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December 8, 2025

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Around the Corner: The Long-Awaited Nuclear Renaissance Shows Signs of Promise, But Still has a Long Way to Go

Amid the growing push for new sources of power generation — especially from the data center sector — we have seen an extraordinary number of announcements concerning nuclear power. At this point, they are occurring almost weekly, something few would have anticipated just a few years ago. 

These announcements generally fall into one of three areas: rehabilitation of closed nuclear facilities, potential development of new large-scale facilities such as the AP 1000 technologies currently deployed across the country, and development and deployment of an entirely new class of smaller reactors commonly referred to as small modular reactors (SMRs) or modular nuclear reactors (MNRs). The buzz in the space is considerable, but there still are numerous hurdles to be overcome before we can declare a win for the much anticipated “nuclear renaissance.” 

Not Dead Yet

In recent years, numerous nuclear plants were struggling to survive, especially in competitive power markets where low-cost gas-fired and renewable plants were seriously denting their economics. Indeed, the economic outlook was so poor that five states (Connecticut, Illinois, New York, New Jersey and Ohio) threw their nuclear plants lifelines and created subsidy programs to keep 14 nuclear plants operating.  

Several other states, though, chose to let plants be taken out of service. The typical decommissioning process is to remove and store the fuel, dismantle the plants and decontaminate the sites. In fact, that process has been followed by dozens of sites over recent decades. 

Peter Kelly-Detwiler

However, as forecast power demand has rapidly increased recently, several recently decommissioned sites are now being pressed back into service. These include the 837-MW Three Mile Island 1 in Pennsylvania that is slated to deliver power to Microsoft for 20 years, the 800-MW Palisades plant in Michigan and the 615-MW Duane Arnold facility in Iowa. And most recently, Holtec International, the owner of the 2,000-MW decommissioned Indian Point nuclear plant in New York, suggested the possibility of rehabilitating the facility for an estimated $10 billion. 

While these efforts eventually may bring back over 4,000 MW of capacity online, there may not be many other resurrection efforts to follow, since many of the other decommissioned plants are either too far along in the process or may not prove economically viable. 

An addition to this category might include the uncompleted V.C. Summer plant in South Carolina, which was abandoned in 2017 after burning through $9 billion of investment capital. That facility was thought to be dead until January 2025, when utility Santee Cooper issued a request for proposals seeking “to acquire and complete, or propose alternatives, for two partially constructed generating units at the VC Summer Nuclear Station.” In May, the utility said it had received responses to the RFP but offered few details.  

Revisiting Large Light Water Reactors

New nuclear power supply may come from the traditional light water reactors that have been employed by the U.S. power industry for many decades. For example, the proposed gargantuan 11,000-MW Fermi Project in Texas recently submitted an application to the NRC that includes four, 1,000-MW Westinghouse AP1000 nuclear reactors. (The last such units deployed were in the Vogtle plant in Georgia back in 2023, coming in more than seven years behind schedule and $17 billion over the original budget.) However, it appears that the new smaller and modular nuclear technologies may dominate this space. 

Smaller Cookie-cutter Modular Units

In recent years, SMR-related investments and project announcements have surged, with much of this coming from the data industry. Dozens of companies — from large and established energy players such as GE, Hitachi, Rolls Royce and Westinghouse to numerous startups — are vying for success in this industry. They typically distinguish themselves from the existing light water reactor technologies in terms of size and technology, with many boasting fail-safe designs.  

Models range in size from so-called “micro reactors” as small as 1 MW to larger units offering almost 500 MW of output. Many startups feature competing technologies that have not yet been tested commercially, and given the large number of contenders, many will fail commercially. But that hasn’t seemed to slow the sector of late. In fact, in the frothy SMR waters, just since mid-August the following commitments have been heralded:  

    • Tennessee Valley Authority announced a contract with developer ENTRA1 Energy for a 6,000-MW deployment of MNR startup NuScale’s 77-MW reactors, the only ones thus far to have received NRC approval for their design. 
    • Startup X-energy hailed a collaboration with Amazon, Korea Hydro & Nuclear Power and Doosan Enerbility “to accelerate the deployment of new Xe-100 advanced nuclear reactors in the United States,” with a stated goal of deploying more than 5,000 MW of new nuclear capacity across the U.S. by 2039, while mobilizing up to $50 billion in public and private investments.  
    • Data co-location giant Equinix announced three separate deals with different modular nuclear companies for nearly 775 MW of new capacity in the U.S. and Europe, with power to come from reactors ranging in size from just over 1 MW to 470 MW. 
    • Finally, the Utah Office of Energy Development (OED), TerraPower (the Bill-Gates-backed company) and Flagship Companies signed a memorandum of understanding “to explore the potential siting of a Natrium reactor and energy storage plant in Utah.” 

It’s increasingly looking like a new generation of nuclear reactors may become part of our energy future.

Big Data, Big Commitments

Much of the recent momentum is directly attributable to the data center companies that are hungry for power, while in many cases striving to maintain commitments to reduce associated carbon emissions. In addition to Equinix’s more recent announcements, it also had signed a deal to buy up to 500 MW of power from SMR startup Oklo, with a $25 million pre-payment for future power output and a right of first refusal for from 100 to 500 MW of power. 

Google also has been active. In May, it signed an agreement with nuclear project developer Elementi to commit early-stage development capital to support at least three projects that each would generate more than 600 MW. The company has the option to be a project off-taker once the facilities are commissioned (terms and locations were not specified). 

In October 2024, Google said it would financially support deployment of seven SMRs from startup Kairos Power that eventually would generate up to 500 MW of output, with a first unit operational by 2030 and additional reactors online within five years. Kairos already has started construction of a demonstration project in Oak Ridge, Tenn. 

For its part, Amazon has invested more than $500 million in SMRs, and took the anchor role in a $500 million funding round supporting SMR developer X-energy. And last fall, Oracle announced it intended to develop data centers powered by SMRs.  

More such announcements are likely to come as the data center industry appetite for new power supplies continues to grow. Data centers are not the only industries showing interest. Among others, utility Energy Northwest and materials science company Dow both have committed to projects using X-energy’s technology, with Dow already having designated a development site in Texas. 

Rare Bipartisan Support in Washington

While the promotion of many energy sources fall into red or blue camps, nuclear generally has managed to remain purple. In 2024, Congress passed the strongly bipartisan Accelerating Deployment of Versatile, Advanced Nuclear for Clean Energy (ADVANCE) Act, which specifically seeks to promote advanced reactor technologies. 

In addition, the U.S. Department of Energy has provided significant financial support, including a $900 million effort that began during the Biden administration to accelerate the development and deployment of SMRs. In August, DOE selected 11 advanced reactor projects for accelerated deployment, streamlined testing and fast-tracking toward commercialization. 

A Nuclear Renaissance Won’t Happen Unless Certain Conditions are Met

Major challenges remain to be addressed before we can proclaim the nuclear industry as reborn. The thorny nuclear waste issue remains to be solved. So does the issue of security. It’s one thing to guard the 50+ nuclear sites operating today and quite another to secure hundreds of them. There also are the siting challenges and the problem of convincing neighbors to accept these plants in their communities. Nuclear sites also will face the same interconnection challenges that have bedeviled any other generating assets connecting to the grid.  

Perhaps most critically, though, these new nuclear plants will need to be cost-competitive. Manufacturers will have to build the manufacturing facilities to make all the parts and entice enough firm orders to create the necessary economies of scale. It will not be enough for companies to build these new nuclear reactors in the single digits. The winners in this race likely will need to build dozens of them to get the costs down to where they can become competitive with other sources of generation.  

It’s one thing to do that with solar modules or batteries, where global supply chains wring out inefficiencies through production of literarily hundreds of millions of the devices. It’s quite another to create such efficiencies in a new industry, in which there are many competing companies and technologies.  

To succeed, the infant industry will have to migrate from one-off projects to a broad-based, factory-centered production approach, enjoying a large and predictable order book. It also will need to nurture the necessary talent to manufacture, site and operate the plants in the field. We’re not remotely there yet, but for fans of a nuclear renaissance, recent events offer encouraging signs. 

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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CEC Awards $28M for New Battery Facility in Hayward

The California Energy Commission approved a $28 million grant to Electrochemistry Foundry to build and operate a battery fabrication and testing facility in Hayward, Calif. 

The 20,000-square-foot facility will be “shared-use” and able to produce 10,000 lithium-ion battery cells per year. 

California does not have open-access battery manufacturing facilities, the CEC said in the grant award. Without these types of facilities, startups face “long delays and steep cost barriers that cause many promising battery innovations — especially in underserved sectors like heavy-duty transportation, industrial electrification and stationary storage — to stall before reaching the market,” the agency said. 

Most shared battery testing facilities are thousands of miles away in the Midwest, South or East Coast, Electrochemistry Foundry representatives said. Building such facilities within a one-hour drive of people who use them is ideal and ensures maximum ease of access and collaboration, they said. 

“Early-stage startups cannot justify leasing their own dedicated facilities, and most startups currently can only access fractional lab space from biotech facilities, which are not well-suited for supporting battery and electrochemical companies,” Electrochemistry Foundry representatives said. 

However, Barry Broome, CEO of the Greater Sacramento Economic Council (GSEC), asked the CEC to defer approval of the item and require an outside audit of the award process that granted the project to Electrochemistry Foundry. 

GSEC founded Cal EPIC, a nonprofit that finished second in the CEC’s grant award process, behind Electrochemistry Foundry. GSEC is a public-private partnership that connects business and community leaders to build a regional economic development strategy that focuses on growth, sustainability, equity and competitiveness, the organization says on its website. 

“Given our engagement with the CEC and others during this grant process, we have serious concerns as to the fairness of the solicitation development and award decision and transparency of the communications and processes surrounding them,” Broome said in a Sept. 9 statement. 

“This [battery facility] is a critical asset to our community. … And, you know, in this era of transparency in government, we’re counting on our government to set the tone for that, since it’s been lost throughout the country,” Broome said at the CEC’s Sept. 10 business meeting. “This location has unique advantages that we thought were missed in the [grant award] scoring.” 

VGI Grants, REC Software Changes

At the meeting, the CEC also approved about $15.4 million in grants to nine entities related to Vehicle-Grid Integration (VGI) work. Grants included about $2.4 million to Rivian to build an alternating current bidirectional charging system and $2.7 million to Lucid Group to build an alternating current bidirectional onboard charging system. 

Also at the meeting, representatives of the Western Electricity Coordinating Council (WECC) told CEC commissioners they are working to find new software for the Western Renewable Energy Generation Information System (WREGIS), which tracks renewable energy certificates predominantly in the Western Interconnection. 

WREGIS operates using software provided by CleanCounts, but the organizations’ contract expires Dec. 31, 2027, and CleanCounts has chosen not to extend it, WECC staff said. The contract’s expiration has prompted reevaluation of how WREGIS’s future looks and how its services to users and programs can be enhanced, they said. 

To replace CleanCounts, WECC staff recommend building custom software for WREGIS. They also recommend separating WREGIS from WECC, which would allow the owners of WREGIS to focus solely on the program’s goals. 

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SPP Clears GI Queue Backlog, Ready for New Process

SPP says it has cleared its backlog of generator interconnection requests that dates back to 2018, paving the way for a transition to its “first-in-the-country” Consolidated Planning Process.

The grid operator said in a news release that the six study clusters through 2023 have all reached the restudy phase. Each request in the clusters has completed the two-part study phase and is either signing GI agreements, moving into GIA negotiations or undergoing a restudy, an SPP spokesperson told RTO Insider.

“SPP’s interconnection customers deserve an efficient study process to enable their proposed generator projects,” Jennifer Swierczek, the RTO’s manager of generation interconnection policy and study, said in a statement.

SPP said efficient interconnection studies are critical and give developers and utilities the cost certainty and regulatory approvals needed when energy demand is rising.

Staff have completed 24 cluster studies since 2022, analyzing 340 GW of generation — six times SPP’s peak load — and evaluating 1,652 projects through its definitive interconnection system impact studies (DISIS).

The work has resulted in 190 signed GIAs for more than 30 GW of generation. Another 20 GW of additional generation is expected to execute GIAs in the next 12 months, the RTO said.

According to SPP’s GI queue dashboard, 191 active requests from the backlog remain in the GI queue. The 2024 study cluster, which has not yet gone through DISIS, includes 345 requests for about 90 GW of capacity.

SPP began tackling the backlog in 2022 with the 2018 cluster. The queue contained 1,139 active requests for 221 GW of capacity at the time; it now has 552 active requests for 130.5 GW of capacity. (See “SPP Modifies GI Backlog Process,” SPP Markets & Operations Policy Committee Briefs: Oct. 15-16, 2024.)

The grid operator’s board, state regulators and members approved the CPP in July and August. It replaces the current sequential planning and GI studies that have led to an average of six-year wait times before resources go into service.

The new process includes a long-term 20-year study and an annual 10-year assessment, aligning system modeling, planning assumptions and cost allocation across load and generation needs. The CPP-10 includes a GI capability study, a GI decision point and a regional transmission assessment that recommends projects for construction. The CPP-20 establishes a 20-year regional vision. (See SPP Celebrates Novel Consolidated Planning Process.)

Staff will be able to use the process once it has FERC approval, significantly accelerating the addition of new generating resources to the grid. SPP has said it plans to file the tariff change with the commission by October and will request an effective date of March 1, 2026.

Full implementation will begin in 2027, and the first CPP portfolios are expected to be delivered in 2028. Transitional work will bridge the gap between the CPP framework and the current study process for the 2026 and 2027 assessments.

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PJM Stakeholders Endorse Expansion of Provisional Interconnection Service

The Planning Committee voted to endorse a PJM quick fix proposal to expand provisional interconnection service to allow resources that are not fully deliverable to enter service as energy-only resources. The quick fix process allows an issue charge and corresponding proposal to be voted on concurrently. (See “1st Read on Expanded Provisional Interconnection Service,” PJM MRC/MC Briefs: Aug. 20, 2025.)

PJM Director of Interconnection Planning Donnie Bielak said the proposal is intended to allow resources to begin operations while their requisite network upgrades are proceeding, making more energy available to dispatchers going into emergency conditions. As of the Sept. 9 PC meeting, he said more emergency conditions had been declared in 2025 than in the previous decade combined, a trend he said is likely to continue with rising load growth and limited new generation.

Provisional interconnection service allows a planned resource to enter service before the network upgrades assigned to it have been completed only if an interim deliverability study determines it can reach its full output without triggering transmission violations. The proposal would loosen that standard to grant provisional status if a resource can deliver part of its installed capacity, which would be documented in an operational guide to inform dispatchers about how the unit can be operated. It targets provisional service requests for the 2026/27 delivery year; any agreements it awards would need to be renewed by developers with annual interim deliverability studies until the resource enters full service.

The quick fix proposal focuses on expanding the pathway for developers to apply, and pay, for PJM to study a planned resource for provisional service. A separate issue charge endorsed by the PC will explore a process for PJM to proactively identify projects that might quality for provisional service without slowing the overall interconnection study process.

The longer-term issue charge envisions a 10-month stakeholder effort charging the Interconnection Process Subcommittee with identifying possible changes to the tariff and business manuals. The out-of-scope section includes generation that does not fall under FERC jurisdiction, the requirements for resources to participate in the capacity market, and changes to the interconnection process not pertaining to provisional service.

Bielak said the proposed manual language was amended after the August first read to state that PJM will publish the provisional interconnection service offered to resources to allow market participants to have the same insight on the status of the transmission grid. Additional language was added around how the resources would be dispatched to clarify they won’t receive special treatment.

“The existing procedures under these operations will prevail, and these will be treated like any other energy-only resource,” Bielak told the PC.

Paul Sotkiewicz, president of E-Cubed Policy Associates, argued PJM should post all requests for provisional service, stating it could inform market participants’ hedging strategies. He said the manual language detailing the information about service requests and awards PJM would post should explicitly specify attributes like the output resource owners seek to inject.

Bielak questioned the value that information would provide and said he prefers more generic language to avoid situations where changes to the posting requirements for the overall interconnection process might fall out of sync with the provisional pathway.

Gregory Pakela, manager of regulatory affairs for DTE Energy Trading, said the data Bielak presented shows the bulk of emergency procedures have been initiated during the summer, suggesting reliability risk corresponds to load peaks during heat waves more than PJM’s winter-skewed risk modeling would suggest.

“We have to treat models as tools, but the interpretation of those models is almost more of an art,” he said.

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ISO-NE Faces Criticism over Accountability, DER Policy at Public Meeting

Several panelists and public commenters at the quarterly meeting of the ISO-NE Consumer Liaison Group criticized the RTO over its record on accountability and accessibility, as well as its policy related to distributed energy resources.

The tenor of CLG meetings has been critical of ISO-NE since a coalition of climate activists took control of the group’s coordinating committee in 2022. (See Climate Activists Take Over Small Piece of ISO-NE.) Many of the same themes and critiques from past CLG meetings resurfaced as the group met in Manchester, N.H., on Sept. 11 for its third-quarter meeting.

Marla Marcum, an activist associated with the climate group No Coal No Gas, criticized the closed nature of NEPOOL stakeholder proceedings. She said grassroots climate activists are interested in engaging in discussions around ISO-NE’s ongoing overhaul of its capacity market but are prevented from meaningfully participating in discussions because they are not members of NEPOOL. (See ISO-NE Kicks off Talks on Accreditation, Seasonal Capacity Changes),

Responding to the criticism, Anne George, ISO-NE’s chief external affairs and communications officer, said all materials and minutes from stakeholder meetings are posted publicly, and members of the public are welcome to submit input for review by the RTO’s market development team.

“The ability for us to throw our comments into the whirlwind, no matter how good they are, is not the same as being able to meaningfully participate in this process,” Marcum responded.

Meanwhile, New Hampshire Consumer Advocate Don Kreis repeated his past criticisms of the RTO for being incorporated in Delaware, arguing that it would be more accountable to ratepayers in the region if it was incorporated in New England.

The meeting also featured a panel on how ISO-NE can help address energy affordability. Several panelists urged the RTO to do more to help demand response and DERs participate in its markets.

Allison Bates Wannop, a lawyer and DER advocate with experience working in all U.S. RTOs, said she has “found ISO-NE to have a preference for not enabling distributed energy resources.”

While she praised the work of ISO-NE staff, she said the RTO generally appears “distrustful” of DER aggregators and has been overly conservative in its compliance with FERC Order 2222, which requires RTOs to lower barriers to DER aggregators to participate in wholesale markets.

Bates Wannop highlighted FERC Commissioner Allison Clements’ concurrence on FERC’s ruling on ISO-NE’s original Order 2222 compliance proposal, in which Clements strongly criticized the RTO for putting forward “a proposal that was almost universally panned by prospective market participants seeking to integrate behind-the-meter resources into its markets.” (See FERC Gives ISO-NE Homework on Order 2222.)

Clements wrote in her concurrence that ISO-NE’s submetering proposal for DER aggregations is significantly more burdensome for aggregators than the proposals of other RTOs, adding that ISO-NE’s unique circumstances do not “necessarily provide an excuse for not adopting an approach similarly to those successfully pursued elsewhere.”

Also during the panel, Kreis asked speakers about a recently passed bill directing the New Hampshire Department of Energy to study the possibility of withdrawing from ISO-NE. Multiple speakers expressed hope that the study would allow for a constructive look at improving the RTO.

However, several speakers expressed skepticism about the viability of leaving ISO-NE, along with the benefits this move would have for New Hampshire consumers.

Henry Herndon, acting general manager of the Community Power Coalition of New Hampshire, said the bill poses an “interesting opportunity to ask questions.”

Bates Wannop said that “while I don’t think New Hampshire should leave ISO-NE, I think constantly asking the question how it can be reformed is important.”

Imagining an Ideal RTO

Also at the CLG meeting, Ari Peskoe, director of the Electricity Law Initiative at Harvard Law School, delivered a keynote speech centered around imagining an ideal grid operator for the region, unincumbered by history, compromises and agreements that have led to the current structures and roles of ISO-NE and NEPOOL.

“ISO-NE’s governance is tied to the peculiar history of New England utilities, rather than any particular attributes,” he said.

Peskoe noted that, due to the history of ISO-NE’s formation, New England transmission owners participate in ISO-NE voluntarily and retain filing rights over the revenue requirements for their own system. Meanwhile, candidates for the ISO-NE board of directors are nominated by a committee made up of current board members and NEPOOL participants and are approved by the NEPOOL Participants Committee and the board.

If the region was starting from scratch, Peskoe said, it still would be beneficial to have some form of nonprofit regional entity to ensure cost and operational efficiency across the region’s grid, but he would like to see greater independence from market participants and a stronger emphasis on innovation.

While the hypothetical, redesigned RTO would remain a non-regulatory independent entity, Peskoe said the states could take on a larger role. He floated the idea of allowing each governor to nominate one non-state employee candidate to the board.

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EPA Moves to End Greenhouse Gas Reporting Program

The U.S. EPA is moving to end greenhouse gas emissions reporting requirements for electricity generators and dozens of other industrial sources. 

EPA Administrator Lee Zeldin announced the proposal Sept. 12, saying the reporting is not mandated under the Clean Air Act, has no bearing on the environment or public health, and imposes hundreds of millions of dollars a year in compliance costs on American businesses. 

Eliminating the requirement will help streamline operations, unleash American energy and advance EPA’s core mission of protecting human health and the environment, he said. 

More than 8,000 facilities and suppliers in 47 source categories are subject to the requirements of the Greenhouse Gas Reporting Program. 

The move was not unexpected. Zeldin announced March 12 that EPA was reconsidering the program. 

It is the latest of many attempts to roll back regulations and protections, and it fits with the Trump administration’s skepticism regarding global climate change. 

“It costs American businesses and manufacturing billions of dollars, driving up the cost of living, jeopardizing our nation’s prosperity and hurting American communities,” Zeldin said Sept. 12. “With this proposal, we show once again that fulfilling EPA’s statutory obligations and Powering the Great American Comeback is not a binary choice.” 

Environmental advocates expressed dismay and vowed to fight. 

The Sierra Club countered that the program was in fact fully authorized under the Clean Air Act and said: “EPA cannot avoid the climate crisis by simply burying its head in the sand as it baselessly cuts off its main source of greenhouse gas emissions data.” 

The Environmental Defense Fund said it would fight the move because “the information shows the sources and scale of pollution that causes climate change, including from oil and gas facilities, landfills, and power plants, allowing for better decisions about how to address that pollution. The Greenhouse Gas Reporting Program allows us to create policies that make life safer, healthier and more affordable for all Americans.” 

The proposed amendments to the Greenhouse Gas Reporting Program run 114 pages. EPA will accept comments for 47 days after it is published in the Federal Register. 

EPA indicated in a fact sheet that it is proposing to permanently remove reporting requirements for 46 source categories because there is no statutory requirement for it to collect that data except for petroleum and natural gas emitters in Subpart W subject to the Waste Emissions Charge. 

(Subpart W is being undercut as well: EPA proposes to halt reporting for one of the 10 industry segments and suspend reporting for the other nine until 2034, as directed by the One Big Beautiful Bill Act.) 

EPA estimates the proposal will save businesses $303 million a year through 2033. That breaks down to $256 million for Subpart W sources and $47 million for the other 46 sources. 

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Pathways Bill Passes Calif. Legislature in Lopsided Votes

California lawmakers have passed a landmark bill that will allow CAISO to transition the governance of its markets to the independent “regional organization” envisioned by the West-Wide Governance Pathways Initiative.

With little discussion and no debate, Assembly Bill 825 on Sept. 13 passed the state Senate on a 34-0 vote, followed by a 67-2 approval in the Assembly. Days before the vote, backers of the recently revised bill had expressed confidence the measure would fly through both houses after the initial Pathways bill stalled in the Assembly in July.

AB 825 will implement the Pathways Initiative’s “Step 2” plan to create a regional organization (RO) to oversee CAISO’s Western Energy Imbalance Market and soon-to-be-launched Extended Day-Ahead Market — and authorize the ISO and California’s investor-owned utilities to participate in the RO. (See Pathways Initiative Approves ‘Step 2’ Plan, Wins $1M in Federal Funding.)

“Some doubted if we’d ever get here, but we landed in a great place,” bill co-sponsor Sen. Josh Becker (D) told his colleagues ahead of the Senate floor vote.

Referring to the previous three failed efforts — over 2016 to 2018 — to pass legislation to “regionalize” CAISO into a Western RTO, Becker said AB 825 “enables something that’s been a decade in the making: a Western energy market.”

“This is a pivotal moment for California, and we have an opportunity to make energy in the state of California cheaper, cleaner and more reliable,” co-sponsor Assemblymember Cottie Petrie-Norris (D) said before the Assembly vote.

Becker and Petrie-Norris both played up the affordability angle of the bill, pointing to a January Brattle Group study showing California ratepayers stand to save about $790 million a year if the state were to participate in an “expanded EDAM” that consists of most of the West. The study showed those savings will be more modest, though still significant, in a more likely scenario in which the EDAM shares the region with SPP’s competing Markets+ offering. (See Brattle Study Shows Big Benefits for California in ‘Expanded’ EDAM.)

Previous efforts to regionalize CAISO failed in large part due to the opposition of powerful labor interests — namely the International Brotherhood of Electric Workers — concerned about the impact of such a change on the buildout of renewable resources in the state. But this time around, labor, along with California’s publicly owned utilities, became key supporters of the Pathways Initiative, along with clean energy and environmental groups, who see a broader Western market as a way for all participants to tap increased amounts of renewable energy through geographical diversity.

AB 825 also had bipartisan support in California’s overwhelmingly Democratic state legislature.

“I think most of the stuff we’re doing today will make life less affordable to Californians, but this is one bill that will make life more affordable for Californians,” Republican Sen. Tony Strickland said before the Senate vote. “Expanding our energy markets to include other Western states will help us lower our costs for energy, and that is good for the people of California.”

Petrie-Norris pointed to the estimated $7 billion California utilities have saved from their participation in the WEIM over the past 10 years.

“And this expanded, day-ahead market has even more potential for optimizing costs,” she said. “The reliability benefits of this proposal are just common sense. As we move toward more weather-dependent renewables powering our grid, we need to ensure that we have a grid that is bigger than the weather. So with this proposal, the wider market will make it easier for California to rely on excess solar from Arizona or wind from Wyoming.”

Renewed Support

Passage of the bill in its current form was the product of considerable last-minute maneuvering in the legislature, partly orchestrated — or enforced — by Gov. Gavin Newsom (D), according to sources close to the process.

The original vehicle for the “Pathways” legislation during the 2025 session was Senate Bill 540, sponsored by Democratic Sens. Josh Becker and Henry Stern. SB 540 passed the Senate in early July on a 39-0 vote after picking up a set of controversial amendments.

Those additions prompted some of the original bill’s strongest backers to pull their support, causing the bill to stall in the Assembly. They particularly objected to a provision that would have authorized a new Regional Energy Market Oversight Council to force CAISO and the state’s IOUs to withdraw from the regional market if it found participation no longer served the interests of the state. (See Calif. Pathways Bill Delayed After Orgs Withdraw Support, While Newsom Signals Backing for Effort.)

Sen. Josh Becker shepherded the Pathways bill through the California legislature during the 2025 session. | Office of Sen. Josh Becker

But just as the session was drawing to a close, the Pathways effort was given new life in the 11th hour after lawmakers from both houses worked behind the scenes to strip out the controversial provisions added to SB 540, then shifted the contents into AB 825, originally an “energy affordability” bill that already had passed the Assembly and was poised for a Senate vote before the legislature was scheduled to go into recess on Sept. 12. (See Calif. Pathways Legislation Poised for Passage After Being Shifted into New Bill.)

While the new bill still gives California an out from participating in the RO, its contents largely align with the principles and plans set out by the Pathways Initiative. With that, the backers who’d pulled their support renewed their calls for passage of the bill.

Some of those supporters were first out the door to celebrate passage of AB 825.

“Today’s vote sends a message to the West. California will be part of a fast-moving revolution in how electricity will be bought and sold across the region,” Katelyn Roedner Sutter, California state director at the Environmental Defense Fund, said in a statement. “Despite delays, California lawmakers have committed to regional action that will help deliver a clean, affordable energy future.”

“This is a pivotal moment for the West, demonstrating California’s commitment to regional collaboration and ensuring all states’ voices will be represented,” Leah Rubin Shen, managing director at Advanced Energy United, said. “The broad geographic footprint enabled by this legislation will provide the greatest economic benefits, improve affordability for consumers and support a more resilient future for the whole region.”

The Northwest Energy Coalition (NWEC) said passage of the bill “has addressed the primary concern cited by the Bonneville Power Administration (BPA) when it chose Markets+” over EDAM in May: the CAISO market’s lack of independent governance. (See BPA Chooses Markets+ over EDAM.)

“This legislation is a fundamental change to the governance of EDAM and makes BPA’s choice to prioritize joining Markets+ over reducing energy costs for the region even more questionable,” NWEC’s Ben Otto said in press release. “We continue to urge BPA to reassess its decision, particularly in light of this fundamental change to the market options. BPA can still change course and choose the better energy market for Northwest customers.”

Seattle City Light, a BPA preference customer that has strongly urged the agency to join EDAM rather than Markets+, said it “applauds the passage of AB 825 (formerly SB 540) as an important step toward establishing an independent, West-wide regional market.”

This legislation reflects strong leadership and thoughtful engagement with stakeholders across the West, laying the foundation for a robust independent governance structure that will ensure reliable, affordable and clean energy outcomes for customers,” the utility said. “Building on the success of CAISO’s market services, AB 825 creates the opportunity for market participants across the west to collaborate and deliver the best results for the communities and customers we serve.”

BPA called the passage of AB 825 “a positive development toward a more equitable market landscape in the West,” but defended its decision to join Markets+.

“While Bonneville participated in the development of several important provisions in the Pathways Initiative – like broader stakeholder engagement and the assurances for public purposes – BPA has been and remains clear in its desire to participate in a market wholly separate from the authority of any single state or entity,” BPA said.

“Markets+ offers the independent management and governance that Bonneville seeks and meets the needs of our customers. It also offers advantages in market design such as support for a regional resource adequacy platform and meeting the state policy obligations of its participants,” it said.

CAISO commended the legislature, Newsom “and the diverse coalition of stakeholders for their leadership in advancing this important legislation. This marks a crucial next step toward independent governance of Western electricity markets — a milestone shaped by years of successful and evolving regional collaboration.”

The ISO said it will “coordinate closely” with the Pathways Initiative as it develops the new RO “to ensure alignment with legislative requirements.”

‘Sound Foundation’

The passage of AB 825 unsurprisingly drew praise from those who drove the work of the Pathways Initiative.

“The [Pathways] Launch Committee is excited to see the California Legislature’s passage of AB 825, enabling participation in the new, independent Regional Organization,” Launch Committee co-chairs Kathleen Staks (Western Freedom) and Pam Sporborg (Portland General Electric) said in a statement. “It is a critical step in implementing the work of the Pathways Step 2 proposal and achieving the largest energy market footprint possible resulting in the greatest affordability and reliability benefits for customers. We are looking forward to the incorporation of the new, fully independent Regional Organization in the next few months and seating the initial board.”

“Energy affordability and reliability are top of mind for households across the West”, Oregon Public Utility Commission Chair Letha Tawney said. “The West-Wide Pathways Initiative and AB 825 have created a sound foundation for our work on these critical priorities. I appreciate the thoughtful work of the Launch Committee creating solutions that protect customers in every state.”

“The dedication of the Launch Committee, and those involved from the beginning, deserve a huge round of applause!” Arizona Corporation Commission Chair Kevin Thompson said. “Thank you to the California Legislature for resolving the governance issue of developing a Western day-ahead market with the passage of, and signing of, AB 825. Well done!”

“Commissioners across the West are working to ensure as many options as possible exist to enable affordable, reliable power. The West-Wide Pathways Initiative is an example of what we are doing, [and] passage of AB 825 is an important element of achieving the goal,” New Mexico Public Regulation Commission member Pat O’Connell said.

“The passage of AB 825 is a significant step to improve electric reliability and affordability in the West,” California Public Utilities Commission President Alice Reynolds said. “This achievement was the result of the extraordinary efforts the Pathways Launch Committee and a broad array of stakeholders across the West. I am grateful for everyone’s contributions”

All four utility commissioners were signatories to the letter that launched the Pathways Initiative in July 2023. (See Regulators Propose New Independent Western RTO.)

The bill now goes to Gov. Newsom’s desk.

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BOEM Seeks to Vacate Maryland Offshore Wind Approval

BOEM is formally seeking to vacate approval of the US Wind project off the Maryland coast, saying it made errors in granting the approval. 

The move is the latest in the campaign against offshore wind power development that President Donald Trump initiated hours after the start of his second term in January. 

Along with erecting a series of new regulatory barriers to future projects, the Trump administration has moved to impede existing projects in advanced development or actual construction. 

It issued stop-work orders against Empire Wind and Revolution Wind, two projects in active construction; remanded the air quality permit for Atlantic Shores; and most recently indicated it would seek to remand Biden-era construction and operations plan (COP) approvals for New England Wind, SouthCoast Wind and US Wind. (See Interior Reconsidering Approval of Two OSW Projects and BOEM Plans to Vacate New England Wind Project Approval.) 

The three COP remands are sought as part of lawsuits that offshore wind opponents filed against federal agencies seeking to invalidate their approvals of the three projects. 

In the US Wind case in U.S. District Court in Maryland (1:24-cv-03111), elected leaders of Ocean City, Md., and others are trying to prevent construction of wind turbines with as much as 2.2 GW of nameplate capacity as close as 10 nautical miles from the popular vacation destination. 

On Sept. 12, the Bureau of Ocean Energy Management asked the court to remand and vacate its approval of the COP for the Maryland project. BOEM said its desire to reconsider the approval is by itself sufficient reason to grant remand, and BOEM’s identification of an error in the approval process justifies vacating the approval. 

BOEM also asks the court to dismiss the lawsuit if it grants the motion to vacate approval, as the lawsuit would be moot. If only remand is granted, BOEM asks the court to place the lawsuit on hold for the duration of the remand. 

There was no real suspense about the Sept. 12 filing: BOEM had indicated in an Aug. 25 filing that it would make such a motion no later than Sept. 12. 

US Wind struck back first. 

On Sept. 3, it countersued the Department of the Interior and other defendants in 1:24-cv-03111, saying the effort to vacate or otherwise undermine the federal agencies’ previous efforts is illegal, factually incorrect and a pretextual means to achieve policy goals. 

It wrote: “The federal defendants’ efforts to vacate and undermine the federal approvals are inextricably tied to a wider plan to hinder or kill outright offshore wind projects (and renewable energy projects more generally) for political purposes, as evidenced by numerous official acts and public statements by federal defendants, various members of the current presidential administration and others within the federal government acting in concert with federal defendants.” 

US Wind is asking the court to declare that federal approvals for its project were lawfully issued, to enjoin the federal defendants from taking any action to undermine any of the approvals, and to award legal fees and costs. 

In its Sept. 12 motion, BOEM faults its prior assessment of factors in Title 43 Section 1337(p)(4) of the U.S. Code, which pertains to commercial activity on the Outer Continental Shelf. 

As examples, BOEM said it now feels it underestimated the effect the offshore wind farm would have on helicopter search and rescue operations and said its impact on commercial fisheries may not be sufficiently mitigated under terms of the COP. 

BOEM brushed aside US Wind’s objections: “US Wind may be concerned that BOEM will make a different decision than its prior COP approval, but those concerns are speculative and unripe.” 

BOEM also said offshore construction still is months or years away, so it would not be disruptive for the court to vacate the COP approval. 

Later Sept. 12, the Oceantic Network criticized BOEM’s motion: “Today’s news is yet another targeted action against American energy. The unlawful actions by the Trump administration against fully permitted offshore wind projects up and down the East Coast represent one of the largest, economically devastating assaults on U.S. workers, businesses and energy in decades. Revoking a permit on an approved project after years of thorough agency review will raise electricity prices for families, jeopardize private investment, delay economic growth and weaken our power grid.” 

The Maryland Offshore Wind project dates to an Aug. 19, 2014, auction of what now is OCS-A 0490. BOEM issued a record of decision in favor of the project in September 2024 and approved the COP in December 2024. 

The first two phases of the project — the 300-MW MarWin and the 800-MW Momentum Wind — hold offshore renewable energy certificate agreements with Maryland. 

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Texas PUC Approves Entergy Gas Plants, Caps Costs

Texas regulators have approved Entergy Texas’ request to build two natural gas-fired generating units in MISO’s portion of the state, but they limited the construction costs eligible for recovery to a combined $2.4 billion.

Thomas Gleeson, the Public Utility Commission’s chair, filed a memo Sept. 10 outlining his proposal to protect ratepayers from “bearing the burden of … potentially higher costs” during construction. In doing so, Gleeson rejected an administrative law judge’s recommendation to deny Entergy’s application (56693).

“I think the proper thing to do on the cost cap is to impose a hard cost cap of $2.4 billion,” he said during the PUC’s Sept. 11 open meeting.

The ALJ found in June that, while all parties agreed Entergy had shown a “significant near-term need” for additional capacity, it had not demonstrated the two gas units were a cost-effective alternative to meet that need. The judge recommended Entergy’s application be denied as it did not meet its burden of proof.

However, the judge said also that Entergy had demonstrated an “imminent” need for additional capacity as early as 2028, leaving little time to secure different resources. It said the PUC could approve Entergy’s Dispatchable Portfolio, as it has been labeled, but that it should impose certain conditions of cost recovery.

The PUC applied conditions in the order requiring weatherization and permit approval for future implementation of hydrogen operations and carbon capture and storage.

Entergy Texas filed an application for approval to build the two plants in June 2024, saying they were part of the company’s “urgent need” to add 40% more generation capacity in four years in the face of “extraordinary” economic and population growth in Southeast Texas.

“We’ve heard directly from our customers and communities about the need for more power to support our rapidly growing region, and these facilities will deliver just that,” Entergy Texas CEO Eliecer Viamontes said in a statement.

The plants will be capable of providing 1,207 MW of energy and will generate a combined $2.74 billion in regional economic activity during construction, Entergy said. The company said the units are expected to be in service by 2028.

Rendering of Entergy’s proposed Legend Power Station and Lone Star Power Station | Entergy Corp.

Legend Power Station, near Port Arthur in southeast Texas, is a 754-MW combined cycle turbine facility. It will be carbon capture-enabled and feature a hydrogen-capable combustion turbine.

Lone Star Power Station is a 453-MW hydrogen-capable combustion turbine facility near Cleveland, northeast of Houston.

Under the terms of the PUC’s approval, Legend will be limited to $1.6 billion and Lone Star to $799 million in recoverable costs.

An Entergy Texas spokesperson said both projects have been accepted into MISO’s new Expedited Resource Addition Study process (ERAS). “We expect their generator interconnection agreements to be available next year,” she said.

However, the projects do not appear on the list of 10 finalists to enter the first ERAS cycle. MISO plans to accept another round of applications for a second cycle in early November and begin studies in December. (See MISO Selects 10 Gen Proposals at 5.3 GW in 1st Expedited Queue Class.)

Legend and Lone Star are part of Entergy Texas’ Southeast Texas Energy Plan, also known as STEP Ahead. The six-step plan aims to add 1,600 MW of capacity to the grid by 2028 along with transmission and grid-hardening projects.

Commissioner Kathleen Jackson agreed with Gleeson in the 2-0 decision. Commissioner Courtney Hjaltman recused herself from the discussion and vote.

Mobile Gens Synchronized

ERCOT legal staff told the commission that CPS Energy and LifeCycle Power have interconnected eight of the 15 mobile generators that have been moved from Houston to San Antonio to address a transmission constraint.

Nathan Bigbee said the remaining units are expected to be synchronized and available for ERCOT’s dispatch by mid-October, two months later than originally planned. All 15 30-MW units will be dispatched only during emergency conditions through March 2027.

The units originally were leased from LifeCycle Power by CenterPoint Energy in Houston. ERCOT says the generators are necessary to mitigate emergency load-shed that may be necessary to avoid overloads of a generic transmission constraint. It became apparent in February that the grid operator would not be able to extend reliability-must-run agreements to two aging CPS gas-fired units. (See ERCOT Board OKs Mobile Generators in San Antonio.)

ESRs as ‘Stand-alone’ Resources

Commission staff recommended that energy storage resources (ESRs) be included in the PUC’s first proposed rulemaking on net metering arrangements involving a large load co-located with an existing generation resource (58479).

Legislation passed during the 2025 biennial session requires ERCOT to study the system impacts of net metering arrangements involving “stand-alone” resources as of Sept. 1, 2025, and new large-load customers. On Sept. 2, staff posted a market notice that included an attachment listing the types of stand-alone resources.

Bigbee said he found “near-universal” support for including ESRs during a Sept. 2 workshop on net metering.

“We believe that’s a defensible approach as well,” he said. “So, if it’s the commission’s will, we’d be happy to include them on the list.”

The commission will discuss the proposed rulemaking at its Sept. 18 open meeting.

The PUC also:

    • Remanded back to docket management a revised order on CenterPoint’s system resiliency plan. In a memo, Hjaltman said the utility’s proposed transition from a five-year to a three-year vegetation management trimming cycle lacked key information supporting cost recovery. She requested supplemental evidence to justify the plan’s approval and a proposed cost-recovery mechanism. An ALJ filed the revised order in July (57579).
    • Delayed action on Entergy Texas’ proposed 500-kV single-circuit transmission line in Northeast Texas. The 150-mile line has drawn opposition from local landowners, who requested a rehearing of the State Office of Administrative Hearings’ decision to recommend a certificate of convenience and necessity for the line. The project’s various routes range from 131 to 160 miles and its costs are projected to be between $1.33 billion and $1.52 billion (57648).
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E-ISAC Updates NERC Committee on GridEx VIII Scenario

GridEx VIII, a security exercise, will see changes both visible and behind the scenes that are designed to match real-world developments in the past two years, an official with the Electricity Information Sharing and Analysis Center (E-ISAC) told members of NERC’s Reliability and Security Technical Committee. 

Speaking at the RSTC’s quarterly meeting Sept. 11, GridEx Program Manager Jesse Sythe outlined some of the updates to the biennial training event scheduled for Nov. 18-19. These include new participation options for the distributed play portion: In addition to the traditional full-scale exercise, participants can choose a simplified “GridEx-in-a-box” option designed for smaller planning teams and organizations new to the exercise, or a streamlined “tabletop” scenario for entities unable to participate in a real-time program. 

All three participation options will be based on the same scenario, Sythe said, and will involve physical and cybersecurity threats to grid infrastructure inspired by real-world events. While he did not provide the full scenario, he said it will involve climate change impacts such as wildfires and heat domes, along with attacks coinciding with a major world sporting event. This element was added in light of the 2026 FIFA World Cup and 2028 Summer Olympic games, both of which will be held in the U.S. 

Planners also have incorporated new tools for the scenario, including a new social media and news simulation tool, ATSsim Media, to provide a smoother and more realistic experience for participants. The new tool incorporates social media bots to “create some noise and … background chatter” that might be heard during a real security event. 

Like GridEx VII, the scenario timeline comprises four separate “moves”: the first four hours of the event (move 1), hours 4-8 (move 2), hours 24-28 (move 3) and a week after the main action (move 4). This element debuted in GridEx VII, and planners decided to bring it back based on favorable participant reactions. 

“Folks seemed to really like that; [it] lets you look through recovery a little more in depth than we have in previous GridExes and shift to more of a discussion-based exercise for that final phase,” Sythe said. 

Committee to Post EV White Paper

Committee members unanimously voted to approve a paper submitted by the RSTC’s Electric Vehicle Task Force outlining “potential risks and benefits of integrating EVs with the grid.” 

As EVTF Vice Chair Syed Ali reminded attendees, the group submitted a draft of the paper at the committee’s June meeting for a 45-day comment period. (See NERC RSTC Tackles Priority Projects in Quarterly Meeting.) The final draft was updated to take the committee’s feedback into account and to address “policy impacts” on the EV industry. 

The highest-priority risks identified in the paper include difficulty in forecasting EV characteristics, a lack of available charging profiles, inability of current models to represent charging and discharging behavior, inadequate studies of the impact of EVs on the grid, and lack of information sharing among manufacturers, utilities and end-use customers. Ali said the EVTF’s next product will be mitigations for these and other risks. 

Members also approved a reliability guideline submitted by the System Planning Impacts from Distributed Energy Resources Working Group (SPIDERWG) addressing the impact of DERs on underfrequency load shedding program design. As part of its triennial review process, SPIDERWG determined the document remained applicable, effective and useful to registered entities in addressing risks. The new guideline includes “minimal revisions … based on SPIDERWG’s review and comments” from industry after a 45-day comment period earlier in 2025. 

Finally, members agreed to post another guideline relating to the commissioning of inverter-based resources for a 45-day comment period, and to accept for internal comment a paper on the ability of current standards and engineering practices to address emerging large loads. The paper will be ready for comment in late September or early October, NERC Engineer for Power Systems Modeling and Analysis Jack Gibfried said.