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January 7, 2026

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Enviros Warn NIPSCO Against Rebuilding Coal Unit on DOE Emergency Order

Earthjustice has warned Northern Indiana Public Service Co. against making costly repairs to its R.M. Schahfer Generating Station to keep it running through spring in accordance with a federal emergency order.

The environmental law organization, representing Citizens Action Coalition of Indiana, Just Transition Northwest Indiana, Hoosier Environmental Council and Sierra Club, sent a joint letter to NIPSCO, telling the utility to think twice before pursuing expensive fixes for the non-functioning Unit 18.

DOE has put a freeze on multiple coal plants’ planned retirements, including Units 17 and 18 at R.M. Schahfer Generating Station. (See DOE Orders Two Indiana Coal Plants to Stay Open Through Winter.) NIPSCO planned to idle the units Dec. 31, 2025; they now must operate through March 23, 2026.

“There are several legal bases to conclude that DOE lacks authority under Section 202(c) to direct NIPSCO to revive the generation facility. We intend to litigate the recovery of any imprudently incurred expenditures,” Earthjustice wrote in the Dec. 30 letter addressed to Erin Whitehead, NIPSCO’s vice president of regulatory policy and major accounts.

Earthjustice said Unit 18 is broken and restoring it likely would entail significant equipment repairs. It said before NIPSCO undertakes repairs, it should examine whether they would be sensible.

Earthjustice pointed out that Schahfer’s Unit 18 underwent a 2,890-hour forced outage from Feb. 16, 2025, to June 23, 2025, due to a turbine blade separating from its root. The unit confronted a second, 1,996-hour outage beginning July 9, 2025, this time because of damage to an upper section of condenser tubes.

“We expect that the expenditure to procure and install the referenced long-lead time equipment to revive Unit 18 — instead of allowing the units to retire as previously planned — will be substantial,” Earthjustice said in its letter.

The law organization argued DOE exceeded its authority and treaded on state jurisdiction by effectively ordering the renovation of a rundown and worn-out coal unit. Earthjustice said while Section 202(c) of the Federal Power Act permits temporary connection in emergencies, it does not authorize the physical rebuilding of a generating unit. It added that Congress has never given DOE that power.

‘State of Disrepair’

“Because the plant is at the end of its useful life, with years of forgone maintenance and capital expenditures, and in a state of disrepair, the department’s order essentially requires rebuilding significant parts of the plant. Nowhere does the statute empower the department to issue such directive, and the department’s order is facially ultra vires,” Earthjustice told NIPSCO.

Earthjustice said in addition to NIPSCO needing FERC approval for a cost allocation to run the plant (under which only prudent costs can be recovered), Indiana has a federally mandated costs law. Under that state law, any costs cleared for recovery must be just and reasonable. Expenditures deemed unnecessary, excessive or imprudent, along with expenses that aren’t considered useful to ratepayers, are not to be recouped.

“A reasonable utility management does not in good faith expend money in response to an unlawful directive, particularly when the utility management is on notice of the unlawful nature of the directive,” Earthjustice and others wrote.

“The Trump administration’s unlawful emergency orders are not a blank check for NIPSCO to be paid by billpayers. NIPSCO is required to make prudent decisions about incurring costs to repair and operate its coal-fired units. We will not let NIPSCO simply add unneeded, unlawful and very high costs to peoples’ electricity bills without a fight,” Earthjustice attorney Sameer Doshi said in a statement to RTO Insider.

NIPSCO said its compliance with the DOE’s directive is mandatory and it’s reviewing the “details of this order to assess its impact on our employees, customers and company to ensure compliance.” The utility told RTO Insider that while the decommissioning timeline for the Schahfer plant is altered, its long-term plan to “transition to a more sustainable energy future remains unchanged.”

“Guided by our integrated resource plan, NIPSCO and NiSource recognize the importance of reliable and affordable energy as we manage costs and adapt to changing regulatory requirements. Our commitment to providing safe and dependable energy remains steadfast both now and in the future,” NIPSCO said in a statement provided to RTO Insider.

NIPSCO did not respond to RTO Insider’s request for comment on whether it plans to repair Unit 18 to comply with the order, the extent or estimated cost of the repairs, whether it plans to recover potential costs from ratepayers or whether it’s planning to make a FERC filing to recover costs. The utility also did not address RTO Insider’s question on whether it’s appropriate for the coal units’ costs to be allocated to the entire MISO Midwest region, as Michigan’s J.H. Campbell coal plant is poised to do. (See FERC Rules Costs of Mich. Coal Plant Extension Can be Split Among 11 States.)

‘Needs Rebuilt’

Unit 18 apparently needs extensive turbine work.

At the Indiana Utility Regulatory Commission’s (IURC) 2025 Winter Reliability teleconference, a NIPSCO executive acknowledged that Unit 18 is in an extended “forced outage” and it would take time and effort to restore to service.

“Frankly that unit, it needs rebuilt,” NIPSCO President and COO Vince Parisi described Unit 18 to the IURC. “It’s just the reality of that unit being close to retirement. We’re not completely unprepared, but it will take time to get long-lead time items in to be able to make the repairs necessary.”

Parisi said the work would involve long-lead time equipment that would have to be ordered and repairs could take six months or longer to get the unit to be able to operate on an extended time horizon.

NIPSCO also said Unit 17 likely would require work to stay online.

Following questions from the IURC, NIPSCO executives said they likely would roll potential repair costs stemming from the DOE order into a deferral account, like Consumers Energy is doing with its J.H. Campbell plant.

NIPSCO, anticipating the emergency 202 order, told the IURC in early December that it reached out to coal providers to ensure a fuel supply.

The utility plans to convert the Schahfer station to gas-only to supply electricity to data centers, including Amazon Web Services’ planned, $15 billion campus. The Schahfer plant is composed of two natural gas units in addition to the two older, large coal units.

Indiana’s Citizens Action Coalition reported the most dramatic electric bill increase in two decades in Indiana in a July 2025 roundup. The group said statewide averages were up more than $28/month (17.5%). NIPSCO customers were hardest hit at about $50/month (26.7%) due to climbing fuel costs, coal plant cleanups and investments in infrastructure.

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Calif. Electricity Consumption Headed off the Charts, CEC Forecast Shows

California’s electricity consumption is projected to increase dramatically over the coming decades due in large part to planned artificial intelligence data centers, although questions remain about how many of those data centers actually will be built.

The Golden State’s consumption could increase from about 280 TWh in 2025 to more than 450 TWh in 2045, California Energy Commission staff said in a presentation during a Jan. 5 online workshop.

This steep increase would be unprecedented: In 2005, electricity consumption in California was about 270 TWh — almost the same as in 2025.

The consumption forecast is part of the CEC’s demand forecast for the 2025 Integrated Energy Policy Report (IEPR). The CEC revised the demand forecast last month because it received new information about data centers and known loads.

The initial 2025 IEPR forecast results used data from September 2025 that had been provided by some of the state’s utilities. The revised results included December data from these utilities.

For data centers, the state’s projected capacity in 2039 increased from about 3,993 MW using the September data to about 4,280 MW based on the December data in a “mid-case” scenario. The “high-case” scenario showed an increase from about 5,944 MW to about 6,510 MW.

CEC staff would like to perform a more detailed analysis of data centers in the future, CEC Energy System Planning Coordinator Mathew Cooper said during the workshop. For example, staff want to look at “different sizes of data centers” and how those variations affect forecast results, Cooper said.

In a Dec. 31 letter to the CEC, Sanya Kwatra, an engineer with the California Public Utilities Commission’s Public Advocates Office (Cal Advocates), requested the CEC verify the data center applications that have been categorized as having signed agreements. Pacific Gas and Electric (PG&E) showed about 2,000 MW of data center applications with signed agreements as of September 2025, but 4,000 MW as of December 2025, Kwatra said.

The CEC decided not to make any changes to the data center forecast based on the comments submitted by Cal Advocates, CEC Information Officer Gilbert Magallon told RTO Insider in an email. It is “very rare for a project to withdraw its application in between signing the engineering study and signing the interconnection agreement,” Magallon said.

At the CEC’s Dec. 17 IEPR commissioner workshop on energy demand forecast results, agency Vice Chair Siva Gunda said it is important to think about “the balancing act of affordability and reliability.”

“If we are in an untenable situation this year, we recognize that there’s these large known loads that most likely are going to come in 2025, but maybe not,” Gunda said. “I want to be super conscious about the liquidity in the market in terms of the total energy supply in California and the West and how that impacts the resource adequacy prices. That’s a very important thing to think about.”

In the updated data, PG&E’s capacity request increased from about 12,000 MW to about 14,300 MW, while Southern California Edison’s decreased from about 6,000 MW to about 4,800 MW. CAISO’s annual coincident peak load increased from about 48,000 MW in 2025 to more than 70,000 MW in 2045.

Data Center Costs

In the Cal Advocates letter, Kwatra said also that the CEC should provide a more detailed explanation for how it incorporated data center costs in its comparison of statewide average electricity rates.

In the letter, Kwatra noted the CEC said it incorporated the preliminary estimates of the costs of data centers into the statewide average electricity rates, with the estimates based in part on data from a PG&E application, which is being used to build out the utility’s transmission revenue requirement (TRR).

Certain entities disputed PG&E’s data, specifically how it might be underestimating the cost of data center interconnections, she said.

The CPUC has not yet ruled on a proceeding involving PG&E’s data, so “the CEC should avoid relying on PG&E’s workpapers as factual data,” Kwatra said.

Instead, the CEC should provide more information about what data it is using and how it is using this data to build out the TRR, Kwatra added. Doing so will “help enhance transparency related to the cost impact of data centers on the transmission grid,” she added.

In the 2026 IEPR forecast update, the CEC will continue to monitor energization dates of uncompleted projects and will continue to analyze meter data, among other tasks, staff said at the Jan. 5 workshop.

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FERC Defends Order 1920’s Tx Planning Changes Against Appeals

FERC defended Order 1920 against appeals in a brief filed Jan. 5, saying the transmission planning and cost allocation rule is firmly within its authority and builds on previous pathbreaking rulemakings like Orders 888 and 1000.

“The rule responds to an extensively documented, pervasive problem left unsolved by prior efforts: In recent years, FERC-jurisdictional transmission utilities have too often pursued inefficient and unnecessarily costly expansions to the nation’s electric grid that are short-term and parochial,” the commission said.

The 4th U.S. Circuit Court of Appeals is considering challenges to the rule that were filed by different groups including states and transmission owners who argued the commission went too far and other parties who argued it did not go far enough. (See Parties Argue for Appeal of Order 1920’s Tx Reforms in First Set of Briefs.)

“While these challenges variously claim that the rule did too much, too little or simply the wrong thing, the rule itself answered all these concerns,” FERC said.

Despite the previous round of transmission planning changes in Order 1000, the past decade has seen utilities focus on “piecemeal” grid-expansion projects focused on the immediate needs of their own service territories, the commission said. In the rulemaking process that led to Order 1920, FERC determined that such a “disjointed approach to transmission planning is woefully inadequate” to meet the grid’s rapidly evolving needs.

Even where regional needs were being met, as much as 80% of investment was concentrated in resolving local needs, FERC said, citing figures from MISO and PJM. All that meant customers were likely paying more than needed, forgoing benefits that outweigh their costs, or some combination, which could render rates unjust and unreasonable.

“Energy-hungry data centers and electrification (think gasoline to electric cars) have proliferated in recent years and are driving accelerating increases in energy demand, whose overall growth will likely necessitate scores of new power plants and billions of dollars in new investments by the year 2050,” FERC said. “For their part, states have directed their utilities to procure power for their residents from particular sources, which could be within the state or farther away and require transmission lines to transport that power to consumers. And extreme weather events have — and will continue to — stress an aging electric grid.”

If states are mandating the construction of new nuclear facilities, new gas plants or new “zero-emitting sources,” then it is not just and reasonable to ignore those trends in transmission planning, the commission argued. FERC-jurisdictional utilities have to ensure that power flows to market at a reasonable cost, and that requires understanding the drivers of future transmission needs.

The rule requires transmission providers to assess several factors influencing the grid’s needs over a long-term, two-decade time frame, and in doing so, it reacts to, but does not dictate, government and utility policies and market factors that impact regional transmission, FERC said. Planners need to assess proposed facilities against a set of reliability and economic benefits, which ensures just and reasonable costs for consumers and a reliable grid, it said.

Order 1920 directs costs to be assigned in a manner roughly commensurate with benefits. The rule requires transmission planners to consult with them on cost allocation and to file any competing cost proposals developed by a region’s state regulators for FERC’s consideration on compliance.

The requirement to file any state cost allocation proposal faced arguments that it infringed on utilities’ First Amendment rights by forcing them to file proposals they do not agree with. But FERC argued that the filing requirement does not constitute expressive activity warranting First Amendment protection.

“The commission adopted the inclusion and consultation requirements to ensure that it has sufficient information to determine a ‘just and reasonable’ rate under the Federal Power Act,” FERC said. “Such regulatory compliance requirements do not implicate protected speech.”

FERC and other federal agencies can direct disclosures from companies when they fall under their jurisdiction. The commission noted the utility challengers did not extend their First Amendment argument to a requirement that firms publicly disclose the transmission links they expect to replace in the next decade, instead arguing that requirement is anticompetitive.

The challenged provisions require nothing more than utilities to attach one or more files to their mandatory compliance filings with Order 1920, FERC said. “Transmission providers remain free to advocate for their preferred cost-allocation methods in both their FERC filings and through non-regulatory means.”

Cooperatives have argued that they should get some of the same rights because they set retail rates, but they lack the ability to site and permit transmission infrastructure. But FERC gave state regulatory commissions a special role in the hope that their buy-in might motivate states to approve transmission lines from the regional plans, it said.

Some states appealed Order 1920 on the grounds that it infringes on their power to regulate electric generation, but FERC argued that it steers clear of regulating any state decisions on generation.

“That the rule accounts for, or might even impact, state generation policies does not divest FERC of its exclusive authority over interstate transmission and practices that directly affect rates for such transmission,” the commission said. “Put another way, that FERC’s actions taken within its jurisdictional field might affect matters within the states’ own is of no legal consequence.”

States opposing the rule also argued that Order 1920 violates the “major questions doctrine,” but FERC pushed back by saying Congress granted clear authority over interstate transmission and that the Supreme Court has repeatedly recognized its broad authority in that area.

The states in opposition to the rule argue it will subsidize certain states’ generation policies at the expense of others.

“But the rule’s transmission planning provisions — which require only that transmission providers consider how states’ policies might affect transmission needs — include no subsidies at all,” FERC said. “Nor do they otherwise preference some states’ generation choices; the rule is resource neutral.”

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NECEC Transmission Line Ready to Begin Commercial Operations

After a multiyear delay caused by intense political opposition, the New England Clean Energy Connect (NECEC) project finally is ready to begin commercial operations, Avangrid wrote in a Jan. 2 filing to the Maine Public Utilities Commission (MPUC 2017-00232).

Once in service, the 1,200-MW transmission line will facilitate baseload power supply from Hydro-Québec to New England. The project was selected in a 2017/18 procurement led by the Massachusetts Department of Energy Resources (DOER), leading to contracts between the state’s electric distribution companies and Avangrid for the transmission line and 20-year supply contracts between the EDCs and Hydro-Québec.

“As of Dec. 31, 2025, the NECEC project has satisfied all conditions precedent for commercial operation,” Avangrid wrote in its filing. “NECEC’s commercial operation is scheduled to commence on Jan. 16, 2026, unless the parties — NECEC, the Massachusetts electric distribution companies and Hydro-Québec — mutually agree in writing to an alternative date (such as a slightly earlier start).”

NECEC began to ramp up bidirectional testing in late November, eventually sending up to about 900 MW of power from New England to Québec and as much as 1,300 MW from Québec to New England, according to ISO-NE data.

The EDCs are working with Avangrid to review final materials before the line officially comes online.

“We have been actively testing the equipment for the past several weeks,” a spokesperson for Hydro-Québec wrote. “We aim to begin contractual energy deliveries this month, taking care that all technical prerequisites are met.”

The new transmission line runs for about 145 miles from the U.S.-Canada border to its interconnection point in Lewiston, Maine, while the Québec portion of the line extends for about 60 miles.

The project faced substantial political opposition in Maine, backed by more than $20 million in funding from NextEra Energy, which owns the Seabrook nuclear plant in New Hampshire and several other fossil fuel and clean energy resources throughout the region.

While the project initially aimed to come online at the end of 2022, a nearly two-year suspension of construction caused by a voter referendum challenging the line contributed to the roughly three-year delay in the project’s in-service date.

In 2024, Avangrid sued NextEra for antitrust violations and alleged NextEra engaged in an “exclusionary and anticompetitive scheme” that caused $350 million in damages to Avangrid. In September 2025, a U.S. District Court judge in Massachusetts dismissed the claims of antitrust violations, ruling Avangrid had not demonstrated NextEra had monopoly power enabling them to set above-market prices in ISO-NE. (See Avangrid Sues NextEra over ‘Scorched-earth Scheme’ to Stop NECEC and Court Dismisses Claims of NextEra Antitrust Violations to Block NECEC.)

The project delay has been costly for ratepayers; the Massachusetts Department of Public Utilities approved a settlement agreement in early 2025 regarding the effects of the delay on project costs. The Massachusetts EDCs estimated the settlement would cost ratepayers about $521 million in 2017 dollars (DPU 24-160).

Despite the cost increase, the DOER estimates that, once in service, NECEC will save Massachusetts electric customers about $18 to $20 annually and cut emissions by about 2 million tons per year. ISO-NE studies also have shown significant winter reliability benefits associated with the line. (See ISO-NE Sees Little Shortfall Risk for 2032.)

It’s unclear how the line will affect net imports and exports between New England and Québec. New England’s imports from the province have declined significantly in recent years, driven by an extended drought and Hydro-Québec’s efforts to prepare for the supply contracts associated with the NECEC and Champlain Hudson Power Express projects. While the NECEC supply contracts require Hydro-Québec to send baseload power over the NECEC line, they do not prevent the company from importing power from New England over other lines.

The upgrades associated with the NECEC project will affect the transfer limits for two internal interfaces in ISO-NE. When NECEC is online, the limit of the Surowiec-South interface will increase to 2,800 MW, compared to the previous limit of 1,800 MW, and the Maine-New Hampshire interface will increase from 2,000 MW to 2,200 MW.

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NRC Approves First Digital Conversion of Nuclear Plant Safety Controls

A 40-year-old Pennsylvania facility that is among the nation’s younger nuclear power plants is the first to win approval to replace its analog safety systems with a single digital system.

The Nuclear Regulatory Commission (NRC) said Jan. 5 that its approval of the digital upgrade at Constellation Energy’s Limerick Clean Energy Center paves the way for instrumentation and control modernization across the U.S. commercial fleet.

Operators of other facilities have taken advantage of regulatory flexibilities to make limited, targeted digital upgrades, NRC said, but the Limerick project is the first authorized to take a broad, comprehensive approach. Much of the U.S. fleet still relies on analog controls.

Constellation said Jan. 6 that the $167 million overhaul will be performed in phases to maintain operational continuity, with major work planned when the reactors are taken offline for refueling.

The company said the Limerick Digital Modernization Project would enhance safety system reliability and cybersecurity; significantly reduce manual maintenance, testing and surveillance requirements; enhance operator interfaces and diagnostic capabilities; reduce plant operating and maintenance costs; and eliminate obsolete components.

The effort is part of Constellation’s $5.1 billion effort to preserve and expand the capacity of its nuclear fleet in Pennsylvania and comes as the Trump administration tries to bolster nuclear power generation nationwide. It is supported by the U.S. Department of Energy’s Light Water Reactor Sustainability Program.

The NRC license amendments place some requirements on the project but conclude that the changes will not endanger the health, safety and security of the public (Docket Nos. 50-352 and 50-353).

Limerick Clean Energy Center is 35 miles southeast of Philadelphia. Its two General Electric boiling water reactors are rated at a combined 2,317 MW. They operated at a capacity factor of 95.2% to generate a net 19.36 million MWh of electricity in 2024.

Unit 1 entered commercial service in February 1986 and Unit 2 in January 1990.

In October 2014, the NRC renewed the operating licenses for Unit 1 through October 2044 and Unit 2 through June 2049.

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MISO Announces Microsoft AI Partnership for Planning, Operations

MISO announced it will partner with Microsoft’s AI technologies to operate its markets and plan its system.

MISO said it would create a “unified data platform designed to transform how the grid is planned, operated and optimized” with Microsoft’s help. The grid operator said it will incorporate cloud computing platform Microsoft Azure and Microsoft Foundry’s generative AI technologies.

“Partnering with Microsoft allows us to harness the full power of advanced analytics, AI and cloud platforms to improve forecasting, enhance decision-making and build resilience into our operations. Ultimately, these advancements benefit our members and stakeholders,” MISO CIO and Vice President Nirav Shah said in a Jan. 6 press release.

MISO said it should be able to better predict and detect grid conditions and make faster, data-driven decisions by integrating these versions of machine learning and insights from massive datasets on the cloud. It said the move will help it make more proactive decisions during disruptions like extreme weather events and improve real-time reliability.

The RTO said it would use Microsoft Foundry to devise better grid forecasts and long-range transmission planning. MISO’s engineers and operators would use tools like Microsoft Power BI’s interactive data visuals and AI chatbot Microsoft 365 Copilot to assist in their work, it added.

MISO began using AI to influence decisions in the control room in 2024, but said over fall 2025, its AI-based risk prediction model failed to foresee the highest risk days of the season. (See “Risk Predictor not Quite There Yet,” MISO Usage, Outages Up in Fall 2025.)

MISO said the data platform should cut some of its work from “weeks to minutes” and would allow MISO to pinpoint and avoid transmission congestion before it occurs.

“Such acceleration is critical because of the increasing diversity of energy mix, electrification, rising demand and the growth of data centers,” Shah said, adding that “now is the time to partner with organizations that share a common interest in modernizing the grid operations of the future.”

Darryl Willis, Microsoft corporate vice president of energy and resources industry, said the partnership is a “bold step forward in modernizing one of North America’s most complex and critical electricity markets.” Willis said Microsoft’s AI capabilities and cloud-based analytics can build a “future-ready, more resilient and sustainable grid that can anticipate challenges, optimize performance and deliver reliable power as electrification and demand grow.”

MISO said the new partnership is its way of “taking a leadership role in ensuring that digital transformation benefits are shared across the grid.”

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DOE Awards $2.7B to Help Reshore Uranium Enrichment

The U.S. Department of Energy has awarded $900 million each to three companies to help expand the country’s uranium-enrichment capabilities.

The Jan. 5 announcement is the latest step in a long-running effort to expand domestic production of the fuel that generates approximately 19% of U.S. electricity — almost all of which is imported. If the widely held ambitions for expanded nuclear generation come to fruition, much more enriched uranium will be needed.

DOE intends its awards to expand capacity for the low-enriched uranium (LEU) used in most commercial reactors and to foster innovation and supply chain development in the high-assay low-enriched uranium (HALEU) that some next-generation nuclear reactors will use. The $2.7 billion will be disbursed as milestones are reached over the next decade.

The recipients are American Centrifuge Operating, to create domestic HALEU enrichment capacity; General Matter, to create domestic HALEU enrichment capacity; and Orano Federal Services, to expand domestic LEU enrichment capacity.

DOE also awarded $28 million to Global Laser Enrichment to continue development of its next-generation uranium enrichment technology.

The announcement came two weeks after American Centrifuge’s corporate parent, Centrus Energy, announced it had begun domestic centrifuge manufacturing to support commercial LEU enrichment activities at its Piketon, Ohio, facility. Centrus said it has secured $2.3 billion in contingent LEU sales and is working toward future HALEU production.

Orano said Jan. 5 that the DOE award would support development of its planned uranium enrichment facility in Oak Ridge, Tenn., which has an anticipated price tag of $5 billion. The company has named it “Project IKE” after President Dwight D. Eisenhower’s “Atoms for Peace” speech to the U.N. in 1953. It expects to submit the facility design to the Nuclear Regulatory Commission soon and hopes to build it quickly enough to begin LEU production in 2031.

The company has supplied enriched uranium to the U.S. reactor fleet for 40 years from production facilities in France and intends to continue this with production in Tennessee.

“Orano is the only Western company in the last 15 years that has successfully built and operated a new, modern, commercial-scale gas centrifuge uranium enrichment facility with our completion of the Georges Besse II facility in 2011. Plus, we are currently performing a 30% capacity expansion of this facility,” said François Lurin, executive vice president of Orano’s Chemistry and Enrichment business. “Our objective is to apply the best practices from that construction and expansion to the benefit of the Project IKE uranium enrichment facility in Tennessee.”

U.S. Energy Secretary Chris Wright said the awards would reduce U.S. reliance on foreign suppliers as the country works toward energy security: “Today’s awards show that this administration is committed to restoring a secure domestic nuclear fuel supply chain capable of producing the nuclear fuels needed to power the reactors of today and the advanced reactors of tomorrow.”

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Offshore Wind Developers Fight to get Back in the Water

Three of the four developers building wind farms in U.S. waters are challenging the Trump administration’s Dec. 22 order suspending all such construction.

Some light soon may be shed on the reasoning for the stop-work order, although not publicly: The federal government said it should, during the week of Jan. 5, be able to provide classified information bearing “secret” or higher classification to a judge hearing the first of the challenges.

Coastal Virginia Offshore Wind (CVOW) developer Dominion Energy sought a preliminary injunction Dec. 23 in U.S. District Court for the Eastern District of Virginia.

Revolution Wind, a joint venture of Skyborn Renewables and Ørsted, challenged the suspension Jan. 1 in U.S. District Court for the District of Columbia.

Empire Wind developer Equinor challenged the suspension on Jan. 2, also in U.S. District Court for the District of Columbia.

Avangrid and Copenhagen Infrastructure Partners have not announced any response to the suspension of Vineyard Wind 1, which is in late stages of construction and already generating power with some of its turbines.

The only other wind farm being built in U.S. waters is Sunrise Wind, which is in earlier stages of construction. Developer Ørsted said it is considering its options for how to respond to the Sunrise suspension.

The direction of the greatly diminished U.S. offshore wind sector rides on these challenges, as no other projects appear likely to start construction during the Trump administration.

After 11 months of actively working to thwart offshore wind development, the Trump administration paused all offshore wind leases Dec. 22 on national security grounds, saying the towers and spinning blades interfere with military radar. (See All U.S. Offshore Wind Construction Halted.)

The Department of the Interior said the pause would give all relevant government agencies time to work with the leaseholders and state governments to mitigate those risks.

But the pause also will cause the developers to incur millions of dollars in unbudgeted expenses per day.

Dominion was first in line to fight back.

It said it has spent $8.9 billion of CVOW’s projected $11.2 billion cost to date and already begun recovering that money from ratepayers. It called the order by the U.S. Bureau of Ocean Energy Management arbitrary and illegal, as well as inconsistent with BOEM’s previous actions during its “extraordinarily thorough” reviews of the CVOW proposal during a yearslong permitting process.

Interior indicated its Dec. 22 pause came in response to a situation that evolved after the BOEM permitting and said some of the explanation for this was classified.

Judge Jamar Walker on Dec. 28 converted Dominion’s request for a temporary restraining order to a motion for a preliminary injunction and set a Jan. 16 hearing on the motion. He gave Interior until Jan. 9 to provide the classified information that he called critical to evaluating the case.

‘Patently Unlawful’

The complaint filed Jan. 1 by Revolution Wind is another chapter in its running battle with Interior over the stop-work order the department had slapped on it Aug. 22.

Judge Royce Lamberth ordered that stop-work order lifted Sept. 22, and Revolution is asking him to do the same with the Dec. 22 order, saying it too is “patently unlawful” and violates the Administrative Procedure Act (APA), the Outer Continental Shelf Lands Act (OCSLA) and the U.S. Constitution.

In its news release, Ørsted said Revolution is 87% complete, with 58 of 65 turbines installed. It had been set to start generating power later in January.

The Danish company said Aug. 25 that total investment in Revolution and Sunrise was expected to be approximately $15.6 billion.

Empire Wind also is a two-time target of the Trump administration, which slapped a stop-work order on it in April but lifted it a month later without court intervention.

Empire said in its Jan. 2 filing that the April stop-work order cost it $200 million in delay costs and drove the project to the brink of cancellation. It said this new stop-work order likely will result in project cancellation if it lasts 90 days — the developer cannot draw down on construction financing and the complex, highly choreographed schedule would be thrown off.

Empire said the project is approximately 60% complete at a cost of more than $4 billion so far, $1.5 billion of it since the April stop-work order was lifted.

Empire asks the court to vacate the suspension and to declare it unlawful, arbitrary and capricious, an abuse of discretion, and a violation of APA and OCSLA. It seeks a preliminary injunction as the case proceeds through the legal system.

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FERC Approves Settlement for Luminant in Texas

FERC has approved a settlement between Luminant Generation and the Texas Reliability Entity for violations of a regional reliability standard governing primary frequency response in the ERCOT region (NP26-2).

NERC submitted the settlement Nov. 26 in its monthly spreadsheet Notice of Penalty (SNOP); FERC said in a Dec. 23 filing that it would not further review the agreement. The settlement carries no monetary penalty.

Luminant’s settlement concerned violations of BAL-001-TRE-2 (Primary frequency response in the ERCOT region), a regional standard approved by NERC’s Board of Trustees in 2020 and approved by FERC the same year. (See “Standards Actions,” NERC Board of Trustees Briefs: Feb. 6, 2020.) Requirement R9 of the standard specifies the 12-month minimum rolling average value of each generating unit’s initial primary frequency response (PFR) performance, while requirement R10 sets the minimum sustained PFR.

The utility self-reported both violations, the first on Aug. 18, 2022. On that date, Luminant notified Texas RE that it had not set the required initial PFR at four generating units: Unit 1 at the Lake Hubbard gas plant, Unit 1 at the Odessa-Ector combined cycle plant, Unit 2 at the Oak Grove coal plant and the Castle Gap solar plant.

Lake Hubbard was the first to fall below the required value on Aug. 31, 2021. That unit and the Odessa-Ector unit have since been reset and returned to compliance; the other two were still noncompliant at the time the SNOP was filed, although mitigation efforts — including reviews of the plant controller logic and updates to turbine control and distributed control systems for Oak Grove and correcting high sustainable limit telemetry for Castle Gap — were ongoing. The SNOP did not provide an estimated date of completion for the mitigation.

Luminant reported its noncompliance with requirement R10 to Texas RE on June 30, 2023, notifying the regional entity that the average sustained PFR at Lake Hubbard 1, Oak Grove 1 and 2, and Castle Gap had fallen below the required value. Only Lake Hubbard had returned to compliance at the time of the SNOP. Similar mitigation measures to those for the R9 infringements were underway at the affected plants.

Texas RE assessed the root cause of both violations as ineffective detective controls — specifically a failure to “identify and correct issues with [Luminant’s] controller frequency response logic and other settings that affect PFR performance.” The RE wrote that the violation posed a minimal risk, observing that “the overall market frequency response in the Texas Interconnection is robust enough to ensure sufficient frequency response [was] available to respond to” frequency events despite the incorrect PFR settings.

Texas RE acknowledged the duration of the infringement, with some units having the wrong PFR value for several years, but wrote in the utility’s defense that the problem might not have been detected because detection requires frequency events that were rare in the area. For example, the RE observed that the last score recorded for Oak Grove 2 was in April 2023, and Castle Gap’s last recorded score was in June 2024. Texas RE also considered Luminant’s “robust” internal compliance program to be a mitigating factor in the penalty determination.

Finally, Texas RE acknowledged that Luminant has experienced prior noncompliance issues with the same requirements, but it determined that these incidents “should not aggravate the penalty” for two reasons. First, those violations were disposed of as compliance exceptions, which are not meant to be used as aggravating factors for a later violation unless it is considered a serious or substantial risk. Second, Texas RE determined that the mitigations for the previous violations would not have prevented the most recent issues because they affected different settings.

Commissioners also approved a separate SNOP concerning violations of NERC’s Critical Infrastructure Protection standards. Details of that SNOP were not made public in keeping with the commission and NERC’s policy against sharing critical energy/electric infrastructure information.

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FERC Approves SPP’s Changes to Transmission Cost Allocation

FERC rang out the regulatory year for SPP by accepting the grid operator’s tariff revisions establishing subregions for the cost allocation of future byway projects under its highway/byway methodology.

The Dec. 30 order decouples SPP’s Schedule 9 (zonal rates) and Schedule 11 (highway/byway) transmission pricing zones and creates five larger Schedule 11 subregions of existing zones (ER26-407).

Two-thirds of the cost of byway upgrades (between 100 and 300 kV) will be allocated to the subregion in which they are connected, with the remaining 33% allocated to the SPP footprint. New base plan upgrades larger than 300 kV will be allocated RTO-wide as highway projects.

SPP plans to group its 18 existing transmission pricing zones into five new Schedule 11 subregions: North, Nebraska, Central, Southwest and Southwest. The subregions will replace legacy pricing zones only to allocate costs for future byway facilities under Schedule 11 and will not affect Schedule 9 zonal boundaries or previously approved cost allocations.

The commission found that the RTO’s proposed modifications to the cost allocation for byway facilities “reasonably reflects that the transmission customers within a subregion use and benefit from these facilities.” It said SPP’s technical analyses demonstrate that the zones within each proposed subregion are significantly integrated based on their “complementary import/export patterns, significant inter-zonal connectivity, similar power-flow patterns and other operational interdependencies.”

FERC disagreed with protests filed by the Louisiana, Oklahoma and Texas regulatory commissions that SPP’s proposal was facially deficient and that it had not satisfied its burden under the Federal Power Act because the RTO failed to identify or quantify the proposal’s future cost impacts. The commission said SPP had met its burden to show the tariff changes comply with FERC’s cost-causation principle.

It also was unpersuaded by an assertion by the city of Springfield, Mo., that SPP did not demonstrate how the Regional Cost Allocation Review (RCAR) process would fairly evaluate cost-benefit imbalances under the proposed modifications. The RCAR reviews the highway/byway cost-allocation methodology every six years to analyze the effects on each pricing zone.

SPP’s proposal was approved by its board, state regulators and members in 2025. Several members pushed back over concerns about unreasonable cost shifts. (See “Members Pass Last of HITT’s 2019 Recommendations,” SPP MOPC Briefs: April 15-16, 2025.)

FERC disagreed, finding that the grid operator had “adequately demonstrated” that allocating two-thirds of byway facility costs to its subregion and the remainder on a regional load ratio share basis “allocates the costs in a manner that is at least roughly commensurate with the benefits of these facilities.”

SPP’s proposal was the last recommendation from the Holistic Integrated Tariff Team (HITT), which was created in 2018 to conduct a comprehensive review of the RTO’s cost-allocation model, transmission planning processes, Integrated Marketplace and real-time operations. After a year of discussion, the 15-person HITT published a report with 21 recommendations. (See HITT Shares Draft Report with SPP Stakeholders.)

The tariff change was hung up for several years by work on another HITT recommendation to adopt a policy creating an appropriate balance between cost assessed and value attained from energy and network resource interconnection service products and generating resources with long-term firm transmission service.