VALLEY FORGE, Pa. — Stakeholder opinions were sharply divided at the PJM Members Committee’s meeting Nov. 21 regarding RTO proposals to allow high capacity factor resources to be sped through the interconnection queue and revise aspects of the capacity market. 

The Reliability Resource Initiative (RRI) would advance 50 interconnection requests to Transition Cycle 2 (TC2) — an interim group of queues established as part of PJM’s interconnection process overhaul that began in 2023 — in an effort to address a possible resource adequacy gap identified in the 2029/30 delivery year. The proposal would require tariff changes to be approved by the PJM Board of Managers and FERC. (See Stakeholders Divided on PJM Proposal to Expedite High-capacity Generation.) 

Presenting the RRI, PJM Director of Interconnection Planning Donnie Bielak said the proposal is being brought to address “unique circumstances” and would be a one-time measure to allow uprates and resources that can quickly come online to be expedited through the queue to address a reliability need. 

If more than 50 projects are submitted, selection would be based on a scoring formula that awards up to 35 points to projects based on their unforced capacity (UCAP); 35 points for the viability of being in service by June 1, 2029, or sooner; 20 points for higher effective load-carrying capability ratings; and 10 points for site location. The only hard eligibility requirements would be that a project must have a UCAP above 10 MW and that they are not part of a project under FERC Order 1000’s State Agreement Approach. 

Resources not already subject to the requirement that they participate in the capacity market would be compelled to offer for at least 10 delivery years. Bielak said developers would have the choice of accepting a must-offer requirement for a project they are truly certain can be rapidly brought to market or wait to be sorted into TC1. 

TC2 was open to projects sorted into the AG2 and AH1 queues, the latter of which closed in September 2021. Studies on projects submitted after that date are not likely to initiate until 2026. 

Responding to stakeholder questions regarding the scale of the impact the RRI could have on TC2 cost allocation, Bielak said PJM does not know which projects will be submitted, and there are hundreds of projects that dropped out of the interconnection process that could be resubmitted. Potential cost allocation impacts vary significantly depending on which projects are submitted and ultimately selected by PJM. 

Criticisms and Alternatives

Several renewable developers objected to the proposal, arguing it would constitute queue jumping and disrupt network upgrade cost allocation for projects that have been waiting in the queue for years. 

Rahul Kalaskar, AES senior director of regulatory affairs, offered an alternative from AES Clean Energy and REV Renewables to run TC2 and RRI projects in separate cycles. The RRI projects would be added to the separate cycle, which starts after Decision Point 2 of the TC2 cycle and runs all the studies in one condensed process. Doing so would keep the network upgrades for the TC2 and RRI projects in two different buckets. 

Kalaskar said that if PJM’s RRI design were to proceed, transmission headroom could be consumed, increasing the costs assigned to TC2 projects and possibly causing some to drop out of the queue. 

Steve Lieberman, vice president of transmission and regulatory affairs for American Municipal Power, said his organization conditionally supports RRI if changes are made to the scoring weights to prioritize project size and viability; projects that would be part of fixed resource requirement (FRR) plans are excluded; and developers are prohibited from buying out of their obligations. 

Tonja Wicks, vice president of regulatory affairs for Elevate Renewables, said “project viability” and the “in-service date” should account for at least half of the project weighting, as it gets to the core issue that PJM is trying to resolve with the RRI: getting capacity that has the most certainty to come online by a set date. Otherwise it risks selecting projects that promise to bring a large amount of power, but with no firm site control or demonstration that they can meet milestones. 

Independent Market Monitor Joe Bowring said the RRI should be preserved as a permanent option that PJM can deploy when it identifies reliability needs that can be resolved by expediting new development. Because projects are being fast-tracked to resolve capacity needs, he said the 10-year must-offer requirement should be expanded to the lifespan of the asset. 

Mike Cocco, senior director of RTO and regulatory affairs at Old Dominion Electric Cooperative, said data center loads in northern Virginia are accelerating rapidly, and the RRI is necessary to ensure PJM can continue to meet demand. He said ODEC intends to submit projects to be studied under the RRI, possibly including combustion turbine generators, and he encouraged PJM to consider how the milestone deadlines for RRI projects could conflict with timelines for air quality regulations and other requirements. 

“We’re in a position to bring generation online with the timeline that you’re looking for,” he said.  

Grant Glazer, MN8 Energy’s manager of regulatory and market affairs, highlighted that projects in TC2 will be studied under a new generation deliverability test, which he said could identify violations prompted by projects in TC1. The status quo rules would assign those network upgrades to TC2 clusters, increasing their cost allocations for up to two-thirds of projects in the cycle. Instead, he encouraged PJM to revise the Regional Transmission Expansion Plan to capture those upgrades. 

SIS Eligibility

Along with the RRI proposal, the filing with FERC would include tariff revisions to expand eligibility for projects seeking surplus interconnection service (SIS) by striking language prohibiting projects that could impact the network upgrades for new service customers in the queue. 

Stakeholders argue the language is overly prohibitive and prevents developers from co-locating thermal resources with renewables and storage. 

Sarah Toth Kotwis, RMI senior associate, said SIS is the fastest process available for bringing new resources online. Storage co-locating with existing resources can come online within 2.5 years of receiving an interconnection agreement, about half the time for adding new generation. 

Wicks said PJM stands alone among RTOs in studying open-loop batteries as discharging in light load cases and using those outcomes to determine whether projects would consume headroom that could be used by other queue projects. 

“With short duration times for construction and energizing, batteries are the types of resources FERC’s SIS directive envisioned utilizing excess capacity — a.k.a. surplus — at existing facilities to meet resource shortfalls and enhance reliability,” Wicks said. 

PJM CEO Manu Asthana said RTO staff are open to revisiting the light load case test for storage, but that needs to be a discussion in the stakeholder process to ensure there are no unintended consequences. The tariff changes would remove barriers to allow that conversation to proceed. 

Asthana said his read on stakeholder impressions on the proposed SIS changes is that PJM is on the cusp of resolving their core concerns about the service. He said PJM is taking that feedback and plans to continue pursuing changes. 

“The door is not closed: We want to hear how we can make that work,” he said. 

Bruce Grabow — a partner in Sheppard, Mullin, Richter & Hampton — urged PJM to take more time to vet the proposal through the stakeholder process, noting that stakeholders had only a few minutes to make their comments during the meeting, with some rushing to include all of their arguments. That is not how the stakeholder process is supposed to occur, he said. 

Because of the lack of discussion, along with his assertion that PJM still had not provided data to stakeholders supporting the need for expedition, the RTO risks protests at FERC and in court, Grabow argued. He asked questions about the weighting system PJM intended to apply to determine which new generation projects would be winners and losers and whether the scoring means would be transparent; when PJM did not provide further detail, Grabow argued that meant the criteria would be subjectively applied, which does not comport with FERC standards of transparency, non-discrimination and preference. 

Asthana said there is a need for as many TC2 projects as possible — ideally all of them — to be interconnected. He encouraged members to submit written comments by email, with directions provided in a communication to members. Comments will be accepted through Nov. 27, with staff aiming to submit a filing to FERC about Dec. 9, if the board approves the proposal. 

“It felt like people had more to say, and we do want to hear what you have to say,” Asthana said. 

Proposal to Modify Capacity Market Components

PJM also consulted with the MC at the meeting on a separate proposal that would revise the capacity market to include the output of some resources operating on reliability-must-run (RMR) contracts as supply, revert the reference resource to a dual-fuel CT, and remove the reactive compensation component of the energy and ancillary service (EAS) offset. (See “Insight into Upcoming Filing,” FERC Approves PJM Capacity Auction Delay.) 

The 2026/27 Base Residual Auction (BRA) would be the first to use a combined cycle generator as the reference resource, a change that was made in the most recent Quadrennial Review. The higher EAS revenues for CC generators over a combustion turbine unit pushed the net cost of new entry (CONE) value to zero, affecting several parameters derived from net CONE. The variable resource rate (VRR) curve, which defines the slope of the demand curve defining auction clearing prices, would become substantially steeper, and the Capacity Performance penalty rate would fall to zero. (See “Price Cap Increases in 2026/2027 BRA Planning Parameters,” PJM MIC Briefs: Sept. 11, 2024.) 

Even with the change, PJM’s Adam Keech said some locational deliverability areas (LDAs) still could see a $0 penalty rate because of the forward price estimates showing a widening spread between gas and electric prices, increasing EAS revenues for all categories of gas generation. The final net CONE will not be known until PJM completes the process of posting the revised planning parameters. 

The proposal aims to address those regional impacts by replacing zonal nonperformance charge rates with a uniform penalty derived from the RTO-wide net CONE. Keech said doing so would also reflect the regional emergency capacity deployments PJM tends to experience. 

Paul Sotkiewicz, president of E-Cubed Policy Associates, questioned if PJM has examples of dual-fuel CTs being built in the RTO’s footprint within the past five years, adding that the necessary air quality permits to run the backup fuel would be almost impossible to get in many areas, particularly in the regions capacity is needed most. 

The reference resource has “to be a resource that can be realistically built,” he said. 

Keech said PJM considered several restrictions that would affect the viability of virtually all technologies and looked for the lowest-cost resource that viably can be built. If it were entirely impossible to build a dual-fuel CT across the RTO, the technology would not qualify to be the reference resource, but staff believe there are enough regions where such a unit could be sited to proceed. 

Vistra’s Erik Heinle, also speaking for Calpine and LS Power, said a single-fuel CT would be more appropriate as the reference resource by virtue of being viable to build in a wider range of locations. 

Constellation Director of Wholesale Market Development Adrien Ford said CTs are “the pure capacity resource,” and setting it as the reference resource would reduce the impact of higher energy revenues on the capacity market. 

The inclusion of expected output of generators operating on RMR agreements is aimed at Talen Energy’s 1,273-MW Brandon Shores and 702-MW H.A. Wagner generators outside Baltimore. It would pertain only to agreements accepted by FERC by Feb. 6, 2025, and require that the units be able to operate for the entire delivery year; have sufficient run hours to address transmission violations and capacity emergencies; have deliverable CIRs; and be available for dispatch under emergency conditions unless on outage. The changes would be effective for the 2026/27 and 2027/28 delivery years while stakeholders pursue a more permanent approach to how RMR units interact with the capacity market. 

Keech said it is not clear that Brandon Shores would be able to operate in accordance with those requirements because of an agreement with the Sierra Club that mandates that the plant cease coal combustion by the end of 2025, with no plans apparent to convert to alternative fuels. Wagner Unit 3 likely meets all of the criteria, but the RTO still is investigating whether Unit 4 has sufficient run hours to address the transmission needs and be available as capacity. 

The RMR units would not be required to take a capacity obligation or enter into BRAs and therefore would not be subject to CP penalties nor included in the balancing ratio. Rather than paying the RMR units as if they had taken a capacity obligation, the proposal would collect capacity revenues and allocate them as credits to consumers assigned a portion of the costs associated with the RMR agreement. 

LS Power Vice President of Wholesale Market Policy Dan Pierpont said PJM should ensure that it is considering how the run hours for each of the Talen units may interact. If Brandon Shores cannot operate because of the Sierra Club agreement and Wagner then needs to run more often to resolve transmission violations, that would affect its ability to meet the requirements to be modeled as supply. Keech responded that PJM would address any such interactions. 

ACES Power Executive Director of Regulatory Strategy John Rohrbach said PJM is in a bind where it’s likely the Talen units will run through some avenue — either through a modification to the Sierra Club agreement or an emergency order from the U.S. Department of Energy under Federal Power Act 202(c) — but it does not have concrete knowledge of how the generators will be available. He said if PJM believes the RMR units will run one way or another, their output should be modeled.

The third prong of PJM’s proposal — to remove compensation for generators providing reactive service from the EAS offset — is in line with a FERC order finding that consumers cannot be charged for reactive service within a standard range (RM22-2). The commission’s Oct. 17 order provided PJM with more time to submit a compliance filing to determine a transition mechanism to eliminate reactive service, but it also required a separate filing to address how it is reflected in the EAS offset. 

The proposed change would be a severable component of the filing, allowing FERC to approve or deny it separately from how it rules on other aspects of the proposal. (See “PJM Details Path Forward on Reactive Power,” PJM MIC Briefs: Nov. 8, 2024.)