Planning Committee
Stakeholders Endorse LS Power Issue Charge on CETL
PJM’s Planning Committee voted by acclamation to endorse an issue charge from LS Power to examine a “disconnect” between risk modeling that has shifted loss of load risk from summer peaks to the winter and the calculation of zonal capacity emergency transfer limits (CETLs), which continues to be based on summer peaks.
The issue charge argues that the CETL calculation continues to focus on summer risk in a holdover from the capacity accreditation model in place before FERC approved PJM’s shift in accreditation and risk modeling in January. The difference could lead to incorrect capacity prices between locational deliverability areas (LDAs), the company wrote. (See FERC Approves 1st PJM Proposal out of CIFP.)
The issue charge considers as out of scope any changes to accreditation outside of the marginal effective load carrying capability (ELCC) accreditation model and consideration of a sub-annual capacity market.
The issue charge is one in a series of changes to the capacity market LS Power is seeking to make in the first quarter of 2025. The Markets and Reliability Committee (MRC) also endorsed two issue charges focused on the transparency and functionality of PJM’s marginal ELCC paradigm, which was also implemented through PJM’s critical issues fast path (CIFP) filing approved in January. (See “Stakeholders Endorse Issue Charges on ELCC,” PJM MRC Briefs: Oct. 30, 2024.)
PJM Floats Fast Track Proposal on Site Control Modifications for Queue Projects
PJM’s Jonathan Thompson presented a fast track proposal to add more detail to Manual 14H: New Service Requests Cycle Process around how developers can modify their site control requirements for projects in the interconnection queue. The fast track process allows for an issue charge to be voted on concurrent with a proposal.
At Decision Point 1, the footprint of a project can be reduced so long as it continues to meet the minimum acreage and energy output listed in the application. The land requirements are scaled down if the project output is correspondingly reduced. Additional parcels can be added to a project as long as they are adjacent to the land included in the application. If they do not abut the original outline, then easements must be provided showing how the additions will be connected to the project.
Parcels can continue to be removed from a project at Decision Point 2, and land can be added similarly to Decision Point 1. No additions are permitted at Decision Point 3; however, reductions in size can be submitted.
The revisions would also rework Exhibit 10 in the manual, which is meant to detail how a generator interconnects to existing transmission substations but incorrectly uses a diagram from a different exhibit.
Transmission Expansion Advisory Committee
PJM Presents Shortlist of Projects for 2024 RTEP Window 1
Eight packages of projects have been shortlisted to expand west-to-east power flows across the PJM region under the first window of the 2024 Regional Transmission Expansion Plan (RTEP). The need is largely driven by data center load growth in Dominion drawing increasing power from the west, which is expected to see growth in generation.
Developers submitted 88 individual projects, along with six joint proposals packaging multiple components together. All the proposals would include expanding west-to-east flows by expanding the 765-kV network, either through a Joshua Falls to Axton-Morrisville corridor or a corridor from the John Amos substation to northern Virginia.
The 765-kV upgrades Dominion, FirstEnergy and Transource jointly proposed to develop to the south of the Dominion region would offer higher initial transfer capability, while upgrades to the north would have greater possible transfers once complete. Variants of the northern reinforcements were proposed by LS Power, NextEra and a joint Transource, FirstEnergy and Dominion package.
The projects will be ranked on their effectiveness in meeting system needs in 2029 and providing long-lead reinforcement for 2032, as well as on how they maximize use of existing rights of way, cost evaluation and containment provisions, development experience and operating 765-kV assets and scalability to address future load growth.
PJM Director of Transmission Planning Sami Abdulsalam said there has been a significant intake in load growth since the RTEP project submission window was opened, leading the RTO to widen the lens it views projects through to include needs being identified in the upcoming 2025 load forecast.
Several stakeholders objected to PJM including an unreleased load forecast in its consideration of the projects, arguing that doing so would be unfair to transmission developers who were unable to include that data when designing their submissions. It could also provide an advantage to incumbent transmission owners, who would have insights into load growth that is not yet public and could design their project submissions to address both the inputs available when the RTEP window opened and future load forecast being supplied to PJM.
Virginia ratepayers also spoke against the possible impacts the projects could have on residents along the proposed corridors, saying that routes could require eminent domain of homes and arguing that PJM is misclassifying expansions of right of way as upgrades rather than greenfield development. Abdulsalam responded to the latter point saying PJM is trying to avoid having several different definitions of greenfield, brownfield and upgrades.
Supplemental Projects
AEP presented a $169.1 million project to serve a data center customer in New Haven, Ind., with an initial load of 480 MW coming online in November 2026, which is set to grow to 1,200 MW by July 2029. The project is in the scoping phase with a projected in-service date of July 1, 2029.
The load would be served by five 138-kV double circuit lines to customer-owned substations, which would be fed by a new Zodiac 138-kV substation in a breaker-and-a-half configuration. Zodiac would be cut into the Allen-Lincoln double circuit 138-kV line, and the Allen- Wayne Trace and Allen-Magley 138-kV lines. Two additional 345/138-kV transformers would be installed at the Allen substation, along with three additional 138-kV breakers and three 345-kV breakers.
PPL presented a $117.8 million project to serve a 138-kV customer in Lancaster, Pa., increasing its load by 350 MW in 2028. The project is in the conceptual phase with a projected in-service date of June 1, 2028.
A new 138-kV switchyard, to be named Pitney, would be constructed in a breaker-and-a-half configuration with five 138-kV breakers to feed into the customer substation. The facility would cut into the South Akron-Prince 138-kV line with 0.2 miles of new line.
A second new 230/138-kV substation, named Lampeter, would be built with two transformers and two breakers for each voltage. The facility would be cut into the Millwood-South Akron 230-kV line and the 69-kV double circuit tap line terminating at the Strasburg substation would be reconstructed to 138-kV to loop into Lampeter and terminate at Pitney. Both the Greenland and Strasburg substations would be upgraded from 69/12-kV to 138/12-kV.
An additional load increase in Lancaster to serve an additional 350 MW of load at the same customer substation by 2029 would be served by a $67.5 million project to build a new 138-kV switchyard named North Lancaster. The project is in the conceptual phase with a projected in-service date of June 1, 2028.
The facility would cut into the West Hempfield-Prince and South Akron-Dillerville 138-kV lines and serve the load with three 138-kV lines running 0.1 miles. Around eight miles of the West Hempfield-Prince line would need to be rebuilt as part of the project.
PPL presented a third project to serve a new customer in Hazleton with an initial load of 250 MW in 2027 growing to 1,000 MW by 2030. The $73.3 million project is in the conceptual phase with a projected in-service date of May 30, 2028.
The customer would be fed by a new 230-kV breaker and a half switchyard named Slykerville, which would be equipped with a 125-MVAR capacitor bank. The Harwood-Tresckow 230-kV line would be looped into the Slykerville facility with 0.2 miles of new line.
Around 2.7 miles of the Susquehanna T10-Susquehanna 230-kV lines would be reconductored and 15-ohm series reactors installed at the Susquehanna switchyard on the 230-kV line to Harwood.
Dominion presented a $13 million project to construct a new 230-kV substation, named Towerview, to serve a new customer in Fairfax County, Va., with an initial load of 56 MW in 2027 growing to 300 MW in 2029. The new facility would be cut into the Reston-Park Center 230-kV line. The project is in the engineering phase with a projected in-service date of Nov. 30, 2027.
FirstEnergy presented a $15.4 million project in the JCPL zone to address a possible load drop under N-1-1 contingency on the Gilbert-Martins Creek 230-kV and Gilbert-Pequest River 115-kV lines and replace a 115/34.5-kV transformer at the Morris Park substation. The project is in the conceptual phase with a projected in-service date of Jan. 29, 2027.
The project would reconfigure the Morris Park 230-kV substation into a four-breaker ring bus and cut the facility into the Martins Creek-Gilbert line. A second 230/34.5-kV transformer would be installed at Morris Park and all 115-kV equipment, including the 115/34.5-kV transformer, would be removed.
The utility also presented a $16.3 million project in the Met-Ed zone to mitigate a stuck breaker and fault contingencies at the North Hershey substation. The project is in the conceptual phase with a projected in-service date on Dec. 17, 2027.
The project would convert the 69-kV bus into a four-breaker ring bus and install a second 230/69-kV transformer, one 230-kV circuit breaker, four 69-kV breakers and associated breaker equipment.
