market offers to be entered into the Market Clearing Engine. The original proposal was rejected by the commission in March, and PJM opted to bring the alternative that received the second-highest vote count for endorsement. (See “Monitor, PJM Present Processes to Enable Multi-schedule Modeling,” PJM MRC/MC Briefs: June 27, 2024.)