Planning Committee

Stakeholders Discuss Change to CIR Transfer Issue Charge

The East Kentucky Power Cooperative presented potential revisions to the process for transferring capacity interconnection rights (CIRs) from a retiring generator to a replacement resource. 

The changes would allow for solutions to include CIR transfers to planned resources interconnecting at the same substation as the deactivating unit, but on a different breaker. Both sets of language would preclude proposals contemplating shifting CIRs to a resource connecting to an entirely different substation. 

During the April 2 PC meeting, EKPC Vice President of Federal and RTO Regulatory Affairs Denise Foster Cronin said package formation at the Interconnection Process Subcommittee revealed the issue charge would prevent solutions sought by some stakeholders to allow CIRs to be transferred to a new resource interconnecting on a different breaker, but which otherwise are electrically equivalent. (See “Stakeholders Discuss Expanding CIR Transfer Issue Charge,” PJM PC/TEAC Briefs: April 2, 2024.) 

Exelon Director of RTO Relations Alex Stern suggested modifying the proposed revisions to require that solutions allow only CIR transfers to generators interconnecting at the same or lower voltage as the original resource. Stern argued that increasing the voltage would be more likely to impose additional costs as well as implications to service to others that would compromise the clean CIR transfer the issue charge intended to explore. The suggestion was not accepted to provide more time for the package sponsors, EKPC and Elevate Renewables, to consider the changes. 

First Read on CIFP Manual Revisions

PJM presented a set of manual revisions to codify changes to capacity accreditation, reliability risk modeling and procurement targets FERC approved in January following PJM’s Critical Issue Fast Path (CIFP) process last year. (See FERC Approves 1st PJM Proposal out of CIFP.) 

Manuals 20, 21 and 21A would be replaced with new Manuals 20A and 21B — which respectively detail resource adequacy analysis and the determination of generating capability. Manual 14B, which pertains to the regional transmission planning process, would see changes to its load deliverability analysis and the capacity emergency transfer objective (CETO) and capacity emergency transfer limit (CETL) analyses. 

PJM plans to ask the PC to vote on endorsing the manual revisions during its June 4 meeting. The Market Implementation Committee endorsed related revisions to Manual 18, which relates to the capacity market, on May 1. If endorsed, the manual revisions would be effective for the 2025/26 delivery year. 

Transmission Expansion Advisory Committee

PJM Updates RTEP Timeline

PJM intends to open two competitive Regional Transmission Expansion Plan (RTEP) windows in July to solicit proposals to resolve transmission violations and interconnect 3.5 GW of wind generation planned off the New Jersey shoreline. (See “PJM Preparing 2 Competitive Transmission Windows in July,” PJM PC/TEAC Briefs: April 2, 2024.) 

PJM’s Sami Abdulsalam presented the Transmission Expansion Advisory Committee with a plan to use an eight-year horizon when identifying grid upgrades necessary under New Jersey’s second State Agreement Approach (SAA), under which the state agreed to cover the cost of transmission necessary to meet its policy goal of developing 3.5 GW of offshore wind. 

The longer window allows the RTEP analysis to capture how load growth, generation deactivations and the first round of SAA transmission — which aims to facilitate the interconnection of 7.5 GW of offshore wind in New Jersey — may interact with transmission needs identified, Abdulsalam said. 

The eight-year window also will identify any reliability needs and could lead to multi-driver projects that share reliability and facilitate offshore wind interconnection in New Jersey.  

PJM also aims to open the first standard reliability-focused five-year window of the 2024 RTEP in July. Abdulsalam said the window likely will be open for 60 days. Vice President of Planning Paul McGlynn told RTO Insider that more detail about needs identified in the window likely will be presented in June or July. 

Scope Change to 2022 Window 3 RTEP Adds $19.5 Million

PJM has expanded the scope of a component of the 2022 RTEP Window 3 to upgrade an existing 230-kV line to 500-kV for an estimated $19.5 million. 

The original project scope was to add a 500-kV line parallel to the existing Otter Creek-Conastone 230-kV line. Abdulsalam said dialogue between PJM and PPL suggested there could be substantial benefits to upgrading the existing line as part of the project. 

Upgrading the line as part of the 2022 RTEP could limit construction along the corridor and add scalability to a vital corridor for moving power between northern and southern PJM regions. 

The project is one component of a larger $5 billion transmission expansion the PJM Board of Managers approved in December 2023 to address concentrated load growth in northern Virginia and about 11 GW of deactivating generation, most notably the Brandon Shores plant and the Wagner Generating Station outside Baltimore. 

Supplemental Projects

FirstEnergy proposed a $35 million project to upgrade its South Reading 230-kV substation in the Med-Ed transmission zone to mitigate the risk of multiple breakers or a bus fault causing the entire facility to go offline. The proposal would reconfigure the substation to a double-breaker, double-bus configuration; replace the bus conductor; install new circuit breakers; and build a new control house. The work would increase the ratings of the 230-kV lines between South Reading and the Boonetown, Lauschtown and Berks substations. 

The project is in the engineering phase, with a project in-service date of Dec. 31, 2026. 

The utility also proposed rebuilding its gas-insulated 230-kV Smithburg substation in the JCPL transmission zone due to the need for specialized parts, poor performance and its age at over 40 years old. The $30.2 million project would reconfigure the substation to be open-air, along with upgrading terminal equipment, retiring the Smithburg-Larrabee and revising relays at the Larrabee, East Windsor, New Prospect Road and Manalapan facilities. 

The project is in the conceptual phase, with a possible in-service date in June 2027. 

FirstEnergy also presented several proposed projects to replace transformers across its facilities. A $56.4 million project would replace three 500/138-kV transformers at its Belmont substation in the APS transmission zone. The utility said the units are approaching their end of life and are experiencing degradation challenged by obsolete replacement parts. The replacements would be staggered to go in service between June 2027 and December 2029. 

Two separate projects also would replace 230/69-kV transformers at the South Reading substation, due to increased gas levels and their age. The projects, which are in the engineering phase, would total $17.6 million, with completion targeted in June and December 2025. 

In the Penelec zone, FirstEnergy proposed replacing a 230/115-kV transformer at its Shawville substation due to age, maintenance issues and nitrogen leaks. The utility also discussed replacing a 345/230-kV transformer at the Homer City substation as it approaches its end of life and parts have become obsolete. The projects are estimated to cost $17.6 million. 

Exelon presented a $35 million project to install seven new 345-kV circuit breakers at its Libertyville substation in the ComEd zone, as well as replace two deteriorating oil circuit breakers with SF6 based units. 

Dominion presented a problem statement for possible reliability violations along the transmission corridor between the Possum Point and Fredericksburg substations. More than a dozen substations are planned in the region to serve growing data center load, which could strain existing transmission even with four ongoing projects to upgrade the corridor to hold two 230-kV lines, the utility said. 

Projections of the load interconnecting on the 13 new substations suggest consumption could increase by more than 1,700 MW by 2029 and by more than 3,000 by 2032. Dominion said load is increasing at a similar pace along the corridor to the south of Fredericksburg, with 14 new substations along that segment estimated to have 2,000 MW of new load by 2029 and an additional GW by 2032. 

Ensuring adequate transmission in place would require either new “diverse transmission sources” or additional reconfiguring of the two 230-kV lines to allow additional lines to be installed, which Dominion said may result in increased outage times, higher costs and delays to consumer in-service dates. 

Dominion proposed rebuilding its 10.6-mile Harrisonburg-Grottoes 230-kV line as it approaches the upper end of its expected lifespan. Most of the line was built in 1970 with wood structures, which would be replaced with steel at an estimated cost of $28 million. The project is in the conceptual phase, with a possible in-service date in December 2027.