Planning Committee

PJM Presents Changes to DESTF Issue Charge

PJM’s Chen Lu on March 4 presented the Planning Committee with a draft amendment to the Deactivation Enhancement Senior Task Force’s (DESTF) issue charge to add a key work activity (KWA) focused on creating pro forma language for reliability-must-run agreements with generation owners seeking to deactivate a unit identified as being necessary for reliability.

The new language seeks a proposal that would be effective for the 2028/29 delivery year, which is the tail end for a temporary measure allowing some resources operating on RMR agreements to be counted as capacity if they meet certain requirements (ER25-682). Approved by FERC in February, the temporary change allows resources that PJM believes can act as capacity to be counted in the supply stack for the 2026/27 and subsequent Base Residual Auction. (See FERC OKs Changes to PJM Capacity Market to Cushion Consumer Impacts.)

While PJM will ask the Markets and Reliability Committee to vote on the changes during its March 19 meeting, Lu brought the language to the PC, Market Implementation Committee and Operating Committee during their March meetings to provide stakeholders with advance notice.

Paul Sotkiewicz, president of E-Cubed Policy Associates, asked Lu why PJM had reversed its earlier position that RMR agreements should be out-of-scope for the DESTF. He stated that RMR agreements are different from other areas the task force has focused on because they are specific to transmission security, not market design.

Lu responded that there are relevant issues around RMR agreements, such as the operational parameters needed to maintain reliability and on the markets side what is needed to count those resources as capacity. PJM believed a senior task force was the best forum rather than a standing committee.

Speaking during the MIC meeting March 5, Philip Sussler, of the Maryland Office of People’s Counsel, and Clara Summers, of the Illinois Citizens Utility Board, questioned whether the added work item would impact the ability for the task force to proceed with KWAs exploring alternatives to RMRs, an addition to the issue charge the two consumer advocates sought to have included in 2024. (See “Stakeholders Approve Generation Deactivation Issue Charge,” PJM MRC/MC Briefs: Sept. 20, 2023.)

Other work areas include education on alternatives to rebuilding transmission assets when generation deactivations would trigger reliability violations, such as reconductoring or the deployment of grid-enhancing technologies; developing alternatives to RMR agreements; and accounting for any changes stakeholders and the RTO may make to its capacity interconnection rights transfer process.

Transmission Expansion Advisory Committee

Market Efficiency

PJM’s Nicolae Dumitriu presented the Transmission Expansion Advisory Committee with an update on the RTO’s 2024/25 long-term market efficiency window.

The congestion drivers behind the analysis were identified through base cases pairing the 2024 load forecast with the expected grid topology in 2029 and 2032. An additional sensitivity was included examining how increased load identified in the 2025 forecast could impact the 2029 case to allow PJM to right-size the solutions built on the two base cases.

The inclusion of the 2024 Regional Transmission Expansion Plan (RTEP) Window 1 slate of grid updates mitigated 13 constraint overloads that prevented the market efficiency analysis from being able to calculate interface limits, in addition to reducing congestion on several lines. The remaining congestion is largely located along the PJM/MISO border. PJM also included planned resources sorted into the fast-track study queue and those with suspended interconnection service agreements (ISAs) to the analysis to allow it to meet the expected 17.8% reserve requirement.

The preliminary congestion drivers identified include the 138-kV Museville-Smith Mountain line in the AEP zone, which has $39.7 million of congestion in the 2029 base case and $51.5 million in the 2032 case; the 115-kV West Point-Lanexa line in the Dominion zone, which has $1.2 million of congestion in 2029 and $1.3 million in 2032; and the 115-kV Garrett-Garrett Tap line in the APS zone, which has $1.8 million in 2029 and $2.4 million in 2032.

PJM’s Nicholas Rodak said the next step is finalizing additional sensitivities and the models for the 2025, 2029, 2032 and 2035 simulated years.

Tightening Supply and Demand Impacting RTEP Planning

PJM’s Wenzheng Qiu presented stakeholders with an update on the assumptions being developed for the 2025 RTEP analysis, which includes an expectation that existing generation and planned resources with signed ISAs will not be sufficient to meet loads in 2030.

Window 1 will include the 2025 load forecast, which includes 16 GW of growth in 2030 above the prior year’s forecast.

The five-year analysis of the balance between load and generation finds that peak loads could be met with the addition of projects with suspended ISAs, fast-lane queue projects, the Chesterfield Energy Reliability Center planned in Virginia and the Coastal Virginia Offshore Wind project, albeit with a loss-of-load expectation of 1.6 days per year. If the 2,308 MW of offshore wind planned in New Jersey and 255 MW in Delaware are not completed, the LOLE would increase to two days per year, 20 times higher than the one-in-10 benchmark.

If all those projects are included in the seven-year base case, Qiu said the 2032 LOLE would be 2.3 days per year. The seven-year case is being included in the analysis to identify projects that could be right sized for long-term needs.

PJM’s Sami Abdulsalam said resources with suspended ISAs and fast-lane projects are being included in the RTEP analysis to allow the amount of available generation to meet peak loads. The point of interconnection for those projects is being set at the nearest bus at 500-kV or higher to avoid impacts to lower-voltage facilities. The seven-year case also includes all projects being studied in Transition Cycle 1 and 2, which will also be modeled on the high-voltage backbone network.

Responding to stakeholder questions on how any network upgrades required for those generation projects will interact with the RTEP needs, Abdulsalam said the seven-year case will inform the solutions chosen to resolve the five-year needs. Not all network upgrades expected to be completed in the latter analysis will be included in the five-year case, so any such upgrades would be removed.

Supplemental Projects

FirstEnergy presented two projects in the ATSI zone to address transmission overloads and congestion identified in MISO’s Long-Range Transmission Planning process (LRTP) and support projects in the 2024 MISO Transmission Expansion Plan.

The first would construct a 20-mile optical fiber line between the Lemoyne and Toledo Edison substations and replace line relaying at Lemoyne at a $15.6 million cost. The second would install 7 miles of fiber from Toledo Edison to the Lallendorf substation, where line relaying would also be replaced, at a $5.9 million cost. The overall $40 million project is in the conceptual phase with a projected in-service date of June 1, 2032.

FirstEnergy also presented three projects to replace transformers in the JCPL zone for maintenance issues and the infrastructure approaching the end of its useful life. The 230/115-kV Whippany transformer No. 12 is about 66 years old and has had problems with leaking oil and nitrogen gas; the unit, associated relaying and substation conductor would be replaced at a $8.1 million cost, with an in-service date of March 7, 2030.

The 230/34.5-kV Chester transformer No. 4 is nearly 46 years old and has been reading elevated ethane gas in its oil. Replacing the transformer, a 230-kV circuit switcher, 34.5-kV breaker and limiting terminal components would cost $7.3 million with an in-service date of Dec. 31, 2029. The 230/34.5-kV Chester No. 1 would also be replaced, as it was installed about 60 years ago and there are signs of degrading insulation. Its replacement would cost $7.3 million, which includes a 34.5-kV breaker and limiting terminal components.

FirstEnergy presented a $12 million project to replace the control building at its Glade substation in the Penelec zone. The building is 56 years old and degrading, with rusting walls and broken windows. Several line ratings are also limited by terminal equipment. Several other components of the substation would also be replaced, including: four disconnect switches, two 230-kV breakers, and substation conductor and the line trap on the 230-kV Lewis Run-Warren line. Substation conductor and terminal equipment would also be replaced at the utility’s Warren and Lewis Run substations. The project is in the conceptual phase with a projected in-service date of Dec. 17, 2027.

American Electric Power presented a $173 million project in its zone to connect LRTP Tranche 2 projects to the PJM grid. While the full cost would be assigned to MISO customers, there could be impacts to the PJM grid, so AEP determined to submit them as supplemental projects to be studied for any transmission violations. No “large-scale issues” have been determined, AEP said.

The Sorenson substation would be reconfigured to terminal two new 765-kV lines to the Greentown and Lulu facilities, and four new 345-kV lines would be terminated at the Sullivan substation, with two running each to Fairbanks and Dresser.

Several lines would also be modified to cut into new substations:

• • the 765-kV Sullivan-Rockport line would cut into a new Pike County substation;
  • the 765-kV Jefferson-Greentown and 345-kV Tanners Creek-Hanna lines would both cut into the Gwynneville substation;
  • the planned 345-kV Gwynneville-Tanners Creek line would cut into the existing Batesville substation;
  • the 345-kV Fall Creek-Sunnyside line would cut into a new Madison County substation; and
  • the double-circuit, 345-kV Olive-University Park and Olive-Green Acres lines would cut into the 345-kV Babcock substation.

Exelon presented a $874.2 million project to extend two 765-kV lines from ComEd’s Collins substation, which would also be expanded, to interconnect with projects in MISO’s Tranche 2.1 portfolio. All costs associated with the project would be allocated to MISO.

A new 765-kV Woodford County substation would be built in the MISO grid as part of the project, which would cut into ComEd’s 345-kV Powerton-Katydid and Powerton-Nevada lines. Two 300-MVAR line reactors would be installed at Collins, along with associated circuit breakers for each new line.

Exelon also presented a $40 million project in the ComEd zone to construct a new 345-kV substation, named Eldamain, to serve a new customer bringing 600 MW to the area of its Plano substation. The new facility would be cut into the 345-kV LaSalle-Plano line with 0.4 miles of new double-circuit line. The project is in the engineering phase with a projected in-service date of June 1, 2029.

Dominion Energy presented a $30.6 million project to rebuild 10.3 miles of its 230-kV Shawboro-Elizabeth City line as it approaches its end of life, having been built with wooden H-frames in 1975. The project is in the engineering phase with an estimated in-service date on Aug. 31, 2025.