Planning Committee

LS Power Seeks Issue Charge to Align CETL Calculation with Winter Risk

VALLEY FORGE, Pa. — Tom Hoatson, of LS Power, presented to the Planning Committee the third in a “trilogy” of issues charges seeking changes to PJM’s effective load carrying capability (ELCC) accreditation paradigm, focusing on aligning the capacity emergency transfer limit (CETL) with PJM’s winter-skewed risk modeling. 

LS Power presented two issue charges at the September Markets and Reliability Committee meeting addressing the transparency of ELCC and how it is applied to individual units. (See “LS Power Issue Charges on Accreditation Transparency, Unit-specific Performance,” PJM MRC Briefs: Sept. 25, 2024.) 

The issue charge states that PJM models transfer limits for locational deliverability areas (LDAs) looking at their summer peaks, which is incongruent with a risk modeling approach that has shifted the bulk of risk into the winter. The issue charge is set to be voted on at the PC’s Nov. 6 meeting. (See FERC Approves 1st PJM Proposal out of CIFP.) 

“Having switched now to a model that assesses risk throughout the year, using a summer peak-based CETL calculation without reference to the EUE [expected unserved energy] distribution creates a misalignment between the periods when capacity is most valuable and the transfer limits for LDAs during those periods,” the issue charge reads.

Hoatson said that during the December 2022 Winter Storm Elliott, it appeared there was insufficient west-to-east transfer capability despite no such transmission constraints being modeled in the CETL analysis. The winter power flow issues were not modeled in CETL for that LDA.

Stakeholders Endorse Dual Fuel Manual Definitions

The PC endorsed by acclamation a proposal to revise the definition of dual-fuel combustion turbines and combined cycle resources to reflect the Reliability Assurance Agreement (RAA) definitions accepted by FERC in July (ER24-1988). (See “First Read on Manual 21B Revisions,” PJM PC/TEAC Briefs: Sept. 12-13, 2024.) 

The change would allow dual-fuel resources that are capable of starting on their primary fuel before shifting to their secondary to qualify as dual-fuel. During the earlier stakeholder process, Calpine’s David “Scarp” Scarpignato said some gas units can start on a small amount of fuel already purchased and packed into the portion of the gas pipeline on generator property, even if the regional pipeline is offline. (See “Quick Fix for Dual-fuel Classification Endorsed,” PJM MRC Briefs: April 25, 2024.)

Transmission Expansion Advisory Committee

2024 RTEP Window 1 Projects Include Expansion of 765-kV Network

PJM has closed the solicitation period for transmission developers to propose projects in its 2024 Regional Transmission Expansion Plan (RTEP) Window 1, which focuses on addressing heavy power flows from west to east driven by load growth in Dominion being served by power in the western half of the footprint. 

Senior Manager of Transmission Planning Sami Abdulsalam said past RTEP windows have resolved much of the need to import power from the east and are performing well in the analysis. But load growth is continuing to accelerate and driving more transfer needs. 

“Data centers are a strong influencer toward the increasing load forecast,” he said, as well as electrification and electric vehicles.

PJM received 88 project components, with an additional six packages of components, all of which include expanding the RTO’s 765-kV network either toward the area of the Joshua Falls and Acton-Morrisville substations or into northern Virginia near the John Amos substation. The proposals include 48 upgrades of existing facilities, 40 of which are mostly new greenfield infrastructure. 

Staff will begin shifting toward building the components into a package they believe meets the regional needs most effectively, with an eye toward future expandability. Once that has been completed, Abdulsalam said Board of Managers approval of a recommended package is being targeted for the first quarter of 2025, with first reads at the TEAC expected in December and January. 

Several residents in the northern Virginia region spoke out against the proposed expansions, saying that constructability will be inhibited by the impacts to residents already being affected by several projects and whether new generation could be an alternative.

Status of Supplemental Projects

FirstEnergy has reduced the scope of a project to upgrade equipment at its Beaver substation in the ATSI zone to replace a 345/138/13.2-kV transformer with a higher-rated unit. The original scope included replacing two existing transformers and installing two more 138/13.2-kV units. The change reduces the project cost estimate from $12.7 million to $10 million with an in-service date of March 23, 2029. 

American Electric Power (AEP) presented a $185 million project to build two new 345-kV substations to accommodate 1,100 MW of new load in the New Carlisle, Ind., region expected to come online by Dec. 15, 2026. Both of the new substations would cut into the Elderberry-Dumont and Dumont-Olive Bypass 345-kV lines. 

Toward Elderberry, the new Larrison Drive facility would be configured as a breaker and a half, with 16 345-kV breakers and six bus ties to the new customer for $70.4 million. The New Prairie substation would be similarly configured and cost $79.5 million. 

Five overtaxed 345-kV breakers would be replaced at the Olive substation and three new breakers would be added for $29.3 million. End work also would be required at the Sorenson, Elderberry and Dumont substations for $1.72 million for each facility. A sag study and mitigation for the Kenzie Creek-Thomson 345-kV line would cost $620,000 more. 

AEP also presented a need to serve a 1,000-MW data center near Granger, Ind., which aims to come online initially with 300 MW of load in December 2027 and ramp up to its full consumption in January 2029. 

PPL presented an $81 million project to build a new 230-kV switchyard to serve a 1,000-MW customer near Hazleton, Pa. The load is expected to come online in April 2027 with 250 MW, growing to 1,000 MW in 2030. 

The new Tresckow switchyard would be cut into the Harwood-Siegfried and Harwood-East Palmerton 230-kV lines for $8 million. The facility itself would cost $45 million and be configured as a breaker and a half with four bays and a 125-MVAr capacitor bank. Three 230-kV lead lines would stretch four miles to the customer for $28 million.