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December 23, 2025

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MISO Stakeholders Request Theoretical 2025/26 Auction Clearing Sans Sloped Curve

Stakeholders continue to ask MISO to crunch hypothetical auction clearing prices absent the RTO’s new sloped demand curve that sent prices past $660/MW-day for summer.  

During a May 21 Resource Adequacy Subcommittee meeting, multiple stakeholders asked MISO staff to publish 2025/26 hypothetical auction clearing prices through a simulation with the old, vertical curve. The exchange led Independent Market Monitor David Patton to chime in to defend MISO’s installment of a sloped demand curve.  

The 2025/26 planning year auction marked the first time MISO used a sloped demand curve, meant to procure more capacity than strictly necessary to meet MISO’s one-day-in-10-years reliability standard. MISO ultimately cleared 137.5 GW, more than the 135.3 GW it designated prior to the auction to meet its one-day-in-10-years reliability standard, at a cost of $666.50/MW-day for the upcoming summer. (See MISO Summer Capacity Prices Shoot to $666.50 in 2025/26 Auction.)  

“Given that we just switched from a vertical demand curve to a sloped demand curve,” it’s appropriate for MISO to show what the clearing would have been with a vertical curve, WEC Energy Group’s Chris Plante said during the meeting.  

WPPI Energy’s Steve Leovy said he failed to see how MISO could claim that its sloped demand curve “enabled MISO to secure more capacity at a significantly lower price,” as the RTO claimed in its presentation. He asked which alternate reality MISO used as a comparison.   

MISO Resource Adequacy Manager Andy Taylor said MISO’s comparison “is not a counterfactual to” the old, vertical demand curve, but a counterfactual to other sloped demand curve designs.  

MISO develops its sloped curves by assessing the value of additional capacity beyond the one-day-in-10-years standard relative to its price. If the cost isn’t too steep, MISO shapes the slopes with the OK to clear extra megawatts.  

MISO said had the auction cleared only to its initial planning reserve margin requirement of 135.2 GW, prices would have been $846/MW-day based on the sloped curve it ultimately used.  

Plante said MISO’s comparison is “very confusing to a casual observer.”  

Clean Grid Alliance’s David Sapper said he didn’t believe MISO’s auction clearing process as described in its business practice manual makes sense. He asked MISO to redraft a process that could be more readily understood. 

Sapper said he also was “dismayed” that FERC Chair Mark Christie, whom he said is consequential in RTOs’ capacity auction changes and “a scholar and a gentleman,” didn’t seem to understand auction clearing processes.  

“He seems to have thrown up his hands that they’re impenetrable,” Sapper said.  

Minnesota Power’s Tom Butz said prices this year “rocketed up to CONE-like values” and it seems they will be there for the foreseeable future. 

But IMM David Patton said, “for the first time,” auction clearing prices in MISO reflected the marginal value of capacity. Patton said the auction clearing an additional 2% in capacity is a good thing despite what stakeholders might think.  

“I know this is a shock with prices being high, but we do find that this is going to set up for a much more reliable system,” he said. Patton said prices should compel utilities and regulators to make more informed decisions in integrated resource plans and selecting resource retirement dates.   

Patton estimated summer prices would have been about $20/MW-day under the old, vertical curve. But he cautioned that hypothetical, low prices aren’t as attractive as they appear.  

“What you should take away from that is: Our previous market was flawed and wouldn’t have produced prices in line with reliability,” Patton said.  

Had inexpensive capacity prices held court for another planning year, Patton said it wouldn’t meet any “fundamental objectives of the capacity market to set prices this way.”  

During the April 29 auction results call, Taylor said had MISO used its vertical curve, the auction would have produced “extreme, very low or very high” pricing outcomes as it has in years past.  

At the time, Clean Grid Alliance’s David Sapper asked if MISO would commit to re-running the auction if it’s discovered the RTO drew on incorrect inputs in its sloped curve. MISO counsel Michael Kessler said it would be “highly unusual” for FERC to order any capacity auction to be rerun.  

The 2025 auction results are poles apart from auction results a decade ago, when Southern Illinois’ Zone 4 clearing price of $150/MW-day sparked concerns that pivotal supplier Dynegy manipulated capacity availability to raise prices. (See FERC Sets Dynegy’s MISO Market Manipulation Case for Hearing.)  

MISO to Allow Resources with Provisional Agreements to Provide Capacity

At the same resource adequacy meeting, MISO said it will take steps to allow resources with provisional generator interconnection agreements (GIAs) to offer capacity in MISO’s seasonal capacity auctions if they can deliver.  

MISO’s tariff expressly prohibits resources with provisional GIAs from participating in capacity auctions. MISO announced it will pursue a turnaround on its longstanding policy and open the auction to the resources with the provisional agreements starting with the 2026 seasonal capacity auction.  

“We would like these resources to participate in the planning resource auction as well, provided they’ve procured deliverability,” Taylor said.  

Taylor said the “current length and state” of MISO’s interconnection queue might have influenced MISO’s rethinking of the nearly complete resources’ ability to furnish capacity.  

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Trump Orders Nuclear Regulatory Acceleration, Streamlining

President Donald Trump moved to speed up nuclear power development May 23 with a series of executive orders designed to ease federal regulations on the sector. 

The measures require the Nuclear Regulatory Commission to issue timely licensing decisions, allow construction on federal lands to serve national and economic security, attempt to re-invigorate the nuclear energy industrial sector and allow for reactor design testing at nuclear laboratories. 

The end goal is to quadruple U.S. nuclear power production by 2050. A shorter-term goal is to have three new experimental reactors online by July 4, 2026. 

Nuclear industry executives spoke appreciatively as they watched the president sign the orders, and advocacy groups not present at the ceremony issued a chorus of supportive comments. 

But others raised concerns about the Trump administration speeding up review of nuclear development and construction, particularly as the industry attempts to pivot from time-tested designs to new and unproven technologies. 

The narrative of commercial nuclear power in the United States is well-known: The nation pioneered the industry and built the largest reactor fleet in the world, then stepped back, completing zero commercial plants for 30 years. The nation’s first new reactors in a generation were completed recently, far behind schedule and at stunningly high cost. 

One after another, Trump and his invited speakers blamed this turn of events on federal over-regulation and said the executive orders would change that. 

“We’re not going to have cost overruns,” Trump said. 

“It’s time for nuclear, and we’re going to do it very big.” 

Reactions

The reporters gathered for the ceremony asked the president two almost cursory questions about the safety of nuclear energy, then quickly switched to tariffs and other topics. 

Trump replied that nuclear generation has become very safe. 

Neither he nor any of the speakers or questioners present drew any correlation between nuclear generation becoming safer at the same time as regulations on it were becoming more strict. 

But others made that connection. 

Edwin Lyman, director of nuclear power safety at the Union of Concerned Scientists, said in a news release: “By fatally compromising the independence and integrity of the NRC, and by encouraging pathways for nuclear deployment that bypass the regulator entirely, the Trump administration is virtually guaranteeing that this country will see a serious accident or other radiological release that will affect the health, safety and livelihoods of millions.” 

Shortly after Trump was inaugurated and began to assert power over independent federal regulators such as the NRC, Allison Macfarlane, the NRC chair from 2012 to 2014, warned in the Bulletin of the Atomic Scientists about the dangers of faster, looser regulation of the next generation of reactors now being designed: “These proponents — some with no experience in operating reactors — want the NRC to trust their simplistic computer models of reactor performance and essentially give them a free pass to deploy their untested technology across the country.” 

But others cheered Trump’s moves. 

Constitution CEO Joe Dominguez was present at the signing ceremony. 

“The problem in the industry has historically been regulatory delay,” he said. “Mr. President, you know this because you’re the best at building big things. Delay in regulations and permitting will absolutely kill you.” 

He also noted “silly questions” by the NRC, such as the investigations into whether new reactors are suitable for a site adjacent to reactors that have been operating safely for decades. Addressing that one line of inquiry has cost Constellation $35 million each in three application processes, he added. 

Jacob DeWitte, CEO of fast reactor developer Oklo, also was present for the signing and said, “Nuclear is a manifestation of energy dominance” and “changing the permitting dynamics is going to help things move faster.” 

ClearPath Action CEO Jeremy Harrell said in a news release: “These executive orders take a whole-of-government approach to move quickly in support of new deployments.” Harrell also called for additional policy and financial support from Congress. 

Nuclear Innovation Alliance CEO Judi Greenwald applauded the Trump administration’s goals with the orders but raised concerns about some parallel actions: “Adequate staffing and funding are required for these goals to be met. Recent DOE staffing reductions and proposed budget cuts undermine the department’s efforts and make it harder to implement these executive orders.” 

Greenwald added that the alliance has long thought the NRC needed to be more efficient, but sees it making significant progress and feels it important this not be undermined by staff cuts or conflicting directives: “NRC effectiveness, efficiency and independence are critical to the public, the industry and potential customers of U.S. nuclear technology both here and abroad.” 

The Orders

President Trump signed five executive orders May 23, four of them pertaining directly to nuclear energy and the fifth requiring federal research agencies to conform to Gold Standard scientific practices. 

The nuclear executive orders are lengthy and detailed. 

The NRC order, for example, specifies: 

    • reorganization and staff cuts, including a reduction in personnel and functions of the Advisory Committee on Reactor Safeguards; 
    • wholesale revision of NRC regulations and guidance; 
    • adoption of fixed deadlines; 
    • an expedited pathway for approval of reactors already tested by the departments of Defense or Energy; and 
    • consideration of nuclear energy’s economic and national security benefits alongside the traditional safety, health and environmental considerations. 

At times, the wording is blunt in its criticism of the NRC: “A myopic policy of minimizing even trivial risks ignores the reality that substitute forms of energy production also carry risk, such as pollution with potentially deleterious health effects.” 

Trump did not mention in his order that he also has moved to ramp up those other forms of energy production and remove safeguards against their deleterious effects. 

Other actions ordered by Trump include: 

    • A nuclear reactor will be built and operational on a domestic military base within three years. 
    • The departments of Energy and Defense will explore categorical exclusions under the National Environmental Policy Act for the construction of advanced nuclear reactor technologies on federal sites. 
    • The State Department and other agencies will aggressively explore opportunities for export of U.S. nuclear technology to allies to bolster the U.S. nuclear industrial sector. 
    • DOE will release at least 20 metric tons of high-assay low-enriched uranium into a readily available fuel bank for private sector projects operating nuclear reactors to power AI infrastructure at DOE sites. 
    • The “severely atrophied” domestic nuclear fuel supply chain will be expanded. 
    • All relevant federal agencies will work together to develop solutions for the “difficult problem” of treatment of nuclear waste. 
    • Multiple efforts will be undertaken to build a workforce that can do all of these things. 
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DOE Orders Michigan Coal Plant to Reverse Retirement

Energy Secretary Chris Wright issued an emergency order May 23 that seeks to keep Consumers Energy’s 1,560-MW J.H. Campbell coal plant in West Olive, Mich., running past its May 31 retirement date. 

“Today’s emergency order ensures that Michiganders and the greater Midwest region do not lose critical power generation capability as summer begins and electricity demand regularly [reaches] high levels,” Secretary Wright said in a statement. “This administration will not sit back and allow dangerous energy subtraction policies to threaten the resiliency of our grid and raise electricity prices on American families.” 

The Office of Cybersecurity, Energy Security and Emergency Response issued the order under Section 202(c) of the Federal Power Act, which is in accordance with President Trump’s Executive Order Declaring a National Emergency. (See Trump Seeks to Keep Coal Plants Open, Attacks State Climate Policies.) 

Section 202(c) effectively is a federal backstop for reliability-must-run deals to keep power plants needed for reliability open, overruling environmental laws in the process. Recently, it has been invoked for brief periods. The Trump administration’s order signals a more aggressive use of the authority. 

The rule was used in 2005 to keep power flowing to the White House by preventing the closure of coal plant across the Potomac River in Alexandria, Va. 

Consumers signed a deal with Michigan regulators in 2022 that it would stop burning coal by the end of 2025. (See Michigan PSC Oks CMS Plan to End Coal Use by 2025.) 

“We’re officially retiring our J.H. Campbell Complex beginning in early 2025,” the utility’s website said. “This will allow us to get closer to end coal use by 2025, lower our carbon footprint and add more renewable energy for us to deliver.” 

DOE cited NERC’s recent Summer Reliability Assessment that listed the Midcontinent ISO (and several other regions) at an elevated risk for outages this summer due to a narrow reserve margin. The order declares an emergency on the grid to keep the J.H. Campbell plant open. 

“Its retirement would further decrease available dispatchable generation within MISO’s service territory, removing additional such generation along with the other 1,575 MW of natural gas and coal-fired generation that has retired since the summer of 2024,” the order said. 

The retirement was in MISO’s and Consumer’s summer forecasts, as was a new 1,200-MW natural gas plant it purchased, which expected sufficient capacity to meet peak demand, the order said. 

“For the duration of this order, MISO is directed to take every step to employ economic dispatch of the Campbell Plant to minimize cost to ratepayers,” the order said. “Following conclusion of this order, sufficient time for orderly ramp down is permitted, consistent with industry practices. Consumers Energy is directed to comply with all orders from MISO related to the availability and dispatch of the Campbell Plant.” 

The secretary’s order directs Consumers to file waivers needed for compliance with FERC. It also directs the plant to follow environmental laws while producing power. 

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Regulators Focus on Energy Affordability at NECPUC Symposium

MYSTIC, Conn. — Government officials and industry executives discussed how to mitigate rising energy costs in New England at the 77th annual New England Conference of Public Utility Commissioners Symposium May 19 and 20.

Moderating a panel on affordability, Ron Gerwatowski, chair of the Rhode Island Public Utilities Commission, compared the different components of a customer’s bill to a large stack of pancakes. While no one pancake is overwhelming on its own, “when viewed as a tower of components, then you see the problem,” he said.

“With the possible exception of the supply costs … I don’t think it’s fair to blame any one component for the high bills,” he added.

While all speakers emphasized the importance of affordability, there were few easy answers and limited consensus about how to meaningfully cut costs on bills. (See related story, ISO-NE Open to Asset Condition Review Role amid Rising Costs.)

Dan Dolan, president of the New England Power Generators Association, said energy prices have trended down over the past 10 years when adjusting for inflation, and added that “we are in a time of some of the lowest capacity prices in the history of New England.”

Dolan acknowledged that New England faces “massive volatility in cold winters” but argued that “as I look at the data, I don’t know where else to really squeeze on the supply end without pushing out resources that are really performing.”

Looking forward, with above-market-rate clean energy contracts set to take effect and load growth likely to accelerate in the coming years, “the bottom line is that rates are probably going to go up,” Dolan said.

Doug Horton, vice president of distribution rates at Eversource Energy, said “affordability for our customers means looking at the entire stack,” while noting that the company’s distribution charges are “generally aligned with other utilities across the country providing similar services.”

Meanwhile, representatives of climate and energy efficiency organizations made the case their portions of the stack were not the drivers of the region’s high energy costs.

“I don’t see a correlation between recent bill increases and the macro-trends we’re seeing on energy efficiency,” said Maggie Molina, executive director of Northeast Energy Efficiency Partnerships. Molina said energy efficiency typically provides a roughly 2-to-1 return on investment and warned policymakers that rolling back energy efficiency programs would bring long-term affordability consequences.

Jamie Dickerson, senior director of clean energy and climate programs at the Acadia Center, said it was “a cold, tough winter, there’s no doubt about it,” but added that “the primary driver of costs was gas and oil, not renewable energy.”

He said adding more clean energy to the grid will help diversify the supply mix and drive down market volatility. The New England Clean Energy Connect transmission line, which is slated to come online at the end of 2025 should save ratepayers millions annually, while the winter-peaking power production profile of offshore wind should provide significant relief for winter price spikes, Dickerson said.

He resisted the idea that adding new pipeline capacity to the region would lower consumer costs, telling attendees that “we actually don’t see that there is an economic case for the buildout of pipelines into New England.”

Arguments for new pipelines to New England have seen some revived interest under the administration of President Donald Trump, who was elected with strong financial backing from the fossil fuel industry, which spent more than $219 million during the 2024 election cycle, according to Yale Climate Connections.

“We need more pipelines,” said Cynthia Niemeyer-Tieskoetter, natural gas markets policy adviser for the American Petroleum Institute. She added that “the system is already facing constraints” during extreme winter weather, with electricity demand projected to increase in the coming decades.

Niemeyer-Tieskoetter lauded the White House for its “pro-energy agenda” and called for permitting reform to reduce the challenges of building new energy infrastructure.

Earlier in the week, New York Gov. Kathy Hochul (D) appeared to agree to concessions relating to a potential new gas pipeline to the Northeast in exchange for the Trump administration lifting the stop-work order on Empire Wind. (See related story, BOEM Lifts Stop-work Order on Empire Wind.) Connecticut Gov. Ned Lamont (D) also signaled he’s open to a new pipeline project.

Connecticut Gov. Ned Lamont | © RTO Insider 

While increased gas capacity in New England would ease some of the region’s pipeline constraints during cold periods — when heating demand backed by firm contracts limits gas generators’ ability to access fuel — it is unclear who would pay for this new capacity, or whether it would be a cost-effective solution in the long term.

Gas generators generally do not receive enough incentives to contract for firm fuel, and it is not clear whether gas distribution companies in New England would be willing to take on the costs of new pipeline infrastructure. In 2016, the Massachusetts Supreme Judicial Court ruled the state’s electric ratepayers could not be charged with the costs of new gas infrastructure, a major blow to a proposed $3.2 billion pipeline project by Enbridge, which ultimately was canceled in 2017.

Massachusetts Gov. Maura Healey (D) served as the state attorney general at the time of the SJC ruling and was a vocal critic of the plan to fund pipelines through electric rates. (See Massachusetts Regulators Endorse Pipeline Contracts.) Elected governor in 2022, Healey’s administration has taken significant steps to transition Massachusetts away from natural gas reliance as the state works to meet its statutory emissions limits.

Doubling down on natural gas likely would undermine state decarbonization efforts, as methane is an intense short-lived greenhouse gas and could risk creating expensive stranded assets as states electrify and move to renewable power.

Matt Nelson, principal at Apex Analytics and former chair of the Massachusetts Department of Public Utilities, said it is “critical” to coordinate clean energy policy to avoid unnecessary gas investments as states transition to clean energy.

“You could see bills going up in the near term to help avoid these long-term costs, and you have to be good about messaging that,” Nelson said, adding that, in the long term, “you’re going to have to build clean generation to meet electrifying customers.”

“In the short term, you may see some increased emissions as people transition from gas to electric heating,” Nelson said. “If you’re committed to adding clean resources, however, those emissions will come down over time.”

Lamont spoke briefly at the symposium prior to its conclusion, pitching lawmakers on the importance of regional collaboration to help support new and existing generation in the region. He highlighted the Millstone Nuclear Power Plant, which is owned by Dominion Energy and is under contract with Connecticut’s electric distribution companies through 2029.

“I like Millstone. … It represents about half of our power and almost all of our carbon-free power,” Lamont said. “I think we ought to give Dominion the incentives they need to continue, and I can do that a lot more effectively with the other governors.”

Lamont advocated for a formal collaboration between Northeast energy officials to ensure resource adequacy in the coming years. He noted that the Northeastern governors will meet in the coming weeks and said this concept is at the “top of the agenda.”

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BPA Approves $700M Plan to Boost Columbia Generating Station Output

The Bonneville Power Administration has approved a $700 million plan to increase the output of the Pacific Northwest’s only commercial nuclear plant by 162 MW by 2031. 

BPA said May 22 that it approved implementation of an extended power uprate (EPU) project for the 1,207-MW Columbia Generating Station (CGS) it publicly proposed in April. (See Northwest’s Only Nuclear Plant Could Get Uprate.) 

The federal power agency also said CGS will gain an additional 24 MW of capacity from a series of energy efficiency upgrades made during the plant’s 2027, 2029 and 2031 refueling cycles, bringing the total increase to 186 MW. 

Located near Richland, Wash., CGS is owned and operated by Energy Northwest, a consortium of Washington utilities. BPA markets the energy produced by the plant and covers its costs, which are included in the revenue requirements of the agency’s power services rate structure. 

“This is a great value for ratepayers in the Pacific Northwest,” BPA Administrator John Hairston said in a statement. “Upgrading an existing resource to provide additional reliable energy will help BPA keep pace with its customers’ growing electricity needs and keep rates low.” 

“We applaud BPA for its decision to approve this project and for its strategic vision in advancing our region’s future with additional, reliable capacity that nuclear energy can provide,” Energy Northwest CEO Bob Schuetz said. “Their leadership in supporting this initiative underscores a commitment to affordable and carbon-free electricity for the Northwest region, including our public power member utilities and their customers.” 

BPA and Energy Northwest said the EPU will increase electrical output at the plant by upgrading and replacing key pieces of equipment, including turbines, heat exchangers and the plant’s generator. The process also will involve 30 individual upgrades focused on increasing the size of pumps and motors. 

During an April 8 meeting to discuss the proposed uprate, a BPA representative said the agency’s resource program includes the CGS EPU in its least-cost portfolio for meeting future customer needs, reducing the amount of new solar and wind capacity it otherwise would need to procure. 

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2026 to be ‘Bridge Year’ for NERC Budget

NERC has postponed its work on a new three-year plan that would have guided its work starting in 2026 amid recent economic and political uncertainty, CEO Jim Robb said during an informational webinar May 21 on the ERO’s draft 2026 Business Plan and Budget. 

Robb reminded attendees that NERC is nearing the end of its current three-year plan, which the ERO created in 2022. NERC had planned to create another plan in 2025, but leadership decided a different approach was needed in light of the uncertainty that has grown since the beginning of President Donald Trump’s second term in January 2025. 

“When we started that planning process in earnest, we concluded that that was really kind of a fool’s errand at this point in time,” Robb said. “We decided that we should probably not do a robust three-year plan this year, but … let a few things mature over the balance of this year.” 

The efforts that need to “mature” include NERC’s Large Loads Task Force and the Modernization of Standards Processes and Procedures Task Force created by the Board of Trustees in February to examine the ERO’s standard development process for opportunities for improvement. (See “Task Force to Examine Standards Process,” NERC Leaders Highlight Canada-US Collaboration.) 

Instead of setting an overarching plan, Robb said NERC will “approach 2026 as a bridge,” with the budget covering only a single year. The ERO hopes to resume its three-year planning process in 2026, creating a plan for 2027-2029. 

As for the 2026 budget, which NERC posted for public review the day after the webinar along with the draft budgets of the regional entities, Robb said the ERO is “painfully aware of all the austerity measures” underway at the federal government and “took a very hard look at what we really needed [for] the core needs of” the ERO’s mission. 

“We all know that the risks aren’t taking a timeout. If anything, they’re accelerating and expanding,” Robb said. “So you’ll see not a flat budget for 2026, but, I think, a very prudent budget in light of everything going on in the world around us.” 

NERC CFO Andy Sharp provided more details on the draft budget, which is set to increase $5.3 million over the 2025 budget to $128.3 million. The organization’s assessment, which load-serving entities pay to support the ERO’s work, also is expected to rise by $5.3 million, to $113.7 million, with the remaining budgeted expenses to be covered by its other sources of funding, such as fees from the Electricity Information Sharing and Analysis Center’s Cyber Risk Information Sharing Program and vendor affiliate program. 

The biggest driver of the projected budget increase is personnel, Sharp said, with NERC planning to add 9.1 full-time-equivalent positions in 2026 relating to engineering, security and engagement. These additions, along with an average pay increase of 4% and increased spending on benefits, add up to a total budget of $76.2 million, $4.7 million higher than 2025. 

Operating expenses are expected to decrease by 1.4% to $43.3 million, which Sharp attributed primarily to the end of the lease on NERC’s Atlanta office in October 2025. The ERO will move operations to its office in D.C. 

Personnel is the largest increase in the REs’ budgets as well, with every entity except SERC Reliability planning to add staff in the coming year for a total of 30.4 new FTEs across the ERO Enterprise. Nearly 25% of the new hires are earmarked for outreach, training and education, followed by standards with 10%. 

Overall, all of the RE budgets are projected to grow, with the Northeast Power Coordinating Council planning the biggest increase, at $2.7 million — to $28.4 million — and WECC growing the least, with $800,000, to $40.1 million. WECC’s budget is the highest of the REs; the Texas Reliability Entity will remain the lowest, with $21.6 million, up from $20.3 million in 2025. 

NERC will accept comments on the draft business plans and budgets for 30 days beginning May 23, Sharp said. On July 22, the Member Representatives Committee’s Business Plan and Budget Input Group will review NERC’s final budget, which will be submitted to the board at its meeting Aug. 14. NERC and the REs plan to file their final budgets with FERC by Aug. 25. 

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House Passes Reconciliation Package that Would End Energy Tax Credits

The House of Representatives narrowly passed President Donald Trump’s “One, Big Beautiful Bill” that would extend tax cuts for individuals and render energy tax credits effectively useless. 

After meeting through the night, the House passed H.R. 1 by 215-214 in an early morning vote May 22. The Senate has yet to take up the package, but the bill is being passed through reconciliation, meaning it is exempt from the filibuster. 

“Today, the House has passed generational, nation-shaping legislation that reduces spending, permanently lowers taxes for families and job creators, secures the border, unleashes American energy dominance, restores peace through strength, and makes government work more efficiently and effectively for all Americans,” House Speaker Mike Johnson (R-La.) said in a statement. 

The bill would sunset tax credits for renewables, storage and nuclear earlier than current law and add new restrictions to foreign components. (See House Committees Mark up Budget Bill that Guts Energy Tax Credits.) 

It also would require that renewable and storage projects be completed — rather than begin construction — by the end of the year to qualify. Nuclear plants were spared this provision. (See related story, So far, Nuclear Energy Credits Remain in Reconciliation Bill.)

American Clean Power Association CEO Jason Grumet called on the Senate to reject the House’s hardline approach to winding down tax credits, which last were updated by the Inflation Reduction Act of 2022, passed by Democrats using reconciliation. 

“This morning, the House voted to immediately end the clean energy tax incentives that provide economic growth, good-paying jobs and low-cost electricity to millions of Americans,” Grumet said in a statement. “By a margin of one vote, the House voted to retreat in our competition with China for manufacturing jobs and to weaken our technology sector in the global race for digital dominance.” 

American Council on Renewable Energy President Ray Long said growing demand for electricity requires generation of all kinds, and the bill would set back Trump’s goal of reliable and affordable power. 

“ACORE is committed to working with Congress and President Trump to make any improvements to this legislation and help them deliver on his promise to slash energy costs for Americans by 50%,” Long said in a statement. “It’s time to achieve American energy dominance across all technologies.” 

Advanced Energy United also argued that the bill would lead to reliability issues and raise prices. 

“At a time of growing demand, economic uncertainty and fierce competition, we need smart, certain tax policies that are pro-growth,” CEO Heather O’Neill said in a statement. “Last year alone, the advanced energy industry added over 50 GW of new capacity to the U.S. grid, generated an estimated $400 billion in domestic revenue and led the way with critical investments in energy storage, nuclear power and American manufacturing. This work must continue without delay to power the U.S. economy and to keep the lights on across the country.” 

The Solar Energy Industries Association also called on the Senate to change the legislation, with CEO Abigail Ross Hopper saying that deploying solar and storage is the “only way” the grid can keep up with growing demand. 

“If this bill becomes law, America will effectively surrender the AI race to China, and communities nationwide will face blackouts,” Hopper said in a statement. 

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So far, Nuclear Energy Credits Remain in Reconciliation Bill

Nuclear energy got at least a temporary boost May 22 as the reconciliation bill hashed out in the House of Representatives spared it from most of the policy changes aimed at other forms of clean energy.

How nuclear energy fares in Senate deliberations and whether the provisions extend far enough into the future to benefit the slow-moving nuclear industry remains to be seen.

The 45U zero-emission nuclear power production credit would remain in place almost as long as specified in current law rather than gradually phasing out sooner, as specified in one of the drafts of the bill.

Also, a new advanced nuclear facility or expansion of an existing nuclear facility would remain eligible for production tax credits and investment tax credits if construction begins by the end of 2028 — which may be a tight timeline for some of the new designs that still must complete their R&D phases and then undergo regulatory review.

Nonetheless, it is a much better picture than the one that faces other clean energy technologies under the Republican-engineered megabill.

Law firm Akin Gump Strauss Hauer & Feld wrote in a May 22 alert:

“While advanced nuclear facilities would only experience a one-year credit window haircut under the bill, other technologies that currently qualify under the ‘tech-neutral’ Clean Electricity Production Tax Credit (§ 45Y) and the Clean Electricity Investment Tax Credit (§ 48E) would be eliminated under the bill if construction of the applicable facility did not begin before 60 days after enactment.” (See House Passes Reconciliation Package that Would End Energy Tax Credits.)

Also on May 22, Oak Ridge National Laboratory highlighted the work it’s doing to connect nuclear developers with national laboratory resources and expertise amid the push for more and better nuclear generation.

Oak Ridge pointed to its collaboration with Elementl Power on a data-driven approach to siting advanced nuclear projects, intended to make siting less complicated and time-consuming.

Elementl and Google on May 7 announced an agreement to pre-position three sites for development of at least 600 MW of advanced nuclear generation on each.

Google is committing early-stage development capital as Elementl prioritizes sites for development and continues its evaluation of technology, engineering procurement and construction.

Elementl is supplementing its in-house methodology with the Oak Ridge Siting Analysis for power Generation Expansion (OR-SAGE) tool, which uses GIS data including population density, water proximity and seismic data to identify potential sites for small modular reactors.

Google and Kairos Power in October 2024 announced the first corporate agreement for multiple advanced reactors. It envisions deployment by 2035 of 500 MW of the high-temperature salt-cooled reactors Kairos is designing.

Elementl is not designing its own reactor. It is a technology-agnostic developer creating a procurement model that offers turnkey development, finance and ownership solutions to companies that may not want to own or operate reactors themselves.

Elementl COO David Faherty said his company gained access to the national laboratory system through a Gateway for Accelerated Innovation in Nuclear voucher. This allowed it to overcome technological and commercialization challenges and accelerate predevelopment work that Elementl would have needed years to replicate on its own.

The OR-SAGE platform “gives us a data-driven foundation to screen regional siting options efficiently and allows our team to layer in our own project-specific criteria with greater speed and confidence,” Faherty said.

The growing support being shown for advanced nuclear technology can go only so far in making its development and deployment progress at a faster pace and lower cost. Pioneering projects are expected to be expensive, making federal policy support an important part of project finance, and making the timing of credit expiration a critical detail as the reconciliation bill goes to the Senate.

Kairos has begun construction of its Hermes demonstration reactor in Oak Ridge, for example, and intends to use it inform and de-risk subsequent commercial projects. But Hermes is not expected to be operational until 2027.

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Arizona Utilities Explore Expanded Use of Nuclear

Arizona utilities are seeking U.S. Department of Energy funding to help plan for more nuclear power facilities in the state.

Representatives from Arizona Public Service (APS), Tucson Electric Power (TEP) and Salt River Project (SRP) discussed their plans May 21 during an Arizona Corporation Commission workshop on advancing nuclear power generation.

APS is leading the effort, working in partnership with TEP and SRP. The goal is to select a site for a future nuclear facility and submit an early site permit application to the Nuclear Regulatory Commission, according to Brian Cole, vice president for resource management at APS.

In evaluating sites, the utilities will consider the availability of land, water, transmission infrastructure and workers. Coal-fired power plant sites are one possibility, as are the site of the Palo Verde nuclear generating station and other locations.

To help with the planning, the utilities have applied for funding through the Generation III+ Small Modular Reactor program in the DOE’s Office of Clean Energy Demonstrations.

The utilities are applying for funding in the “fast follower” category, which will provide up to $100 million to address hurdles the U.S. nuclear industry has faced in areas such as design, licensing, supply chain and site preparation. Awardees must match the DOE funding.

DOE opened the funding opportunity in October and reissued the solicitation in March. The Arizona utilities submitted a revised application in April. They expect a decision by the end of the year.

Small modular reactors could provide reliable power for energy-intensive applications such as industrial uses, artificial intelligence and data centers, DOE said in a March announcement. SMRs offer flexible deployment due to their compact size and modular design, the agency added.

“Light-water small modular reactors could also leverage the existing service and supply chain supporting the country’s current fleet of light-water reactors, helping speed up the near-term deployment of new nuclear reactors,” DOE said.

Technology Options

Despite the DOE grant’s focus on Generation III+ SMRs, the Arizona utilities are remaining open for now to different types of nuclear technology, Cole said.

“We also want to make sure we keep the door open for both SMRs and large-scale nuclear,” Cole told commissioners.

An early site permit (ESP) from the NRC may consider a range of technologies, according to Tom Cooper, SRP’s senior director of future system assets and strategy. The ESP, which is a voluntary permit, is a way to reduce the risk surrounding a nuclear project, he said.

An early site permit “does not authorize construction or operations, but it is a significant de-risking factor, because it gives you a very strong indication that the … NRC finds that site suitable to host nuclear.”

Palo Verde’s Status

APS operates the 4.2-GW Palo Verde nuclear power plant, the largest power producer on the Western grid. It shares ownership of Palo Verde with six utilities: SRP, El Paso Electric, Southern California Edison, Public Service Company of New Mexico, Southern California Public Power Authority and the Los Angeles Department of Water and Power.

Palo Verde is the only nuclear plant that’s not next to a body of water. The facility uses reclaimed wastewater.

“We continue to evaluate water strategy at the station,” said John Hernandez, vice president of site services at Palo Verde. One idea is to use lower-quality wastewater.

The first of Palo Verde’s three reactors is set to mark 40 years of operation in June. In 2011, the NRC granted Palo Verde a 20-year license extension that runs to 2047. An application for an additional 20-year license extension is being considered, with a target date for approval of 2029, Hernandez said.

Although APS has the largest ownership stake in Palo Verde, at 29%, followed by SRP at 20%, ownership shares in a new nuclear facility would be subject to negotiation, Cole said.

Commissioner Lea Marquez Peterson asked whether California utilities might want to be involved in a new Arizona nuclear facility, a move that might help reduce risk for the Arizona utilities.

California entities “don’t have that political openness to placing a new nuclear plant in their state, but seem to be open to keeping the energy,” she said.

Cole said the current focus for a potential nuclear project is Arizona’s needs.

“We’re looking at this right now as an Arizona project, but that doesn’t mean … that there won’t be additional partners in the future,” he said.

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CAISO Postpones EDAM Congestion Revenue Decision

CAISO has delayed its final decision on how to allocate congestion revenues in its Extended Day-Ahead Market (EDAM) after receiving comments from stakeholders asking for more analysis. 

CAISO planned to vote on its draft final proposal in late May but decided to hold off until June. Adjusting the proposal’s planned approval date has “allowed us to further explore additional enhancements suggested by stakeholders,” said Anna McKenna, CAISO vice president of market design and analysis, at a May 20 WEM Governing Body meeting. 

The congestion revenue initiative is a top priority for CAISO in 2025. The organization received comments from PacifiCorp that questioned the way congestion revenues will be allocated in the proposed EDAM design. The primary concern is whether certain congestion revenues should be allocated to the balancing area in which the congestion costs accrued, or to the neighboring EDAM balancing authority area where the transmission constraint is located, specifically in cases in which parallel — or loop — flows occur. 

On May 19, CAISO published a revised draft final proposal, which fine-tunes the allocation of parallel flow congestion revenues “based on the exercise of eligible firm point-to-point and Network Integration Transmission Service and Open Access Transmission Tariff transmission rights.” 

The revised draft provides details about congestion revenues that are not received under the current design for the EDAM entity. Any remaining parallel flow congestion revenue accrued because of a transmission constraint in a neighboring EDAM balancing area would be allocated to the area where the binding transmission constraint is located, CAISO wrote. 

The revised draft is consistent with FERC requirements that say congestion revenues accruing internal to an EDAM balancing area because of an internal transmission constraint are allocated fully to that balancing area — i.e., where the transmission constraint is located, CAISO wrote.  

“Stakeholders continued to note the concern that the proposed design in the near term may incent self-scheduling by transmission customers in order to receive a congestion hedge, a ‘use it or lose it’ concept to the exercise of transmission rights,” CAISO said in the draft. “In this context, stakeholders indicated broad support for an economic bidding enhancement to enable parallel flow congestion revenue allocation for balanced cleared market schedules based on economic bids, not only self-schedules.” 

The revised proposal includes an example of a load event that shows how much money would be distributed to four balancing areas: BAA-A, BAA-B, BAA-C and BAA-D. In the example, the market footprint net settlement is an over-collection in congestion revenue of $135,800. Under the current EDAM design, all of the congestion revenue is allocated to the BAA where the constraint is modeled, CAISO wrote. However, under the revised draft, the congestion revenue associated to balance OATT self-schedules is allocated to the EDAM entity where OATT rights are exercised. 

CAISO will hold a stakeholder meeting on the revised final draft proposal May 27, with comments due by June 2. CAISO plans to publish a final proposal June 6.