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December 17, 2025

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Counterflow: Big Beautiful Expensive Uranium

President Donald Trump issued four executive orders on nuclear power in late May, bizarrely bragging that this number of executive orders is twice the number of new nuclear plants started in the U.S. since 1978.

Say what? We haven’t built new nuclear plants over the past 50 years (other than the Vogtle disaster) because they haven’t made any economic sense, as I discussed years ago.

One of his executive orders directs a program for installing nuclear reactors at critical defense facilities, based on the claim that nuclear reactors can deliver resilient, reliable power to these facilities.

Trump’s claim is wrong and misleading for many reasons.

Reason No. 1: Nuclear reactors cannot provide resilient, reliable power to defense facilities. As FERC has observed, in the event of an outage on the grid the nuclear reactor has to shut down and cannot restart until grid power is restored (page 44).

uranium

Steve Huntoon

And as 41 transmission owners in PJM recently said to FERC: “Further, load that is co-located with a nuclear unit depends on services such as load following, voltage support, black start and other ancillary services that will be and can only be delivered over the grid. Nuclear units cannot move their output up and down from moment to moment to match variations in the load, and because the nuclear units cannot provide these services, they must instead be provided through connection to the grid” (page 13). Thus, nuclear reactors would contribute 0.0 reliability value to critical defense facilities.

Reason No. 2: Critical defense facilities already have backup power, generally on-site diesel generators. Thus, nuclear reactors would be superfluous.

Reason No. 3: A total of 87% of defense facility outages are due to problems on the distribution systems inside the bases. Thus, a nuclear reactor outside a base would provide 0.0 reliability value relative to such outages.

Reason No. 4: Nuclear reactors have lengthy refueling outages and obviously couldn’t provide power during such outages.

Reason No. 5: If nuclear is to have any hope of commercial viability — which it doesn’t have for reasons I’ve given —then it has to achieve economies of scale through modular production. Since every defense facility has its own unique power needs, that means every nuclear reactor for a given defense facility would need to be unique, thus defeating the only conceivable purpose of having taxpayers subsidize this Trump program.

Defense facilities are only one aspect of Trump’s four executive orders, which collectively are intended to increase the U.S. nuclear fleet from today’s 100 GW to 400 GW by 2050.

What’s that going to cost us? If we take the Ontario SMR cost per reactor (excluding the most expensive first unit) of $3.5 billion, optimistically assume no cost overruns, and divide by the SMR capacity of 300 MW, we get $11.5 million/MW. If we plug that capital cost into the Lazard capital cost range, it interpolates to $181/MWh in the levelized cost of energy range (page 38).

That is an excess of $143/MWh over the $38/MWh average cost of generation in PJM (Figure 3, transmission costs excluded). At nuclear’s 90% capacity factor, Trump’s 300 GW would translate to 2.6 million GWh/year, or 2.4 billion MWh/year, and thus into excessive costs of $343 billion/year for the U.S. overall, and an average excessive cost of $1,000/year for each of us. Please note that this would be a total “own goal” relative to the U.S. Energy Information Administration’s base case for 2050, which has nuclear output and electric customer costs essentially unchanged from today.

Simply put, Trump’s extra 300 GW of nuclear means each of us, as taxpayer or electric consumer or both, would lose $1,000 every year.

Now that is one Big (Not So) Beautiful Bill!

Columnist Steve Huntoon, a former president of the Energy Bar Association, practiced energy law for more than 30 years.

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Interregional Transmission Would Improve Resource Adequacy, ACEG Report Argues

Interregional transmission can help address resource adequacy concerns around the country, according to a report released by Americans for a Clean Energy Grid and Grid United ahead of FERC’s two-day technical conference. (See FERC Resource Adequacy Conference Comes with Markets at a Crossroads.) 

“The last several Summer Reliability Assessments from [NERC], including this year’s, continue to demonstrate resource adequacy risks facing the power system given hotter summers, load growth and an aging generation fleet,” said co-author Adria Brooks, director of transmission planning for Grid Strategies. “This report demonstrates yet another benefit of interregional transmission, adding to a growing list of reliability and cost benefits. We have to stop ignoring the value of interregional transmission and instead create mechanisms to build it.” 

Interregional transmission offers value because different regions have different resource mixes and their peak demand is often at different times, the report says. 

“Interregional transmission allows capacity resources to be shared between regions with noncoincident demand,” the report says. “The interregional transmission assets themselves tend to be available nearly 100% of the time. Consumers benefit from this sharing of reserves, both in terms of improved reliability and reduced costs. These reliability and economic benefits are heightened during grid stress events.” 

To move forward with more interregional transmission investment, the industry will need to integrate capacity value into its resource adequacy assessments, which can be calculated using standard industry methods such as effective load-carrying capacity (ELCC). 

“ELCC considers the difference in loss-of-load expectation (LOLE) — or any other RA metric — for the system with and without the supply resource and calculates how much additional load the resource can serve to return the system to the standard LOLE baseline of one day in 10 years,” the report says. “This method has been successfully applied in several recent transmission facility or resource adequacy studies to derive the capacity value of several interregional transmission lines both in the United States and abroad.” 

System planners historically have not calculated the LOLE reduction from an individual transmission line and converted it to a capacity value. But most have calculated the cut in LOLE associated with the current fleet of interregional lines, which is called “external assistance,” “tie benefits” and “firm and non-firm imports” in different regions. 

Without a benefit that load-serving entities can credit to their resource adequacy obligations that indirectly provides value to transmission developers, or direct payments to transmission for its resource adequacy contributions, the industry will have fewer incentives to build interregional lines. The valuation and compensation can be done for either fully regulated transmission or merchant lines. 

The report argues that considering the benefits of lower planning reserve margins from interregional lines will not worsen reliability; it would represent a cut in the amount of capacity needed to maintain resource adequacy. Those benefits can even come from non-firm imports, with grid planners using a probabilistic treatment of available imports to avoid overcounting such resources. 

“All regions we surveyed include firm imports from neighbors in their resource adequacy assessments, but only a handful also consider the contribution of non-firm imports,” the report says. “Those that do incorporate non-firm imports rarely accredit the interregional transmission [that] enables non-firm imports with a capacity value for their contribution to resource adequacy.” 

Non-firm imports are a way to quantify the “net load diversity” between regions, such as when one region faces a shortage but its neighbor has excess supply. 

“Non-firm imports are a vital resource to the system, allowing operators to keep customers’ lights on even when there are no more internal resources to call on for support,” the report says. “However, these imports are not consistently incorporated into resource adequacy assessments. This omission may result in the over-procurement of capacity resources internal to the planning region to meet the planning reserve requirement, raising costs for ratepayers.” 

At the simplest level, planners can look at historic imports to determine how many non-firm imports can be included in LOLE studies. Doing that seasonally, or only during tight-capacity periods, provides more confidence that external support will be available in the future. 

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SERC Says Most Subregions Prepared for Summer Heat

SERC Reliability expects above-average temperatures to drive higher demand this summer, and registered entities should have the resources to meet demand under normal operating conditions, the regional entity said in its 2025 Summer Reliability Assessment. 

However, SERC also warned that some areas do face a risk of shortfalls should weather conditions become more extreme. 

SERC published the SRA on May 29 as a supplement to NERC’s 2025 summer assessment, in which the ERO warned that multiple subregions across North America showed a potential for insufficient operating reserves in above-normal conditions. (See NERC Warns Summer Shortfalls Possible in Multiple Regions.) NERC identified rising demand and the retirement of traditional generation resources as primary contributors to the risk in the summer season, which for both assessments runs from June to September. 

SERC’s assessment noted that extreme weather continues to be a major concern for the region, which “contains those areas of the U.S. most likely to be in the path of a hurricane, as well as many of the states that are prone to high summer temperatures.” The RE included data from EPA showing that the frequency, intensity and duration of heat waves in major U.S. cities have all steadily increased since 1961, while the average length of heat wave seasons has lengthened from just over 20 days in the 1960s to 70 days in the 2020s. 

“Hotter summer temperatures cause increased demand due to heightened use of commercial and residential air conditioning,” SERC said. “Simultaneously, hotter temperatures can reduce the generation capacity and efficiency of thermal generation units and reduce air density, which decreases the capability of wind turbines. … Extreme heat along with high demand can overwhelm the transmission lines and cause them to sag and touch trees or other objects, which can potentially lead to outages.” 

Despite the growing threat of extreme heat, SERC said all of its subregions have enough resources to meet NERC’s recommended 15% reserve margin target under the 50/50 load forecast, which represents a 50% chance that the actual peak load will be higher or lower than the prediction. This prediction held for most areas even under the 90/10 forecast, in which there is a 10% chance that peak load will be higher than expected. 

Charts included in SERC’s SRA, based on EPA data, on the frequency, duration and intensity of heat waves in major U.S. cities, along with the length of heat wave season, since the 1960s. | SERC

The one exception was the Central subregion, covering all or parts of Alabama, Georgia, Iowa, Kentucky, Mississippi, Missouri, North Carolina, Oklahoma, Tennessee and Virginia. Its predicted reserve margin was 19% under the 50/50 forecast, but 9% under the 90/10, putting it into the “elevated risk” category. 

Natural gas generation constituted the largest share of SERC Central’s summer on-peak generation mix, with 19.7 GW, or 41% of the total generation fleet; coal was next at 12.7 GW (27%); followed by nuclear at 8.2 GW (17%). For comparison, in SERC’s overall footprint, gas accounted for 49% of the nearly 324 GW on-peak generation capacity, with coal at 18% and nuclear at 13%. 

The report observed solar generation still is increasing across the SERC region, with 30 GW of on-peak solar capacity expected to be online by this summer, up 7 GW from summer 2024. This growth has driven operators to rely on natural gas to balance the weather dependence of solar generation. 

However, SERC noted that “while [gas] generators are capable of quickly ramping up and down to provide ‘load following’ service as necessary, this is only possible if they have access to the full amount of natural gas commodity needed for the periods for which they are dispatched.”  

The RE mentioned that one registered entity said, “If operational flow orders (OFO) were issued on the pipelines serving its generating units, the OFOs would require the units to maintain the day-ahead planned fuel usage.” This could prevent operators from redispatching the affected gas units to handle transmission line loading issues. 

SERC recommended that reliability coordinators, balancing authorities and transmission operators review their seasonal operating plans with a focus on communication and resolution of potential supply shortfalls during periods of extreme demand. The RE also said utilities should ensure resource availability through conservative generation and transmission outage coordination procedures, and state and provincial regulators should prepare to implement demand-side management mechanisms. 

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Palisades Nuclear Restart Clears Environmental Review

The Nuclear Regulatory Commission has determined there would be no significant environmental impact from restarting the Palisades Nuclear Plant in Michigan. 

The NRC decision issued May 30 reaches the same conclusion as its draft decision Jan. 31. 

The 800-MW facility in Covert Township formerly operated by Entergy went offline in May 2022 in preparation for decommissioning, but barely a year later, new owner Holtec International began to float the idea of bringing it back into service.

No commercial reactor in the United States has been restarted in such a scenario, although Constellation is working toward that goal with the former Three Mile Island Unit 1, which shut down in 2019, and NextEra has filed notice with the NRC about potentially restarting the Duane Arnold Energy Center, which ceased operations in 2020. 

The NRC issued the environmental assessment of the Palisades proposal in cooperation with the U.S. Department of Energy’s Loan Programs Office, which in September 2024 extended a $1.52 billion loan guarantee to Holtec to help financed the effort. 

More recently, in March, DOE approved disbursement of $56.8 million for that purpose — a relatively small sum, but notable amid the wholesale slashing under way at the time as the new Trump administration took aim at the clean energy priorities of the Biden administration. 

While the two presidents have little common ground on wind and solar generation, both have supported nuclear power with words and deeds. (See Trump Orders Nuclear Regulatory Acceleration, Streamlining.) 

In the determination issued May 30, NRC said restarting Palisades would provide baseload power to meet current system needs. Holtec also noted it would help Michigan reach its targets of at least 80% clean energy by 2035 and 100% by 2040. 

NRC said it considered 11 potential direct or indirect environmental impacts from a restart and determined none would be significant. It also determined there are no environmentally preferable alternatives to restarting Palisades. 

In an April update, Holtec said the project remains on schedule and on budget. As it refurbishes the physical plant, it is rebuilding its workforce: Staffing has rebounded from a low of 220 to 570, 26 plant operators have requalified, and the first initial operator class was on track to complete their license exams this month. 

Also, FERC approved Holtec’s waiver request to maintain the grid interconnection, which was suspended after the plant shut down and otherwise would have been sunsetted. 

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MMU, FTI Argue for Maintaining Uniform Pricing in NYISO Capacity Market

NYISO and its stakeholders continue to consider different designs as part of their Capacity Market Structure Review, but one idea should be dismissed, according to the Market Monitoring Unit and FTI Consulting: bifurcated pricing.

Though all RTOs with capacity markets may be concerned with their effectiveness in maintaining resource adequacy, NYISO is perhaps more unique in that, according to the MMU, new investment in generation primarily is driven by New York state procurements. In a market based on the net cost of new entry, stakeholders are concerned this could lead to keeping older, more inefficient resources longer than necessary and at a higher cost to consumers. (See NYISO Stakeholders Debate Purpose of Capacity Market.)

A bifurcated — or “discriminatory” — market would have two separate demand prices: one for existing resources and one for new entries to the market. According to NYISO consultant FTI, such markets can result in short-term reductions in costs to consumers, but “in the longer run, as more existing capacity inefficiently exits as a result of the artificially low capacity price and is replaced with high-cost new capacity, the short-run consumer savings will tend to turn into higher costs for future consumers.”

“From a social welfare standpoint, all of this is inefficient,” FTI’s Scott Harvey said in the middle of his presentation to the Installed Capacity Market Working Group on May 22. “It’s going to reduce social welfare because unless we do the price discrimination perfectly, we’re going to shut down some existing capacity that’s got lower cost than new capacity, and that reduces social welfare.”

Biasing the market toward new capacity also incentivizes the construction of short-lived assets because they will make less money as they age, even if initially they are higher cost, he said.

Balancing the market such that it retains enough units to meet reliability needs while incentivizing new entry and economic exit is tricky, Harvey acknowledged, especially amid low reserve margins.

FTI offered several approaches to a bifurcated market: holding a two-stage auction with separate supply curves but a single demand curve, with a lower price cap for existing capacity; a single-stage auction with a single supply curve but separate demand curves; and a two-stage auction with both supply and demand curves completely separated. Each construct, however, had its own drawbacks under certain circumstances, according to FTI’s presentation.

“If you are close to the edge already on reliability, then shutting down existing capacity will have a larger impact,” Harvey said. “Anything that drives up the cost of new capacity and less [generation] comes in than you expected is going to have an impact. If some of the existing capacity is already shut down by the time you realize the new capacity isn’t going to show up, you’re going to have problems.”

FTI noted that the natural gas market was bifurcated by the Natural Gas Policy Act of 1978, but this ultimately resulted in inflated, high prices, and by 1989, the law was repealed.

Potomac Economics’ Joe Coscia presented the MMU’s quantitative model using multiple scenarios showing that price discrimination between new and old units would lead to both “inefficient behavior” and higher investment costs.

Capacity prices also rise relative to status quo, and capacity surpluses decrease.

“That’s a result of the early retirement of existing resources or inability to attract imports and firm gas instead of replacing it with more expensive new capacity,” Coscia said.

He said the MMU’s results pointed toward the advantages of uniform clearing prices based on cost of new entry, even when there isn’t much investment in the peaking technology.

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Panel Approves SPP Markets+ Phase 2 Governance Transition

The panel of SPP board members overseeing the development of Markets+ has approved the governance transition plan for the construction phase of the day-ahead market. 

The Interim Markets+ Independent Panel (IMIP) also signed off on Phase 2 sector representation for stakeholder groups, a meeting attendance and proxy policy, and the budget for the Markets+ State Committee (MSC) during its May 27 virtual meeting. 

The IMIP unanimously endorsed the Markets+ Participant Executive Committee’s (MPEC) recommendation to keep the Phase 1 stakeholder groups’ rosters until the committee’s Aug. 12-13 meeting, which serves as the Phase 2 effective date. Potential Markets+ participants must sign one of three agreements — funding, participation or stakeholder — by July 23 to retain seats for their representatives. 

MPEC will vote on stakeholder group nominations during the August meeting in Portland, Ore. (See SPP Readies Participants for Next Phase of Markets+.) 

IMIP Chair Steve Wright praised MPEC’s suggestion for meeting attendance and use of proxies. A stakeholder task force worked to meet the demands of public interest groups and nonprofits, many of which are stretched to cover the various working groups and subgroups. 

“This is a good example of how the process works well. I thought there were some legitimate concerns raised with respect to small organizations’ ability to participate in the process, and some good compromises were made from the initial proposal,” Wright said. “I feel like this is a really strong proposal that aligns with the culture of governance that we want to have as part of the development of Markets+.” 

The MSC budgeted $389,680 for 2025 expenses. That covers the cost of a full-time equivalent dedicated to the committee and two in-person meetings during the year, and compares favorably with SPP’s Regional State Committee in the Eastern Interconnection. 

The costs are allocated to Markets+ participants. The Western Interstate Energy Board provides independent staffing for the MSC, which is composed of state regulators from the West. 

Xcel Defends Markets+ Decision

Joe Taylor, who represents Xcel Energy operating subsidiary Public Service Company of Colorado (PSCo) on MPEC, explained the utility’s decision to join Markets+ rather than an RTO during testimony May 27 before the state’s Public Utilities Commission. 

Taylor said the company is concerned about long delays in grid operators’ interconnection queues. 

“It gives us pause to turn over those activities to an RTO,” he said. “The ability to plan and build are important considerations.” 

A 2021 state law requires transmission-owning utilities to join an organized market by 2030. Tri-State Generation and Transmission Association, Colorado Springs Utilities and the Platte River Power Authority have chosen to become full RTO members of SPP’s Western expansion. 

PSCo estimates it will be assessed $20 million in implementation costs for Markets+. 

MMU Releases 2024 Market Report

SPP’s Market Monitoring Unit has released its annual State of the Market report for 2024 and continues to find the Integrated Marketplace to be competitive.  

The Monitor shared a draft with stakeholders during the quarterly Joint Stakeholder Briefing in May. (See “MMU’s Draft Market Report,” 2025 ‘Challenging’ Year for SPP, Exec Says.) 

The MMU said many of the themes identified in previous years — resource adequacy challenges and increasing renewable generation — persisted in 2024. The market continues to see escalating load growth with a “high likelihood” that it will continue in future years. 

Intermittent resources continue to play an ever-growing role in the SPP markets, with increasing variability and uncertainty of supply, out-of-market actions to ensure system reliability, higher make-whole payments and negative prices, according to the report. 

The MMU will host a webinar June 12 to discuss the report. 

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PJM Files Waiver Seeking Additional Time to Select Board Candidates

PJM has asked FERC to grant it more time to find candidates to fill two Board of Managers positions vacated when the Members Committee (MC) voted against reelecting two incumbents May 12. (See PJM Stakeholders Reaffirm Board Election Results.) 

The May 30 filing states that the RTO’s Nominating Committee (NC) needs more than the one-month period permitted by its Operating Agreement (OA) to select new candidates after the MC fails to elect a full board. It seeks instead to impose a Sept. 25 deadline for the NC to bring new candidates for members to vote on. The committee is composed of one member from each of the five member sectors and three from the Board of Managers. 

“While the Nominating Committee has already been reconvened and met, this waiver request is necessary to ensure sufficient time to identify potential board members and to complete appropriate due diligence, including background checks, prior to announcing the proposed nominees to be considered and voted on by the Members Committee,” the filing states. 

The MC voted against re-electing then-Chair Mark Takahashi and board member Terry Blackwell during PJM’s Annual Meeting on May 12. When stakeholders sought to reconsider the vote the following day, Takahashi removed his name from the running; a subsequent motion to reconsider Blackwell’s election failed. (See PJM Stakeholders Vote Out 2 Board Members.) 

PJM wrote that the current board meets OA requirements for the “size, the expertise and experience, and the composition of the board” and can continue operations until the membership votes on new members. 

PJM Board of Managers member David Mills speaks during the May 14 Public Interest and Environmental Organization User Group meeting. | © RTO Insider 

In a May 29 notification, PJM announced the NC had decided to continue working with Korn Ferry International in the search for the two new candidates. The firm was brought on to aid in finding candidates to replace outgoing board member Dean Oskvig, who retired from the board and was replaced by Matthew “Matt” Nelson, principal of regulatory strategy at Apex Analytics in May. 

Those interested in applying can submit resumes to Korn Ferry at PJMBoard@KornKerry.com. The announcement states the firm will not reach out to state commission members or government employees without their consent “to avoid the appearance of impropriety.” Officers and employees of PJM members or their affiliates are prohibited from serving on the board, as are those with financial interests in PJM members. Prospective candidates are encouraged to submit applications by June 30. 

“The Nominating Committee seeks to consider a broad and diverse field of candidates who possess the appropriate expertise and experience to oversee PJM as it fulfills its public service responsibilities in a complex and changing industry and regulatory environment,” PJM said in the notification. 

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FERC Approves Implementation Delay for ISO-NE Order 881 Compliance

FERC has accepted a 17-month delay to ISO-NE and the New England transmission owners’ (TOs’) implementation of Order 881 and Order 881-A compliance, pushing back the rollout of ambient-adjusted line ratings (AARs) in the region. The RTO and the TOs said the delay is needed to accommodate vendor and software development challenges (ER22-2357, ER25-410). 

FERC Order 881, issued in December 2021, requires transmission providers to adopt AARs, which provide more accurate real-time temperature information on transmission lines, for near-term transmission requests. The order is intended to free up transmission capacity, as existing static rates are based on worst-case temperature conditions. The order also requires operators to use seasonal line ratings for long-term transmission service. (See FERC Orders End to Static Transmission Line Ratings.) 

ISO-NE and the TO’s compliance with the order was to take effect in July 2025 but has been pushed to December 2026.  

“Considering the vendor delay in delivery of the software that is needed for ISO-NE and the [participating transmission owners] to implement Order No. 881, and the time to test and train after delivery of the software, it is highly unlikely that the filing parties will be able to implement the tariff rules as of July 12, 2025,” the groups wrote in their request to FERC.  

The organizations wrote that ISO-NE plans to complete “all initial integrated software testing by January 2026,” which would be followed by trainings, TO testing and procedure development prior to the rollout of AARs in “all required day-ahead and real-time processes.” 

No protests of the request were filed in the docket. FERC accepted the request in a brief order May 30, writing that “good cause exists to defer the effective dates to implement the requirements of Order Nos. 881 and 881-A in order to provide additional time to complete the development and deployment of necessary software updates.” 

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Energy Department Staff Cuts Just Getting Started

The U.S. Department of Energy is poised to lose thousands of employees this year through early buyouts and other mechanisms, but the cuts are heavier in certain offices. 

Cutting down the size of government is a major policy goal of President Donald Trump, as stated in a memo from the White House’s Office of Management and Budget and the U.S. Office of Personnel Management issued about a month after he took office. 

“The federal government is costly, inefficient and deeply in debt. At the same time, it is not producing results for the American public,” the memo said. “Instead, tax dollars are being siphoned off to fund unproductive and unnecessary programs that benefit radical interest groups while hurting hard-working American citizens.” 

The memo called on federal agencies to submit “agency [reduction in force] and reorganization plans that include a “significant reduction” in full-time employees, lower budgets and “better service for the American people.” 

The full effects of that process still are being played out, with the deferred resignation program that many employees have signed up for not being final until the end of September. The law firm Mintz said that up to 5,000 employees at DOE alone could leave, which is out of a total workforce of around 16,000, according to the Equal Employment Opportunity Commission. 

In testimony before the Senate Appropriations Committee on May 21, Energy Secretary Chris Wright said only a small percentage of employees had left the department. 

“We are looking at larger reductions and … we have offered voluntary plans and programs for people to be compensated by the government as they transition to another career,” Wright said. “We’ve done this slowly, carefully, with a lot of engagement with people and while looking at how to restructure our department. So, the ultimate reduction in workforce will be larger than it’s been today.” 

The Federal Reserve Bank of St. Louis estimates that total federal employment has fallen from 3.015 million in January to 2.989 million at the end of April, which still is above January 2024 federal employment levels. 

Speaking during a webinar in May put on by the World Resources Institute, where he is a senior fellow, former DOE Loans Program Officer Director Jigar Shah said some of the smartest people at DOE “were forcibly told to resign” over the previous couple of months. 

“So that expertise is gone,” the former Biden administration official said. “Even if they wanted to figure out a nuclear renaissance, those people decided to take the early retirement program; the same with geothermal; the same with advanced battery storage. So they’re not there to do that planning.” 

Shah listed his old office along with the Office of Clean Energy Demonstrations, the Grid Deployment Office, and the Office of Manufacturing and Energy Supply Chains as being particularly hard hit by staff cuts. 

“If you have a new technology right now, and you go to the Department of Energy … I don’t think there’s actually anyone to talk to over there to help you with commercialization of your technologies,” Shah said. 

Lasting Impact

While administrations and their policies come and go, the staff losses will be difficult to unwind if in four years a new president wants a more active DOE. 

“It is possible, but it’s going to be very difficult,” another former DOE official said in an interview. “You’re going to need to have some kind of authority, from either the administration or Congress, that allows you to hire much more quickly than the normal civil service hiring rules have allowed you to do.” 

Even if hiring can be sped up, many of the employees let go or who left because of new requirements, such as return-to-office, were young and doing their first stint in public service, the official added. Their trust in the system will need to be rebuilt, they said. 

The National Energy Technology Laboratory in Pittsburgh has not been hit as hard as some of the offices that were implementing key Biden-era policies, but about 100 employees have taken the deferred resignation program, said American Federation of Government Employees Local 1916 President Lilas Soukup. 

“Obviously it’s excruciating to lose about 15 to 20% of your workforce and not [be] able to replace them,” she said. 

A hiring freeze is in place until July 15, and it could be extended. Additionally, new rules allow departments to hire only one employee for every four who leave, Soukup said. 

NETL has different focuses, and those dealing with solar energy are being reduced by the Trump administration. But it also works on fossil fuels, so Soukup said hopefully some of the staff losses could be offset by having her members switch to other programs. 

While NETL — as well as the Department of Health and Human Services, whose Pittsburgh-area employees Soukup also represents — have not faced the same cutbacks as other parts of DOE, she worried about the long-term impacts of the staff cuts on public service. 

“Who’s going to want to take and work for the government after all of this fiasco is over with?” she asked. 

DOE Reorganization Goes Beyond Staffing

DOE did not respond to requests for comment on its staff cuts, but on May 30, it put out a press release highlighting the shift in its direction under President Trump and Secretary Wright.  

While the press was bombarded with releases on funding authorized by DOE under President Joe Biden, the department trumpeted $3.7 billion in savings from 24 canceled projects. 

“While the previous administration failed to conduct a thorough financial review before signing away billions of taxpayer dollars, the Trump administration is doing our due diligence to ensure we are utilizing taxpayer dollars to strengthen our national security, bolster affordable, reliable energy sources and advance projects that generate the highest possible return on investment,” Wright said in a statement. “Today, we are acting in the best interest of the American people by canceling these 24 awards.” 

Of the canceled projects, 16 were approved between Election Day in November and Trump’s inauguration Jan. 20, and they primarily were for carbon capture and storage projects. 

The cuts came under criticism from the American Council for an Energy Efficient Economy, which argued they go against the goal of reshoring manufacturing. 

“This program could have been a centerpiece of achieving the administration’s goal to bring manufacturing back to the United States,” ACEEE Executive Director Steven Nadel said. “Choosing to cancel these awards is shortsighted, and I think we’re going to look back at this moment with regret. Locking domestic plants into outdated technology is not a recipe for future competitiveness or bringing manufacturing jobs back to American communities.” 

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Pathways Initiative Seeks $7.1M to Fund RO

The West-Wide Governance Pathways Initiative’s Launch Committee estimates it will cost about $7.1 million to launch the independent regional organization (RO) that eventually will oversee energy markets in the West, staff said during a May 30 presentation, while noting federal funding for the effort is uncertain.

The budget is divided into three categories: preparation, formation and implementation. The estimated total cost for all three phases is about $7.1 million, including a 10% contingency cost, said launch committee member Jim Shetler, general manager of the Balancing Authority of Northern California.

The draft budget runs from Jan.1, 2025, to Dec. 31, 2027, when tariff funding takes effect for the RO. It includes costs for activities like project management, legal services, hiring an executive director and general counsel, and finalizing a draft tariff and service agreements.

However, the committee has yet to receive confirmation on whether the U.S. Department of Energy plans to issue nearly $1 million in funding. Pathways received a commitment under former President Joe Biden’s administration to underwrite the committee’s efforts to establish the RO to oversee CAISO’s Western Energy Imbalance Market (WEIM) and Extended Day-Ahead Market (EDAM). (See Feds Pause $1M Pathways Initiative Funding, Group Leader Says.)

The award was issued through the Pathways Initiative’s philanthropy adviser, Global Impact, which the group’s Launch Committee partnered with earlier in 2024 to secure outside funding for its operations, which so far have been supported by donations — and volunteered staff — from its participants.

President Donald Trump’s administration on Jan. 27 paused all federal grants and loans, according to a memo issued by the White House’s Office of Management and Budget.

“We are still looking to try to engage to see if we can get a DOE grant, but we’re not assuming that that will be the case,” Shetler said.

Instead, the committee seeks donations from stakeholders to support the effort, Shetler added.

“I’ll just let you know I’ve been starting some initial dialog with the utilities that have indicated support for EDAM, and I’m not suggesting the utilities would support all of the $7.2 million, but at least we have started dialog around how we might support that,” Shetler said.

Kathleen Staks, executive director of Western Freedom and the Launch Committee’s co-chair, also provided an update on the RO’s board members, stating that the committee hopes to seat a board by July 2026 and no later than January 2027. (See Pathways Inches Closer to Seating RO Board.)

Per the committee’s draft proposal, the board will have five members, with two additional seats added after FERC approves the tariff changes and RO funding is secured.

The initial board will consist of independent members that will negotiate with CAISO, Staks said. She noted the board “would not yet have any authority over the markets because that authority change does not happen until FERC approves the tariff change.”

The five initial members would serve until the RO tariff goes into effect, and service during this period would not count toward the members’ term limits, according to the committee’s proposal.

The committee has proposed that when the RO is fully implemented and has a seven-member board, two of the seats would be one-year terms; two seats would be two-year terms; and three of the seats would be full, three-year terms.

Staks noted that seating the five-member board in July, as opposed to a smaller board or seating at a later date, “will create a pretty significant increase in our budget.”

But the committee did not want the budget to be a “limiting factor for the important role that this independent body will play as we move forward,” Staks said.

“We decided that we would prioritize having some of these independent board members in place earlier, so that there really is that separation and independence for the negotiations with the CAISO,” Staks said.