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November 26, 2025

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FERC Greenlights LS Power to Sell CPower, 12.9 GW to NRG

FERC has approved LS Power’s deal to sell 12.9 GW of its gas generation in PJM, NYISO and ISO-NE, as well as its 6-GW demand response business, CPower, to NRG Energy for $12 billion (EC25-102).

The transaction, approved Nov. 14, was opposed by PJM’s Independent Market Monitor, as well as the New Jersey Division of Rate Counsel and Maryland Office of People’s Counsel, which argued it would harm competition and lacked safeguards against market power manipulation.

The Monitor urged the commission to condition its approval on requirements around how NRG could structure its cost- and price-based offers, subject them to the requirement that they offer into the day-ahead and real-time energy markets, base the DR strike price on the cost of dispatch and commit to not removing the generators’ capacity status to serve co-located load. (See NRG, PJM IMM Disagree on LS Power Deal’s Market Power Impact.)

NRG submitted analysis on how the deal would affect prices and ownership concentration, finding that the Herfindahl-Hirschman Index (HHI) for the New York City local capacity market is moderately concentrated and would increase from 1,085 points to 1,122 for the 2026 summer auction and go up from 1,157 to 1,214 in the 2026 winter auction. It determined the PJM capacity market is unconcentrated, with an HHI that would increase from 563 points to 565 across the RTO and would decrease within the MAAC zone from 851 to 840. They argued the increases in NYISO are small and below the commission’s threshold for rejecting a transaction and that the units in New York City would be considered pivotal and therefore subject to mitigation rules.

Commission staff issued a deficiency letter Aug. 13, requesting that the companies file more information about whether the DR resources were included in the horizontal market screens for PJM and NYISO. The companies responded with additional sensitivities showing there would be a “trivial impact” in the city and that the sensitivities for PJM and MAAC likewise found little impact.

The Monitor argued that the three-pivotal-supplier test would more accurately represent the impact to market power than the HHI, particularly given how tight PJM’s capacity market is.

“Regarding the PJM IMM’s arguments that the proposed transaction will increase market power in PJM, we find that the PJM IMM has not demonstrated that the proposed transaction will have an adverse effect on horizontal competition,” FERC wrote. “Although intervenors may submit alternative competitive analyses, accompanied by appropriate data, to support their arguments, the commission historically has not relied on three-pivotal-supplier test results or hourly market share analysis for its analysis of [Federal Power Act] Section 203 transactions, and we decline to do so here. Neither the three-pivotal-supplier test results nor hourly market share analysis cast doubt on the results of applicants’ [delivered price test], which indicates that the proposed transaction does not increase market concentration in any relevant market.”

During NRG’s third-quarter earnings call, CEO Larry Coben said the company expects the deal to close in the first quarter of 2026. It includes $6.4 billion in cash and NRG purchasing about 11% of LS Power’s shares, though it will directly receive less than a 10% holding to avoid the commission’s threshold for determining when a party holds functional control. The remainder will be transferred to an independent trust.

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NERC Winter Reliability Assessment Finds Many Regions Facing Elevated Risk

Rising electricity demand has outpaced winter capacity growth over the past year, leaving many North American regions at elevated risk for outages if they face extreme weather this winter, NERC reported in its newly released Winter Reliability Assessment.

Demand in areas covered by the report has grown by 20 GW since last winter, but corresponding grids have added just 9.4 GW of new supplies to meet the higher consumption, the report said.

“The bulk power system is entering another winter with pockets of elevated risk, and the drivers are becoming more structural than seasonal,” NERC Director of Reliability Assessments John Moura said during a Nov. 18 webinar on the report. “We’re seeing steady demand growth faster than previous years, landing on a system that’s still racing to build new resources, navigating supply chain constraints, and integrating large amounts of variable and integrated inverter-based generation.

“We also added the continued threat of extreme cold weather, which has changed over the years, and the margin for error narrows quickly,” he said.

The assessment finds highest risk of outages during extreme weather in the WECC Northwest and Basin regions; ERCOT; SERC Reliability’s Central and East regions; and the Northeast Power Coordinating Council’s New England and Canada Maritime Provinces regions.

While the past two winters have seen noticeable improvements in the delivery of natural gas to bulk power system generators, gas availability remains precarious during extreme cold due to the uneven application of voluntary freeze protection mitigation, NERC found.

“Gas production and supplies going to generators really do strongly affect how well the bulk power system can perform during winter conditions,” NERC Manager of Reliability Assessments Mark Olson said during the webinar. “These two systems are inextricably linked.”

New England stands alone in the report as facing “risk to natural gas pipeline capacity.” The region’s demand forecast for this winter is 2.9% lower than the previous winter’s demand, and firm imports and demand response can make up for retired power plants, the study said.

“New England continues to closely monitor regional energy adequacy, particularly during extended cold snaps where constrained natural gas pipelines contribute to rapid depletion of stored fuel supplies,” the report said. “ISO-NE’s deterministic winter scenario analysis shows limited exposure to energy shortfalls this winter. In New England, winter energy concerns are highest in scenarios when stored fuels are rapidly depleted; during these periods, timely replenishment is critical to minimizing the potential for energy shortfalls.”

‘Pragmatic, Proven Tools’

New England has for decades faced the issue of energy shortfalls during winter, and the idea of building new natural gas pipelines there has gained traction. (See Pipeline Expansion Highlights Key Questions About Gas in New England.)

“Expanding the gas infrastructure into a constrained area like the Northeast would help as you get to these low-temperature periods where gas-fired generation is competing with other users of the gas system; the gas infrastructure would better postured to be able to support the uses,” Olson said. “So basically, for electric reliability, we would expect fewer generator curtailments due to fuel issues, if we can expand that capacity, which can provide reliability benefits.”

That would mean fewer generator outages and less reliance on backup fuels, allowing the region to be more resilient during extended cold snaps, he added.

NARUC recently released its Gas-Electric Alignment for Reliability report, which recommended construction of more pipelines to improve electric reliability. (See NARUC Report Seeks to Make Headway on Gas-electric Coordination.)

Moura said “the preponderance of material that’s being presented to decision-makers around gas-electric” points in the same direction: “That alignment between gas and electric are critical, these are interconnected systems, and there needs to be some changes in the future.”

The power industry continues to build new natural gas plants, but they are not always paired with new pipelines, or contracts with firm service able to ensure delivery during the coldest days of the year, he added.

“The findings around aligning the markets, being able to put in more resilience through more infrastructure, are all lining up with what we need to have a reliable and resilient system in the future,” Moura said.

The National Petroleum Council plans to publish another report on gas-electric coordination in early December that will include recommendations to shore up the reliability of both systems, Moura said.

Electric Power Supply Association CEO Todd Snitchler said his group’s members are investing in the resources needed to maintain reliability, including gas-fired plants and batteries. Evolving demand forecasts increase uncertainty, but competitive markets can shield customers from risk, he said.

“Policymakers should avoid extreme rhetoric or drastic interventions driven by outlier projections and instead focus on pragmatic, proven tools that support reliability and encourage cost discipline,” Snitchler said. “Competitive markets remain the most effective mechanism to deliver reliable, innovative and cost-effective energy. With targeted reforms — and continued private investment — we can better ensure the dependable, affordable power system Americans expect this winter and for years to come.”

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NERC Standards Committee Rejects Nuclear Reporting Carve-out

In a relatively light monthly conference call Nov. 18, NERC’s Standards Committee unanimously agreed to reject a standard authorization request that would have exempted nuclear generators from the reporting requirements of reliability standard EOP-004-4 (Event reporting).

The Nuclear Energy Institute (NEI) proposed the SAR in March, with the goal of making EOP-004-4 consistent with recent changes to the Department of Energy’s DOE-417 form, used by generator owners, generator operators, balancing authorities and reliability coordinators to report electric emergency events and disturbances.

Reportable events include many cyber and physical security events, islanding, system-wide voltage reductions of 3% or more and complete operational failure or shutdown of the transmission or distribution system.

Similarly, EOP-004-4 requires GOs, GOPs, BAs, RCs and other registered entities to report certain events to the ERO, including damage to or destruction of a facility, physical threats to a facility or control center, generation and transmission loss, and complete loss of off-site power to a nuclear generating plant. Entities may use either DOE-417 or the form attached to the standard to report incidents.

Earlier in 2025, DOE-417 was updated to exempt operators of commercial nuclear plants regulated by the Nuclear Regulatory Commission (NRC) from reporting requirements. NEI’s SAR (page 15 of the agenda) proposed revising EOP-004-4 to provide a similar exemption, similar to that found in CIP-008-6 (Cybersecurity — incident reporting and response planning). That standard excuses cyber assets at facilities regulated by the NRC and its Canadian equivalent from reporting cybersecurity incidents to NERC.

However, NERC staff was “very concerned” about the proposal, NERC Manager of Standards Development Sandhya Madan told SC members, because it would eliminate “NERC’s only mandatory source of physical event incident reports for nuclear power plants.” She also said the reporting requirement is not duplicative, contrary to another of NEI’s arguments, because NERC does not have another route for such information.

Jennie Wike, compliance lead at Tacoma Public Utilities, pressed Madan on this point, asking whether keeping the reporting requirement for EOP-004-4 would run afoul of the Trump administration’s push to “eliminate duplicate requirements across government agencies.” In response, Madan repeated that while the NRC might consider the requirement in DOE-417 to be duplicative because the NRC already receives such reports, NERC does not have any other avenue for GOs and GOPs to submit the information.

Paul MacDonald, director of reliability standards, compliance and enforcement for the New Brunswick Energy and Utilities Board, reminded attendees that the standard also applies to Canadian utilities that are not subject to the NRC. He said the information was “important … for NERC to analyze” the behavior of nuclear plants during grid events.

Despite her earlier questions, Wike made the motion to accept NERC staff’s recommendation and reject the SAR. In accordance with NERC’s Rules of Procedure, the SC must provide a rationale for the rejection to NEI within the next 10 days, which Chair Todd Bennett volunteered to do.

INSM Standard Posting Approved

The SC agreed to authorize the posting of proposed standard CIP-015-2 (Cybersecurity — internal network security monitoring [INSM]) (Page 23 of the agenda) for an initial 45 calendar day formal comment and ballot period. Ballot pools will be formed in the first 30 days, and ballots will be conducted in the last 10 calendar days of the period.

The standard was developed under Project 2025-02 (Internal network security monitoring standard revision), in accordance with FERC’s June 26 order to modify the new INSM standard CIP-015-1 by extending its reach. (See FERC Approves NERC’s Proposed INSM Standard.) FERC directed NERC to file, within the next 12 months, a new standard that extends INSM implementation to electronic access control or monitoring systems, along with physical access control systems, outside a utility’s electronic security perimeter — the electronic border around its internal network.

Presenting the draft standard, NERC Manager of Standards Development Alison Oswald said the standard drafting team “has worked very quickly” to respond to FERC’s directive, and that “initial feedback … on this proposed draft has been very positive.” This motion passed unanimously.

New Members Elected

Finally, Standards Developer Dominique Love presented the results of the elections for new SC members that concluded Nov. 3. Seven members have been confirmed to begin two-year terms beginning Jan. 1, 2026:

    • Segment 1: Brandon Weese, NERC compliance manager at American Electric Power
    • Segment 2: Jamie Johnson, infrastructure compliance manager at CAISO
    • Segment 3: Claudine Fritz, senior manager for the principal compliance program at Exelon
    • Segment 4: William Pezalla, vice president for regulatory affairs at Old Dominion Electric Cooperative
    • Segment 5: Terri Pyle, head of utility operational compliance and NERC compliance at Oklahoma Gas and Electric
    • Segment 9: Paul MacDonald

No nominee for the two-year term in Segment 8, or the special election for a one-year term in Segment 5, received a simple majority, so NERC will conduct a runoff election for both seats in early December, Love said. In addition, the nominee for Segment 7 withdrew, so another nomination period is required.

Segment 10, representing regional entities, has an alternate election procedure. NERC will announce the nominee at a later date.

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ERCOT: New Ancillary Service Key to Resource Adequacy

ERCOT staff have told the Public Utility Commission they plan to file two urgent protocol changes with the Board of Directors in their latest push to design a new ancillary service that strengthens the grid’s resource adequacy.

Staff said the new service, now branded Dispatchable Reliability Reserve Service (DRRS) Ancillary Service Plus, will provide the most reliability benefit at the least cost compared to other market design options. Citing an Aurora Energy Research report commissioned by the grid operator, they said the service’s design adds more cost-effective dispatchable capacity and provides greater resource adequacy benefits in different load and extreme weather conditions (55797).

ERCOT’s Keith Collins, vice president of commercial operations, told the commissioners during their Nov. 14 open meeting that staff have been working on “refinements” to DRRS after getting feedback from the PUC, Independent Market Monitor and stakeholders. Collins said the grid operator plans to file two protocol changes and an accompanying revision to the Nodal Operating Guide in November.

Staff plan to ask the board during its Dec. 8-9 meetings to designate the changes as a board priority, Collins said.

The first nodal protocol revision request (NPRR) will establish DRRS as an ancillary service that addresses supply and demand forecast uncertainty and reduces reliability unit commitments. The second change will describe a proposed energy storage resource participation model and a “release factor” concept that allows the service to also support resource adequacy. Both designs open DRRS to online resources instead of just those offline.

Mandated by a 2023 state law, DRRS procures reserves of dispatchable power through the day-ahead market to ensure grid reliability during periods of uncertainty. Its sources include thermal generation, batteries and large loads that can come online within two hours and are able to provide service for at least four consecutive hours.

The stakeholder-led Technical Advisory Committee is expected to make a recommendation on DRRS’ design by the board’s June 1-2, 2026, meeting. DRRS originally had a 2024 go-live date, but ERCOT told RTO Insider that implementation is expected to take 24 to 30 months after a design is approved.

PUC Chair Thomas Gleeson, saying he and his fellow commissioners are not “prone” to curse from the dais, still uttered what he called a “four-letter word”: PCM. It was a reference to the late performance credit mechanism pushed by former Chair Peter Lake, which was likened by many to a capacity construct and a verboten concept in these parts because of ERCOT’s energy-only market. (See Texas PUC Shelves PCM Design Over Lack of Benefits.)

Gleeson asked Collins to explain how DRRS Ancillary Service Plus differs from the PCM. Collins used an analogy involving whales and fish to point out that the huge mammal with fins flopping in the surf is not the fish it appears to be.

“Unfortunately, when you develop something new and innovative, people tend to look for things that look alike and will say, ‘Well, it looks like PCM’ or ‘it looks like capacity markets,’” he said. “When you get down to the actual mechanics of actually how it works, they’re very different.”

The PCM was a forward-procurement mechanism designed to generate credits for thermal resources, Collins said. DRRS AS Plus will perform like all ERCOT ancillary services in that it will be procured in the day-ahead and real-time markets, the latter happening once Real-time Co-optimization + Batteries (RTC+B) is deployed Dec. 5.

Stoic Energy principal Doug Lewin, who monitored the meeting and shared a live thread, didn’t agree with Collins.

“Collins is working hard right now to differentiate between PCM and DRRS [AS] Plus,” he wrote. “But they’re different in degree, not in kind. And in degree, only barely.”

According to the Aurora report, ERCOT’s “status quo” market design will lead to reliability challenges under both moderate and high-load growth scenarios. It said with 22 GW of data center load by 2030 and 60% of the facilities participating in demand response, the chances of load shed during Winter Storm Elliott in 2022 and the 2023 heat wave would have been zero.

“When you have more data centers, you have more flexibility,” Collins said.

ERCOT will host a workshop on the Aurora report at its Austin headquarters Dec. 17.

Braunig Outage to End in December

ERCOT staff told the commission that CPS Energy’s Braunig Unit 3 is expected to return to service by Dec. 15 after an extended outage following the grid operator’s decision to enter a reliability must-run (RMR) contract with the aging gas unit (55999).

The 400-MW unit, which went online in 1970, has nearly completed a maintenance outage that began in March. CPS Energy soon discovered it needed to replace a boiler superheater header, which required steel from South Korea and Italy. The header was built in North Carolina and installed in October. All welding, X-ray examinations and hydrostatic pressure testing have been completed, said ERCOT’s David Kezell, director of weatherization and inspection.

“All of that seems to be working fine,” he said.

The expenses are piling up, though. The Unit 3 outage is expected to cost $32.9 million when it is completed after Thanksgiving. The grid operator has accrued more than $31.8 million in approved costs through June for CPS capital investments and fuel expenses. A 10% incentive factor is applied to other eligible spending, which eventually will exceed the cost of the maintenance outage.

ERCOT attorney Nathan Bigbee, tag-teaming with Kezell, said the 15 mobile generators Houston utility CenterPoint Energy loaned to the San Antonio region have all been installed and synchronized to the grid. Three of the units are dealing with power-control issues, but the other 12 are available for dispatch during emergency conditions.

LifeCycle Power, the generators’ provider, is exploring options to address voltage ride-through events, Bigbee said. However, he said the units are not expected to operate frequently.

“Our priority right now is getting these units commissioned,” Bigbee said.

ERCOT, CPS and LifeCycle entered a contract that runs through March 2027 and costs about $51 million for the entire term. The grid operator has piled up nearly $27 million in costs through October.

Under the contract, ERCOT will be able to dispatch the units only during actual or expected emergency conditions. The costs (an estimated $51 million) will be uplifted to qualified scheduling entities representing load on an hourly load-ratio share basis.

The ISO can terminate the contract early if transmission facilities addressing a regional constraint are completed ahead of schedule.

CPS Energy said in 2024 that it was planning to retire all three Braunig units in March 2025, but the ISO determined that Unit 3 was needed for reliability reasons. (See ERCOT Evaluating RMR, MRA Options for CPS Plant.)

ERCOT’s RMR contract with Braunig is its first since 2016, when it entered into an agreement with NRG Texas Power over a previously mothballed gas unit near Houston. The contract ended in 2017, thanks partly to transmission facilities that increased imports into the region. (See ERCOT Ending Greens Bayou RMR May 29.)

CenterPoint SRP Approved

The commission approved CenterPoint’s proposed system resiliency plan, a three-year, $129.7 million initiative, after Commissioner Courtney Hjaltman said the original filing lacked enough data to support the utility’s main vegetation-management measure (57579).

Hjaltman trimmed more than $10 million from the plan by accepting an estimated cost of $137.9 million in a supplemental filing; CenterPoint’s original budget was listed at $141 million. She cut an additional $8.2 million from the revised figure by striking 350 projects with benefit-to-cost ratios less than 1.0 or without ratios.

CenterPoint said its resiliency plan mitigates the effects of extreme wind, water and temperature events. The plan strengthens the physical security and cybersecurity of its infrastructure and technology assets and the ability to monitor and respond to resiliency events.

The PUC also approved a pair of orders related to the $10 billion Texas Energy Fund.

    • It endorsed staff’s recommendation to enter into grant agreements with four cooperatives, totaling $60.6 million, for reliability, resiliency and facility weatherization projects. The grants are the 14th awarded through the TEF’s Outside ERCOT Grant Program of the $10 billion Texas Energy Fund. The program has granted more than $680 million to projects that update transmission and generation infrastructure and provide vegetation management (58492).
    • The commission also accepted staff’s recommendation to accept an extension request from Hull Street Energy, an applicant for a prospective loan under the TEF’s In-ERCOT Loan Generation Program. The private-equity firm requested an extension to Dec. 31, 2026, saying a “confluence of market forces” outside its control made it unlikely to enter into a loan agreement with the PUC (56896).
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Citing Geopolitical Uncertainty, IESO Lowers Long-term Demand Forecast Slightly

The reference scenario in IESO’s 2026 Annual Planning Outlook indicates net annual energy demand growth of 65% by 2050, from just over 150 TWh in recent years to 250 TWh.

The figure represents “robust” load growth over the next 25 years, according to the ISO, but it is slightly lower than the 262 TWh (75%) predicted in the 2025 APO, released in April.

“While this APO reflects short-term impacts caused by current geopolitical uncertainty, the long-term forecast shows that Ontario is poised to continue growing through the 2030s and beyond — consistent with trends seen in the 2025 APO,” IESO said in a presentation to webinar attendees Nov. 18.

Adam Kliber, IESO supervisor of planning models and forecasts, said there were four main drivers of the lower-than-expected demand. Among them are reduced adoption of electric vehicles and delays in large industrial “step loads” — projects typically over 20 MW that interconnect in large blocks, as opposed to slowly ramping up their growth over time.

IESO officials did not go into details about the delays, saying the underlying assumptions would be released alongside the full APO in the first quarter of 2026. The 2025 APO showed a rapid increase in two types of step loads: data centers, defined as commercial load, and the EV supply chain, including batteries. Data centers still are expected to be the main driver of load growth in Ontario.

But several global situations since have led to delays in an expected ramp-up of EV production in the province. Chief among them is U.S. President Donald Trump’s 25% tariff on imported auto parts, which led Honda to postpone a previously announced $11 billion expansion of its manufacturing plant in Alliston into an EV production hub.

And in late October, Honda slowed production at all its North American plants because of a dispute between the Netherlands and China over the Chinese-owned, Netherlands-based semiconductor manufacturer Nexperia. The dispute has thrown a semiconductor supply chain still recovering from the post-COVID-19 pandemic shortage into disarray. Honda since has resumed normal operations after securing enough chips, but that could change as the conflict continues.

Umicore Precious Metals Canada also had announced plans to build battery components for EVs at its Loyalist Township plant, with the federal and provincial governments contributing a combined $1 billion into the facility. That plan was paused even before Trump re-entered office, and the company has no intention of starting construction any time soon, as lower metal prices and EV demand globally led to reduced revenue.

Another factor leading to the lower growth is IESO’s “new electricity demand-side management framework and its considerable contributions on slowing demand growth by helping families and businesses use electricity more efficiently.” The ISO also projects lower population growth, though Kliber emphasized the data “indicate a very high growth overall.”

The geopolitical uncertainty is reflected in IESO’s high and low demand scenarios, to be included in the APO for the first time to comply with a directive from the Ontario Minister of Energy and Mines. (See Ontario Energy Plan Gives IESO Long ‘To Do’ List.)

While the 2025 APO indicated a 2.2% compound annual growth rate and the 2026 reference scenario shows 2.1%, the high demand scenario shows 2.7%.

The ISO did not go into detail about the assumptions for each scenario, but officials presented how it is developing the 2027 APO’s scenarios, with explanations for each. The reference scenario represents “high-confidence policy, government announcements and continuing trends,” while the high and low demand scenarios vary based on economic growth and consumer-driven electrification trends.

Under the reference scenario, EV adoption would continue to grow but is lower than the federal government’s targets, with the low scenario reflecting even lower adoption rates. Under the high demand scenario, the government’s targets are met.

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PacifiCorp Staffs Up Ahead of EDAM Launch

PacifiCorp is hiring additional employees to prepare for CAISO’s Extended Day-Ahead Market in 2026, with staff expecting the launch will bring a few “scratches and bruises.”

Daniel Koppes, director of main grid operations at PacifiCorp, said during an EDAM workshop Nov. 17 that his department plans to hire a new team of eight engineers who will work seven days a week “to help analyze how our system is going to operate every single day, so that way we can optimize the market solution [and] help prevent curtailments.”

The new hires come as PacifiCorp develops new tools aimed at maintaining grid reliability under EDAM, Koppes said. Contrary to the existing real-time market, CAISO’s Western Energy Imbalance Market, EDAM requires PacifiCorp to analyze how its system will work 24 hours in advance.

“Because of the financial impacts of a 24-hour ahead, every change that we make is going to cost more money than the current market does if … it creates curtailments,” Koppes said.

Koppes’ department will hire more staff “to look at how did we do yesterday … so we know how we can do better. So, we’ve hired one, and we’re working on hiring a couple more business analysts to look at every day after the fact,” Koppes said.

Other PacifiCorp departments have staffed up or are doing so, including energy supply management, transmission services, business and accounting.

“The added staff that we’ve hired will allow us to stand a second operational desk,” said Parker Floyd, generation dispatch manager.

“We’re in the process of rebuilding our small control space into a slightly larger control room,” Floyd said. “With more responsibility and more full-time employees, we need more space, but we also need space to house and protect cyber assets that we’ll need.”

PacifiCorp is expected to begin participating in EDAM on May 1, 2026. Some models estimate EDAM will bring approximately $900 million in annual savings, and more than $300 million for PacifiCorp customers, according to a company presentation. (See ‘Aggressive’ EDAM Schedule ‘Going Smoothly’ for PacifiCorp, PGE.)

‘Sticking the Landing’

But to reach that point, PacifiCorp has a lot of work to do.

“My team is spending an enormous amount of time working on the software upgrades that are necessary to implement EDAM,” said Kris Bremer, transmission customer services managing director. “Specifically, in my team, it’s the customer portals that are going to be used for scheduling for various activities on our transmission system. That is a massive upgrade to what we’ve done in the past.”

Getting PacifiCorp’s legacy customers ready for EDAM is another challenge, because not all those customers fall under the company’s tariff and operate under old transmission agreements, Bremer noted.

Making sure those customers know how to schedule and how their transmission rights can be configured with EDAM is “also a big deal we’re working through right now,” Bremer said.

Dave Novom, manager of energy accounting and jurisdictional loads, said his department has hired one additional person who focuses on validating meter data and “working to make sure that we can submit actual meter data for settlements.”

In addition to PacifiCorp, five other entities have signed implementation agreements with EDAM, with more likely.

“With the expanded footprint, I think we know it’s going to become more complex, especially around optimization and cost allocation,” said Joseph Holland, finance and accounting manager.

“One of our major settlements initiatives, or workflows, right now is to enhance our … vendors’ ability to shadow settlements in EDAM,” Holland said. “This shadowing allows us to ensure that the CAISO settlement is accurate before we suballocate those charges on to customers to avoid having to rework. That’s one of the major areas where staffing is critical for us, adding new folks early in the process, which we’ve done.”

While the EDAM implementation mostly is running smoothly, two areas — CAISO integration and software upgrades — have run into some issues, according to Kerstin Rock, EDAM implementation director.

“It’s all very connected, in some cases, for really trying to orchestrate almost the cascading implication on the different applications,” Rock said. “So, at this point … we have risks that we’re managing. They’re not high-level risks. We have a few issues, which are generally related to timing.”

Rock said she expects the issues to be fixed, adding “I’m not going to sit here and pretend that we plan to stick our landing perfectly.”

“We are working on sticking the landing, and I’m confident that we will do so,” Rock said. “We may come out of it with a few little scratches and bruises and maybe some unkempt hair, a little bit overtired. … As someone in charge of the implementation, I have confidence that we will get there, confidence in our partners.”

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DOE Announces $1B Loan for Constellation’s Crane Energy Center

U.S. Secretary of Energy Chris Wright announced a $1 billion loan for Constellation Energy’s project to bring back the Crane Clean Energy Center, which has a long-term contract with Microsoft. (See Constellation to Reopen, Rename Three Mile Island Unit 1.)

The renamed Three Mile Island Unit 1 in Londonderry Township, Pa., will require $1.6 billion to reopen. Microsoft has signed a 20-year contract to buy electricity from it to power its data centers. Unit 1 closed in 2019 due to adverse economic conditions. It’s adjacent to TMI Unit 2, which partially melted down in 1979.

The loan to restart Unit 1 was funded by the Energy Dominance Financing program passed under the One Big Beautiful Bill Act, which Republicans now call the Working Families Tax Cut, earlier in 2025.

“Constellation’s restart of a nuclear power plant in Pennsylvania will provide affordable, reliable, and secure energy to Americans across the Mid-Atlantic region,” Wright said in a statement. “It will also help ensure America has the energy it needs to grow its domestic manufacturing base and win the AI race.”

The loan announcement marks the first project to get a concurrent conditional commitment and financial closing under the Trump administration. DOE said it remains committed to maximizing the speed and scale of nuclear capacity.

“DOE’s quick action and leadership is another huge step towards bringing hundreds of megawatts of reliable nuclear power onto the grid at this critical moment,” Constellation CEO Joe Dominguez said in a statement. “Under the Trump administration, the FERC and DOE have made it possible for us to vastly expedite this restart without compromising quality or safety.”

The loan will cut Constellation’s financing costs for the nuclear unit restart.

The Crane center is more than 80% staffed with more than 500 employees on site, Constellation said Nov. 18. Inspections of key plant components and regulatory reviews for the restart remain on schedule.

“Utilities and grid operators are moving too slowly and need to make regulatory changes that will allow our nation to unlock its abundant energy potential,” Dominguez said. “Constellation and nuclear energy are helping to lead the way, and we are thankful to President Trump and Secretary Wright for putting the ‘energy’ back into DOE.”

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Market Monitor Urges CAISO to Reconsider EDAM Intertie Proposal

CAISO‘s Department of Market Monitoring has asked the ISO to re-evaluate its intertie scheduling proposal for the Extended Day-Ahead Market because of potential impacts on market participants.

CAISO held an impromptu workshop Nov. 14 to address outstanding stakeholder questions and concerns about the proposal after receiving the DMM’s comments, which urged the ISO to use an alternative for EDAM’s go-live in 2026. (See EDAM Intertie Scheduling Processes Raise Stakeholder Concerns.)

A primary issue is that in CAISO’s existing market, intertie schedules are at a scheduling point (SP). However, a generation facility or load is not exactly at its assigned SP node, and this discrepancy affects congestion management, pricing and settlements, DMM noted in its comments.

CAISO tried to solve this problem by modeling intertie injections and withdrawals at one of several generation aggregation points (GAPs). Each GAP would have its own congestion and loss prices, so the prices of imports and exports at the same intertie would be different for schedules associated with different GAPs, DMM said. This new approach will create multiple prices for the same intertie and will affect market participants with transactions at EDAM and bilateral market interties, DMM said.

“It seems clear to DMM … that market participants are concerned that these changes could negatively impact their business operations and practices, or at the very least they have not had adequate preparation to consider the potential impacts,” DMM said in its comments.

The GAP intertie proposal could cause market participants to be left without knowing which GAP combination will be used for their day-ahead pricing. The GAP approach also could result in a market with multiple prices for the same intertie, meaning imports could clear at higher offer prices than other imports that are offered at lower prices, DMM said.

DMM recommended CAISO either keep the current SP approach or assign each intertie to a single generic GAP until stakeholders have the chance to go through the proposal in the ISO’s policy revision process.

At the Nov. 14 workshop, CAISO staff said the ISO realizes there are a lot of questions and concerns about “how fast we are moving” and that the grid operator is working on implementing a transitional period for the EDAM GAP intertie approach.

“We are interested in making sure everyone is ready for whenever we make these changes in our market’s design,” said George Angelidis, executive principal at CAISO. “We would like to actually work with you and work on a transition plan that would [take] us through the journey together to maintain the timing of EDAM in May 2026.”

CAISO is developing a transitional period for implementing certain intertie scheduling processes, including continuing to use SPs at CAISO interties for scheduling, mirroring and scheduling distribution, among other functions. At non-CAISO EDAM interties, the transitional period would include using a single GAP for scheduling, schedule distribution and locational marginal pricing calculations.

Resource adequacy import processes will be “simplified” during the EDAM transitional period, Angelidis said. RA monthly showings will occur at a CAISO SP tie, which is the same process used today in the ISO’s market. The process for reassigning RA obligations will stay the same in EDAM during the transitional period, specifically for those that are not reassigned in a WEIM or non-WEIM BAA.

CAISO has not designated a concrete time frame for the transitional period, an ISO spokesperson told RTO Insider in an Nov. 17 email. Before transitioning to the FERC-approved intertie scheduling model, the ISO would have extensive discussions with stakeholders to determine the timeline and ensure alignment, the spokesperson said.

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SPP’s ELCC Methodology Contested at Appeals Court

The Sierra Club and Natural Resources Defense Council have filed a petition with an appeals court to toss two recent FERC orders that granted SPP’s request to modify provisions for clean energy resources’ capacity accreditation.

The two organizations, represented by nonprofit advocate Earthjustice, filed the request with the D.C. Circuit Court of Appeals on Nov. 17.

At issue is FERC’s July approval of SPP’s tariff revisions to implement an effective load-carrying capability (ELCC) for wind, solar and storage resources, and a performance-based accreditation (PBA) methodology for conventional resources (ER24-1317). (See FERC Approves SPP’s ERAS Process, Accreditation.)

The Sierra Club and NRDC also are appealing FERC’s denial of a rehearing request for the order. The commission said in August that in the absence of FERC’s action in response to the request, the rehearing “may be deemed to have been denied.”

In approving SPP’s ELCC and PBA methodologies, FERC said the gird operator’s tariff change was a “new data-driven approach to resource accreditation.” Commissioners David Rosner and Judy Chang filed a joint concurrence, noting “numerous” parties raised several methodological concerns with SPP’s proposal.

“However, despite the concerns, commenters nonetheless appear to universally recognize that SPP’s proposal is an improvement over the status quo,” they wrote. “Given the growing urgency of the resource adequacy challenge in SPP, we are persuaded that the commission should accept this just and reasonable improvement.”

The RTO said in its filings that it will be able to more accurately measure generators’ reliability and ensure they are dispatched and compensated for their “real-world performance.”

“This gives utilities and grid operators better tools to plan for and maintain a reliable grid,” SPP said.

The environmental groups say SPP’s proposal “holds renewable energy sources to a significantly higher standard than fossil fuels” and doesn’t consider thermal generation’s “poor reliability during extreme weather.” They cited a report from the Union of Concerned Scientists that found thermal plants as “disproportionately vulnerable to failure” during recent winter storms.

“Power outages were avoided because SPP’s wind fleet significantly outperformed its expected value,” Sierra Club and NRDC said in a news release.

SPP spokesperson Seth Blomeley said staff are reviewing the appeal filing.

“We continue to have confidence in the merits of our [ELCC] plan,” he said.

Sierra Club Senior Attorney Greg Wannier said that “fair and accurate resource evaluation should be the minimum expectation for any grid operator.”

“Unfortunately, SPP decided instead to artificially prop up the value of coal and gas,” he said. “This double standard will force customers to pay more money for less reliable electric service and increases the risk of life-threatening power outages during the next heat wave or winter storm.”

“FERC has allowed SPP to put their thumb on the scale to artificially entrench fossil fuel generators at the expense of clean, reliable, renewable energy,” Earthjustice Senior Attorney Aaron Stemplewicz said. “We look forward to exposing FERC’s misguided approval in court.”

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ISO-NE Provides More Detail on Responses to LTTP Procurement

ISO-NE has published a summary of proposals submitted for its first longer-term transmission planning (LTTP) procurement, which is aimed at reducing transmission constraints between Maine and southern New England and supporting 1,200 MW of new onshore wind in northern Maine.

The solicitation is the first run of ISO-NE’s new LTTP process, which the RTO and the New England states established to select solutions to needs identified in long-term transmission studies. (See FERC Approves New Pathway for New England Transmission Projects.)

Four project sponsors responded to the first LTTP procurement, submitting six proposals in total. The proposals represent “a good diversity of solution designs,” ISO-NE said.

The cost projections range from $962 million to $4.04 billion, though these projections may change as the bidders and ISO-NE work to standardize the cost calculations. The expected in-service dates range from the fourth quarter of 2032 to the third quarter of 2035.

Four of the six projects are joint proposals submitted in collaboration with incumbent transmission owners. ISO-NE has not disclosed the identities of the companies that participated in the solicitation but noted that three of the lead project sponsors are incumbents and one is a non-incumbent.

Three of the submissions propose new HVDC lines running from Maine to Massachusetts, along with new and upgraded AC infrastructure. These proposals are:

    • A 151-mile 400-kV line between Wiscasset, Maine, and Everett, Mass., with a total cost of $2.55 billion.
    • A 144-mile 400-kV line between Wiscasset and Wakefield, Mass., projected to cost $2.6 billion.
    • A 164-mile 320-kV line between the retired Maine Yankee Nuclear Plant (in Wiscasset) and the retired Mystic Generating Station (in Everett), with an expected cost of $4.04 billion.

The three other proposals rely on new AC lines and line upgrades. They are:

    • A $2.2 billion proposal to build two new 345-kV lines totaling 70 miles, upgrade 16 miles of 115-kV line in Maine to 345 kV and upgrade existing 345- and 115-kV lines throughout Maine and New Hampshire.
    • A $2.14 billion proposal that is nearly identical to the prior proposal, but with a reduction in total mileage of 345-kV upgrades.
    • A $962 million proposal that includes a new 43-mile 345-kV line and three new substations.

ISO-NE said all the proposals claim to meet the minimum requirements of the RFP, which are to increase the Maine-New Hampshire interface limit to 3,000 MW and the Surowiec-South limit to 3,200 MW and support the interconnection of 1,200 MW of onshore wind in northern Maine.

For context, when the New England Clean Energy Connect transmission line is online — it is expected to achieve commercial operations this winter — the Surowiec-South limit will be 2,800 MW and the Maine-New Hampshire limit will be 2,200 MW.

ISO-NE said some proposals claimed to increase the limits beyond the minimum requirements. The RTO noted that it received proposals to increase the Surowiec-South limit to 3,800 MW and the Maine-New Hampshire limit to 3,600 MW.

All proposals would build a new substation near Pittsfield, Maine, to enable a 1,200-MW injection of onshore wind. No submissions proposed infrastructure that would accommodate more than the required 1,200 MW of offshore wind.

Separate from the LTTP process, Maine is seeking to procure 1,200 MW of wind in northern part of the state, along with transmission to connect the power to the proposed Pittsfield interconnection point in central Maine. Maine officials have expressed hope that other New England states will join in the solicitation.

Maine issued a draft RFP for this procurement in October 2025 (PUC Docket No. 2024-00099), noting that the procurement “is designed to leverage the LTTP solicitation and is contingent on ISO-NE selecting a longer-term transmission upgrade project.”

To select a preferred solution in the LTTP process, ISO-NE will review the projects to ensure they meet the minimum requirements, evaluate effects on other interfaces and screen for adverse system impacts.

ISO-NE also will rely on a consultant to evaluate the financial health of the project sponsors, the feasibility of the construction proposals and the cost estimates. The RTO will rely on the participating transmission owners to estimate the costs of corollary upgrades.

For projects that meet all the requirements, the RTO will quantify costs and benefits. (See ISO-NE Releases Longer-term Transmission Planning RFP.) Projects must have a positive benefit-to-cost ratio to be eligible to be selected by ISO-NE as the preferred solution.

ISO-NE said it expects to select a preferred solution by September 2026, noting that it is “cautious about committing to an earlier date” because the RFP “involves utilizing numerous new processes.”

By default, the costs of a solution would be allocated by load, though the states could submit an alternative cost allocation methodology or opt to terminate the process following ISO-NE’s selection.

If no proposals pass the benefit-cost threshold, the LTTP process allows one or more states to cover a project’s costs that exceed the threshold, enabling it to proceed.