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December 5, 2025

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FERC Gives Go-ahead on Tougher MISO DR Testing Rules

FERC has greenlit MISO’s plan to require its demand response to make real-world demand reductions to fulfill the RTO’s testing requirements.

FERC said the “modifications more clearly define and standardize the existing testing procedures” in a Nov. 17 order (ER25-2845).

MISO now can mandate DR to make actual megawatt reductions for testing instead of submitting mock tests to prove capability. MISO worked on the proposal over 2025. (See MISO Tries to Ward Off DR Fraud with New Testing Regime.)

“[W]e find that establishing stricter testing waiver criteria and adding specific testing parameters for demand resources in the tariff will provide greater certainty that demand resources will be available when called on by MISO,” FERC said, adding that the rules should diminish the “likelihood of market participants registering resources into the auction in a manner that does not accurately reflect the true capability of their resources.”

The commission granted MISO’s requested effective date of July 15, 2025, so the new testing regime is in place by the 2026/27 capacity auction. It said it weighed the quick turnaround time against the importance of accurate testing. It pointed out that MISO allows market participants to use “operational data gathered in the ordinary course of business” to prove full demand reduction or allows resource owners to defer testing until May 29, 2026.

MISO has about 15 GW of DR as of late 2025. But MISO has said its experience shows that only about half of the DR fleet is available when needed.

Under the new MISO paradigm, DR resource owners must demonstrate they can honor their notification time while dropping demand within the time-of-day periods that match with hours that MISO expects system risk to occur. The resources must hold their demand reduction for 15 minutes, covering at least two meter intervals. Owners must show a full reduction of all the megawatts they specified in registration during a real power test. MISO said it would allow some resources that experience a weather impact during testing to demonstrate a bit less than their full stated capability.

MISO will allow select DR owners to proceed with a mock test if a state authority expressly allows it or if it’s a proven resource that has responded to a call in the past three years and has not changed its specifications since.

DR and distributed energy resource aggregators argued before FERC that MISO’s plan allows discriminatory treatment between load-serving entities’ DR programs and aggregators of retail customers.

Voltus and Advanced Energy United said MISO’s testing waivers for load-serving entities’ DR programs amounted to aggregators’ DR groupings being held to a different standard. The RTO included testing waivers for retail DR programs overseen by state regulatory authorities. It didn’t extend the possibility of waivers to aggregators.

FERC said the testing exceptions aren’t discriminatory and recognize “states’ interest and expertise in ensuring that the demand response programs under their jurisdiction are effective.” The commission further pointed out that MISO’s tariff already contains the potential for testing exemptions for retail programs managed by state regulators. It said it was “reasonable for MISO’s testing requirements to account for relevant testing provisions in retail programs.”

The testing rules are part of a myriad of new restrictions MISO has placed on its DR since the RTO, its Independent Market Monitor and FERC staff discovered multiple instances of fraud, misrepresentation or rule violations among its DR fleet. (See MISO Tries to Clear Up Assortment of New DR Rules.)

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DOE Issues 3rd Emergency Order to Keep Michigan Coal Plant Open

The U.S. Department of Energy has reupped a coal-fired power plant in West Olive, Mich., for another 90-day period, preventing its planned retirement for a third time.

DOE issued another emergency order to MISO and by extension, plant owner Consumers Energy, to keep the 1,420-MW J.H. Campbell plant running from Nov. 19, 2025, to Feb. 17, 2026.

U.S. Secretary of Energy Chris Wright once again said that an “emergency exists in portions of the Midwest region …  due to a shortage of electric energy, a shortage of facilities for the generation of electricity and other causes.” He directed MISO and Consumers Energy to take “all measures necessary to ensure that the Campbell Plant is available to operate” and told MISO to write DOE by Dec. 3 to describe its efforts to keep Campbell running.

Consumers Energy originally planned to wind down operations at the plant in late May 2025, but DOE delivered its first emergency order on the eve of its retirement date. A second order in August followed on the heels of the first. The newest order brings prolonged operations to 270 days past the plant’s planned retirement date.

DOE framed its order as strengthening Midwestern grid reliability as MISO enters winter weather. The department also argued that Campbell would have retired “15 years before the end of its scheduled design life” if it were allowed to power down.

As of the end of September, the plant’s extended operations cost about $80 million, according to Consumers Energy’s financial disclosures. (See J.H. Campbell Bill Rises to $80M on DOE’s Stay Open Orders.)

The Environmental Defense Fund and Earthjustice continued to call the series of orders illegal and vowed to keep fighting them in the courts.

“Consumers Energy committed to retire the plant in 2022 under a settlement approved by Michigan state regulators, finding that replacing the plant with a variety of cleaner resources — including wind, solar and storage — would reduce costs for Michigan customers. DOE’s series of emergency orders ignore those decisions and are now putting consumers across the Midwest on the hook to keep this aging, expensive and highly polluting plant online,” EDF lead counsel Ted Kelly said in a statement.

Kelly said keeping the plant open is a “guaranteed way to needlessly” raise customer bills and worsen air pollution and pointed out the plant has “burned through over $600,000 in losses every day.”

DOE claimed that Campbell has been “critical” to MISO operations during its deferred retirement. It said it operates “regularly” during high demand and low renewable energy output.

But EDF said the plant suffered a partial breakdown in June, and Campbell Units 1 and 2 were completely offline when demand peaked during the month. What’s more, the nonprofit said NERC’s annual winter reliability assessment, released Nov. 18, concludes MISO is resource adequate “even in situations with extreme levels of demand and generator outages.”

Michael Lenoff, Earthjustice senior attorney, called the plant a “jalopy” that’s “prone to breaking down.”

During a third-quarter earnings call at the end of October, Consumers Energy CEO Garrick Rochow said he expects the emergency orders to continue in the long term and Consumers to comply with them.

Rochow said the utility has “a very flexible workforce that is committed … [to] following through with this order through the Department of Energy.”

Rochow said Consumers agrees with FERC that costs of the plant should be allocated across MISO Midwest. He said the region benefits from the continued operation of the plant, not just Consumers ratepayers. Consumers has “great confidence in our ability to recover” costs and will “continue to invest in the plant thoughtfully,” Rochow said.

Rejji Hayes, CFO of Consumers parent CMS Energy Corp., said Consumers is treating all costs associated with Campbell’s extensions as a regulatory asset. He said so far, there has been “minimal” capital investment. Hayes said once Consumers starts receiving cost recovery from MISO Midwest customers, the company would refund Michigan customers.

“We’re trying our best to make sure that Michigan customers are held harmless as we continue to operate the plant to the benefit of the region as noted,” Hayes said during the earnings call.

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Nonprofit Groups Sue N.Y. and N.J. over Pipeline Approval

A group of environmental, energy and water safety nonprofits have sued New York and New Jersey over their recent permits for the Northeast Supply Enhancement pipeline project that reversed multiple prior denials by state environmental authorities.

The New York Department of Environmental Conservation and the New Jersey Department of Environmental Protection, both of which approved the project Nov. 7, were sued Nov. 18. (See Permits for Trump-Favored Gas Pipeline Approved by N.Y. and N.J.)

“DEC’s approval is a 180-degree reversal; in 2020 it denied the exact same application,” Susan Kraham, managing attorney for Earthjustice’s northeast region, said in a press release. “The project hasn’t changed; the impacts haven’t changed; the only thing that has changed is DEC’s decision, which it reversed with no reasonable explanation,”

The NESE project would expand the capacity of Williams Cos.’ existing Transco Pipeline, including building 23 miles of new pipe along sections in Pennsylvania, New Jersey and New York City. The majority of that is designed to go underwater through Raritan Bay to New York Harbor. The plaintiffs say that constructing the pipeline and associated compressor station would violate state air and water quality standards, release mercury and chemicals into the water, and destroy local shellfish habitat.

“The Sierra Club was shocked and disappointed to see New Jersey and New York move ahead with Williams Transco’s dirty and harmful NESE project,” Anjuli Ramos-Busot, director of the Sierra Club’s New Jersey chapter, said in a press release. “We will not stop fighting this project.”

President Donald Trump moved to stop construction on Empire Wind 1 but reversed course after claiming to reach a deal with Gov. Kathy Hochul in May. The White House claimed Hochul “caved” on natural gas, while the governor’s office denied any deal was reached. (See BOEM Lifts Stop-work Order on Empire Wind.)

The plaintiffs include NY/NJ Baykeeper, Protectors of Pine Woods, Food and Water Watch, the New Jersey Safe Energy Coalition, the Surfrider Foundation, the Sierra Club and a group representing local homeowners. They are represented by the Eastern Environmental Law Center, Earthjustice and the Natural Resources Defense Council.

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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.”