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December 7, 2025

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PJM Presents Shortlist of RTEP Projects

VALLEY FORGE, Pa. — PJM presented its shortlist of projects for inclusion in the first window of its 2025 Regional Transmission Expansion Plan (RTEP), which includes need for increased west-to-east transfer capability to supply rising data center load in Northern Virginia and the PPL region.

The projects were sorted into four regions: the PPL region of the MAAC zone, the overall MAAC zone, a southern cluster focused on resolving transmission violations and a western cluster centered around Columbus, Ohio. PJM expects to present its recommendations to the Transmission Expansion Advisory Committee during its Dec. 2 meeting.

The need in PPL is being driven by load growth increasing by about 5 GW between the 2024 and 2025 load forecasts, which is driven predominantly by data centers. The removal of 7.5 GW expected from offshore wind projects in New Jersey also caused five 500-kV lines to overload, increasing the need for more transmission into the Mid-Atlantic.

PJM added scenarios removing the offshore wind generation to reflect the New Jersey Board of Public Utilities canceling solicitations for development and postponing construction of transmission and other infrastructure. (See N.J. Puts on Hold Remaining Pieces of $1.07B OSW Transmission Project.)

PJM has shortlisted a single portfolio from PPL, which would make several upgrades to transmission around the Susquehanna nuclear generator for $565 million. The package includes building a new Kelayres 500-kV substation, extending the Susquehanna-Sunbury 500-kV line to cut into Kelayres and rebuilding the Juniata-Sunbury 500-kV line.

PJM Director of Transmission Planning Sami Abdulsalam said this is the first time a transmission owner has submitted a complete competitive RTEP portfolio with a fixed cost cap. He said there is strong confidence the utility’s forecast will increase again next year, creating the need for upgrades of this magnitude.

Increased transfer capability into the larger MAAC region is being prompted by data center growth in PPL, with three portfolios shortlisted and a fourth under consideration. A joint FirstEnergy and MAIT project would build two 500-kV lines between the Keystone and Susquehanna substations for $1.16 billion; a NextEra and Exelon package would build a 765-kV line from Kammer to Juniata, with two new 765/500-kV substations along the corridor for $1.74 billion; and a proposal from NextEra, Exelon and MAIT would build the Kammer-Juniata 765-kV line, plus a 500-kV line from Keystone to Susquehanna, for $2.82 billion.

New generation in southern Dominion paired with load growth in Northern Virginia is expected to cause multiple overloads on 500-kV lines between the two regions in 2032. Three packages were shortlisted: a high-voltage DC line from the Heritage substation to Mosby paired with a 500-kV line between Elmont and Kraken sponsored by Dominion for $4.82 billion; a pair of 765-kV lines from Heritage to Vontay and between Joshua Falls and Morrisville, passing through Cunningham brought by Transource for $1.97 billion; and two 500-kV lines between Heritage and Morrisville and from Finneywood to Cunningham and ending at Morrisville proposed by Dominion for $1.99 billion.

Several residents voiced support for the HVDC line, noting it would be underground and mostly follow existing transmission corridors. Many of the comments also called for more underground HVDC options. PJM staff responded that they’re limited to the solutions presented by project sponsors.

Abdulsalam said there are several benefits to underground HVDC beyond aesthetics, including easier expansion capability and reduced injection of short circuit. But he cautioned that it’s not a given the transfer capability is greater than overhead 765 kV.

The western cluster aims to address load growth in Ohio near Columbus and Melissa, as well as regional power flows shifting toward the eastern and southern regions of PJM. Transource submitted a $2.78 billion project including several upgrades to the 765-kV and 500-kV networks around Columbus, including a 765-kV line from Greentown mostly using greenfield right-of-way; a $2.92 billion project from NextEra and Exelon to construct a greenfield 765-kV ring from Gwynneville and looping around Columbus; and $1.49 billion to build a 765-kV line from Belmont in West Virginia to Vassell and upgrade several lines to the southwest of Columbus.

Supplemental Projects

FirstEnergy presented a $50 million project in the APS zone to replace 93 wood H-frames with steel structures and reconductor 12.72 miles along the Carroll-Mount Airy 230-kV line. The utility said the wood poles show signs of accelerated decay and woodpecker damage. The project is in the conceptual phase with a projected in-service date of June 30, 2029.

The utility also presented a $36.8 million project to serve a new customer requesting 230-kV service near the Doubs substation by constructing a 230-kV substation along the Doubs-Sage 230-kV line. The facility would feature 10 breakers and have a breaker-and-a-half (BAAH) configuration. The scope also includes reconductoring 2.9 miles of the Doubs-Sage line. The project is in the conceptual phase with a projected in-service date of Feb. 18, 2032.

FirstEnergy presented a $30 million project in the Penelec zone to rebuild 6.7 miles of the Johnstown-Seward 230-kV line to resolve deteriorating wood structures and insulator bells. The project is in the conceptual phase with an in-service date of June 15, 2027.

AEP presented a need to make repairs along 74 miles of its Hanna-Tanners Creek 345-kV line, which has experienced damage to structure legs, insulator assemblies and conductor strands. Brackets holding suspension insulator strings also are wearing out on 87% of the structures inspected, creating increased risk that a conductor could fall from the towers. There have been five momentary and two permanent outages on the line in the past five years.

PECO presented a $176.6 million project to serve a new customer seeking to bring 600 MW of load near Fairless Hills, Pa., by 2028. The project’s first phase would install two temporary 230-kV lines tapping into the double-circuit Ford Mill-Emilie line, followed by the construction of a 230-kV BAAH substation, named Sinter, with 11 breakers and two customer feeds. The line segment between Sinter and Emilie would be rebuilt, and terminal equipment at Emilie would be upgraded.

Two new service requests were presented for 750 MW near Limerick, Pa., by 2032 and another for 500 MW of load in Philadelphia expected to come online by 2029.

Planning Committee Examines Spare Equipment Philosophy

PJM has expanded its guidance on spare equipment for transmission owners, increasing the document from a single page to eight in an effort to consider equipment likely to fail during extreme weather.

The Planning Committee requested that the Transmission & Substation Subcommittee re-evaluate the document, including the possibility of a “targeted return to service” when determining the adequate supply of spare parts, as well as the logistics to deliver that equipment. (See “PJM Seeks Stakeholder Attention on Spare Equipment Requests,” PJM PC/TEAC Briefs: Dec. 3, 2024.)

The new language lists several major types of equipment that may be difficult to procure or transport after a failure, such as transformers, reactors, circuit breakers, tower components and conductors, and it gives high-level guidance on spare equipment storage and typical replacement timelines.

“Spare equipment is critical to the continued integrity of the bulk electric system (BES),” the document reads.” Failure to maintain adequate spare equipment can lead to unnecessary higher operating costs and unnecessarily long outage times, consequently compromising transmission and overall system reliability.

“Interconnected transmission owners (ITOs) need to be able to support any local interconnection agreements. The purpose of this philosophy is to ensure that thought is given to maintaining adequate spare equipment for the BES. Any new facility connecting to the bulk electric system should observe this philosophy.”

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SPP Awards 8th Competitive Project, 3rd in 2025

LITTLE ROCK, Ark. — SPP’s Board of Directors has awarded its eighth competitive project and third in 2025 under FERC Order 1000, a 345-kV upgrade in the Texas Panhandle.

A panel of industry experts designated Transource Oklahoma and Southwestern Public Service as the transmission owners for the project, on a 150-mile line from Beckham County, Okla., to Potter County, Texas.

NextEra Energy Transmission Southwest was the only other bidder on the project in what the panel said were two high-quality proposals.

“Both proposals were from highly qualified, experienced entities with a successful history in the design, build and operation of similar and relevant projects,” said Tom Bozeman, chair of the industry expert panel (IEP).

That was apparent in the IEP’s scoring. The panel saw less than 3 points of difference between the two proposals, with NEET Southwest’s bid getting a slightly higher score than the Transource-SPS proposal: 1,088.54 to 1,086. However, Transource and SPS submitted a lower cost, or “present value requirement,” to customers: $248.68 million to $269.53 million.

Bozeman said the panel questioned the results but agreed the small difference between the bids was “reflective of two highly qualified respondents with very similar proposals.”

“We found [the Transource-SPS proposal’s] cost to customers’ savings of almost $21 million to be a distinguishing package,” he said.

SPP staff has given the project an estimated $429.73 million price tag and a projected November 2029 in-service date.

The Transource-SPS bid was the only one to offer a cap on the annual transmission revenue requirement. That also played a part in the IEP’s unanimous decision.

During questions by the board, the IEP said its requirements did not include information on cost caps and how to deal with them. Director Irene Dimitry, who leads an Order 1000 Strategic Review Task Force that is trying to improve the selection process’ effectiveness and reduce the cycle time, agreed more information and analysis is needed.

“There’s this need to make sure we’re getting all the information we need to make an informed decision,” she said. “We have work to do, especially in thinking about the projects that are coming out of the 2025 ITP. What can we do differently moving forward, so that the information is gathered from the bidders and that guidance is given to whoever’s doing the evaluation to deliver the analysis that we need?”

Dimitry said the task force is weighing the use of outside consultants to augment the IEPs and provide additional expertise to ensure they can handle the volume of projects coming out of the 2025 assessment.

“We’re presuming there will be some big projects coming in, including an expectation of our first [competitive] 765[-kV] projects,” she said.

The Members Committee unanimously endorsed the IEP’s recommendation with its advisory vote. The Advanced Power Alliance and Basin Electric Power Cooperative abstained.

The Beckham-Potter project was one of four competitive upgrades that were approved out of the 2024 Integrated Transmission Plan. It is a companion to SPS’ 765-kV Potter County-Crossroads-Phantom project, which also came out of the same ITP assessment but does not directly address any 2024 needs by itself.

Transource and SPS were both involved in the last two winning bids handed out by the IEP. Transource won the 38-mile Mathewson-Redbud project in Oklahoma in May, and SPS was awarded a 20-mile, 115-kV proposal in August. (See SPP Approves 6th Competitive Transmission Project and SPP Board of Directors/Members Committee Briefs: Aug. 5, 2025.)

Admin Fee Reduced in 2026

“We’re going back to the future as it relates to administrative fees,” CFO David Kelley said, unveiling a 2026-2027 budget that includes a nearly 5% reduction in the effective administrative fee (EAF) that members and customers pay for the RTO’s services.

The EAF will drop to 45.7 cents/MWh from 47.9 cents/MWh, effective Jan. 1, 2026, thanks to a net revenue requirement (NRR) of $216.5 million boosted by the RTO’s expansion into the Western Interconnection. The 2025 NRR was budgeted at $204 million, but SPP expects the expansion to add about $16 million of positive NRR in 2026.

Kelley said the Western RTO participants will bring in slightly more than 40 TWh of transmission billing units, about a 9.3% increase, when the market goes live April 1, 2026. That will help offset an 8.7% increase in budgeted operating expenses, from $273.9 million in 2025 to $297.7 million.

The board approved the budget following the MC’s unanimous endorsement. The board also approved a $27.6 million capital allocation to invest in artificial intelligence and associated hardware.

The retiring Bruce Rew reacts to applause from the board and members. | © RTO Insider 

“We are investing in technology to make the organization more efficient and to limit future increases to our administrative fees,” Kelley said, “both from a staffing headcount perspective and outside services and future technology.”

The rate schedules that go into effect Jan. 1 are calculated by the NRR and the billing determinants for each schedule.

“What I’ve seen is the sophistication of our financial planning has increased over the seven years that I’ve been with SPP,” Director Susan Certoma said. “The complexity of the financials has increased also, but David, his team and all those involved in the budget process have been able to translate the complexity into clear and powerful messages, which provide all stakeholders with a clear understanding of the budget.”

Capacity Assessment Appeal

Board members approved Golden Spread Electric Cooperative’s appeal of a rejected tariff change (RR642) that would enable transmission customers and host TOs to access load-hosting capacity assessment in determining the amount of load the existing system can handle without requiring additional network upgrades.

Golden Spread’s Mike Wise brought the same appeal to the Markets and Operations Policy Committee in October, when it received only 29.51% approval. SPP’s TO members united to vote against the change, citing concerns over reliability issues with sharing load-hosting capacity and creating operational risks. (See Golden Spread to Appeal Rejection of Capacity Assessment Change to Board.)

Staff drafted the proposed change to tariff Attachment AQ’s screening process following a recommendation from the Holistic Integrated Tariff Team’s (HITT) 2019 report. It would allow SPP to proactively perform analysis to determine load capacity at each node on the system without incremental investment. Information gathered from the load-hosting capacity assessment would determine whether transmission customers would be required to go through an AQ delivery point network study.

“It’s my understanding that nobody opposes the tool, necessarily; that it’s a point in time where you have potential, available capacity,” Evergy’s Denise Buffington said. “The challenge we had was it should not replace the study, the need for a study, right? The hosting capacity is like a heat map at a point in time, but if you’re actually going to use it to connect something to the system, then the study needs to be performed. It’s not good enough just to rely on this tool.”

“This tool, as laid out, does not bypass the transmission owners’ right to ask for the study. It’s their prerogative,” Wise said. “This is not removing that decision.”

SPP staff said they would continue their work on the tool with the Transmission Working Group. They offered to gather technical feedback, fix the tool and come back to the board with another recommendation.

Members endorsed the successful appeal 21-1, with one abstention. Liberty Utilities voted against the measure.

Change to LTCR Market

The board approved a proposed tariff change (RR697) modifying the language to allow netting of flows in the long-term congestion rights (LTCR) allocation, giving more opportunities to all participants to receive the rights.

The revision request formalizes a policy approved by the Regional State Committee in February and completes one of the last remaining recommendations from the HITT. (See “RA, Congestion-hedging Recs Pass,” SPP Board/Regional State Committee Briefs: Feb. 3-4, 2025 and SPP Board Approves HITT’s Recommendations.)

“We’ve spent a lot of time trying to figure out how to improve our congestion-hedging process. I think this is just another step on that way,” SPP CEO Lanny Nickell said.

Eligible entities can nominate up to 50% of each path under the change and hold any awarded LTCRs for five years. All current awarded LTCRs will remain under the current rules and can be released yearly, if desired.

The MC endorsed the proposal 17-4, with two abstentions. Basin Electric, Nebraska Public Power District, Oklahoma Gas & Electric and Omaha Public Power District all opposed the measure, as did their state utility commissions (Nebraska, North Dakota and Oklahoma) during the RSC meeting.

The board approved three other revision requests that received a single dissenting vote between the RSC and MC:

    • RR655 establishes clear outage-submission requirements, including definitions, data standards, timelines and rules for submission, extension and updates. Market participants will be required to provide accurate timely outage and capability information; transmission providers will review and potentially deny noncompliant submissions.
    • RR707 incentivizes on-site fuel storage by applying a unique class average for resources that provide the capability. Newly constructed thermal resources and those that undergo a primary fuel conversion will be applied with a 0% equivalent forced outage factor (EFOF) for the first winter season; non-NERC registered resources will use class average EFOF for the 2022/23 and 2023/24 winter seasons.
    • RR719 aligns cost allocation for deliverability by allowing network resource interconnection service’s delivery portion before the Consolidated Planning Process is deployed to also be eligible for base-plan funding.

Rew, Osburn, Ross Honored

Stakeholders celebrated SPP’s Bruce Rew and Oklahoma Municipal Power Authority’s Dave Osburn, who are both retiring, with several standing ovations.

Nickell presented official resolutions to Osburn and Rew, one of SPP’s original 14 employees. Rew announced his retirement in April after 35 years with the RTO. Osburn is stepping away from the MC but plans to continue participating in the Resource Energy and Adequacy Leadership Team through February 2026.

Dave Osburn, OMPA | © RTO Insider 

“One of the things that’s always impressed me when I came here and got involved with SPP is while we sometimes have different business goals when it came to the organization and what’s best for the power pool in general, people kind of came together, found a way to collaborate and reach consensus,” Osburn said. “And I just always appreciated what takes place at SPP and how we try to figure out a good solution for everybody, not just our system.”

“When I reflect back, a lot of things have changed, but a lot of things have stayed the same,” Rew said. “One of those things are meetings like this, where the members are passionately committed to making a difference for SPP and setting the future for SPP. Shortly after I started, SPP celebrated 50 years and a short 15 years from now, it will be 100 years for SPP. So I do want an invitation to the 100-year anniversary so I can see what difference this organization has made in the next 15 years while I’m gone.”

Nickell also called out American Electric Power’s Richard Ross, who is giving up the Market Working Group’s chair after 21 years in the seat.

“I want to call [Ross] a super chair because a lot of work was done under his leadership,” he said. “I remember what our Market Working Group secretary said about Richard: ‘You have guided the MWG with a boot, a gavel, a steady hand, sharp insight and a collaborative, feisty spirit that has left an undeniable mark on this group and on SPP’s market evolution.’”

“That’s the truth,” muttered an SPP staffer in the audience.

Nickell said he wanted to give Ross one of the Gold Stars that he hands out for work well done, except for one small problem: “I’ve just never been awarded one.”

Bastone, Hepper, Wright Re-elected to Board

Members re-elected independent Directors Bronwen Bastone, Ray Hepper and Steve Wright to new three-year terms on the board during the Annual Meeting of Members.

Bastone, Wright and Hepper were first elected in 2020, 2022 and 2023, respectively. Hepper, the board’s chair, said Stuart Solomon has agreed to serve as vice chair, effective immediately.

Members also elected four new members and six incumbents to the MC, which acts as a sounding board and provides input to the directors. The four new members and the sectors they represent are:

    • Brad Hans, Municipal Energy Agency of Nebraska, and Paul Mahlberg, Kansas Municipal Energy Agency (Municipal);
    • Chris Matos, Google Energy (Large Retail); and
    • Ken Miller, OG&E (Investor-owned Utility).

The re-elected incumbents are:

    • Buddy Hasten, Arkansas Electric Cooperative Corp., and Jeremy Severson, Basin Electric (Cooperative);
    • Brett White, Pine Gate Renewables (Independent Power Producer/Marketer);
    • Bleau LaFave, NorthWestern Energy, and Stacey Burbure, Public Service Company of Oklahoma (Investor-owned Utility); and
    • Patrick Woods, ITC Great Plains (Independent Transmission Company).

The nominations were brought forward by the Corporate Governance Committee. Each member will serve two-year terms.

Competitive Project Proceeds

His seat at the table not yet warm, OG&E’s Miller pulled from the consent agenda a working group’s recommendation to make no changes to a construction permit for the 345-kV Sooner-Wekiwa competitive upgrade.

The Project Cost Working Group analyzed the project, awarded to Transource Oklahoma in 2020, but determined it couldn’t make a ruling on a reported cost increase that exceeded commitments because Transource included a confidential obligation in the proposal.

Miller said he had concerns about SPP’s competitive process but that his complaint was about not being able to see the cost overruns.

“We don’t know whether they’re reasonable and should be recoverable. We can’t see that,” he said. “I have concerns about the competitive process, but I also have concerns we are signaling to FERC that these cost overruns are reasonable.”

SPP assured the board and members that staff will continue to review the project and address any issues. The project has a Nov. 17 in-service date.

Miller abstained from the vote on the motion, which passed the MC 19-0, with three other abstentions.

The consent agenda, passed in a voice vote, included the violation relaxation limit analysis report; CGC’s nominations of Miller to the Strategic Planning Committee, and Western Farmers Electric Cooperative’s Rodney Palesano and OG&E’s Brad Cochran to the Human Resources Committee; and RR706. The tariff change adds the federal service exemption transfer point as a qualifying source for candidate LCTRs and auction revenue rights.

The agenda also included recommendations to accept new cost estimates for five projects as reasonable, nine out-of-cycle re-evaluations and two withdrawals.

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PJM Winter Outlook Finds Tightening Reserve Margins

PJM’s winter outlook found the RTO should have enough resources to meet the forecast peak load of 145,700 MW, although the reserve margin continues to decline as new resource development lags. If the forecast is reached, it would surpass the previous winter’s record-setting peak of 143,700 MW. (See PJM Sets Record Winter Peak Load.)

Load growth has continued to erode PJM’s reserve margin, which stands at 7.5 GW in the forecast, down from 8.7 GW in the previous year. About 4.8 GW of new nameplate generation was included in the modeling. Much of that is solar, however, and amounts to just 1 GW of capacity. (See PJM OC Briefs: Oct. 10, 2024.)

“The grid is set up to keep the power flowing reliably this winter under forecast conditions, but the tightening of our margins will begin to impact us in the next few years if it continues,” said Aftab Khan, PJM executive vice president of operations, planning and security, in an announcement of the winter outlook. “PJM is working on multiple levels with all of our stakeholders to reverse this trend of demand growing faster than we can add generation,”

The analysis shows 180.8 GW of operational capacity, which includes 177.9 GW with commitments in the capacity market, as well as resources anticipated to be available. An additional 7.7 GW of load management will be available. Of those resources, 15.9 GW is expected to be on outage during periods of system strain, and 5 GW of exports were included.

The reserve margin measures the amount of operational capacity above the 90/10 diversified load forecast plus the 6.8-GW day-ahead scheduling reserve requirement.

The amount of operational capacity reflects improvements in resource performance observed since the December 2022 Winter Storm Elliott. After that storm, PJM made several changes to its emergency procedures, non-performance penalties and advance commitment practices. The announcement says the margin could become tighter if those improvements do not continue.

“Generator performance will be critical to maintaining reliability this winter,” said Mike Bryson, PJM senior vice president of operations. “We are encouraged by the work we have seen by generation owners to fortify their units for winter operations, and we will continue to focus on communication and coordination that help us understand how PJM can help to mitigate gas scheduling challenges or other generator limitations.”

Presenting the outlook during the Nov. 3 Operating Committee meeting, PJM’s Akash Patel outlined the preliminary results of scenarios exploring how low renewable generation or the largest gas contingency could affect the reserve margin. If wind and solar output were to be 3 GW lower than expected, there would be 200 MW of operational capacity available before load management would be required. The largest gas contingency would take 4.7 GW off the system, shrinking the reserve margin to 5.8 GW; pairing the two scenarios would leave a 2.8-GW margin.

Paul Sotkiewicz, president of E-Cubed Policy Associates, questioned why PJM included 5 GW of exports in the analysis, stating that PJM’s governing documents require that non-firm ties to other regions be curtailed if it falls into a reserve shortage.

PJM Director of Operations Planning Dave Souder said the 5 GW is the historical value PJM has exported over peaks. The study results indicate with that level of exports PJM would be deficient and would begin implementing procedures to curtail off-system sales.

The announcement of the outlook says PJM and ReliabilityFirst intend to double the number of site visits they will conduct at 30 generators to share best practices on winterization. PJM also will conduct unannounced tests of generators that have not run in the weeks ahead of the winter season.

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EDAM Intertie Scheduling Processes Raise Stakeholder Concerns

More than 400 stakeholders attended a set of workshops where CAISO staff described new processes for scheduling intertie resources and resource adequacy imports in the ISO’s Extended Day-Ahead Market, which will begin operation in May 2026.

ISO staff used the Nov. 5 and 6 workshops to review a white paper on the subjects.

“I haven’t seen [this many participants] on a CAISO call since you were dealing with the 2020 blackouts,” said Dan Williams, principal adviser at The Energy Authority.

One of the new EDAM processes involves intertie resource bidding and scheduling. Intertie resources in CAISO are currently modeled at specific scheduling points, but under EDAM, those resources will be modeled at a generation aggregation point (GAP).

A GAP is the collection of supply resources in a balancing authority area or group of BAAs.

EDAM will have three types of GAPs: default, custom and generic. A GAP can be resource specific or not, and its location will be in a Western Energy Imbalance Market (EIM) or non-WEIM BAA where the energy is produced or consumed, CAISO staff wrote in the white paper.

The GAP approach will significantly improve power flow and market accuracy, improve alignment with actual power flows by reducing phantom congestion and reduce operator conformance of transmission limits in real time, staff wrote.

CAISO Executive Principal George Angelidis described five intertie resource types: system resources, intertie transaction resources, intertie generating resources, transfer system resources and mirror system resources.

Some participants said they were unclear about these terms.

“I am already a little lost between the difference between a system resource and an intertie generating resource,” said Carrie Bentley, CEO of Gridwell Consulting. “The words seem almost exactly the same. I’m wondering if it would be helpful to ground us all in what all these different terms are for and maybe … dumb it down for us.”

“Both the system resource and intertie generating resource are registered in the master file,” Angelidis said. “The system resources in implementation are non-resource specific intertie resources.”

Williams added: “We are seven months out from this [process] being a live part of CAISO’s market, and as far as I am aware today, there are sort of two sources of power that trade in the forward market: a CAISO source and a non-CAISO source.”

“Western markets are not set up to be trading with any amount of liquidity on a resource-specific basis in the pre-day-ahead market space,” Williams said.

The paper introduced indirect intertie scheduling in EDAM. CAISO currently offers direct scheduling at interties but will now include indirect scheduling in EDAM to allow non-EDAM BAA resources to wheel power through a WEIM BAA that requires explicit wheel-through schedules, the paper says. Indirect scheduling is more complicated than direct scheduling and requires coordinating schedules of multiple resources, the paper says.

EDAM’s implementation overall has been “going smoothly,” although the schedule remains “very tight and very aggressive,” CAISO staff said in October. (See ‘Aggressive’ EDAM Schedule ‘Going Smoothly’ for PacifiCorp, PGE.)

RA Import Changes

The paper also described generic RA import requirements.

CAISO tried to simplify monthly RA showings in EDAM. Monthly generic RA showings will not be resource specific, and scheduling coordinators who have generic RA import obligations will show these obligations in the ISO’s customer interface for resource adequacy (CIRA) system.

The paper also described requirements for imports of flexible RA. Monthly flexible RA will be resource specific, and CIRA will confirm that a scheduling coordinator has obtained the maximum import capacity at the intertie. If the source of the flexible RA obligation is in a non-WEIM BAA, the custom GAP must be the location of a physical resource in that non-WEIM BAA, the paper says.

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Former State Commissioners Form Affordability Council

The Regulatory Assistance Project (RAP) has assembled nine former state utility regulators to try to make electricity more affordable for ratepayers.

RAP announced the initiative Nov. 6 and said the former commissioners will try to influence regulatory initiatives to “secure access to clean, affordable and reliable energy for all.”

The bipartisan council includes:

    • Jay Griffin, former chair and commissioner of the Hawaii Public Utilities Commission and executive chair of RAP’s U.S. program;
    • Kent Chandler, former chair and vice chair of the Kentucky Public Service Commission;
    • Megan Decker, former chair and commissioner of the Oregon Public Utility Commission;
    • Sarah Freeman, former commissioner on the Indiana Utility Regulatory Commission;
    • Carl Linvill, former commissioner on the Nevada Public Utilities Commission;
    • Michael T. Richard, former commissioner on the Maryland Public Service Commission;
    • Ted Thomas, former chair of the Arkansas Public Service Commission;
    • James Van Nostrand, former chair of the Massachusetts Department of Public Utilities; and
    • Carrie Zalewski, former chair of the Illinois Commerce Commission.

RAP said the council is necessary as the grid becomes strained by growing demand. It said the group can “speak candidly and with authority” to current commissioners “on what’s holding back progress in U.S. energy systems.”

Griffin said the council will offer advice to utility regulators on how to achieve the most meaningful changes through commission action.

“This group understands the pressures on regulators and will serve as trusted peers to commissions throughout the U.S.,” Griffin said in a press release.

“At a time when energy issues are becoming increasingly politicized, this council’s experience will help today’s decision-makers cut through the noise, focus on the most urgent challenges and set the course toward the affordable, safe and secure energy all Americans deserve,” RAP CEO Katherine Dixon said in a press release.

Griffin told RTO Insider that RAP doesn’t plan for the council to weigh in on individual proceedings like rate cases, but it would release statements on topics it deems important.

RAP staff and senior advisers, including some council members, will continue to release reports on regulatory topics and engage directly with commissions, other government entities, utilities and stakeholders, he said. RAP assembled the council “to support today’s leaders in state commissions across the U.S.”

RAP will hold its first full meeting with the council in December and plans to hold a second meeting in February, Griffin said. It plans to maintain the council for the foreseeable future and is working out the details of council members’ terms. He said some “natural turnover” could occur, and he anticipates more former commissioners serving as senior advisers to RAP.

Nationwide, electricity prices have jumped approximately 40% since February 2020, according to the U.S. Bureau of Labor Statistics. The increase is attributed to grid modernization, rising data center demand and higher natural gas prices.

Household debt in the U.S. reached a record $18.59 trillion in the third quarter of 2025, up $197 billion from the previous quarter, according to data from the Federal Reserve Bank of New York.

Financial outlets increasingly refer to a bifurcated, “K-shaped economy,” where the upper arm of the “K” represents upper-class Americans’ income and spending growth since the COVID-19 pandemic, while the lower arm depicts lower- and middle-class Americans struggling with inflation, debt and increasingly expensive necessities like housing and health insurance.

RAP is a think tank that describes itself as “an independent, global non-governmental organization with a mission of advancing policy innovation and thought leadership within the energy community.”

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Michigan PSC Approves Special Data Center Rate Terms for Consumers Energy

The Michigan Public Service Commission has approved tailored rate provisions between Consumers Energy and energy-intensive load customers.

Clean energy groups commended the commission’s efforts to protect consumers but were critical of the Nov. 6 ruling’s lack of directives that large loads meet Michigan’s clean energy standard of 80% by 2035 and 100% by 2040.

The new provisions apply to customers with loads of at least 100 MW. Contracts would contain a five-year ramp-up period to full service and a 15-year term thereafter. The contract’s minimum billing demand requirement would have customers paying for on-peak demand, transmission demand and maximum demand charges based on 80% of their contracted capacity, regardless of actual usage. If customers want to exit the contract early, they must pay a fee equal to their minimum billing demand multiplied by the number of remaining months in the contract (U-21859).

The PSC said its decision attempts to simultaneously take advantage of economic opportunities while making sure large load customers cover the costs required to serve them. It said it believed its order would ensure “adequate guardrails” to avoid socializing data center costs and would prevent other customers from picking up the tab on stranded costs if anticipated loads fail to materialize.

Contracts would extend automatically in five-year increments and require four years’ notice to terminate.

The order requires prospective customers to pay an administrative fee to Consumers for worker hours spent studying and drawing up plans to serve the customer.

“These requirements are meant to ensure large load customers remain in service long enough that they will contribute significantly to new and embedded costs while also giving Consumers time to plan for unprecedented changes to its overall load,” the PSC said in a press release accompanying the order.

The new terms allow a large load customer to seek a one-time capacity reduction of no more than 10%, with a four-year written notice. Requests for reductions larger than 10% will have to go through commission approval. Consumers can suspend service to the customer if its usage begins to exceed contracted capacity by 1 MW or more.

However, the commission did not prescribe a specific rate design, leaving that for future rate cases Consumers brings forward. Instead, the PSC directed Consumers to propose six different cost-of-service study and rate design proposals “meant to analyze large load customers’ impact on rates and their contribution to interconnection costs, which will be used to set the rate for these customers going forward,” the PSC said.

The commissioners said large load customers can expect to be categorized under a separate rate class using a different cost allocation. They told Consumers to file ex parte cases for each large load customer to show that costs wrought by them aren’t bankrolled by other customers.

Consumers is further obliged to make annual reports to the commission containing data on large loads, their demand and energy use, changes in their capacity requirements and possible exit fees.

Finally, the commission held off on ordering further stipulations to mitigate large load customers’ effect on integrated resource planning and the state’s renewable and clean energy standards. The PSC said those matters were best handled in separate, ongoing proceedings before it.

Prior to the PSC’s order, Consumers had only its general primary demand (GPD) rate as its default terms of service, with the largest customer under the GPD at 28 MW. The original GPD uses a minimum on-peak billing demand of 60% based on previous summer use with a one-year minimum contract.

Consumers currently serves just one customer larger than 100 MW through a special rate established by the state legislature.

In testimony, Jim Dauphinais, counsel for the Association of Businesses Advocating Tariff Equity, said Consumers has received inquiries for new data center projects totaling 15 GW, with a half dozen of the inquiries for 900 MW or more for an individual customer. Dauphinais said discovery in the commission’s proceeding showed that Consumers contacted a local transmission owner over a 2.65-GW addition and was told the needed transmission investment to accommodate the extra demand would range from $730 million to $780 million.

Dauphinais testified that Consumers risked entangling its existing customers in subsidizing large loads unless it was held to strict consumer protections and annual reporting.

Consumers’ peak total demand is 7 GW. It announced in late July that it had reached an agreement to supply power to a data center of up to 1 GW for an unnamed developer.

Environmental advocates said that while the commission addressed the threat of higher bills, it didn’t shut down the possibility that data centers would undercut Michigan’s clean energy goals.

“This ruling is an important first step towards protecting Michiganders from the energy costs of data centers and the speculative rush that’s threatening to drive up our already high costs of electricity and deplete our water supply. We cannot afford to continue building high-cost gas or running expensive, dirty and old coal plants just to feed the data center rush. We expect regulators and our utilities to prioritize the use of cleaner, cheaper renewable energy to benefit all Michiganders,” Elayne Coleman, director of the Sierra Club’s Michigan chapter, said in a statement following the ruling.

The Michigan Environmental Council, Natural Resources Defense Council, Sierra Club and Citizens Utility Board of Michigan intervened in the case, arguing for 90% capacity payments instead of 80% under the new service terms. The group was represented by Earthjustice and Troposphere Legal.

“When data centers arrive, they typically bring the threat of higher utility bills and too often the undermining of clean energy goals. Today’s ruling is an important step towards reducing the risk of the former but, unfortunately, fails to address the latter,” said Shannon Fisk, director of state power sector advocacy at Earthjustice.

Fisk said she was encouraged the commission protected consumers against stranded asset costs and vowed to continue fighting to ensure data centers are supplied by clean energy “rather than dirty fossil fuels.”

Derrell Slaughter, a Michigan-based policy director at the NRDC, said that while the PSC’s order “makes strides on customer protection,” it fell short of compliance with Michigan’s clean energy standards.

“Without guardrails from the Public Service Commission order, it creates uncertainty about whether these large new customers will be powered by clean energy and ultimately help Michigan meet its clean energy goals,” Slaughter said.

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How Rising Wildfire Risks Are Rewiring the Future of Power Systems

By Dej Knuckey

A drone shot follows wind blowing through tinder-dry grass to transmission lines that clank ominously in the Sierra Nevada foothills. The opening scene of Apple TV+’s The Lost Bus is not subtle: The electric utility is painted as the villain behind the fire the down-on-his-luck school bus driver hero has to overcome.

Dej Knuckey

The movie was based on the real-life tragedy that unfolded when a 97-year-old suspension hook (C-hook) broke, causing a transmission line to fall and spark a fire that took lives, destroyed 18,000 structures and nearly wiped Paradise, Calif., off the map. The 2018 Camp Fire forever harmed the public’s trust. In a rare criminal case against a corporation, Pacific Gas and Electric pleaded guilty to 84 counts of involuntary manslaughter.

Since then, there have been many other massive wildfires throughout the United States, most notably in Hawaii and California. Some have been blamed directly on utilities, such as the Maui fire that destroyed Lahaina. The Palisades and Eaton fires in early 2025 in California caused an estimated $28 billion to $35 billion of insured property losses, the highest wildfire loss estimate yet in the U.S.

Grid operators and utilities no longer can afford to view climate-change-fueled wildfire risk as merely an environmental or safety issue. It’s a systemic reliability, financial and governance challenge. And it has implications for operations, investment strategy and long-term planning.

This is the third in a series of how extreme climate events affect the grid, following previous features on extreme heat and extreme precipitation.

The Climate-wildfire-electricity Nexus

While fires always have been a risk, multiple studies conclude climate change has “led to an increase in wildfire season length, wildfire frequency and burned area,” according to EPA.

The science is straightforward: Higher temperatures and longer dry seasons pull moisture out of vegetation, making it easier to burn. Precipitation that may end a drought also can create excessive growth in grasses and undergrowth, adding fuel for future fires.

Climate change also causes an increase in lightning strikes, the main natural cause of wildfires, responsible for 15% of wildfires and 60% of acres burned. That risk will continue to grow: Each 1-degree Celsius increase in global temperature increases lightning strikes by about 12%.

Grid operators and utilities have double exposure to the increasingly fire-prone environment: Grid assets can cause fires and be damaged by them.

There’s also a feedback loop when it comes to liability, particularly for investor-owned utilities, according to a report from Stanford University’s Climate and Energy Policy Program (CEPP).

“Because the economic damages from a single catastrophic wildfire can reach into the billions of dollars, the possibility that a utility could be found liable for a fire as a result of its infrastructure causing an initial ignition creates serious financial challenges for utilities,” the report said. “This makes IOUs riskier investments, which, in turn, makes it more difficult and expensive for them to access the capital needed to build infrastructure.”

Oregon PUC Chair Letha Tawney said liability fears impede data-sharing that could help the industry better understand the root causes of fires. (See Retribution Fears Impede Wildfire Mitigation, FERC Conference Speakers Say.)

Three Lines of Defense for Wildfire Risk Management

One approach to wildfire risk is to think about preventive measures, proactive response when fires happen and post-fire recovery. An IEEE paper defined these three lines of defense: “The first line of defense focuses on strategies to prevent wildfires from occurring in the first place.” It includes prediction, detection and vegetation management.

IEEE’s Three Lines of Defense for Wildfire Risk Management in Electric Power Grids | IEEE

“The second line of defense is focused on mitigation strategies and proactive response to minimize hazardous impacts of wildfires on the power system and its surrounding natural and built environment, should a wildfire spark.” This includes modeling active fires to predict their path and de-energizing lines ahead of the fire’s spread.

“Finally, if a wildfire sparks and spreads, we need a third line of defense that is focused on resilience-building measures and recovery preparedness so the system can bounce back to its pre-wildfire condition as quickly as possible without suffering devastating losses.”

This includes not only immediate temporary support, but also investing in resilient rebuilding, such as how PG&E is installing distribution lines underground as it rebuilds Paradise, Calif.

Playing Defense in an Offensive Environment

Utilities, particularly those in the West and Southwest, are taking action, particularly on the first line of defense. For example, PG&E conducts aerial line inspections using LiDAR to identify trees that need trimming. Utilities are hardening lines, replacing aged components and undergrounding selective circuits, an expensive process. In 2023, PG&E lowered the cost of its undergrounding program from $4 million per mile to less than $3 million per mile.

Mapping transmission lines against historic wildfire locations may help utilities plan. | Felt and National Interagency Fire Center data

On dry, windy days with high fire risk, utilities can preemptively power down lines. Public safety power shutoffs (PSPS) may lower risk but create public backlash when they stretch into days. It’s an example of how utilities must juggle tradeoffs between safety and reliability, as well as liability and service continuity.

Technology is helping to both monitor and manage the grid’s wildfire risk, with solutions ranging from pole-based monitoring, such as Gridware, to overhead line sensors, like those from Sentient Energy, as well as hardened components from hardware suppliers like ABB and Eaton.

Fires also complicate forecasting load and, where there are lots of solar assets, generation. “Wildfire smoke causes wiggling in the PV power output, which has the potential to impact the frequency stability of the grid,” a research paper found.

Some utilities have tried to get ahead of the financial risks, too. For example, the three largest California IOUs have started a California Wildfire Fund, with a $3 charge each month for account holders; however, the massive 2025 fires will drain funds earlier than expected. A group of policy experts proposed a national wildfire fund to spread risk across states.

While these approaches are needed, many are reactive and localized, focused on risk reduction, not system transformation.

Operating in the Heat of the Moment

When a wildfire starts, utilities must decide whether and where to power down the transmission and distribution lines. In the 2025 Altadena fires in the Los Angeles area, Southern California Edison (SCE) was criticized for powering down only four of the 12 circuits in the community.

Technology can give utilities and emergency services real-time fire monitoring and precise modeling of where and how fast the fire is likely to spread, based on satellite monitoring feeding into models that account for topography, wind, vegetation cover and more. OroraTech’s map of the spread of part of the Eaton fire shows how sophisticated this modeling has become.

Communication between grid operators and emergency services is critical, but often challenging, during a fire. The Associated Press reported that during the 2023 Lahaina wildfires on Maui, dispatchers, the local fire department and the utility, Hawaiian Electric Co., had significant difficulty coordinating. The culprits? Failing cellular networks, downed towers and separate radio channels.

Toward Climate-adjusted Grid Architecture

Utilities in areas with wildfire risk must treat that risk as a fundamental design parameter, in the same way they plan for load growth or changing generation mix.

There are questions for asset siting: Should critical lines or substations even be in fire zones? And for resilience planning: How should fire exposure be reflected in reliability metrics such as SAIDI and SAIFI? And for investment frameworks: How should regulators support preemptive resilience spending, not just post-event recovery?

The goal should be a climate-adjusted grid architecture with distributed, flexible and modular systems that can operate safely in fire-prone regions. Software, sensors and hardware solutions need to be designed to make a grid that can fail safely or self-isolate.

As remote communities consider their future resilience, the “grid edge” shifts. The main hospital in Paradise, for example, was rebuilt with an islandable 1-MWh energy storage and 425-kW solar microgrid to protect against PSPS and outages. Grid-attached microgrids and stand-alone systems should be explored for remote communities, a strategy that has worked in fire-prone remote areas in Australia, where removing the connection to the grid reduces fire risk for grid and off-grid customers.

The changing insurance and finance landscape will constrain the buildout of climate-adjusted grid architecture: Utilities are facing harder capital environments due to fire risk exposure.

From Centralized Risk to Distributed Resilience

To achieve a grid that is less likely to cause fires and more able to react to and rebuild resiliently after, there are policy levers at federal and state levels that can help.

While the federal government has reduced incentives for many types of renewables, utilities should lobby to reinstate incentives that support distributed resilience investments.

At the state level, regulators need to assess nontraditional infrastructure investments with an eye on their lifetime value, especially given that the value may be measured in not only homes but also lives saved. The gnarliest issue for regulators is how to balance cost recovery for proactive adaptation while keeping utility bills reasonable.

The Fire Next Time

Wildfire risk is reshaping the grid faster than most planning cycles can adapt. Yet for utilities and grid operators, rebuilding better after fires and getting ahead of future fires is not optional, it’s essential. Without moving from reactive defense to proactive resilience, the grid’s assets and their owners’ financial health will be at risk.

To mitigate wildfire risk and minimize future liability, utilities need to integrate climate risk — from fires, floods and storms — into every capital and operational decision. As the industry adapts to these risks, there are opportunities to develop innovative business models centered on resilience as a service. There also is a need to build cross-sector partnerships to facilitate smooth coordination with first responder groups on the ground when fires happen.

Wildfire is a risk no one wants, but it’s a reality that no longer is a seasonal hazard. Industry leaders who shift their organization’s mindsets from “compliance operators” to “resilience stewards” will be best positioned to survive in this new era.

Power Play Columnist Dej Knuckey is a climate and energy writer with decades of industry experience. 

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Duke Paper Lays out How FERC Can Make Flexibility for Large Loads Reality

FERC can make large load flexibility a reality through the implementation of the Department of Energy’s Advance Notice of Proposed Rulemaking on large load interconnections, according to a recent policy paper published by Duke University’s Nicholas Institute for Energy, Environment & Sustainability (RM26-4).

The paper — “How DOE’s Proposed Large Load Interconnection Process Could Unlock the Benefits of Load Flexibility” — was authored by a group of lawyers from Roselle, a firm “focused on the energy transition,” and former FERC Commissioner Allison Clements, now with 804 Advisory.

The Nicholas Institute produced a paper on data centers and load flexibility earlier in 2025 that found just 0.5% flexibility could unlock nearly 100 GW of headroom for new data centers. (See US Grid Has Flexible ‘Headroom’ for Data Center Demand Growth.)

The ANOPR mentions flexibility as one way to increase speed to market. The paper is meant to flesh out the details of what FERC can do in the rulemaking to make its use widespread, Roselle partner and co-author Sam Walsh said in an interview Nov. 7.

“There are huge benefits potentially from these kinds of flexibility commitments, [and there are] benefits in terms of speed to power, because if you commit to a flexible operation, there may be fewer needs for upgrades [and] less capacity that needs to be procured,” Walsh said. “It’s kind of easier for the interconnecting transmission owner to bring you onto the grid, and so the whole thing should be able to be achievable on a faster timeline.”

Flexibility from large loads means other ratepayers will not be on the hook for as many upgrades as would be required by data centers and others requiring firm service at peak demand times, he added.

“What we tried to do in the paper is start to kind of roll up our sleeves. … DOE is opening the door to, No. 1, creating a new rule that asserts jurisdiction over large loads interconnecting to the transmission system,” Walsh said. “And No. 2, it is urging that load flexibility, curtailability, to be part of that. Then what are they going to actually need to do in this rulemaking to make it happen?”

The paper noted the ANOPR will set up a jurisdictional battle over interconnection of customers, which historically has been left to the states. The National Association of Regulatory Utility Commissioners is debating a resolution at its Annual Meeting on that jurisdiction issue. The meeting, which began Nov. 9 in Seattle, will conclude just over a week before the first round of comments are due Nov. 21. (See Energy Secretary Asks FERC to Assert Jurisdiction over Large Load Interconnections.)

Data centers can offer flexibility in several ways, such as by cutting energy use at the sites themselves, sending compute to another site or using on-site resources. Those can include backup diesel, which comes with issues around air permits, and co-located generation and or batteries.

“Energy supply resources may also be located adjacent to (but not behind the meter of) load, integrating with load to provide joint value (reducing net capacity market impacts for the combined load-supply pair and, largely, the transmission impact), but otherwise operating independently,” the paper says. “Data center developers have indicated that these types of arrangements are often more commercially workable than the fully integrated energy park model.”

Commitments to flexibility can be temporary on behalf of large loads so they can connect to the grid before the five years on average it takes to build a new generator or the transmission grid and distribution system are fully upgraded. Or it could be a permanent commitment.

“Both can provide value to customers: Bridge flexibility can accelerate site energization, defer major upgrades and help ensure affordability and reliability in the near term, while permanent flexibility supports enduring grid optimization,” the paper says.

FERC needs to work through several issues to make large load flexibility a reality, including rules around how often data centers would be expected to curtail and what notice they get, Walsh said.

“Similarly, if you’re going to enable flexibility to reduce upgrades, you need to have a study process that incorporates that,” he added.

Interconnection studies now take a customer’s largest load and assume it will fall on the hours that the grid is most stressed, but that will not be the case with flexible loads, Walsh said. “They would need to build in these flexibility commitments into the modeling in order to see … what upgrades might be needed and might not be needed if they operate flexibly.”

In regions with capacity markets, large loads should be eligible for at least some kind of discount, allowing them to be non-capacity-backed loads, as PJM originally proposed, Walsh said. (See PJM Drops Non-capacity Backed Load, Shifts Focus to Resource Queue, PRD.) The loads themselves will need to face requirements so that they actually curtail when that is needed, he added.

The paper argues that “FERC could consider requiring transmission providers to offer non-firm network transmission service. Such an offering would allow a greater array of hybrid facility and adjacent load-supply arrangements to facilitate additional speed-to-power benefits, perhaps using technical approaches and business models we cannot currently foresee. As more load connects to the system and load interconnection studies more frequently identify network upgrades, such service arrangements could be valuable tools in providing speed to power.”

It points to ERCOT’s “connect and manage” approach to interconnecting generators as a possible model, as it has helped the Texas market achieve faster interconnections than others.

Flexibility can help hybrid resources work, Walsh said. The ANOPR discusses such arrangements and indicates pairing supply and demand could be one way to offer hyperscale customers speed to market.

“What we’re talking about really is kind of vital to the success of hybrid resources,” Walsh said. “If you get into the paper, we talk a fair bit about making sure that flexible loads and hybrid resources have access to non-firm, injection and withdrawal rights. We think that’s really critical. There are very few data center operators that don’t also want grid access. Even if they have a co-located generator, they want grid access to ensure their uptime.”

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MISO Installs Former Bonneville Executive to Board

MISO is adding Bonneville Power Administration’s former chief operating officer to its Board of Directors and welcoming back two term-limited directors in 2026 after collecting membership votes.

MISO members approved three-year terms for board incumbents Todd Raba and Barbara Krumsiek alongside Joel Cook, BPA’s former COO and senior vice president of transmission services. (See MISO Board Set to Add Bonneville Power Exec, Keep 2 Existing Members.) New terms begin Jan. 1, 2026.

Joel Cook | Bonneville Power Administration

Cook departed Bonneville in February when he took up the federal Office of Personnel Management’s buyout offer.

Incumbents Raba and Krumsiek are relying on a special waiver of MISO’s rules that allows them to serve a fourth, three-year term. Ordinarily, MISO board members are limited to three terms. This year, MISO’s Nominating Committee — comprised of three board members not up for re-election and two MISO stakeholders — recommended the use of waivers to prevent a potential 33% turnover on the board. MISO’s board is comprised of nine independent directors and MISO CEO John Bear.

Longtime board member H.B. “Trip” Doggett is vacating the seat Cook will take over. Doggett’s final official duties will be during MISO Board Week in December.

MISO membership voted electronically throughout October on the trio of candidates. MISO’s board elections require preselected candidates to receive a majority of votes in support among membership. MISO members can vote for, against or abstain from selecting any of the candidates.

Twenty-five percent of MISO membership (39 members in 2025) must vote in order to establish a quorum. MISO will release more details concerning the vote at its annual meeting Dec. 11, part of Board Week in Indianapolis.

“As MISO faces growing complexities and dynamic changes, the continuity of directors Raba and Krumsiek provides a source of strategic leadership and momentum that is critically important,” MISO CEO John Bear said in a press release. “We also welcome the new insights and perspectives from Director-elect Cook. His experience in the electric power industry will be beneficial to MISO and its members.”

Board Chair Raba thanked Doggett for his service. “His deep experience, insights and professionalism have been immeasurable during a period of extensive transformation,” Raba said.

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ISO-NE Forecasts Minimal Shortfall Risk for Upcoming Winter

ISO-NE’s probabilistic modeling indicates there is minimal risk of shortfall in the upcoming winter, COO Vamsi Chadalavada told the NEPOOL Participants Committee on Nov. 6.

The risk levels identified by ISO-NE’s Probabilistic Energy Adequacy Tool are well below the duration and magnitude metrics recently established by the RTO in its Regional Energy Shortfall Threshold (REST). (See ISO-NE Proceeding with Shortfall Threshold After Positive Feedback.)

The REST shortfall metrics are calculated based on the 0.25%, 21-day model cases with the greatest shortfall risk. These extreme model cases averaged a 0.1% shortfall magnitude and a 0.7-hour shortfall duration for the upcoming winter, well shy of the 3% magnitude and 18-hours criteria that would need to be exceeded to violate the REST.

Chadalavada said ISO-NE is confident it can maintain grid reliability even in the worst-case scenarios.

“The worst-case 21-day energy shortfall quantities result from a low probability combination of several uncertainties,” including low LNG and fuel oil inventories, low import levels and high levels of unexpected outages, Chadalavada said.

“In the worst cases, energy shortfall begins on Day 14 or later, thus allowing time for additional actions,” he said. “ISO expects that in the event of a forecasted energy shortfall, market-based incentives will encourage relief in the form of market response, including additional fuel replenishment.”

If ISO-NE’s 21-day forecast indicates a shortfall is likely, the RTO would have access to other emergency measures, including limiting exports, scheduling imports, seeking waivers to air permit limits and conservation appeals, he said.

Seasonal weather forecasting shows a 33 to 40% probability of above-average temperatures for southern New England, and equal changes for above average and below average temperatures in northern New England, Chadalavada said.

He said ISO-NE anticipates the tanks at the Saint John LNG terminal being full, and he added that generators with large fuel oil storage capabilities have indicated “that pre-winter replenishment is underway and supply chains are expected to be strong with adequate supply available.”

Operations Report

Energy market value totaled $429 million in October, up significantly from $350 million in October 2024, ISO-NE reported. Ancillary market value totaled nearly $17 million, more than double the $8 million total in the prior October.

ISO-NE recorded its first monthly net export in 13 years in October, Chadalavada noted.

The low import levels appear to be driven by continued drought conditions and low reservoir levels in Québec and also may be affected by Hydro-Québec’s looming baseload export commitments associated with the New England Clean Energy Connect and Champlain Hudson Power Express transmission projects.

Hydro-Québec has said it is managing its reservoir levels to ensure it will have enough power to meet these commitments. ISO-NE expects NECEC to be in service this upcoming winter. (See Drought, Climate Drive Uncertainty on New England Imports from Québec.)