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January 17, 2026

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PJM Board of Managers Selects CIFP Proposal to Address Large Load Growth

The PJM Board of Managers has selected a path forward for addressing a groundswell of large load interconnections expected over the coming decade. It announced a framework to speed the development of capacity resources, overhaul load forecasting and conduct a holistic review of how each of the RTO’s markets can better support resource adequacy needs. (See PJM Stakeholders Reject All CIFP Proposals on Large Loads.)

“This decision is about how PJM integrates large new loads in a way that preserves reliability for customers while creating a predictable, transparent path for growth,” said board Chair David Mills, who is serving as interim CEO. “This is not a ‘yes/no’ to data centers; this is ‘how can we do this while keeping the lights on and recognizing the impact on consumers at the same time?’ We look forward to implementing, along with our stakeholders, these proposals to manage the phenomenal demand growth we are experiencing.”

The proposal is the culmination of the Critical Issue Fast Path (CIFP) process initiated in August 2025 to address large load growth, which resulted in a dozen packages drafted by PJM staff and stakeholders being rejected by the membership in November.

The proposal directs staff to accelerate the reliability backstop to procure additional capacity and define how the related costs will be allocated to load serving entities (LSEs). This includes exploring mechanisms to assign costs to utilities that are capacity deficient.

The board wrote that the current trigger for the backstop, which requires three consecutive capacity auctions falling short of the reliability requirement, is insufficient in light of the 6.6 GW shortfall in the 27/28 base residual auction (BRA). It also noted that FERC’s December 2025 order on co-located loads requested information about proposals to use the reliability backstop to address “acute resource adequacy shortfalls.”

The board wrote that the backstop is considered a “transitional measure” to maintain reliability while the holistic market review is ongoing. (See FERC Directs PJM to Issue Rules for Co-locating Generation and Load.)

The board pointed to a joint CIFP proposal from Amazon, Calpine, Constellation Energy, Google, Microsoft and Talen Energy that included an alternative reliability backstop triggered if a capacity auction clears below 98% of the reliability requirement. It would open an auction for multi-year capacity commitments for new resources or those outside the capacity market. While the board did not mirror the coalition proposal, it wrote that proposals should “specify price, term and quantity as core award parameters.” (See “Joint Stakeholder Proposal,” PJM Stakeholders to Vote on Large Load CIFP Proposals.)

PJM’s CIFP proposal requested a second phase of the process to evaluate changes to the reliability backstop and incentives for large loads to bring their own generation or participate in demand-side capacity resources. (See “PJM Proposal,” PJM Stakeholders to Vote on Large Load CIFP Proposals.)

A backstop auction was requested by governors of PJM states and the White House in a statement of principles released Jan. 16. It calls for the auction to be conducted by September 2026 to allow “15-year price certainty” for new capacity resources. The costs resulting from the auction should be allocated to LSEs that have not procured their own capacity or agreed to be curtailable. (See White House and PJM Governors Call for Backstop Capacity Auction.)

Another parallel between the statement of principles and the board’s proposal lies in the price collar limiting capacity prices to between $175 and $325/MW-day for the 2026/27 and 2027/28 capacity auctions. The statement requested that the collar be extended for two years, while the board requested feedback from stakeholders on such an extension.

During a press conference following the announcement of the 2027/28 BRA results, PJM said the auction would have cleared at $529/MW-day without the collar and the Dominion zone would have separated at $542/MW-day. (See FERC Approves PJM-Pa. Agreement on Capacity Price Cap, Floor. See PJM Capacity Auction Clears at Max Price, Falls Short of Reliability Requirement)

The board’s proposal adopts staff’s recommendation to create a bring-your-own-new-generation (BYONG) pathway allowing new capacity paired with large loads to qualify for a fast-tracked interconnection process, expected to be rolled out by August 2026.

Large loads exceeding available incremental new resources within an LSE would be subject to curtailment under the proposal, under a model similar to the CIFP proposal sponsored by several state legislators, consumer advocates and the NRDC. The large loads would be curtailed prior to pre-emergency load management, which the board wrote is intended to avoid disrupting other demand response (DR) participants.

“Should system conditions over a given period force PJM to invoke its emergency procedures, the board finds it reasonable for certain large loads, including data centers, to move to their backup generators, or curtail their demand, for a limited number of hours during the year to prevent a larger scale outage for residential and other consumers. Such curtailment would be expected to occur infrequently, for limited durations, and only when necessary to prevent broader system impacts, consistent with PJM’s longstanding operational practice of avoiding curtailment whenever possible,” the board wrote.

The board directed a slate of changes to PJM’s load forecasting process, including a pathway for state utility commissions to review large load adjustments (LLAs) submitted by utilities, requirements for utilities to inquire with customers seeking service for large loads about whether they are exploring multiple sites for a single project, and a third-party review of the forecast to identify national trends that may impact PJM’s assumptions.

The holistic review of PJM’s markets is intended to improve how the energy, reserve and capacity markets create the incentives needed to meet resource adequacy. Staff will conduct an analysis in the first half of 2026, followed by a stakeholder process to create a set of recommendations for the board to consider.

“PJM is establishing clear, transparent guardrails for integrating large new loads under defined conditions,” PJM Chief Operating Officer Stu Bresler said in the Jan. 16 announcement of the board’s proposal. “This proposed course of action will require intense work by all of us in 2026 and involve significant changes. But it’s clear that bold action will be required to support the positive growth that is happening throughout the PJM region and the nation.”

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White House and PJM Governors Call for Backstop Capacity Auction

The White House and governors in PJM states have released a plan to get more generation built in the RTO, which saw its recent capacity auction clear short of the target as data center demand proved too much to meet. (See PJM Capacity Auction Clears at Max Price, Falls Short of Reliability Requirement.)

“Under President Trump’s leadership, the administration is leading an unprecedented bipartisan effort urging PJM to fix the energy subtraction failures of the past, prevent price increases, and reduce the risk of blackouts,” White House spokesperson Taylor Rogers said Jan. 16.

The most immediate idea is to run a special auction that would procure generation for data centers, which they would pay for. Trump and the White House’s National Energy Dominance Council (NEDC) said they’ve reached agreement with several states to advance more than $15 billion of new generation projects and a “coalition of leading technology companies has committed to funding” the new capacity.

“This initiative will ensure we usher in the age of artificial intelligence with new power plants funded by the technology companies, not taxpayers, securing the steel of Pennsylvania, the manufacturing of Ohio and the ships of Virginia,” NEDC chair and Interior Secretary Doug Burgum said in a statement.

The plan is to run a reliability backstop auction to procure the new capacity and give it 15-year contracts paid for by data centers. PJM’s tariff allows for a backstop capacity auction, but only after its main capacity auctions fall short for three years, so implementing it would require a rule change.

“PJM is reviewing the principles set forth by the White House and governors,” PJM said in a statement. “The PJM board’s decision, resulting from a multi-month stakeholder process on integrating large load additions, will be released later today. The board has been deliberating on this issue since the end of that stakeholder process. We will work with our stakeholders to assess how the White House directive aligns with the board’s decision.”

PJM released its proposed reforms on the afternoon of Jan. 16, just hours after the governors met with the NEDC at the White House to sign their deal. (See PJM Board of Managers Selects CIFP Proposal to Address Large Load Growth.)

The NEDC and governors also called on the RTO to improve load forecasting, queue management and to return to “market fundamentals” with long-term capacity market reforms that should go into effect in time for the base residual auction scheduled for May 2027. They suggest extending the price cap that has been in place for another two capacity auctions.

The governors agreed to use their powers to ensure that state regulators assign the costs from the backstop auction to data centers that have not otherwise procured supply or have agreed to flexible operations.

Pennsylvania Gov. Josh Shapiro (D) said in a statement that he’s been working to get power prices under control for two years and welcomed the deal with the White House and fellow governors.

“I sued PJM when they refused to act and secured a price cap that saved consumers tens of billions of dollars on their energy bills,” Shapiro said. “Since then, I’ve been working with my fellow governors and federal energy officials to push PJM to make needed reforms, and I’m glad the White House is following Pennsylvania’s lead and adopting the solutions we’ve been pushing for — including the extension of the price cap that I insisted be included today.”

Former FERC Chair Mark Christie welcomed the commitment for data centers to pay for the capacity they need to connect to the grid.

“In the Susquehanna case and the PJM co-location 206 proceeding initiated when I was chairman, that is exactly the principle I advocated, so I am glad the president and the governors are endorsing it,” Christie said. “Now I am interested to see the details of how PJM can or will implement this type of emergency auction for a 15-year PPA.”

The NEDC and governor’s proposals endorse the idea of “bring your own generation” with a special procurement auction and that all makes sense, said PJM Independent Market Monitor Joe Bowring.

“One question, is, how will those costs from the procurement be assigned to data centers and … is that literally a 15-year contract with the data centers that they have to pay regardless, or is there any risk that some of that cost will be shifted to load?” Bowring said. “So, I mean, this is an example of a question that you know is yet to be answered. But at a high level, it’s a positive, but there are a lot of details to be worked out.”

Based on the governors’ commitment on cost allocation, PJM likely will assign the costs of the special auction to load serving entities and let the state regulators figure which data centers ultimately pay, he added. The question is who would cover the stranded costs if those data centers were to go away before the 15-year contracts expire, Bowring said.

Speaking at the American Enterprise Institute a couple of days before the PJM deal was announced, NEDC Senior Director of Power Peter Lake (the former Texas Public Utilities Commission chair) highlighted the issue around mismatched time scales in the two industries.

“Consuming electricity is not new to America, but it’s the timing that is unique, both in a challenging way, but also it presents an opportunity,” Lake said. “The speed which with which these large consumers of electricity come to market is certainly a new paradigm.”

Building major industrial facilities in the past often had similar time frames to building power plants: four to six years; and they both last for decades. Data centers take 18 to 24 months to be developed and then the chips used in them become obsolete much quicker than a factory’s assembly line.

“The technology inside the data center might be obsolete before the power plant is even built,” Lake said. “If you think of the value of the data center and the GPUs, that’s how fast the innovation is going, which is a good thing. We want the innovation. … We want to accelerate that. That’s the beautiful part of AI and all the wonderful things it can bring to enhance our lives, but that is such a staggering shift.”

That dynamic makes predicting data center load difficult, Bowring said.

“To me, the best way to manage the forecast is make the data center responsible for paying for whatever capacity they need,” he added. “So that gives them incentive to be as serious as possible building the data center. And if they incur the cost and then go walk away, then those costs stay with them.”

While Bowring sees the increased attention to the reliability crisis in PJM as generally a good thing, nothing in the deal announced will negate the impact the growth in data centers already has had on consumers in PJM.

“We would not have this crisis but for data center load,” Borwing said. “So regardless of retirements, regardless of the economics of power plants, regardless of even PJM’s interconnection queue process difficulties — shall we say, holding all that constant, we would not have these problems, not be short, but for data center load. Data center load is forcing PJM to be short, and it’s imposed $23 billion worth of costs on customers.”

The gap in between supply and demand is about 13,000 MW, but any backstop auction could be rounded up to a more even 15,000 MW, Bowring said.

The White House and politicians are not this involved in wholesale power markets, but Grid Strategies President Rob Gramlich noted in an interview that under President Bill Clinton there was a coordinated effort to deal with the fallout from the California energy crisis by getting new contracts in place to keep power flowing.

The situation needs fixing, but the documents released about the plan are sparse on details and those will be important, Gramlich said.

“There’s a bigger picture than this tries to address, that FERC didn’t address and didn’t have before the commission, which is new load came into the region and started buying up power from existing generation capacity,” Gramlich said. “And I think the states and consumers in the region thought that those power plants in the PJM region were there to serve them. They thought they could count on them, but unfortunately for them, those power plants had not committed their power under any contract.”

Gramlich has argued for years that power plants in the region needed long-term contracts, a position he came to after dealing with the California energy crisis, in which state rules requiring utilities to buy entirely from the spot market made things much worse.

State regulators and others in PJM did not heed his warnings largely because there were no counterparties big enough to take on the major, long-term contracts that hyperscalers have announced recently. Still other wholesale power markets with restructured states like Texas have had more long-term contracting than PJM, he added.

“The fact that the large buyers are willing to say they’ll pay their fair share and willing to work with the bipartisan group of governors, and with the federal government to reach a conceptual proposal here, I think is very noteworthy,” Gramlich said. “And PJM does have the ability to do backstop auctions that are separate from its capacity market. So, I think there’s potentially a workable concept there.”

A big question is how the cost allocation and retail side of these reforms are handled. Gramlich indicated it ultimately might require an expansion of federal authority.

Everyone agrees PJM is struggling to add new generation and that some sort of intervention is required, but Aurora Energy Research’s USA East head Julia Hoos sounded a note of caution.

“This type of ‘out of market’ action can quickly add new generation, but may be financially disastrous for existing generation, which ultimately hurts reliability in the entire region,” Hoos said.

The separate auction is likely to reduce price signals for existing units and could affect the financial health of coal plants in PJM, which the Trump administration likes to keep open.

“Investor confidence to build new power generation in PJM has been low for years,” Hoos said. “Prices were low for almost a decade and generators were shutting down, and no one was intervening to keep them online. Now that prices are high, PJM and lawmakers are intervening to keep them low. Understandably, developers willing to build new generation in PJM saw that as a substantial risk. Now, this action means that any existing generation is likely to see significantly lower prices, confirming those fears.”

In a thread on X, LS Power CEO Paul Segal made similar points to Hoos and cautioned that the special auction needs to be treated as a bridge.

“Bottom line: shifting toward ‘pay your own way’ is directionally right,” Segal wrote. “Just don’t confuse a one-off auction (or a permanent cap) with the solution. The durable fix is stable rules + earlier signals + faster pathways to connect + true cost-causation — so competition can do its job.”

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Dominion Wins Injunction, Can Restart Offshore Wind Construction

A federal judge has granted Dominion Energy a preliminary injunction against the stop-work order the Trump administration slapped on the nation’s largest offshore wind project.

In response, Dominion said it would resume construction of Coastal Virginia Offshore Wind (CVOW) and hopes to begin exporting electricity in a matter of weeks.

The Jan. 16 ruling by Judge Jamar K. Walker in U.S. District Court for the Eastern District of Virginia (2:25-cv-00830) was the third such injunction issued in five days, each by a different judge, two of whom had been appointed by Republican presidents.

Counting the September 2025 injunction against an earlier stop work order, the CVOW ruling dropped the Trump administration’s court record on these orders to 0-4.

Work on all five wind farms under construction in U.S. waters was halted Dec. 22 by a Department of Interior directive that cited national security concerns including radar interference.

Developers of all five separately challenged the move in court, starting with CVOW on Dec. 23, then Revolution, Empire, Sunrise and finally, on Jan. 15, Vineyard.

Revolution, which in September secured an injunction against the stop-work order slapped on it alone, won an injunction against the blanket stop-work order Jan. 12. Empire secured its injunction Jan. 15.

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As it promotes fossil fuel and nuclear power development, the Trump administration has moved to thwart renewable energy development to varying degrees, with some emissions-free technologies treated more harshly than others. The president himself has voiced a particular animus for offshore wind, though, and the stop-work orders are just one chapter in his continual campaign against it.

As Revolution, Empire and now CVOW have succeeded in pausing this latest attack, their statements indicate they view the injunctions as progress, not victory.

Dominion said Jan. 16: “While our legal challenge proceeds, we will continue seeking a durable resolution of this matter through cooperation with the federal government.”

CVOW has a nameplate capacity of 2.6 GW — nearly three times more than the next-largest U.S. project — and will feed a grid that has capacity concerns.

PJM on Jan. 9 submitted an amicus brief supporting CVOW’s attempt to lift the stop-work order. It wrote: “Given the long lead times associated with the development of any alternative new generation, let alone delay of this project, extended delay of construction and operation of the CVOW project will cause irreparable harm to the 67 million Americans served by PJM given this region’s (including Virginia’s) critical need for new generation resources to achieve commercial operation in the next few years.”

CVOW has been in the works for more than a decade; recent increases pushed its price tag to more than $11 billion.

Unlike the other four projects, however, CVOW’s developer also is its offtaker. Dominion’s ratepayers still will be on the hook for the cost of the project if it does not generate electricity. The developers of the other projects will recoup their multibillion-dollar investments only through electricity sales.

Along with ratepayers and electric grids, Trump’s campaign against offshore wind threatens an industry that was creating jobs and economic activity.

North America’s Building Trades Unions also filed amicus briefs against the stop-work orders. On Jan. 16, it said: “We applaud this week’s federal court rulings restarting U.S. offshore wind projects. … The shutdown order stalled every East Coast offshore wind project, freezing massive builds in place and sidelining our members, local communities, and urgently needed domestic energy supply.”

Even as it suffers setbacks in court, the Trump administration’s efforts against offshore wind have succeeded in an important sense: They have created such an atmosphere of financial risk and regulatory uncertainty that most developers have suspended or canceled their U.S. plans.

The five projects under construction now appear likely to be the last in U.S. water for years to come. They total 5.8 GW, a far cry from the 30 GW goal the Biden administration set for 2030.

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Colo. Officials Push Back on Craig Coal Plant Extension

Local elected officials in Colorado are speaking out against the Trump administration’s order to keep the coal-fired Craig Generating Station Unit 1 available to operate past its planned retirement date.

The officials addressed the Colorado Public Utilities Commission during the public comment portion of the Jan. 14 meeting.

“It is painfully clear that the federal government currently has not only abandoned climate-sensitive policies and fuel choices, but that it is actively seeking to destroy a durable climate and to return to the damaging fuel sources that got us into this pickle in the first place,” said Glenwood Springs City Council member Steve Smith.

The U.S. Department of Energy issued an emergency order Dec. 30 to Tri-State Generation and Transmission Association and other co-owners of Craig Station Unit 1 to keep the unit available to operate. Unit 1 was slated to retire Dec. 31; Tri-State said it had planned for adequate resources to maintain reliability after the unit retired. (See DOE Blocks Retirement of Another Coal-fired Plant.)

A DOE news release said the order was to ensure access to “affordable, reliable” electricity through the winter. The order is in effect through March 30.

Tri-State said in a release that Unit 1 was hit by an outage Dec. 19 due to a valve failure. But Tri-State has a “100% compliance” policy, CEO Duane Highley said, and planned to take needed steps to repair the valve.

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Local officials said their communities are ready for the coal plant to close.

“[The] heavy-handed order to Tri-State to keep the Craig Unit 1 coal plant open flies in the face of Colorado law, Tri-State’s bottom line and what people in Craig and Moffat County want,” Ridgway Mayor John Clark told the PUC.

Speakers pointed to the impact that climate change is already having on their communities.

Broomfield City Council member Sean McKenzie said a grass fire that broke out in the community Jan. 5 was quickly contained, but sparked memories of the devastating Marshall Fire in December 2021 that destroyed 1,084 homes.

“The conditions that were once reserved for July are now visiting us in January,” McKenzie said. He urged commissioners to “uphold the policies you’ve worked so hard to put in place.”

Basalt City Council member Hannah Berman called climate change an “existential threat” to the area’s economy, which relies on outdoor recreation. She asked the PUC to “take any and all action they can to ensure that Colorado continues to transition off of coal power as mandated by Colorado law.”

Adams County Commissioner Emma Pinter warned the commission that now is not the time to backslide on climate goals.

“In Colorado, our climate emission goals still stand and must be achieved,” Pinter said. “This commission needs to work to ensure that we meet all of our climate goals in spite of any federal efforts to the contrary.”

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ISO-NE’s Proposed Capacity Market Reform Likely to Boost Reliability While Resulting in Higher Prices

Over the past year, “capacity” — the assurance that electricity will be there when one flips the switch — increasingly has dominated the electricity conversation. PJM has been the epicenter of that conversation.

That market has seen its previous three capacity auction revenues skyrocket by tens of billions of dollars, driven largely by unexpected and rapid load growth from data centers as well as the adoption of a more rigorous method for accrediting the capacity of various resources.

Seeking to avoid a similar problem, ISO-NE is reforming its approach to acquiring sufficient capacity, submitting a proposal to FERC on Dec. 30. The filing is ISO-NE’s biggest change in this area since such markets first were established 18 years ago, evolving from its traditional three-year lead time model to a “prompt” approach, beginning in 2028.

Closing the 3-Year Gap

With the new proposal, ISO-NE will shake things up considerably. Citing growing uncertainty in load forecasting — a result of hard-to-predict end uses such as “the construction of data centers, and changes in public policy that could impact the pace of electrification,” as well as increasingly volatile weather and the variability of renewables output — the grid operator proposes to reduce the three-year lead time to only a single month.

The three-year schedule originally was intended to provide economic signals that provided sufficient time for developers to build new resources. But given the evolution of markets and technologies, that logic has unraveled.

Peter Kelly-Detwiler

When I oversaw Constellation Energy’s demand response group back when the formal DR markets were created around 2005, we found that prices whipsawed significantly from one year to the next. Consequently, it was nearly impossible to assess the long-term value of planned investments. A single annual price signal — even three years in advance — was not very valuable. It was bad enough for existing DR end-use assets that could be enrolled within a year; for multibillion-dollar generation units with lifespans of 30-40 years, such annual price indicators were next to useless.

Furthermore, the reality of today’s generation asset development — characterized by sclerotic interconnection queues, lengthy and complex state and local permitting processes, and a brutally slow supply chain — means that nothing gets built within a three-year timeframe even in the most optimistic scenario. To take one example, one cannot even get a new gas turbine from GE until 2028/29 at present.

The result of the old three-year forward system was an abundance of “phantom assets” haunting the resource mix — projects that cleared the auction but never were developed. Those shortfalls in capacity subsequently had to be addressed through intermediary reconfiguration auctions. The new prompt auction, taking place just a month ahead of delivery, helps ensure that ISO-NE will secure capacity from actual resources capable of delivering, rather than empty promises from developers who may never see steel in the ground.

Seasonality: Addressing the Worst Days of Winter

The New England grid operator also changed its approach to seasonality, an approach that is long overdue. While summer heat may challenge the grid, New England’s lengthy winter cold snaps are where the greatest risk lies. With only two pipelines feeding the region, on the coldest days there is simply insufficient gas to generate power and keep people warm and safe. In that equation, power generation loses. At that point, the region resorts to its store of fuel oil, which is not limitless.

During the extended cold weather of 2017/18, for example, New England’s generators burned through nearly three million gallons of fuel oil reserves, with two million gallons consumed over just eight days. As can be seen in the graphic, oil reserves plummeted from 34% to 19% availability during the coldest 24-hour period, meaning the region was perhaps a single day away from rolling blackouts.

ISO-NE’s revised approach to capacity planning will address that seasonal challenge by establishing a bifurcated system with summer (June 1 to Oct. 31) and winter (Nov. 1 to May 31) periods. This scheme will differentiate resources based on performance during each season. So, for example, solar may fare well during the summer, while assets with on-site fuel would have an advantage in the winter.

Resource Capacity Accreditation: Who Shows Up When the Party Starts?

ISO-NE’s greatest proposed technical change is the way in which capacity resources are “counted.” The existing summer performance-based accreditation process will give way to an approach intended to “accurately capture the marginal reliability contribution of resources during the periods that will be of highest risk to reliability.” In other words, resources will be rated based on their effectiveness at staving off a blackout when the system is under maximum stress.

The grid operator will evaluate characteristics such as forced outages, output variability and access to fuel. For the reasons discussed above, gas-fired generation may be significantly impacted, with ISO-NE reflecting the effect of “pipeline constraints that can limit the ability of the region’s gas-fired resource fleet to obtain fuel during the winter.”

Gas units without firm supply contracts are likely to be penalized by this approach, and they should be. They rarely show up to the party when needed, on those days when power generation and other demands are both clamoring for the same gas molecule. As illustrated in ISO-NE’s planning document, those two demand peaks are highly coincident.

| ISO-NE

ISO-NE is not the only grid operator seeing this dynamic. 2021’s Winter Storm Uri in Texas and 2022’s Winter Storm Elliott in the Mid-Atlantic aptly demonstrated the fact that a megawatt of gas-fired capacity is useless if gas is frozen in at the wellhead or if pipeline pressures fall and generating turbines are starved of fuel.

After Elliott, PJM significantly reduced the accredited capacity off gas plants, with combined cycle plants falling from 96% to 79% over one year as a result. ISO-NE’s new rules may have a similar effect, so that a 1,000-MW gas plant might be credited for only 700 MW or 800 MW of “reliable” capacity.

A Better Way of Saying Goodbye

ISO-NE is reforming its resource retirement process. Currently, a power plant must signal its retirement four years in advance. With the new approach, plant owners can submit a retirement notification one year in advance. This approach gives owners far better knowledge as to the remaining life of their equipment and the near-term market conditions, allowing them to remain in the market if conditions are favorable.

The Inflationary Bottom Line for the New England Power Market

ISO-NE has asked FERC to approve these revisions by March 31, 2026, with the first affected auction occurring in May 2028 for delivery starting in June. The new approach is more realistic, but it may well have a significant inflationary effect for two reasons.

First, if the experience of PJM holds true, ISO-NE could find itself short of accredited capacity because of its revised accreditation approach. With 42% of 2025’s capacity supplied by gas generators, a significant de-rating could cut supply and drive prices up, especially if the demand side heats up.

Second, the seasonal approach may further affect future available capacity figures, especially with the winter re-rating of gas-fired generation, creating additional shortfalls.

And finally, with the capacity auction only a month prior to delivery, there’s zero time for the supply side to react to higher prices.

It’s probable we’re entering an era in which our “friendly little electron” demands a much higher price for the privilege of being there exactly when we need it. So, customers must be prepared to focus more intently than ever before on managing their demand — on a seasonal basis — even as they reluctantly reach for their checkbooks.

Around the Corner columnist Peter Kelly-Detwiler of NorthBridge Energy Partners is an industry expert in the complex interaction between power markets and evolving technologies on both sides of the meter.

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CPUC OKs New Tx Projects for Microsoft Data Center Despite Cost Unknowns

The California Public Utility Commission approved a set of transmission infrastructure projects to support a 90-MW data center owned by Microsoft, but questions remain about whether the upgrades will increase or decrease ratepayer costs.

The transmission projects present “unique considerations” not fully addressed by certain existing electric rules, the CPUC said in a resolution approved at its Jan. 15 voting meeting. The resolution is based on advice letter 7635-E, which was submitted by Pacific Gas and Electric (PG&E) in July 2025.

The electric rules in question normally apply to distribution energization projects, but Microsoft’s data center is expected to have a 90-MW load — a “significant” amount that will require a new 115-kV transmission line and substation upgrades, the resolution says.

“Because the Microsoft project will be interconnected at the transmission level, Microsoft will pay lower electric rates than an equivalent large load customer that is connected at the distribution level and normally covered by the Rule 15 process, while at the same time potentially contributing to the need for broader transmission network upgrades in the region,” the commission said in the resolution.

Providing electricity to the new data center requires “significant costs but comes with the opportunity for significant revenue received by PG&E,” the resolution says.

If these revenues are large and consistent, other customers might need to pay less of PG&E’s overall revenue requirement, which could lower rates for PG&E customers, the resolution says. But if the revenues are small or are not received consistently, PG&E customer rates could increase, it says.

PG&E will complete the following work for Microsoft’s data center:

    • transmission upgrades at PG&E’s Los Esteros substation
    • a new 115-kV transmission line from PG&E’s Los Esteros substation to Microsoft’s Kaku substation
    • a design review of Microsoft’s Kaku 115-kV substation
    • an additional 115-kV transmission line from PG&E’s Los Esteros substation to Microsoft’s Kaku substation

PG&E could not determine which transmission facilities CAISO will control, according to the resolution.

The data center will operate at a continuous 90-MW load for 24 hours a day, 365 days a year, the resolution says.

Microsoft has also requested a second 115-kV line to provide redundant service; however, this project falls under a special facilities agreement and will not be paid by PG&E ratepayers at any point, the resolution says.

Microsoft also plans to install two natural gas-fired generators for critical load and emergency backup, the advice letter says.

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Dirac BESS Approved

At the meeting, the CPUC approved also a 225-MW lithium-ion battery storage project for PG&E. The storage facility will provide resource adequacy capacity and has a planned online date of May 20, 2028, with a 15-year energy delivery commitment.

The storage facility’s capacity will replace Diablo Canyon Power Plant’s capacity when, and if, the nuclear plant is retired. The facility, called the Dirac Battery Energy Storage System, will be built by Aypa Power Development using the company’s subsidiary, Balsam Project.

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Earthjustice Says Change to Louisiana Meta Data Center Funding Fishy, Asks PSC to Investigate

Earthjustice accused Meta of deliberately executing an unsanctioned financial arrangement to underwrite its planned, multibillion-dollar data center in northern Louisiana and asked the Louisiana Public Service Commission to investigate.

Representing the Alliance for Affordable Energy and the Union of Concerned Scientists, Earthjustice said it appeared Meta had ulterior motives for the financial risk it was willing to undertake for the data center.

Meta did not reply to a request for comment on the allegations.

In a Jan. 14 motion for investigation to the Louisiana PSC, the environmental law center said “immediately after” the commission approved Entergy Louisiana’s application for three new gas plants to power the data center in August 2025, Meta “fundamentally altered” the financing structure of the project.

Enter asset management firm Blue Owl Capital. In late summer, it and Meta created the joint venture Beignet Investor, which now reportedly owns an 80% stake in the data center. Meta owns the remaining 20%. Beignet acquired Meta company Laidley to secure the majority ownership. (Stay with us here.)

When the Louisiana PSC approved Entergy’s power supply proposal for the data center, Meta used Laidley, its development affiliate, to represent itself. Laidley is the sole signatory to the data center’s energy service agreement with Entergy Louisiana for the three natural gas plants. Earthjustice noted that Beignet Investor registered as a limited liability company in Delaware on Aug. 20, 2025, the same day the Louisiana PSC voted 4-1 to approve Entergy’s supply contracts (U-37425). (See Louisiana PSC Approves 3 Controversial Gas Plants Ahead of Schedule for Meta Data Center.)

Now, Meta would pay rent to Beignet to use the Meta Hyperion data center, with the option to exit the lease every four years. Should Meta decide to depart, Beignet would sell the center to pay outstanding bonds and then pay itself, Earthjustice told the Louisiana PSC. If sale proceeds fall short of what’s owed to bondholders combined with Blue Owl’s investment, then Meta would pay the difference. Meta would guarantee its rent and payment obligations via parent guaranty to Blue Owl.

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Earthjustice said because Meta already has significant debt load, Blue Owl invested $3 billion for an 80% stake in the Hyperion data center. Meta’s existing $1.3 billion investment earned it the remaining 20%.

Beignet then borrowed $27 billion for the project. The new LLC has no assets beyond the data center; Earthjustice said that makes it a “riskier partner as the guarantor” of the supply arrangement with Entergy.

Meta’s rent payments would go to bond interest and principal payments, as well as dividends for Blue Owl.

The joint venture between Meta and Blue Owl is the largest private credit transaction ever and allowed Meta to receive a $3 billion cash distribution from the venture upon closing.

The convoluted arrangement was referred to as “Frankenstein financing” by The Wall Street Journal, which published a Nov. 11 investigative piece on the labyrinthine financing Big Tech uses to break ground on data centers.

‘A Secret’

Earthjustice said the “remarkable,” same-day creation of Beignet “illustrates that Meta and Blue Owl were working behind the scenes to significantly alter the financial structure of the data center project while the proceeding to examine the now irrelevant data center financial structure was ongoing.”

“Meta kept this significant change a secret, just like Meta kept how they developed their load forecast and how they determined their job numbers a secret,” Earthjustice claimed, adding that the PSC needs to know the facts behind the funding of the data center.

Earthjustice said if the AI boom were to dry up, Meta could walk away from the deal as soon as 2033. It said by then, the data center could lose prospects for another buyer and depreciate.

Meta, Entergy and the Louisiana PSC expect construction on the data center campus to continue through 2030.

“This novel financial arrangement lets Meta add computing power quickly and then wait to see how demand for AI shapes up before fully committing to projects that can last for decades. Thus, Meta is off-loading its own risk by placing that financial risk on others, including ratepayers who will be on the hook for all the infrastructure built solely for this data center should Meta exercise its option to walk away,” Earthjustice argued. The law organization said all the ratepayer protections the Louisiana PSC hammered out in its approval are “at best, called into question” because Meta no longer is Laidley’s parent company.

Throughout the PSC’s consideration of the gas plants to power the data center, the Alliance for Affordable Energy and the Union of Concerned Scientists voiced concern of the risk of after-the-fact changes to the electric service agreement with Entergy, the risk of stranded costs or capital cost overruns on the gas plants and an “inappropriately short” 15-year contract term on the power supplied by Entergy.

“This new, novel financial arrangement, which very likely was withheld from the commission prior to its action on [Entergy Louisiana’s] application, calls into question the meager ratepayer protections included in the application and contested settlement agreement and undermines the assumptions made by the commission when it voted to approve the application,” Earthjustice wrote.

The Louisiana PSC approved consumer protections including a provision that Meta’s minimum bill payments would cover 100% of the costs of the trio of generating units, including cost overruns. Meta also agreed to fund development of 1.5 GW of solar generation under the state’s Geaux Zero program and to provide up to $1 million per year for Entergy’s Power to Care, which is a bill assistance program for low-income, elderly and disabled Entergy Louisiana customers.

Entergy has entered the first of three gas plants into MISO’s expedited interconnection queue and submitted the 500-kV facilities needed to connect the data center into MISO’s expedited transmission approval process.

At publication time, Meta did not respond to RTO Insider’s questions on whether the new financing arrangement would transfer more risk to Entergy’s ratepayers; who would be responsible for termination fees should Meta take Beignet up on one of the four-year exit options; and whether Meta is prepared to honor its end of the deal as spelled out in the Louisiana PSC’s original approval order even with the additional investors involved.

Investigation Request

Earthjustice asked the PSC to launch an investigation to decide whether it was deliberately misled and establish the new financial setup’s effect on ratepayer protections. It also said the commission should open a prudence review to figure out whether Entergy Louisiana was aware of the financial reformatting and to decide whether it’s wise to allow Entergy to continue with the trio of gas plants.

Finally, Earthjustice said the PSC should direct Entergy Louisiana to file a copy of the “parent guaranty that is executed by Laidley’s current parent that does not include a cap on the parent’s cumulative liability;” and order Entergy to file a legal opinion clarifying that the parent is bound by the parent guaranty and confirming that termination payments to Entergy must be paid out before investors are compensated.

Meanwhile, Entergy is seeking a 10-year property tax exemption worth an estimated $237 million to build the first 1.5-GW natural gas plant for the Meta data center campus. Entergy submitted the application under Louisiana’s Industrial Tax Exemption Program, which waives local property taxes on some industrial projects.

Entergy plans to build the more than $2.3 billion Titanium Power Station first, which would consist of two combined-cycle combustion turbines.

Entergy has pledged that Meta will foot the bill for the power station — at least for the contract length of the first 15 years of the generating unit’s life — and that it should save ratepayers about $650 million in the long run.

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Wash. AG, Environmental Groups Challenge DOE’s Centralia Coal Plant Order

Washington’s attorney general and a coalition of environmental groups have mounted separate challenges to the U.S. Department of Energy’s December decision to order TransAlta to continue operating the state’s last coal-fired plant for three months beyond its scheduled retirement at the end of 2025.

Attorney General Nick Brown and the coalition — which includes Earthjustice, NW Energy Coalition, Washington Conservation Action, Climate Solutions, Sierra Club and the Environmental Defense Fund — have separately filed requests to rehear DOE’s Dec. 16, 2025, order to keep the Centralia Power Plant’s 670-MW Unit 2 running until March 16, 2026, due to an energy “emergency” in the Pacific Northwest this winter. (See DOE Orders Retiring Wash. Coal Plant to Stay Online for Winter.)

The order was one in a series of such moves the Trump administration’s DOE has taken over the past year to extend the life of aging fossil fuel-fired plants slated for closure, including in Michigan, Pennsylvania and Colorado.

“The Trump administration is once again ignoring both the law and the facts,” Gov. Bob Ferguson said in a Jan. 13 statement accompanying announcement of the state’s request, which asks DOE to “immediately withdraw” the order. “DOE needs to reverse course on this harmful and misinformed order.”

“DOE is misusing its narrow authority reserved for imminent emergencies to force a dirty, inefficient coal plant to keep operating,” Earthjustice attorney Patti Goldman said in a Jan. 14 statement by the coalition. “Our region has moved beyond reliance on coal and this plant. We are meeting our region’s energy needs, now and into the future, with cleaner sources.”

In their statements, the AG’s office and the coalition questioned DOE’s authority to keep the Centralia plant open under Section 202(c) of the Federal Power Act — and the department’s reason for doing so, arguing that the law is intended to address only “real” emergencies.

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The coalition contended that the order “exceeds that authority and instead tries to impose the administration’s preference for coal-fired power over a 2011 agreement between the state of Washington and TransAlta, the owner of the plant, to shut down the plant by the end of this year.” (Unit 1 at Centralia was shut down in 2020 under the first phase of that agreement, and TransAlta plans to convert the facility to natural gas.)

The AG said the order “is a clear attempt by DOE to bypass the limits imposed on it by Congress.”

In its rehearing request, the AG said the department failed “to properly identify or clarify the appropriate entities that have any authority to direct” Centralia’s operation. The Dec. 16 order called on TransAlta to “take all measures necessary” to ensure the plant is available operated at the direction of either the Bonneville Power Administration as a balancing authority or CAISO’s RC West as the regions reliability coordinator, but it was apparent neither of those entities was consulted before the order was issued.

Getting the Story Straight

The coalition in its rehearing request argued that DOE failed to provide evidence of an energy emergency or electricity shortage that warranted continued operation of the plant. It notes that two third-party studies cited by DOE to support its order “demonstrate the absence of an emergency.”

The coalition points out that the first study, NERC’s assessment of reliability for this winter, “expressly states that ‘operating reserve margins are expected to be met after imports in all winter scenarios.’ … This means that the study on which the department relies anticipates that the region will be able to meet peak demand and maintain the full added buffer of reserves on top.”

The second study, by Energy and Environmental Economics (E3), has not yet been released, the coalition noted. Instead, DOE based its finding on a September 2025 presentation on the pending study, whose author has said shows the Northwest’s resource adequacy risk is “slightly elevated above the target risk,” which “was calculated to achieve a loss of load expectation of one event-day per decade.”

“E3 also confirms that it calculated this ‘slightly elevated’ risk without examining the actual conditions this winter; as a planning document, the presentation is based on a historical model and does not reflect actual weather and hydrological conditions presently existing for this winter,” the coalition wrote in the rehearing request.

The coalition contends that recent actions by DOE undercut the department’s claim of an emergency, including an October 2025 order by the Grid Deployment Office that allowed the Northwest to export electricity to Canada based on a finding (in DOE’s own words) “that the wholesale energy markets are sufficiently robust to make supplies available to exporters and other market participants serving United States regions along the Canadian and Mexican borders.”

In that order, DOE itself pointed to the “comprehensive” reliability processes in the region that ensure “bulk-power system owners, operators and users have a strong incentive both to maintain system resources and to prevent reliability problems that could result from movement of electric supplies through export,” the coalition noted.

“The Trump administration can’t get its story straight,” Tyson Slocum, Public Citizen’s Energy Program director, said in the coalition’s statement. “While it claims the West Coast is in a state of emergency requiring families to bail out an expensive coal plant, Trump’s Department of Energy is simultaneously concluding the region has energy abundance to authorize electricity exports to Canada. Which is it, Donald?”

The coalition contends that complying with the DOE order will “be expensive, as Centralia does not have the coal, customers or workforce to keep the coal plant running. Other coal plants forced to keep operating are experiencing extremely high costs, which [FERC] can require ratepayers to pay.”

The groups point to the pollution impact of the order, and how it violates Washington’s Clean Energy Transformation Act, which required the state’s utilities to stop using electricity from coal-fired plants by the end of 2025.

“So many of us — from state leaders and utilities to elected officials and public interest groups — have worked for decades to plan for and build cleaner, more efficient generation and transmission that will ensure Washington state’s transition to clean energy while keeping energy affordable and reliable,” said Lauren McCloy of the NW Energy Coalition. “That work is ongoing, and burning more coal at Centralia is not the answer to meeting growing energy demand in the Northwest.”

Asked to comment on the challenge, a DOE spokesperson responded: “Under the disastrous energy subtraction policies of the previous administration, the U.S. was on track to lose 100 GW of reliable generation capacity by 2030. Much of the U.S. is now at ‘elevated risk’ of blackouts under extreme conditions, which NERC declared a ‘five-alarm fire’ for grid reliability.

“At the same time, the U.S. may need to build 100 GW of new reliable capacity to win the AI race and onshore manufacturing. The Trump administration is committed to preventing the premature retirement of baseload power plants and building as much reliable, dispatchable generation as possible to achieve energy dominance.”

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Resetting the Reset: Demand Curve Reform Discussions Begin

NYISO kicked off the demand curve reset reform process with a discussion of how to improve the overall process and what could be done to strengthen the definition of the proxy unit. The ISO seeks to stabilize the installed capacity market by reducing volatility and making the DCR less complex and burdensome.

“I think, uncontroversially, we can consider this process quite burdensome for both NYISO and stakeholders, and we want to address those issues now as part of a project,” said Michael Ferrari, a market design specialist for NYISO.

No specifics, tariff changes, definitions or formulas were discussed. The discussion at the Jan. 12 Installed Capacity Working Group Meeting was centered on possible avenues to improve the DCR and what the ISO might explore with stakeholders.

The DCR anchors capacity prices on a curve by picking a “proxy unit” to represent the cost of a hypothetical new generator entering the market every four years. The most recent DCR set a two-hour battery energy storage system as the proxy unit for the 2025/29 period. (See FERC Accepts NYISO Demand Curve Reset.)

The current process involves considerable debate, outside consultation and stakeholder meeting time to pick a type of generator to serve as the proxy unit and determine a reasonable hypothetical capital cost estimate for it. Debating the engineering cost assessments to estimate capital costs for potential technology takes much of the 18-month DCR process. These findings are subject to an annual adjustment to try to keep the curve in line with market conditions.

“We want to address the issues now as part of a project before the status quo process of the demand curve reset begins in earnest,” said Ferrari.

Ferrari outlined some of ISO’s preliminary ideas for smoothing the DCR. The ISO is considering a periodic review that would use the existing annual update framework to apply systemic, formulaic adjustments to reduce the need for a total reset every four years. This would involve using cost-trend publications, inflation-based indexes and various annual financial parameters such as interest rates to adjust prices periodically. This would, in theory, reduce the administrative burden by getting away from detailed engineering studies.

NYISO also is considering redefining the proxy unit. It would no longer be a unit based on specific technology; instead, the proxy unit would merely be a hypothetical unit that meets a minimum operating criterium.

Stakeholders seemed skeptical of NYISO’s proposal. Some pointed out that national price indexes were extremely bad at predicting costs in New York City. Others pointed out that the annual adjustment mechanism already doesn’t work very well.

“I think it’s fair to say, not pejoratively, that the analysis group kind of threw up their hands and said ‘Well, there really aren’t good indices for certain things so this is as good as it can get,’” said Doreen Saia, a lawyer for Greenberg Traurig, referring to the NYISO consultant’s comments during the last DCR. (See NYISO Offers Final Staff Recommendations for Demand Curve Reset and NYISO Stakeholders Continue Debate over Battery as Proxy Unit.)

Adam Evans, a representative of the New York Department of Public Service, pointed out that the status quo was not tenable.

“In the last reset we saw a potential $2.5 billion increase in demand curve cost based on what some folks were arguing for the proxy unit, which is frankly untenable,” said Evans. “I think this type of proposed solution to limit volatility … I think it makes sense.”

Other stakeholders pointed out that the current DCR process was not responsive or flexible in the face of state policy shifts. One stakeholder pointed out that state incentives for procuring carbon-free energy were not incorporated into the cost of new entry models. Another said the state climate law could be altered or removed by the legislature if the political winds shifted and any new process would have to account for that.

“I would be very concerned about trying to have a demand curve process that is super responsive to every policy shift that comes at us. That undermines the idea of certainty,” said Mike DeSocio, a consultant with Luminary Energy. He disagreed with the idea of a flexible process and asked NYISO to instead focus on market certainty.

Stu Caplan, representing New York Transmission Owners, said the market should not be designed for high price increases without reliability gains.

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Judge Allows Construction to Resume on Empire Wind

Equinor has won a temporary injunction against the Trump administration’s stop-work order on U.S. offshore wind projects, allowing it to resume work on Empire Wind.

The Department of the Interior on Dec. 22 shut down work on all five projects under construction in U.S. waters, citing national security concerns.

Empire, which incurred millions of dollars in added costs from a monthlong stop-work order in April and May 2025, filed a challenge to the new stop-work order Jan. 2 and a motion for preliminary injunction Jan. 6 in U.S. District Court for the District of Columbia (1:26-cv-00004).

After a Jan. 14 hearing, District Judge Carl Nichols — appointed to the federal bench by President Donald Trump in 2019 — granted the motion Jan. 15.

Equinor, which holds an offtake contract with New York for the 810-MW Empire Wind project, had told the court it likely would need to abandon the project if it could not resume work by Jan. 16. With any further delay, it said, crews would not be able to finish a key component before the specialized installation vessels had to depart for the next contracted work.

Later Jan. 15, Equinor said: “Empire Wind will now focus on safely restarting construction activities that were halted during the suspension period. In addition, the project will continue to engage with the U.S. government to ensure the safe, secure and responsible execution of its operations.”

It was the second court victory this week for the beleaguered U.S. offshore wind sector.

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On Jan. 12, another Republican-appointed federal judge lifted the stop-work order on Revolution Wind, a 704-MW project nearing completion off the New England coast. (See Judge Again Lifts Revolution Wind Stop-work Order.) The same judge also lifted the Trump administration’s August stop-work order against Revolution.

Meanwhile, Dominion Energy is contesting the stop-work order on Coastal Virginia Offshore Wind, a 2.6-GW wind farm near completion, and Ørsted is fighting to restart work on the 924-MW Sunrise Wind, an earlier-stage New York project. (See Offshore Wind Developers Fight to get Back in the Water.)

Vineyard Wind was the last project to join the legal fray. On Jan. 15, it filed a complaint in U.S. District Court in Massachusetts (1:26-cv-10156) asking the court to declare the stop work order unlawful and allow work to resume.

The Avangrid-Copenhagen Infrastructure Partners joint venture is 95% complete and already able to send 572 MW of its planned 800-MW capacity to the New England grid, according to the court filing. Construction began in 2021 and was on track to be completed by March 31.

In a statement, the developers said they will continue to work with federal regulators to understand the matters raised in the stop-work order but believe the order was unlawful and said if it is not promptly enjoined, it will cause immediate and irreparable harm to the project and the communities that will benefit from it.

Despite the setbacks it has sustained in court, the Trump administration has succeeded to a significant degree in its bid to thwart offshore wind development: The level of risk it has created has scared away further investment.

The five offshore wind projects hit with the Dec. 22 stop-work order constitute the entire large-scale U.S. offshore wind sector, and they appear unlikely to be followed by others anytime soon. To cite the obvious example, Empire Wind 2 has been shelved indefinitely.

Oceantic Network welcomed the Jan. 15 ruling: “Empire Wind is critical to securing New York’s electric grid, stabilizing rising energy costs for local communities, creating jobs and achieving energy independence, underscoring the importance of building out America’s energy infrastructure to meet rising electricity demand.”

Regional Plan Association hailed the win but warned it is not a final victory: “Despite the good news of these decisions, they still do not ensure that these projects will be completed. The court rulings are temporary injunctions that allow the companies to continue to build while the lawsuits against the administration’s efforts to stop them make their way through the courts. Even an ultimate victory against the administration’s freeze — based on supposed national security concerns — does not prevent them from taking additional steps to disrupt, delay or cease the projects.”

Advanced Energy United said: “Restarting Empire Wind is a major win. This project will deliver clean power and local jobs exactly when we need them the most. Today’s ruling shows that smart energy planning beats political games every time — and that delaying critical projects only drives up costs for consumers.”