Planning Committee

Stakeholders Discuss Revised IRM and FPR Values for 3rd Incremental Auction

VALLEY FORGE, Pa. — PJM’s Andrew Gledhill presented a proposal to the Planning Committee to revise the installed reserve margin (IRM) and forecast pool requirement (FPR) for the third 2025/26 Incremental Auction (IA) to account for higher load growth identified in the preliminary 2025 load forecast. 

While the proposal initially was brought as a voting item, PJM told stakeholders it plans to conduct more analysis before publishing the forecast and will bring the proposal back for consideration after that point. No changes are anticipated to the IA planning parameters, which are scheduled to be published Jan. 26.

The rising load growth is expected to cause reliability risk to become more concentrated in the winter, increasing from 86.9 to 96.2% of expected unserved energy (EUE), causing effective load-carrying capability (ELCC) ratings for most resources to shift. Onshore and offshore wind, which tend to perform better in the winter, would see their ratings go up 7 and 11%, respectively, while all other resources would remain the same or see hits to their ratings. Storage particularly would see ratings fall by 10 to 15%, depending on resource duration, and demand response also would decline by 8%. All other resources would see declines of between zero and 3%. 

The IRM would increase from 17.8 to 18.5% under the proposal, and the FPR would fall from 0.9387 to 0.9263, both following a trend. Revisions approved in March 2024 increased the IRM by 0.1% to 17.8% and saw the FPR decrease to 0.9387 from 1.1165. (See “Revised Reserve Requirement Study Values Endorsed,” PJM MRC/MC Briefs: March 20, 2024.) 

Several stakeholders said the revisions would be a significant change in the planning parameters used to conduct the 2025/26 Base Residual Auction and IA, undermining investors’ ability to use auctions as a data points guiding decision-making and creating a possibility that units with diminished ratings could be forced to cover shortfalls in the obligations they received in the BRA. 

“How are investors supposed to make any decisions when you have such huge changes between the Base Residual Auction and Incremental Auctions?” asked Paul Sotkiewicz, president of E-Cubed Policy Associates, comparing the ELCC analysis to a “random number generator” into which stakeholders have no insight. 

Preliminary 2025 Load Forecast

PJM’s Molly Mooney presented preliminary figures for the 2025 load forecast, which estimates that load growth will escalate to about 2% annually in the summer and 2.4% in the winter.  

Last year’s forecast projected 1.6% of summer load growth and 1.8% in the winter.  

The complete 2025 forecast is set to be published in mid-January. (See “Preliminary Large Load Adjustment Requests for 2025 Load Forecast,” PJM PC/TEAC Briefs: Dec. 3, 2024.) 

The expected growth is sharpest in the first few years of the forecast through 2033, when it slows for the remainder of the 20-year lookahead. Compared to the 2024 forecast, the difference is starkest in the winter, with about 22.4 GW of new load expected in the first five years on top of that already projected last year; an additional 11.1 GW in additional load is forecast for the following nine years. 

Focusing on the 2030/31 delivery year, over 90% of the winter load growth above what already was forecast last year is expected to be from large load additions (LLAs), such as data centers and chip manufacturing facilities in several zones. Those additions increase the 2024 forecast by 11.8%, while electric vehicle load decreases by 0.8%. 

LLAs have been the focus of stakeholder attention over the past year, with a proposal endorsed in May to revise how capacity obligations to serve LLAs are assigned to load-serving entities. Some also seek more information on how PJM reviews LLA forecasts produced by utilities, arguing that forecasting practices could vary and one project could be brought to multiple utilities, raising concerns of double counting. (See “New Approach to Large Load Addition Capacity Assignments Endorsed,” PJM MRC Briefs: May 22, 2024.) 

Calpine’s David “Scarp” Scarpignato noted that the 2025 forecast is the first to use a 20-year window, which he said could undersell the scale of the load growth in the initial years of that period when just looking at the annualized growth rate. 

Monitor Proposes Interconnection Queue for Large Loads

The Independent Market Monitor proposed a new interconnection process for large loads that could pose significant impacts to PJM reliability, akin to how generators are studied before being brought online in terms of network upgrades, as well as how the new load would affect resource adequacy. 

If PJM determined that an LLA would jeopardize reliability, Monitor Joe Bowring said the RTO should have the authority to form a queue and impose delays to in-service dates until any necessary generation or transmission is brought online. He said planning by PJM needs to address not only transmission, but also generation and operations to ensure the system can reliably meet the loads. 

There are tensions, Bowring continued, between existing PJM consumers, traditional load growth and the LLAs that are driving ballooning forecasts and requiring market redesigns. Reconciling those must be done in a rational way that avoids inappropriately shifting any costs associated with serving new load onto existing customers. The status quo does not offer PJM a voice in how large loads come online, he said, arguing that private bilateral deals do not offer a satisfactory solution because they lack the transparency of a full planning process. 

“Of course all load should be served; the question is how to do it reliably” and at least cost, he said. 

Stakeholders were mute in opining on the merits of the proposal, though some transmission owners commented that they are limited in the conditions they can place on load interconnections. Some asked how a large load required to go through the study process would be distinguished from more traditional additions. 

Bowring told RTO Insider there are several components of the proposal that require more thinking through and consultation with stakeholders, including the definition of large loads. He noted that many data centers being planned in the footprint have requested to come online with a relatively small initial load but would scale up to as high as 1 GW over the course of several years, creating more challenges for classifying large loads. He said he plans to bring the discussion up again at the Members Committee webinar scheduled for Jan. 21. There also are jurisdictional questions that would have to be answered before the process could be implemented. 

“It clearly needs to happen, and those with the jurisdictional authority need to talk to one another,” he said. “I think it’s clearly something that needs to be considered carefully and acted on before reliability is affected.” 

Other Committee Business

PJM has launched a new Grid Optimization Solutions webpage, where it has published four technical reference guides and educational materials on the implementation of grid-enhancing technologies. It includes information on PJM’s deployment of advanced conductors, dynamic line ratings and topology optimization, as well as its analysis of advanced power flow controllers. 

Stakeholders also endorsed revisions to the TO/TOP Matrix that reflect NERC’s EOP-11-4 standards on emergency operations, as well as changes to indexing between the manuals and PJM’s Reliability Audit Program. PJM’s Gizella Mali said no new responsibilities are included for TOs. The committee also endorsed review of the matrix charter with no changes made to the document. 

Transmission Expansion Advisory Committee

Update on Recommended Tx Upgrades in 2024 RTEP Window 1

PJM presented an update on the package of transmission upgrades it plans to recommend to the Board of Managers for inclusion in the 2024 Regional Transmission Expansion Plan (RTEP), which includes about $4.6 billion in projects focused on meeting rising power flows from the west to east. 

Staff plan to bring the proposal to the board in the first quarter. (See “PJM Unveils Recommended Projects for 2024 RTEP Window 1,” PJM PC/TEAC Briefs: Dec. 3, 2024.) 

The initial $5.8 billion cost estimate aggregated from all the projects included has been optimized by PJM, reducing the cost by more than $1 billion. Changes include revising Dominion’s Kraken Loop project to consolidate two proposed 765/500-kV substations into one, named Yeat, where the loop would terminate, deferring some of the 230-kV upgrades associated with the loop, and excluding a rebuild of the 230-kV Carson-Clubhouse line in Dominion’s package of transmission reinforcements. 

Much of the need stems from rising data center growth in Northern Virginia, centered around “Data Center Alley,” near Washington Dulles International Airport, as well as electric vehicle and electrification trends.  

Prior to announcing the recommended projects, PJM said it had expanded its assessment to include the preliminary 2025 load forecast with the aim of ensuring that the upgrades could hold up to higher load growth. That raised objections among some TOs who argued that changing the factors PJM used to evaluate projects after they had been submitted was unfair and benefited incumbent utilities with more insight into expected LLAs. (See “PJM Presents Shortlist of Projects for 2024 RTEP Window 1,” PJM PC/TEAC Briefs: Nov. 6, 2024.) 

The proposal includes a new 765-kV line that would run from the John Amos substation in West Virginia, through the Welton Springs facility, and terminate at a new 765/500-kV Rocky Point substation in Virginia. That site also would be looped into 500-kV lines running between the Doubs, Goose Creek, Aspen and Woodside substations. Construction of the corridor from John Amos to Rocky Point would be assigned to FirstEnergy, with Transource doing upgrades in the AEP region. 

The $704 million Kraken Loop proposal would create a new 500-kV line running from North Anna, passing the Ladysmith substation to the east and turning north to a new Kraken substation. It would continue to the new Yeat substation in Fauquier County. Kraken also would be cut into the existing 500-kV Ladysmith-Possum Point line. 

Supplemental Projects

FirstEnergy presented a $15.8 million project to replace a 500/138-kV transformer and other equipment at its Pruntytown substation in the APS zone because of obsolescence and difficulty sourcing replacement parts. The project is in the conceptual phase with a possible in-service date of June 30, 2029. 

PPL presented a conceptual $242 million project to serve a new service request in New Buffalo, Pa., by building a new 500/138-kV substation, to be named for the town, along the 500-kV Juniata-Alburtis line. The 9.6-mile segment of existing line that would run from New Buffalo to Alburtis would be rebuilt as a double circuit as part of the project. The in-service date is May 30, 2028. The customer is expected to come online in 2027 with an initial load of 200 MW, growing to 1 GW in 2031. 

Exelon presented a $22 million project to install 12 new 230-kV breakers at its Mount Zion substation in the PEPCO zone to limit the number of taps on one line, addressing the potential for multiple networked elements to go offline simultaneously. The project also would replace 24 disconnect switches, install relays at each new breaker and end station, and new telecommunications equipment. The project is in the engineering phase with an estimated in-service date of June 1, 2030. 

Duke Energy presented a $63 million project to build a new 345-kV substation, named Turner, to serve a new service request near Mount Orab, Ohio, which is expected to ramp up to 2 GW of load in 2029. The line would be cut into the 345-kV Stuart-Hillcrest line, with additional lines of the same voltage being built to the Pierce and Don Marquis substations and a 1.2-mile loop connecting Turner to the existing 345-kV Pierce-Kyger Creek line. The work would be split between Duke; American Electric Power, which owns the Don Marquis site; and the Ohio Valley Electric Corp., which owns Kyger Creek and would split the Turner facility with Duke. The project is in the scoping phase with a projected in-service date of June 1, 2029.

Dominion presented four projects to construct adjacent substations in Henrico County, Va., to serve nearly 1 GW of data center load expected to come online in 2029. The network would be linked with $51 million of 230-kV lines cut into the existing transmission between the Chickahominy substation and White Oak and Portugee sites. 

The $20 million Gray Bark substation would be cut into the Portugee-Chickahominy line and be configured in a 230-kV six-breaker ring configuration serving an ultimate load of 300 MW. Gray Bark would be linked to the $20 million Saltwood substation with two lines into a six-breaker ring serving 300 MW. Both substations are set to come online in the third quarter of 2027. 

A $20 million Thicket substation would be built along the Chickahominy-White Oak line to serve 255 MW with a six-breaker ring. It would be linked to Saltwood by one line and another to a $15 million Bunker substation configured as a four-breaker ring to serve 104 MW. Both are estimated to come online in the fourth quarter of 2027, and the overall project is in the engineering phase.