Markets and Reliability Committee
Stakeholders Endorse CIR Transfer Proposal
VALLEY FORGE, Pa. — The PJM Markets and Reliability Committee on Nov. 21 endorsed a proposal to create an expedited process to study interconnection requests that would reuse the capacity interconnection rights (CIRs) of a deactivating resource.
The tariff revisions, proposed by East Kentucky Power Cooperative and Elevate Renewable Energy, were approved with 77% sector-weighted support and added to the Members Committee’s consent agenda, which also passed during the committee’s meeting later that day. (See “CIR Transfer Proposal Discussed,” PJM MRC Briefs: Oct. 30, 2024.)
Under the proposal, PJM would study replacement resource requests in parallel with projects sorted into the standard interconnection queue with the aim of offering developers an interconnection agreement on an eight- to 10-month timeline. To minimize impacts on queue timelines, CIR transfers would be studied using the most recent phase 2 or 3 grid model developed for queue clusters.
The process could be initiated within one year of a formal deactivation notice being received. The replacement resource would be required to interconnect at the same substation and voltage as the original resource, though it could be physically located elsewhere so long as it ties in at the same point. The maximum facility output and CIRs would have to be equal to or lesser than the deactivating generator.
Paul Sotkiewicz, president of E-Cubed Policy Associates, said the proposal would allow developers to take advantage of transformers and other infrastructure already in place to avoid supply chain issues causing delays to construction across the U.S.
“This is something that helps avoid some of the supply chain issues to get resources on quicker,” he said.
Greg Poulos, executive director of the Consumer Advocates of the PJM States, said his members were divided on the motion, with some supporting it as an improvement that would speed development. Others are concerned that interconnection would remain too slow, in part because of the ability for generation owners to wait a year before transferring CIRs, and preferred a design the Independent Market Monitor offered during deliberations at the Planning Committee. If the MRC had not endorsed the proposal, Poulos said some advocates intended to move the Monitor’s proposal as an alternative.
The Monitor’s package would have prohibited bilateral exchange of CIRs and instead created a PJM-administered process to shift headroom from retiring resources to any project in the queue or proposed by a developer that could resolve transmission violations associated with that deactivation.
A third proposal sponsored by PJM at the PC was closer to the endorsed proposal — allowing CIRs to be traded after a deactivation — but would have imposed tighter eligibility limits, including outright barring storage, and required that any replacement resources that prompted network upgrades or would consume available headroom be removed from the expedited process and directed to submit an application to be studied under the wider queue.
The language endorsed by the MRC and MC would allow projects with network upgrades to proceed so long as they cover associated costs. Developers also would be permitted to reduce the scope of a project to avoid network upgrades before proceeding.
The EKPC-Elevate proposal received 51.8% support at the PC during the Oct. 8 vote, while PJM’s design received 40.6% and the Monitor’s received 11.1%.
Monitor Joe Bowring said he does not believe the expedited process would be an improvement, and PJM would continue to face challenges attracting new entry. He suggested it should expand its Reliability Resource Initiative to be retained as a long-term tool to speed interconnections when reliability issues are identified. The initiative — an in-development, interim accelerated interconnection process — would open 50 slots for high capacity factor projects to be added to Transition Cycle 2, allowing them to be studied in advance of projects that have yet to receive a queue position.
He argued that a private, bilateral CIR trading process would introduce delays and create market power for holders of existing CIRs. Owners of deactivating assets would be able to pick the highest bidder for the replacement resource, rather than PJM being able to select the projects that would have the highest impact. Intermittent and storage replacement resources also would not be required to offer into the capacity market, meaning they may not provide the reliability benefit PJM is seeking through the process.
Third Phase of Hybrid Resource Rules Endorsed
Stakeholders endorsed by acclamation a proposal to implement the third phase of PJM’s hybrid resource rules, expanding the model to include non-inverter-based generation paired with storage.
The language is slated to be voted on by the MC on Dec. 18. (See “1st Read on 3rd Phase of Hybrid Resource Rules,” PJM MRC Briefs: Oct. 30, 2024.)
Participation in the energy and ancillary service markets would be along the lines of the Energy Storage Resource Participation Model detailed in Manual 11; capacity accreditation would focus on the storage element of the resource while taking into account the availability of the generation component.
Hybrids with any component subject to the requirement that resources offer into the capacity market also would be subject to the must-offer rule. Hybrids with no component subject to the rule, such as intermittent generation or storage, would not be mandated to participate in the market.
PJM’s Maria Belenky said a friendly amendment was offered following the first read in November to align the binding notice of intent requirement for hybrids with other resource classifications. She said stakeholders pointed out that a different timeline would exist for hybrids than all other planned resources under the original tariff language drafted.
First Read on Quick Fix for Revising Load Drop Estimate Inputs
PJM’s Andrew Gledhill presented a proposal to grant PJM more flexibility to reflect errors in the availability of load management when calculating the unrestricted peak loads component of the load forecast.
The revisions to PJM Manual 19: Load Forecasting and Analysis are being brought as a quick fix — allowing the issue charge and solution to be voted on concurrently — in an effort to have the changes effective for the 2025 load forecast.
Gledhill said the change is intended to account for instances when load management deployments occur at times that participants are operating below their peak load, which would reduce the estimated load drop PJM is likely to receive. That includes holidays when industrial consumers are likely to be offline.
If starting with the premise of peak load contribution rather than what the actual loads would be at that time, Gledhill said it’s likely inaccurate information would be included in the forecast.
PJM’s Pete Langbein said that historically, peak loads were concentrated on hot summer days, but the RTO’s risk modeling has shifted the focus toward winter deployments, when the energy reduction capability can vary more significantly. Load drop estimates are used to calculate unrestricted load for forecasting, capacity compliance and the addback reported to the utility for the following year. The hourly forecasts also are an input into the effective load-carrying capability models used in resource accreditation.
Manual Revisions to Clarify DASR Calculation for 30-minute Reserves
PJM’s Kevin Hatch presented revisions to Manual 13 to document how the day-ahead scheduling reserve (DASR) is used to determine when the 30-minute reserve requirement may be insufficient for procuring adequate reserves.
The Operating Committee endorsed the language as a quick-fix proposal during its Nov. 8 meeting. (See “Stakeholders Endorse Quick Fix Solution on Day Ahead Scheduling Reserve Calculation,” PJM OC Briefs: Nov 8, 2024.)
The 30-minute reserve is set at the greater of 3,000 MW, the primary reserve requirement or the largest active gas contingency, which Hatch said does not reflect the full range of operational risks dispatchers must account for when determining necessary reserves. The DASR calculation accounts for load forecast error and forced outage rates, both of which were factors that PJM sought to include in a dynamic 30-minute reserve formula stakeholders rejected in July. (See “Stakeholders Endorse Reserve Rework, Reject Procurement Flexibility,” PJM MRC Briefs: July 24, 2024.)
Hatch said the revisions reflect an existing practice and no changes are being made to PJM processes.
Manual 14D Periodic Review
PJM’s Madalin How presented a package of revisions to Manual 14D drafted through the document’s periodic review. The changes would correct grammatical errors and typos, and update communication protocols, including adding a new email address.
The manual also would be updated to document that generators must provide reactive capability curves to PJM before they can come online and that reactive testing must be completed within 90 days of initiating commercial operations.
Members Committee
Comment Period Opens on Cost Allocation Tariff Revisions
PJM told the MC that the Transmission Owners Agreement Administrative Committee had opened a 30-day consultation period on revisions to tariff Schedule 12, which details the solution-based distribution factor (SBDFAX) process for allocating the costs of Regional Transmission Expansion Plan projects (EL21-39, ER22-1606).
The revisions would address a FERC order granting a complaint from the Long Island Power Authority and Neptune Regional Transmission System regarding components of the SBDFAX method.
Merchant transmission facilities would be considered “responsible customers” within the zone they are interconnected to be assigned a portion of the transmission enhancement charges associated with RTEP projects. If material modifications are made to the boundary of that transmission zone, merchant transmission owners would have the option to have the DFAX analysis separated from that zone.
Required transmission enhancements approved by the PJM Board of Managers prior to Dec. 11, 2023, will be located in the zone of the relevant TO, while enhancements approved after that date would be located in the zone where the physical enhancements are sited.
