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December 9, 2025

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NextEra Energy Pursues Gas-fired Data Center Deals

NextEra Energy is pursuing a goal to power 15 to 30 GW of data center hubs by 2035 and a series of nearer-term agreements in the technology sector.

The 2025 Investor Day presentation Dec. 8 did not mince words: “We are in a golden age of power demand,” and NextEra is “America’s premier energy infrastructure company.”

Until recently, NextEra had been promoting itself as the leading renewable energy developer, but now it is an “all-forms-of-energy company.”

The data center hubs are expected to contribute at least 15 GW of new generation by 2035 under a base scenario and 30 GW under an upside scenario. They already have identified more than 20 potential hubs and expect to have more than 40 possibilities by the end of 2026.

Natural gas will play a large role in this, “and we are making excellent progress in our development efforts,” the company reported.

Accompanying the projections was a set of diverse announcements, led off with a partnership with Google Cloud to develop multiple new gigawatt-scale data center campuses with accompanying power generation and capacity.

The two companies expect the collaborative approach to speed land development, load interconnection and development of infrastructure.

Additionally, they will collaborate on NextEra’s internal digital transformation and use technological innovations and artificial intelligence to accelerate the buildout of data centers and the energy infrastructure supporting them.

In Related News

NextEra Energy Resources and Meta Platforms have reached 11 power purchase agreements and two storage agreements totaling approximately 2.5 GW of clean energy. This consists of nine solar projects in ERCOT, MISO and SPP totaling 2.1 GW; two solar projects in New Mexico rated at 190 MW; and 168 MW of battery storage, also in New Mexico. They are expected to come online in 2026 through 2028.

NextEra Energy Transmission and Exelon say they will partner to build an approximately 220-mile bidirectional 765-kV line in PJM territory to facilitate more than 7 GW of power generation. The project carries a $1.7 billion price tag; the PJM board’s final vote on it is expected in early 2026.

NextEra Energy Resources says it will acquire natural gas supply, storage and management company Symmetry Energy Solutions, which has 5,500 commercial/industrial customers and 80,000 mass-market customers in 34 states. The deal is intended to complement NextEra’s buildout of gas transmission and gas-fired generation and is expected to close in the first quarter of 2026, pending regulatory approvals.

NextEra Energy Resources and Basin Electric Power Cooperative say they will explore joint development of a new 1,450-MW combined-cycle gas-fired power plant in North Dakota to serve as the foundation for a multi-gigawatt data center campus. Under Basin’s Large Load Commercial Program, the two submitted an application to the SPP Expedited Resource Adequacy Study process in October.

NextEra Energy Resources is partnering with Comstock Resources on a plan to build up to 8 GW of new gas generation and storage to support hyperscaler data center development in central Texas. Initial power is expected as early as 2027.

NextEra Energy Resources and ExxonMobil are pursuing construction of a 1.2-GW gas-fired, carbon-abated plant on a site with proximity to ExxonMobil’s Denbury carbon dioxide pipeline, gas supply and transmission. They are jointly marketing the plant to hyperscalers, and they view it as a proof of concept that could lead to multisite development opportunities.

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Ariz. Regulators Slash APS’ DSM Plan, Express Support for VPP Programs

Arizona regulators approved a demand-side management plan for Arizona Public Service that slashed the plan’s proposed budget by more than half and eliminated many of its programs — but spared and even encouraged virtual power plant programs.

The Arizona Corporation Commission voted 5-0 on Dec. 3 to approve the scaled-back plan with a budget of $40 million rather than the requested $91 million.

ACC staff recommended approval of APS’ DSM plan, finding that the plan’s newly proposed programs would be cost-effective.

But Chair Kevin Thompson proposed an amendment, which the commission approved, that slashed the plan’s programs and budget.

“I’ve been anxious to get this matter before this commission so that we can trim some of the bloat and fat from this budget,” Thompson said.

Thompson blamed the situation on previous commissions that “condoned and even required these programs to expand to the point where they ballooned beyond the intent of the original goals.”

An APS representative said the company didn’t oppose Thompson’s amendment.

ACC rules require utilities to file a DSM plan. The cost of programs in an approved plan can be recovered through a customer fee.

Among programs the commission rejected were APS’ proposed measures to encourage mini-split heat pumps and air conditioners and pool pump recalibrations in existing homes.

The ACC suspended all funding for the residential new construction program, which offered incentives to builders that meet energy efficiency standards in new homes. APS had proposed increasing an incentive, from $100 to $200, for prewiring new homes for EV charging.

Thompson said installing energy efficient appliances in new homes is already required by law.

The ACC axed incentives for electric golf carts, high-frequency golf cart battery chargers and energy-efficient livestock fans. APS said in its plan that golf cart-style utility vehicles are increasingly popular as work vehicles beyond golf courses.

Funding was eliminated for the conservation behavior program, which has provided home energy reports and personalized energy-saving tips to about 500,000 residential customers.

VPP Programs Spared

Spared from the chopping block was a home weatherization program for low-income residents.

The commission also saved APS’ virtual power plant programs, which include commercial and industrial demand response and the Cool Rewards residential program. Cool Rewards gives a $35 annual credit to customers who agree to have their thermostat setting raised when energy demand increases during a summer heat event.

APS wants to expand Cool Rewards beyond its 4 to 7 p.m. timeframe in June through September. Market prices can still be high from 7 to 8 p.m., said Kerri Carnes, director of customer to grid solutions for APS.

“There have been instances where it would have been nice to call on those thermostats in early October, for instance,” Carnes told the commission.

Also spared was a “bring your own device” pilot program for home batteries, which the commission approved in March. APS customers who agree to participate in up to 60 battery-dispatch events from May through October will be compensated with an annual $110/kW capacity payment.

The commission approved an amendment from Vice Chair Nick Myers that directs APS to strengthen its VPP programs.

Myers wants to see APS adopt a “more cohesive” VPP strategy, potentially consolidating separate programs.

“A VPP should not be treated as a niche pilot or a scattered set of incentives,” Myers said. “It should operate as a true grid asset — one capable of delivering firm capacity, supporting reliability events and reducing the pressure on ratepayers to build traditional generation or wires solutions prematurely.”

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Raab Associates’ Restructuring Roundtable Looks Back on 30 Years

BOSTON — Raab Associates held its final New England Electricity Restructuring Roundtable on Dec. 5, bringing reflections from speakers about the legacy of restructuring and the future of the power sector in the region.

Several speakers praised the Roundtable for consistently bringing together a wide range of perspectives and interests, and helping to promote collaboration and consensus among stakeholders.

“The diversity of perspectives that are at the table is pretty incredible,” said David Cash, former EPA regional administrator for New England. “There are people here who have sued each other; there are people here who are competitors.”

Dan Sosland, president and co-founder of the Acadia Center, said the Roundtable has been somewhat unique among power industry events for its inclusion of climate and environmental perspectives.

“At the Roundtable we were co-equals,” Sosland said. “We were included, and that’s a testament to” Raab Associates President and Roundtable convenor Jonathan Raab.

The Roundtable was founded in 1995 to bring stakeholders together to discuss the details and challenges of electricity industry restructuring. It opened to the public after Massachusetts passed its restructuring law in 1997, and Raab Associates formally took over the event from the Massachusetts Department of Energy Resources in 2000.

As the states worked through the kinks of restructuring, the Roundtable gradually became “much more of a policy forum,” said Raab, who helped found the Roundtable and moderated the events for most of the 30-year run.

In 2026, the consulting firm Apex Analytics will take control of the Roundtable. The company was selected through a competitive request for proposals and plans to hold its first event in March.

“The Roundtable’s strength lies in its adaptability and commitment to discussing meaningful substance around the evolving energy landscape,” said Matt Nelson, principal at Apex and former chair of the Massachusetts Department of Public Utilities. “Our team is committed to maintaining that core while thoughtfully exploring ways to evolve and provide relevant content as industry needs change.”

Reflections on Restructuring

The event also may mark ISO-NE CEO Gordon van Welie’s last public appearance at the helm of the RTO he has led since 2001. (See Retiring ISO-NE CEO van Welie Reflects on 25 Years at the RTO.)

He emphasized the progress that has been made around collaboration in the region, saying, “Even when things do seem a bit tense, we’ve developed mechanisms to deal with those frictions.”

Restructuring and the move to wholesale markets have brought customers significant savings, though not all initiatives have worked as well as he would have liked, he said.

“I would say we made a mistake in going to the Forward Capacity Market back in 2004,” van Welie said, adding that it “became too much of a crutch” for ensuring resource and energy adequacy.

ISO-NE’s proposed move to a prompt capacity market will “hopefully stimulate bilateral contracting,” he said. “The market needs to invest more on a foundation of bilateral contracting with the spot capacity market really being a deficiency charge for somebody who’s not fully hedged.”

Rebecca Tepper, secretary of the Massachusetts Executive Office of Energy and Environmental Affairs, praised ISO-NE’s reliability record.

“ISO-NE has never had to call a control outage in its history,” Tepper said. “It’s something that we shouldn’t take for granted and a huge benefit for consumers.”

“Some of it has been luck — we dodged the bullet once or twice — but a lot of it has been operational awareness and market design,” van Welie said.

Tepper said it has taken longer to get the retail side of restructuring right, pointing to the lingering problem of predatory supply practices that target residential customers. The growth of municipal aggregation programs in Massachusetts in recent years has enabled better protections and options for residential customers, she said.

As the ongoing deployment of advanced metering infrastructure in the region enables new rate designs that incentivize shifting demand away from peak hours, van Welie said New England should consider “a more command-and-control structure for [demand response],” allowing customers to give up some control of their home appliances in exchange for a lower rate.

Looming Supply Challenges

Both van Welie and Tepper also emphasized the need to focus on bringing in new sources of supply to meet rising demand, and Tepper said regional collaboration will be essential to addressing looming supply challenges.

Katie Dykes, commissioner of Connecticut’s Department of Energy and Environmental Protection, said the states are “working on multiple multistate RFPs; that is becoming much more of the norm than the exception.”

Several speakers stressed the importance of demand-side innovation, new programs and rate reforms to help prevent supply issues in the coming decades.

While most demand growth projections forecast peak demand to roughly double by 2050, “I don’t think these have to be written in stone,” said Jamie Dickerson, senior director of energy and climate programs at Acadia. He pointed to a Brattle Group study indicating that grid flexibility could reduce New York’s 2040 winter peak by about 21%. (See Study Finds Considerable ‘Grid Flexibility’ Potential in New York.)

Jesse Jenkins, a Princeton University associate professor focused on the decarbonization of energy systems, echoed Dickerson’s comments and said even greater demand flexibility gains may be achieved if costs come down for technologies like thermal storage.

“There are lots of ways we can cut [peak demand forecasts], including ground-source geothermal, which is often twice as efficient, if not more, than air-source heat pumps,” he said.

Dickerson also stressed the importance of energy efficiency investments while urging policymakers to find more progressive ways to fund EE programs, including through the tax base.

“We do need to lean on those with a greater ability to pay,” he said.

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PJM Stakeholders Endorse Manual Revisions for Modeling DERs

The PJM Planning Committee on Dec. 2 endorsed by acclamation manual revisions to reflect how distributed energy resources (DERs) would be accredited for participation in the 2028/29 Base Residual Auction (BRA) in compliance with FERC Order 2222. The market-side rules were endorsed by the Market Implementation Committee in November. (See PJM Stakeholders Endorse Rules for DER Participation.)

The changes to Manual 20A: Resource Adequacy Analysis detail how components of DERs would be reflected in effective load-carrying capability (ELCC) modeling and the reserve requirement study (RRS), how hourly output would be simulated for each component technology class, and how accredited unforced capacity (AUCAP) would be calculated for each resource. Class ratings would not be produced for DERs as a whole; instead, they would be calculated for each resource based on its composition.

The proposed Manual 21B: PJM Rules and Procedures for Determination of Generating Capability language includes the calculation of installed capacity (ICAP) and effective nameplate capacity values for each DER component and how backcasts of hourly performance would be produced. Aggregations including wind or solar components can substitute PJM’s backcast with their own going back to June 1, 2012, with accompany documentation of the methodology and date used to produce it.

Planning Manual Revisions Endorsed

Stakeholders endorsed revisions to Manual 14B: PJM Region Transmission Planning Process drafted through its periodic review, including several administrative updates and a change to ambient ratings to conform with FERC Order 881.

When PJM is developing the light-load ambient ratings in the assumptions for the Regional Transmission Expansion Plan (RTEP), transmission owners would be permitted to choose either the default 59F thermal rating or 60F.

The RTEP Reliability Planning section was tweaked to add phase angle regulators when referencing phase shifting transformers to improve consistency between manuals and the new equipment energization process checklist. The section was updated with links to the relevant PJM departments.

First Read on Manual Revisions Expanding Dual Fuel Definition

PJM presented a first read on revisions to Manual 21B to reflect FERC-approved changes to the definition of dual-fuel gas generation to include configurations where the secondary fuel is stored off site but connected to the generator with a dedicated firm pipeline (ER25-3413). (See “Reworked Dual-fuel Definition Endorsed,” PJM MRC/MC Briefs: July 23, 2025.)

When first introducing changes to the governing documents in June, Dominion said resources with a dedicated connection to secondary fuels can provide a comparable level of reliability as those where the fuel is stored on site. (See “Dominion Presents Proposal to Change Dual-fuel Definition,” PJM MRC/MC Briefs: June. 18, 2025.)

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DOJ, Constellation, Calpine Reach Antitrust Settlement

Under a federal antitrust settlement, Calpine Corp. will divest ownership in several generation assets on the PJM and ERCOT grids as a condition for its acquisition by Constellation Energy.

If approved by a court, the resolution will clear the way for a $26.6 billion transaction that will make Constellation the largest U.S. wholesale power generator.

FERC and regulators in New York and Texas previously approved the deal.

On Dec. 5, Constellation and the Antitrust Division of the U.S. Department of Justice (DOJ) announced a proposed resolution to the final regulatory hurdle.

DOJ said it was concerned the acquisition could harm competition and raise prices in the PJM and ERCOT grids by more than $100 million a year. DOJ and the state of Texas simultaneously initiated a civil antitrust lawsuit (1:25-cv-04235) seeking to block the acquisition and a proposed divestiture settlement that would allow it to go forward.

The companies accepted the terms. DOJ said it was the first settlement consent decree the Antitrust Division had filed in a power industry merger in 14 years.

“This settlement includes a six-plant divestiture to an acquisition that risked harming tens of millions of electricity consumers in the mid-Atlantic and Texas,” Assistant Attorney General Abigail Slater said in a news release. “I am appreciative of the partnership with our co-plaintiff, the state of Texas, to secure relief for consumers.”

Constellation CEO Joe Dominguez hailed the agreement as clearing the way for a foundational step in the next era of American growth and innovation. “We thank the department for its professionalism and tireless work reviewing this transaction through these many months. It’s now time for us to complete the transaction, welcome our new colleagues from Calpine and together begin our journey to light the way to a brilliant tomorrow for all.”

FERC’s approval in July entailed Calpine selling 3,546 MW of generation, all of it in PJM: the 1,134-MW natural gas combined-cycle Bethlehem Energy Center, the 569-MW dual-fuel combined-cycle York Energy Center Unit 1, the 1,136-MW dual-fuel combined-cycle Hay Road Energy Center and the 707-MW simple cycle gas-fired Edge Moor Energy Center. (See FERC Approves Constellation Purchase of Calpine with Conditions.)

The proposed antitrust settlement entails sale of York Unit 2, an 828-MW natural gas-fired, combined-cycle plant in Pennsylvania; the Jack Fusco Energy Center, a 605-MW natural gas-fired combined-cycle facility outside Houston, Texas; and a minority ownership interest in the Gregory Power Plant, a 385-MW natural gas fired combined-cycle near Corpus Christi, Texas.

When it announced the Calpine deal Jan. 10, Constellation anticipated the need for some asset sales in PJM. (See Constellation to Acquire Calpine for $29.1B.)

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CPUC OKs PG&E Request for 2026 Diablo Canyon Cost Recovery

The California Public Utilities Commission on Dec. 4 approved Pacific Gas and Electric’s request to recover about $382 million from ratepayers to continue operating the Diablo Canyon Power Plant in San Luis Obispo in 2026.

The approved 2026 revenue amount covers operations and maintenance activities, resource adequacy substitution capacity forecasts and fuel from 2025 through 2030, among other items, the decision says.

“I know these issues [in the decision] have not been easy,” CPUC Commissioner Darcie Houck said. “The extended operations of Diablo Canyon Power Plant are a critical piece of the state’s electricity reliability requirements, and PG&E does need to be compensated consistent with the statute.”

Diablo Canyon had been scheduled to close by 2025, but in 2023 the CPUC approved a 5-year extension for the plant, keeping its two reactors online until at least 2029 and 2030. The approved 2026 revenue requirement will decrease the average bundled service rate for PG&E customers from about 34.8 cents/kWh to about 34.6 cents/kWh.

The revenue requirement costs will be split among PG&E (44%), Southern California Edison (46%) and San Diego Gas & Electric (10%). The decision requires PG&E to provide a “detailed account” of why it did not seek government funding to offset certain ratepayer costs.

“The tracking of costs is going to continue to be very important to ensure that there is no double recovery at a later date,” Commissioner John Reynolds said.

SGIP Refunds

At the Dec. 4 voting meeting, the CPUC also approved a decision that closes the ratepayer-funded portion of the Self-Generation Incentive Program (SGIP), setting out the return of leftover money to ratepayers, while establishing rules for implementing the portion of the program financed by the Greenhouse Gas Reduction Fund (GGRF).

The SGIP was implemented more than 20 years ago to provide incentives to certain distributed energy resources on the customer’s side of the utility meter to help shave peak demand. Qualifying technologies included internal combustion engines, gas turbines, energy storage systems, and combined solar and energy storage systems, among others.

The structure of the program has gone through multiple iterations, and over time its focus has shifted from reducing peak load to cutting greenhouse gas emissions.

In 2020, SGIP was extended from Jan. 1, 2021, to Jan. 1, 2026, under California Senate Bill 700, which authorized the CPUC to collect $166 million in ratepayer funds per year for the program from 2020 to 2024. In 2022, Assembly Bill 209 removed a requirement that the CPUC administer solar resources separately from other technologies under the SGIP, provided funding for combined solar and storage resources and directed the agency to use AB 209 funds for all residential customers, including those served by publicly owned utilities.

In 2023, SB 102 allocated $280 million in GGRF money to the SGIP and restricted participation to eligible low-income residents installing behind-the-meter storage or solar-plus-storage systems. According to the CPUC’s ruling, the GGRF-funded SGIP budget was opened for reservation in June 2025. The program’s administrators — namely the state’s utilities — are expected to administer the GGRF-funded SGIP similarly to the ratepayer-funded program.

SGIP projects are subject to time-of-use and demand response requirements to support grid reliability and were required to enroll in a TOU rate and DR program for 10 years.

“Once SGIP closes it will be important for the electric investor-owned utilities associated with SGIP projects and customers to monitor ongoing compliance with TOU and DR requirements to ensure that the state is achieving the full ongoing benefits of these systems,” the CPUC said in the decision. “This approach will allow SGIP to close before all projects get through the 10-year permanency period while maintaining program and grid benefits.”

High Stakes on Undergrounding

The CPUC approved a resolution that updates its guidelines for undergrounding electric distribution lines. The updates include new requirements for determining whether cost recovery is reasonable for an undergrounding project; a revised method for choosing the most cost-efficient projects; and an explanation of how to calculate cost-benefit ratios to maximize wildfire risk reduction and minimize costs, among others.

“Our electric grid … has experienced catastrophic failures leading to loss of life and home,” Reynolds said. “This has led us in this regulatory space to rethink our approach to risk on the grid.”

“We know we will need additional standards to judge what undergrounding projects should be funded by ratepayers … the costs here are enormous,” Reynolds added. “We know we will be evaluating 10 to 11 figures in capital costs with average monthly customer bill impacts as high as $25. With stakes that high for a single capital program, we need to get the methodology right.”

The CPUC also approved a new rate for 2026 for the state’s wildfire fund non-bypassable charge. The new rate of $0.00591/kWh rate will add about $909 million to the fund, according to the decision.

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BPA Outlines Next Steps in Markets+ Implementation

As the Bonneville Power Administration prepares to join Markets+, the agency hopes to complete the initial program governance setup and define its commercial model for market participation early next year, though questions persist about the timeline and market seams.

BPA provided the update during a Dec. 4 day-ahead market participation workshop. BPA committed to SPP’s Markets+ in May 2025, and the power agency is to begin participating in the day-ahead market in October 2028. (See BPA Chooses Markets+ over EDAM.)

But several key steps remain, according to Nita Zimmerman, acting vice president of bulk marketing at BPA.

“The policy direction is to pursue Markets+, but several important steps still remain, which include a rate case, a tariff proceeding, a National Environmental Policy Act analysis and the successful negotiation of a Markets+ implementation agreement,” Zimmerman said.

Another step includes defining BPA’s commercial model framework. While the network model deals with physical elements, such as electrical nodes, metering and transmission elements, the commercial model connects those physical elements to the financials, explained Sara Eaton, senior analyst at BPA.

“The commercial model is creating that mapping between the network model, the physical and then the financial,” Eaton said. “So, when we say ‘commercial model,’ it’s going to have settlements impacts, and that’s why it’s really important to get it right and to start those conversations early.”

To define the commercial model, BPA must answer questions about how entities interact in the market, how resources and loads are modeled, and how information is shared among market participants, said Libby Kirby, BPA’s Markets+ program manager.

“A lot of those framework questions drive all of the downstream work that ends up happening,” Kirby said.

“So, once we have gotten some of those commercial model framework questions answered, we will move into some of those more formal work streams — developing software, developing processes, etc. — as well as getting into our internal testing,” Kirby said.

According to BPA’s presentation slides, the agency aims to complete the initial governance program setup by March 17, and the commercial model by March 31, 2026.

Other preparations include aligning the agency’s provider-of-choice contracts with Markets+ and preparing the exit from the Western Energy Imbalance Market.

Another issue is the market seams expected to arise from the split between Markets+ and CAISO’s Extended Day-Ahead Market. (See SPP Markets+ Cruising Through Early Development.)

Steve Greenleaf, senior director of regulatory affairs and policy at Brookfield Renewable, asked whether BPA plans future workshops on seams or if those concerns are limited to SPP.

Kirby responded that BPA does not view seams as an “SPP-only issue.”

“I think we all have a stake in the outcome, and so I don’t think we expect to just say, ‘Yep, [SPP is] going to do it all, and we have no interest in that,”’ Kirby said. “I think we have lots of interest and probably some opinions that we’d like to share with them.”

She noted SPP plans to host a symposium on seams in February.

“I don’t know that there’s an explicit full road map … yet that sort of bridges both sides, but I think that is something that [SPP is] considering, and that we very much know that we will continue to poke at,” Kirby said.

‘Weakest Link’

Henry Tilghman, a consultant with the Northwest & Intermountain Power Producers Coalition, questioned whether BPA can keep its Markets+ implementation timeline, given that certain upgrades are still pending.

“The reason I’m asking is a chain is only as strong as its weakest link, and the [Automatic Generation Control] upgrade has been pending for at least a year and a half,” Tilghman said. “And for some reason, I still can’t get a timeline for when that’s going to be completed.”

“What is your confidence level in delivering on the schedule given that there is a very important software upgrade that doesn’t have any timeline to complete, as near as I can tell,” Tilghman said.

Kirby described her confidence level as “decent.”

“I think it’s too early to be too confident. It’s too early to be too pessimistic,” Kirby said. “Right now, we are making plans to meet it. Right now, we think we can meet it, including with AGC. But I think obviously there are risks. There are risks for workload; there are risks if we go live and [market participants] aren’t ready, what do we do? We have to have contingency plans. We have to have backup plans. I think that is all part of the conversation right now.”

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Rosner Voices Support for Large Load ANOPR

BOSTON — FERC Commissioner David Rosner was supportive of the Department of Energy’s request that the commission assert authority over the interconnection of large loads while emphasizing the importance of collaboration and consensus-building in response to concerns raised by state regulators.

Speaking at a meeting of the ISO-NE Consumer Liaison Group on Dec. 3, Rosner said the Advance Notice of Proposed Rulemaking submitted by the department to FERC includes “ideas that I know people in this room have talked about for a long time and that I think we know will work.” (See Energy Secretary Asks FERC to Assert Jurisdiction over Large Load Interconnections.)

“I think there’s a lot of consensus on: We need to do this because there’s a lot of economic development opportunities for the country and states that want to build, but we also need to do it in a way that protects consumers,” he added.

Certain aspects of DOE’s request have drawn significant pushback from state regulators. A resolution passed by the National Association of Regulatory Utility Commissioners stressed that FERC must not assert control over “end-use sales,” which are “squarely within the exclusive jurisdiction of state retail energy regulatory authorities.”

The resolution also warned that “large load interconnections without sufficient available generation capacity could threaten reliable power service to existing retail customers.” (See Regulators Urge FERC to Honor State Authority over Large Load Interconnections.)

Expediting the interconnection of large loads, including hyperscale data centers, is a politically sensitive issue across the country. Critics of hyperscale data development point to impacts on energy costs and emissions, as well as the relatively limited number of people the facilities employ. Growing bipartisan pushback against data centers has blocked or delayed about $64 billion of investments over the past two years, according to a recent study.

The ANOPR floats the idea of processing large load interconnections within 60 days, which has caused some concern about effects on load forecasts. In regions with wholesale markets, rules encouraging co-location could remove generation from the market and drive consumer costs up.

Regarding the controversial aspects of DOE’s request, Rosner said he is excited to work with his fellow commissioners “to figure out which of these levers do we need to pull on to solve this problem.”

He said the benefit of an ANOPR proceeding is that because it is a generic rulemaking, commissioners can have open conversations with stakeholders to build consensus.

Reflecting on his work on Order 1920-A, he stressed the importance of state buy-in. Working closely with then-Commissioner Mark Christie, “one of the things that we did was to dramatically elevate the state role and state input into the development of those plans.” (See FERC Order 1920-A Wins Approval with Accommodations to States.)

Getting states to agree on transmission cost allocation plans “de-risks the ability of the utility to actually build these projects, and it makes them more likely to actually get sited,” he said, noting that FERC does not have authority over transmission siting, except in “very rare cases that have never worked.”

Rosner also emphasized the importance of the independent, bipartisan structure of FERC, which he said is “fundamental to having durable solutions.”

“It’s a good model, and it didn’t happen by accident,” he said. “I know there’s some litigation in the courts about the president’s ability to exert influence over these agencies and make staff decisions, and we’ll see what happens.”

The Supreme Court is scheduled to hear oral arguments on Dec. 8 for Trump v. Slaughter, a case that could lead to rollbacks of limits to the president’s ability to fire members of independent agencies. (See Former FERC Commissioners Ask Supreme Court to Preserve Agency Independence.)

New England Issues

Rosner also commented on several New England-specific issues, including capacity accreditation, asset condition projects and the region’s gas constraints.

He said ISO-NE’s efforts to establish an internal, non-regulatory entity that reviews spending on asset condition projects — potentially enabling third parties to challenge costs with FERC — appears to be a step in the right direction. (See ISO-NE Gives Update on Asset Condition Reviewer Role.)

Regarding ISO-NE’s work on capacity accreditation, he said it will likely benefit from learning from reforms that have been implemented in other regions.

“I am really encouraged by New England’s move toward accreditation,” he said. “What I like about tools like this is that they send signals to the private sector and to our state policymakers — who I know play a big role in what gets built here — of, ‘here’s how your investment will pay off.’”

He also said he remains concerned about the region’s constrained access to pipeline gas.

“I have worries about making sure that lights stay on and will stay warm and safe in our home,” he said. “I do want to have a sort of all-options-on-the-table approach to this.”

During peak periods, there may be opportunities to increase efficiency across the gas and electric systems through artificial intelligence, Rosner said. He also pointed to success in California around using demand response to shift natural gas use throughout the day, saying, “I wonder if there’s the potential for using that here.”

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Grid Strategies: Pace of Load Growth Continues to Speed up

The power industry’s own demand forecasts expect national summer peak to swell by 166 GW by 2030, which would be the equivalent of adding 15 times the peak load of New York City, Grid Strategies said in its latest load growth report.

The estimates, which are based on reports submitted to FERC through Form 714, include 90 GW of new data centers, 30 GW of industrial growth, 10 GW from oil and gas and mining, and 30 GW from other sources. This is the third report in a row published by Grid Strategies showing demand growth, and the pace has grown each time, the firm’s president, Rob Gramlich, said during a webinar hosted by Americans for a Clean Energy Grid on Dec. 4.

“We’re talking about over 5% annual growth, which is pretty extraordinary,” Gramlich said. “Now it’s not, by historical standards, a growth rate that is unprecedented.”

It certainly is in total gigawatts, however, as the last time the electric industry saw growth at similar levels in the middle of the 20th century, it was from a smaller base, he noted.

“We’ve been able to meet the pace of growth in the past,” Gramlich said. “But of course, we’ve, in a way, as an industry and a regulatory community, lost our muscle memory on a lot of these things. It’s just not something that most of us in our careers have had to deal with.”

Energy use is growing even faster than the peak numbers, at 50% over the next half decade, which means the new demand has a higher load factor, he added. The bulk power system in the U.S. averages a 60% load factor today, but that is expected to reach 66% by 2030 as new demand comes online, the report says.

“Data centers generally operate at an above-average load factor,” the report said. “For example, Dominion Virginia reported an 82% load factor for large data centers in 2024, and Duke Energy states that it plans for new large loads to have an 80% load factor. It appears that some large load forecasts may use higher values, perhaps as high as 100%, which is unrealistic.”

The utility reports to FERC are likely overstating the amount of data center load, with an estimate from Cleanview showing just 60 GW by 2029, and TD Cowen predicting 65 GW by 2030 based on orders for advanced microchips.

“Somewhat similar to what we have on the generation side, there are always way more proposed projects than there are actual projects that go forward,” Gramlich said. “I never liked the term ‘speculative’ about generation. I don’t really like it about load either. It’s just how the business works. If you’re building anything, you have to not put all your eggs in one site basket.”

All the new load being projected means that the industry and regulators are going to need to expand the BPS, Virginia State Corporation Commission Judge Kelsey Bagot said on the webinar.

“We’re certainly going to have to build a lot of generation right, which necessarily includes the transmission component,” she added.

Generally, the industry has been reactive but meeting the needs of these new customers while keeping costs affordable will require it to be more proactive in its planning, Bagot said. The cost of the expansion naturally leads to questions about allocation, which can lead to litigation at the state level and goes to the core of concerns that existing ratepayers have about affordability.

“In order to be comfortable proactively building, I think we need to pay attention to cost allocation, and at the state level, that means making sure that we are allocating transmission build to the folks that are driving the need for the build, right?” Bagot said. “That will get the end-use customer more comfortable with the amount of transmission that we’re building.”

Getting the expansion done affordably means using all the tools available, including advanced transmission technologies, distributed energy resources and virtual power plants, said Sarah Freeman, a principal at the Regulatory Assistance Project.

“It’s so critical that we encourage/force our utilities to take these bigger picture looks,” Freeman said.

Amazon Web Services Energy Policy Manager Ray Fakhoury agreed that the industry needs to proactively plan to meet new loads more than it has recently, and he said the new technologies his company and others are working on — those that are driving the growth — can help.

“There is a way to integrate artificial intelligence, machine learning [and] the highest standards of all of these software programming so that we can identify the optimal spots to build out transmission,” he argued.

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Colorado PUC Approves Extension for Comanche Coal Plant

The Colorado Public Utilities Commission granted a one-year extension to Unit 2 of the coal-fired Comanche power plant as uncertainty lingers about the fate of outage-plagued Unit 3.

The commission approved the extension Dec. 3. Comanche Unit 2 now is scheduled to retire by Dec. 31, 2026, rather than at the end of 2025. The 335-MW Unit 2 began operating in 1975.

The commission’s decision was in response to a petition filed Nov. 10 by Xcel Energy subsidiary Public Service Company of Colorado (PSCo), which is the coal plant’s primary owner and operator. PSCo was joined in the petition by the Colorado Energy Office, the state Office of the Utility Consumer Advocate and PUC trial staff. (See Xcel Seeks Extension for Comanche Coal Plant from Colorado Regulators.)

The petitioners argued the extension was needed because of the unexpected outage of the 750-MW Unit 3, which began Aug. 12 and is expected to last until at least June 2026.

Other factors contribute to the need to keep Unit 2 open, the petitioners said. Those include growth in the peak demand forecast in PSCo territory and the delay of generation and storage projects because of supply chain and tariff issues.

The PUC emphasized the Unit 3 outage was the sole reason for granting the extension.

“Clearly we wouldn’t be making this decision if not for the unreliable operation of Unit 3,” Commissioner Tom Plant said.

Comanche Unit 3, which went online in 2010, has a history of unplanned outages. From mid-2010 through 2020, the unit averaged 91.5 outage days a year, according to a March 2021 report from the PUC. A 2020 outage lasted much of that year and extended into 2021.

For two years starting in August 2023, the plant has been shut down unexpectedly for part or all of 138 days, according to Western Resource Advocates (WRA).

Unit 3 is slated for retirement by Jan. 1, 2031, as Xcel plans to exit from coal by 2030. Unit 1 retired in 2022.

Commissioner Megan Gilman expressed concern that PSCo might be presuming that fixing Unit 3 is the best path forward. In addition to unknown costs to repair Unit 3, the costs to extend the life of Unit 2 aren’t yet known, she said.

“We are in the dark about what any of this costs,” Gilman said. “We are just in a real reliability pickle because once again Unit 3 has broken in a catastrophic way. And it just so happens that we’re already somewhat tight on resources, so now it has really created a significant problem.”

The commission’s decision requires PSCo to report to the commission by March 1 on the status of Unit 3. A more detailed report is due by June 1.

Commission Chair Eric Blank said he wants monthly reports from PSCo on costs to fix Unit 3.

“I’m not interested in seeing very large capital expenditures on an after-the-fact prudency review fight,” Blank said. “I’d like at least visibility into what’s going on ahead of time.”

Commissioners noted there would be no presumption of prudence from the monthly reports.

The commission also placed a cap of 3,942,000 MWh on combined generation from Units 2 and 3 in 2026 — a status quo limit that was requested by WRA and other environmental groups.