Top 5 Stories from Utility Dive

The PJM Interconnection on July 30 announced that capacity costs will soar to $14.7 billion for the 2025/26 delivery year — the 12-month period that starts June 1 — up from $2.2 billion in the previous auction.

The next capacity auction for the 2026/27 delivery year is set for early December and there's no reason to believe the resulting prices won’t be at least as high, which could lead to about $30 billion in capacity costs over two years, according to Steve Lieberman, vice president of transmission and regulatory affairs for American Municipal Power.

“It's a mind boggling, staggeringly incomprehensible number,” he said.

The jump in capacity prices was primarily driven by power plant retirements, increased load and new market rules, according to PJM, which runs the grid and wholesale power markets in 13 Mid-Atlantic and Midwest states, and the District of Columbia. The auction drew 110 MW in new generation, down from 330 MW in the previous auction.

The auction results come as PJM has been warning it could face power supply shortfalls late this decade. At the same time, after delays in holding auctions, PJM is trying to catch up to its normal annual auction cycle for buying capacity three years in advance, Lieberman said.

The high capacity prices may lead power plant owners to delay planned retirements, but there isn’t enough lead time to respond by building new power plants, a process that takes years to complete, according to Lieberman.

“Houston, we have a problem,” he said. “If we don’t see new capacity in the [2027/28] auction, we’re really running out of time.”

So what are utilities, state lawmakers and utility regulators doing in response to the high capacity prices? Some utilities are seeking to get back in the power business while lawmakers are looking at ways to get generating resources online more quickly.

Deregulated utilities offer to provide power supplies

Investor-owned utilities operating in deregulated states such as Illinois, Maryland, New Jersey, Ohio and Pennsylvania contend they could be part of the solution.

In financial earnings conference calls after the auction results were released executives from Exelon, FirstEnergy and PPL said their utilities — which generally no longer own power plants — could help get new generation online to ensure PJM has adequate power supplies.

“I’d call yesterday’s [PJM auction results] the canary in the coal mine, and the canary didn’t make it,” Brian Tierney, FirstEnergy president and CEO, said on July 31.

Tierney doubts PJM’s capacity market will attract significant power plant investment into the region. “So it’s something we need to figure out,” he said. “I just don’t think the PJM construct is going to fix the issue even if it sends some positive price signals.”

Earlier this year, officials from Exelon, FirstEnergy, PPL and Duquesne Light sought a meeting with state utility regulators to argue that their companies could have a role helping ensure PJM has enough power supplies, according to Kent Chandler, a resident senior fellow at the R Street Institute.

They pressed their case in that meeting in February, which was held at the same time as the National Association of Regulatory Utility Commissioners’ winter policy summit, and Duke Energy and American Electric Power advanced the same talking points publicly at a June meeting of the Mid-Atlantic Conference of Regulatory Utilities Commissioners, said Chandler, whose term as chairman of the Kentucky Public Service Commission ended June 30.

“They’ve been laying the groundwork for this for a while,” Chandler said, noting that getting into generation would expand their ratebase, and thus their earnings.

But there didn't seem to be much interest amongst regulators in moving away from restructuring in areas of PJM, according to Chandler, former president of the Organization of PJM States Inc., or OPSI, which represents state utility regulators. “In my conversations with retail regulators, there does not seem to be much interest in shifting the risk of financing generation from shareholders to customers for the exclusive benefit of utilities,” he said.

Further, in many PJM states, lawmakers would likely need to pass legislation to allow utilities to get back in the power plant business, Chandler noted. “It will be an uphill battle for these states to reregulate,” he said.

State ratepayer advocates haven’t expressed interest in reregulating utilities, according to Greg Poulos, executive director of Consumer Advocates of the PJM States. “There is some reluctance to support that approach,” he said.

Generally, ratepayer advocates in PJM support competitive wholesale markets, but the auction results are eroding their confidence in the grid operator’s ability to run the markets, he said.

Certain flaws in PJM’s capacity construct, such as reliability must-run resources not participating in auctions, are magnified and will cost consumers billions as the grid operator returns to standard annual auctions for capacity three years ahead of time, Poulos said. The failure to include RMR resources in the auction added about $5 billion in costs to the last auction, ratepayer advocates said in an Aug. 30 letter to PJM.

State lawmakers eye bills to spur generation

Meanwhile, key utility-oriented state lawmakers in Maryland and Pennsylvania said they were open to the idea of giving utilities a role in power generation, but that they were focused on other avenues to help bring new power supplies online.

There are “reasonable conversations” about the pros and cons of reregulating the utility sector in Maryland, but it wouldn’t address near-term problems, according to Maryland state Delegate Lorig Charkoudian, a Democrat.

Instead, Charkoudian said she is focused on legislation that could pass in the Maryland General Assembly’s next session. She is considering introducing a bill aimed at adding energy storage to the distribution system as a bridge to more generation coming online in Maryland, she said.

Another option under consideration would modify the state’s solar renewable energy credit program to help advance ready-to-go solar projects, according to Charkoudian.

PJM’s auction results have been a “wake up call” for Maryland state lawmakers on related issues such as interconnection queue reform, reliability must-run contracts and transmission planning. “It has all come to a head in this capacity auction,” she said.

The auction results weren’t unexpected to Pennsylvania state Sen. Gene Yaw, a Republican and chairman of the Senate Environmental Resources and Energy Committee. 

“I think the handwriting has been on the wall for a couple of years as to where things are going to go,” Yaw said. “The PJM auction just kind of confirmed what a lot of people have been talking about with the supply situation.”

Thermal baseload power plants have been retiring in PJM without adequate replacements, according to Yaw.

It would be “reasonable” to consider letting Pennsylvania utilities back into the power supply business, he said.

However, Yaw said he is focused on two bills he plans to introduce: one that would create a revolving fund to support power plant construction and another to provide greater certainty to the state’s permitting process.

Maryland PSC eyes options

Maryland could be especially hard hit with rate hikes driven by the capacity auction, according to a mid-August report from the Maryland Office of People’s Counsel. It found that electric bills in Maryland could jump 2% to 24% depending on the location.

After getting over the “shock” of the auction results, utility regulators, officials from other state agencies and lawmakers are talking about how Maryland should respond to the spike in capacity prices, including how to possibly add in-state generating resources, according to Michael Richard, a commissioner on the Maryland Public Service Commission.

“Suddenly seeing a 500% to 800% increase in capacity prices, that is not indicative of a well functioning market. They need to look at their [market] constructs and do it quickly.” Richard said. “We know we need additional resources, but we need PJM to be a partner with us in getting these resources online.”

It would help to have increased transparency from PJM about where solar and storage would be most effective on the distribution system, according to Richard.

Richard said discussions about the capacity auction are also going on among state regulators at OPSI.

“There needs to be a consideration for the ratepayer,” Richard said. “We need some predictability in the market.”

North American Electric Reliability Corp. CEO Jim Robb spoke July 25 at the WIRES summer meeting, laying out the challenges and opportunities that a changing resource mix creates for the North American energy system.

“We are in a pretty amazing period of time for the electric grid, because of the pace of change that we're seeing, and the fact that it's coming at the grid from a number of different directions at the same time,” he said. “We're having to rethink a lot of things.”

Historical planning approaches are not as effective as they once were, as weather has become more extreme. Physical and cyber attacks are on the rise, while generation retirements are threatening reliability. Utilities see electricity demand rising for the first time in years, Robb said.

NERC was formed in 1968 to address issues related to a blackout three years prior that left 30 million people in the U.S. and Canada in the dark. For decades, the organization focused on the basics of utility operations, like vegetation management, situational awareness, training and communications, Robb said.

“And now we're into a lot of very frontier issues where we need to understand the science at the same time [that] we're trying to draft requirements — and that's obviously challenging all of us to rise to the occasion,” Robb said.

Here are five takeaways from Robb’s speech.

Another 100 GW of retirements could further threaten reliability 

NERC published its annual Long-Term Reliability Assessment in December, warning that rising peak demand and the planned retirement of 83 GW of fossil fuel and nuclear generation over the next 10 years creates blackout risks for most of the United States. In particular, the Northeast and Western half of the U.S. face an elevated risk of blackouts in extreme conditions, while parts of the Midwest and central South areas could see power supply shortfalls during normal peak operations.

The next LTRA will likely show the risk is growing, as new data center loads are added into the assessment, Robb said. Electricity demand from data centers could double by 2030 to consume 9% of U.S. electricity generation, according to the Electric Power Research Institute.

And NERC is aware of another possible 100 GW of capacity at risk of retirement in the PJM, Mid-Atlantic and South areas.

Right now those areas are characterized as having a “normal energy risk,” but the next LTRA “will almost certainly put those areas into the high-risk category if those retirements get solidified,” Robb said.

2 TW of capacity in interconnection queues

While increasing thermal retirements are driving reliability risks, renewables developers are working to bring on new resources quickly. Interconnection queues are “now twice the size of the existing resource base of the country,” Robb said.

There are about 2 TW of projects looking to connect to the grid, though there is some double counting in that figure, he said. Meanwhile, existing capacity today is about 1 TW.

“That 2-to-1 ratio is stunning ... Typically, the aggregate interconnection queues are about half to a third of the installed base,” Robb said. “So that shows how much investor interest there is in new generation resources,”

And the vast majority of the proposed projects are wind and solar, “with a smattering of batteries, a little bit of gas, no coal, no nuclear of any consequence, and no hydro. So it's very, very clear that as we move forward, the lion's share of new additions we'll see on the grid will be largely variable resources,” Robb said.

Electric-gas coordination is vital

The transition to a renewables-heavy resource mix will require natural gas generation and greater coordination between the gas and electric systems, Robb said.

“It's not that I love natural gas so much, but I really love natural gas generation,” Robb said, pointing to its ability to operate reliably and flexibly on a dispatchable basis.

“We need to be paying really, really close attention to securing the balancing resources to integrate variable resources reliably,” he said. “Long term, we may come up with a long-duration battery technology that can be used. Hydrogen in some areas may play a role in that. But right now, really the only way to deal with that is natural gas.”

That means the gas and electric systems must work in tandem, he said.

“We think of these two systems as being increasingly interdependent and interconnected, not just two parallel systems that happened to grow up together and have some marriages of convenience,” Robb said. “They're now intimately linked ... electricity is now 40% of gas consumption in the U.S.”

Grid faces a ‘toxic soup’ of security threats

Along with risks related to the clean energy transition, cyber and physical threats are growing, Robb said.

“We're living in an absolute toxic soup of security threats,” he said. “And I think over the last four years, the threat environment, both for physical and cybersecurity has really changed.”

Utilities must defend against the “big four” nation state adversaries of Iran, China, Russia and North Korea and the organized cyber criminals that they sometimes sponsor, Robb said. And then there are the “punks, thugs and crooks” focused on ransomware and physical attacks.

The cyber risk is “driven by the fact that we have software embedded everywhere [but] we rarely know exactly where the coding came from,” he said. The National Institute of Standards and Technology publishes a list of vulnerabilities and it is averaging about 60 entries a day, Robb noted.

Once a vulnerability is published, chief information security officers must determine the extent of the exposure and how to mitigate it, at the same time hackers look for ways to exploit it. “It becomes a foot race, to figure out how to defend against it while [hackers] are trying to figure out how to exploit it,” Robb said.

There has been a similar threat shift on the physical side, Robb said. Substation attacks in Moore County, North Carolina, knocked out power to about 40,000 customers in December 2022, and similar incidents have been seen in Idaho and Washington.

“The ability of adversaries to physically attack different pieces of infrastructure, and be able to create a wider spread event, is of increasing concern,” Robb said. “So we have to be paying really, really close attention to physical and cyber [security] hygiene.”

Transmission study a ‘bigger beast’ than anticipated

NERC, at the direction of Congress, is in the process of developing an interregional transfer capability study that will be delivered to the Federal Energy Regulatory Commission by December 2. Following that, NERC will produce an analysis in the first quarter of 2025 to evaluate transfer capabilities from the United States to Canada and between Canadian provinces.

“This turned out to be an even bigger beast than we thought it was when we started,” Robb said. NERC published an initial report on the study in June, providing context and study details. 

“What we're looking at is not trying to optimize price or cost, but looking at optimizing reserves,” Robb said. “The challenge with interregional transfer assessments is that it really has a little bit to do with the wires but it's got a lot to do with the generating resources in the various planning areas and the loads and the nature of the weather patterns that we're dealing with.”

NERC is doing scenario analysis, using historical data on big storms to pressure test the system. “We also have to forecast where we think new generation will come in and what it will look like, and how it would be impacted by those weather systems,” Robb said. 

Early insights from the work show that regional transmission capacity is very different in summer and winter, and it's not very evenly distributed, he said. NERC plans to publish another report in August that will lay out the current transfer capability, and then around November will disclose where additions are likely to provide value.

“There's not going to be a lot of time from the time we ... publish our draft report to when we have to file it at FERC. So I'm encouraging everybody to try to engage in the webinars that we're having to get points of view across earlier rather than later because there's not going to be a lot of review time,” Robb said.

The still growing backlog of generation projects in U.S. transmission provider interconnection queues may soon be relieved by emerging innovative solutions.

Proposed generation and storage awaiting interconnection is about twice the estimated 1,280 GW of U.S. generation capacity, according to an April Lawrence Berkeley National Laboratory report. And while projects built before 2015 had taken “about 17 months” to go from application to operation, that time was “approaching 5 years for projects completed in 2022-2023,” the report said.

But in response to Federal Energy Regulatory Commission Order 2023, approved in July 2023, U.S. transmission providers and system operators have been developing new solutions.

FERC Order 2023 established some important new requirements for interconnection that update a 20-year-old process, said LBNL Energy Policy Researcher Joseph Rand. “It prioritizes more viable projects that have met readiness criteria and imposes financial penalties that require both transmission providers and system operators to step up their game,” he added.

But FERC’s order only begins to address the streamlining of the project interconnection process needed to meet newly growing loads, regulators and stakeholders agree.

Order 2023 “is an important step forward in the effort to address interconnection backlogs,” wrote former FERC Commissioner Allison Clements in her concurrence to its approval. But transmission providers, interconnection customers and other stakeholders should “consider the rule’s requirements a strong baseline and not a ceiling,” and develop further reforms, she added.

The Texas “connect and manage” streamlined interconnection option may prove viable in its energy only market, analysts said. And SPP’s work to link system planning with the interconnection process across its multi-state region could be a breakthrough in reducing queue backlogs when it is complete, they added.

California, with its just-approved interconnection enhancements, leads the innovation because it is already linking transmission planning and generation procurement with the project interconnection process, stakeholders agreed. But scoring of projects’ viability, commercial readiness and system value may not balance the needs of utilities and developers and may impede meeting load growth, some said.

California’s innovative enhancements

The CAISO Board voted 5-0 on June 12 to move ahead on identifying and prioritizing project interconnection where planning shows “transmission capacity exists or new transmission has been approved,” according to the just-approved plan. The enhancements are designed to interconnect projects with the most operational readiness and commercial and system value, the board added.

CAISO’s plan identifies “zones” where transmission capacity is available or will be built, said CAISO Principal of Infrastructure Policy Development Danielle Mills.

This zonal approach “is the cornerstone of the whole reform effort,” and other “procedural reforms” are to “enable the new approach,” Mills said. The plan guides developers to “transmission plan deliverability” zones with available transmission identified in CAISO planning, and gives utilities and other load-serving entities, or LSEs, incentives to procure those projects, she added.

Projects will earn 35% of their total “score” based on viability criteria, such as control of the proposed site and completeness of the engineering design. The project’s value as system-wide or local resource adequacy will determine another 35% of its score.

Demonstrated commercial interest by LSEs in a project will determine the remaining 30% of the score, though that could give LSEs negotiating leverage over developers who need LSE interest to score higher, both CAISO and stakeholders acknowledged.

In each zone, CAISO will select projects with the highest scores to study in detail, with the project’s value to the zone’s local distribution system as the first tiebreaker, Mills continued. For projects still tied, “the developer willing to pay more in a sealed-bid auction to have an interconnection study done wins and moves its project into the study process,” she said.

Developers of generation and battery system projects can also apply to interconnect where there is no available or planned transmission capacity, CAISO said. The developer must finance all network upgrades needed for the interconnection, and only some of the upgrade costs are eligible for cost recovery, it added.

These procedures limit CAISO studies “to the most viable projects,” but will include projects totaling 150% of the available transmission capacity to ensure LSEs have an adequate selection to procure from, Mills said. “That is the most original piece of the new process, because it ensures enough new generation to meet state goals but limits the interconnection queue to prevent backlogs,” she added.

The new enhancements bring dramatic if imperfect changes to a process that urgently requires reform to manage the interconnection queue and meet the state’s energy transition goals, CAISO’s Board of Governors agreed in its unanimous approval of the plan.

Two controversial questions

From early in the enhancements’ development, LSEs and developers debated the fairness of the influence provided to LSEs regarding projects’ commercial interest score.

An LSE could leverage its influence in the viability of a project through the expression of commercial interest to get exclusive rights or a lower off-take price from the project’s developer, said Phoenix Consulting Principal and Manager Susan Schneider, a consultant to the Large Scale Solar Association, which represents solar developers.

“CAISO is encouraging stakeholders to communicate about the projects,” but “there are no guidelines or regulations for LSE scoring of projects,” Schneider continued. Filings by large developer advocate and clean energy trade group American Clean Power Association and the Clean Energy Buyers Association supported Schneider’s concerns.

The lack of strong guidelines for LSEs has already led to LSEs trying to extract concessions, said Ryan Millard, west region senior director, regulatory and political affairs, for independent power producer NextEra Energy Resources, during the June 12 Board of Governors meeting.

An LSE recently told NextEra that “to secure LSE point allocations, developers will need to grant a right of first offer and submit a $5 per kilowatt deposit to secure that right of first offer,” Millard said. For “a 300 MW storage project, that's a $1.5 million deposit that we would need to post 10 years before [the] expected beginning [of] construction just to enter the queue,” he added.

CAISO will “monitor the new processes for potential manipulations,” but it is up to state and local agencies to regulate procurement, responded CAISO President and CEO Elliot Mainzer.

Pacific Gas and Electric and Southern California Edison insisted regulatory oversight will protect developers and ratepayers.

There is an “urgent” need to process the interconnection backlog, and commercial interest is “essential,” said Ed Smeloff, consultant to the Center for Energy Efficiency and Renewable Technologies. “There are adequate governance structures to assure project developer concerns will be heard by the LSEs,” he added.

CAISO has over 500 GW of interconnection requests, “10 times more than its roughly 50 GW peak load,” which has kept its focus on reducing the queue, said LBNL Energy and Environmental Policy Research Scientist and Engineer Will Gorman. 

But available transmission may not accommodate California’s forecasted load growth of eight GW per year, some stakeholders said.

Many of the 541 projects in 2023’s Cluster 15 could be lost because available transmission plan deliverability zones will be taken up by the over 300 projects in the 2021-22 Cluster 14, said LSA consultant Schneider. And to interconnect projects where there is no remaining transmission capacity, “merchant developers would need to fund expensive upgrades and face the risk of not being reimbursed,” she added.

A June 14 CAISO report showed approximately 30 GW of transmission plan deliverability zones was allocated to Cluster 14 projects, said CAISO Vice President of Transmission Planning and Infrastructure Development Neil Millar. Some 30 GW or more of pre-Cluster 14 projects also received allocation, and the more than 60 GW of allocated transmission plan deliverability should allow meeting projected load growth and policy goals through 2030, he added.

“An additional level of analysis will be available in August to show what transmission plan deliverability is left for Cluster 15 projects,” Millar said. But “LSEs ultimately do the procurement that allows these projects to move forward,” he added.

The CAISO enhancements “reflect the reality of queue backlogs,” former FERC Commissioner Clements told Utilty Dive. “The solution is not neatly penciled out yet, but California is trying to find that path.”

Other innovations are even less developed, observers said.

Three alternative innovations

California’s enhancements “are probably the most substantial changes from the status quo interconnection process in the country,” said LBNL’s Gorman.

But to comply with Order 2023, other ISOs RTOs, and transmission providers have been developing new approaches.

The Southwest Power Pool plan to integrate planning, procurement and interconnection is still a year from going before FERC for approval, according to Steve Gaw, senior vice president for infrastructure and markets with the Advanced Power Alliance and a member of several SPP advisory committees. “It is designed to avoid the time and costs of redundant studies,” by using planning and procurement results to inform the interconnection process, Gaw said.

The concept is like California’s enhancements but is “more challenging to achieve” across SPP’s 14 states, Gaw continued. Specifically, the RTO’s Strategic and Creative Re-Engineering of Integrated Planning Team faces “the challenge of allocating costs for transmission upgrades,” he said.

But “SPP has a history of diverse states working together, and in this new moment of load growth and the need for new resources, utilities and states are more inclined to be cooperative,” said former FERC Commissioner Clements.

Developers in the Electric Reliability Council of Texas system can interconnect projects without incurring system upgrade costs if they are willing to incur the costs of curtailments. Called “connect and manage,” it is “a relatively fast and consistent interconnection process,” according to a February 2024 paper by Grid Strategies and The Brattle Group.

Introduced in the U.K. in 2010, connect and manage has allowed Texas to lead the U.S. in bringing new generation online in 2021 and 2022. 

But “proactive transmission planning is needed to manage congestion,” said Grid Strategies Founder and President Rob Gramlich. And “because Texas renewables still face significant congestion and curtailment, some developers are critical of connect and manage,” he added.

The Texas interconnection success “is compelling evidence” that connect and manage can work in an energy-only market but may not work “in non–energy-only markets,” according to a 2023 Nicholas Institute paper. It would be especially difficult to replicate in multistate RTOs, because of cost allocation and resource adequacy and capacity requirements, the paper added.

No region outside of Texas is moving toward connect and manage right now, but researchers are studying ways to “delink resource adequacy from the interconnection process,” said LBNL’s Gorman.

These and other interconnection innovations are vital because “our nation is facing a grid infrastructure crisis,” former FERC Commissioner Clements wrote in her concurrence to Order 2023. The order’s changes “will help to ameliorate interconnection backlogs, but are inadequate, on their own,” she added.

As the Biden administration aims for a U.S. net-zero emissions economy by 2050 and works to deploy up to $1.6 trillion in climate and infrastructure funding, efforts to update the permitting process for renewables, transmission and other projects are catalyzing intense debates, sometimes between those typically allied on policy issues.

Clean energy groups generally support streamlining the permitting process to accelerate the deployment of renewables, storage and other resources and help mitigate the immediate effects of climate change. But many environmental groups oppose permitting reforms that could also benefit the fossil fuel industry, or weaken the National Environmental Policy Act.

“[NEPA] has been seen as a vanguard for environmental justice communities,” said Anthony Rogers-Wright, a racial and climate justice advocate who has worked for ICF International and the New York Lawyers for the Public Interest. “It doesn't even go far enough, but it's still seen as a first line of defense for cultural communities and indigenous communities as well. And to see that being tampered with now — it's like, for some, almost akin to tampering with Social Security.”

The high stakes of this conflict have “brought us to this phase where we're starting to see a lot of headbutting and a lot of lines being drawn, and philosophies and approaches that come with those respective lines,” he said.

From an environmental justice perspective, removing roadblocks to permitting and siting projects could endanger communities that are already burdened by pollution, advocates say.

“In some cases, we do want these analyses to be long. We don't want them to be rushed. We're talking about critical resources, and activities that require disturbing soil and disturbing landmasses,” said Rogers-Wright.

Costs, delays and uncertainty

Advocates for permitting reform, on the other hand, argue that the current demands placed on project developers can not only be burdensome but unhelpful to the communities they’re supposed to protect.

In a 2022 analysis, the Institute for Progress argued that NEPA in its current form “imposes massive costs on the federal government, drags clean energy projects out for years, and generates uncertainty that stops other projects from ever getting off the ground.”

Alec Stapp, a co-founder and co-CEO of IFP and one of the authors of that report, said he advocates for a “strong” permitting process that also offers certainty and efficiency. 

“I think you could describe a strong permitting process as one that provides a quick and informed answer on whether a project has government approval to be built — a very swift and certain ‘yes’ or ‘no’ on whether you can build this project,” he said.

Stapp said that an efficient permitting process with imposed time limits would be “strong,” but “antithetical to what the environmental activism groups want, which is a tool that they can use to stop projects that they don't like.”

Those groups want it to be “easy to leverage [the permitting process] to stop bad projects that they don't want built at all,” he said — projects like “pipelines, new natural gas facilities, and export terminals.”

Stapp said he supports the use of categorical exclusions to the NEPA environmental review process — a category which the Environmental Protection Agency defines as “actions that a Federal agency has determined, after review by [the White House Council on Environmental Quality], do not individually or cumulatively have a significant effect on the human environment.”

In April, the CEQ finalized a rule to update the federal environmental review process under NEPA, including “new and more flexible methods for agencies to establish categorical exclusions to speed up low-impact projects” such as solar, electric vehicle charging infrastructure and transmission, the White House said in a release.

Earlier that week, the Department of Energy had issued a final rule establishing the Coordinated Interagency Transmission Authorization and Permits, or CITAP, program, which will make DOE the lead agency handling permits for new transmission projects. 

Congress is also tackling permitting reform, with 10 bills introduced in this session alone, but the bills have struggled to advance despite bipartisan calls for action. Sens. Joe Manchin, I-W.Va., and John Barrasso, R-Wyo., announced May 21 that they would soon share a new draft of bipartisan permitting reform legislation with colleagues.

Manchin remarked that the Federal Energy Regulatory Commission’s recently-issued transmission planning and cost allocation reform rule was, “as my friend Senator Hickenlooper said … ‘a Band-Aid on Congress’s inaction.’”

Stapp said he wants to see reform that ends “the litigation doom loop that all kinds of projects are trapped in right now.” He noted his concerns about the uncertainty faced by project developers and their financiers, as well as lingering questions about the fate of the massive investments represented by the CHIPS Act, the Infrastructure Investment and Jobs Act and the Inflation Reduction Act.

“Is that money turning into steel in the ground?” he asked. “Are projects actually being built in the real world? Or are these just large dollar contracts that have been spent, but are now stuck in permitting purgatory? .... We by no means have final answers here, but we are starting to see some warning signs.”

Stapp added that the president himself “has been reported to be concerned that there’s not enough groundbreakings for new projects that are funded by the infrastructure bill or the IRA.”

“I share those concerns — like, where are the real projects?” he asked. “There's lots of investment. But there seems to be quite a lag in terms of actual real world deployment.”

Rogers-Wright said he thinks there is a political element to permitting reform supporters “on the liberal side of environmentalism ... because many of these people have staked their reputations” on the IRA with “very, very little time to show that it is actually beneficial and efficacious, because there's an election coming up in November.”

Community input and environmental justice

Denae King, an associate director and researcher at Texas Southern University’s Bullard Center for Environmental and Climate Justice, said permitting reform is a priority and the center is “really grateful” for the White House and EPA’s recent moves on the issue. However, thorough environmental reviews remain “extremely important,” she added.

“Oftentimes, in environmental justice communities, there are already several sources of industrial pollution, or sources of contaminants in air or water,” she said. “So really understanding cumulative impacts is becoming more and more important, and this permitting reform does that. I think the other thing that it does is promote meaningful public input.”

The new rule from the White House removed NEPA provisions that it says “created litigation risks and jeopardized community input” by “removing detailed and onerous requirements on what public comments must contain to be considered by agencies” and “removing provisions that attempted to curtail judicial review.”

King said that the public comment period for projects in development is often “short and not well advertised. So by the time [communities] actually get to have some input, it's not necessarily valued at that point…. After the developer has drawn a full map and already decided how the facility is going to be placed and located, it's a little too late to ask the community.”

That disadvantages both developers and communities, she said, as the former may end up sinking costs into an ultimately untenable project.

“Community members are experts,” King said. “They really have a good grasp on what's happening in their community, both in terms of their routes of exposure, and what kinds of health impacts they're seeing in their school, in their neighbors.”

Renewable project opposition

When it comes to the permitting of wind and solar projects, visual and noise complaints often drive community opposition, according to a May 22 report from the The Hamilton Project. 

The report cites a 2023 paper from David Adelman, the Harry Reasoner Regents Chair at the University of Texas at Austin School of Law, which found that “litigation pressures against offshore wind [have] occurred in northeastern rural communities where residents place a high premium on protecting local landscape.”

“Other times, the renewable energy transition threatens existing local economies,” the report noted. “In Kentucky, coal is the most powerful political incumbent, in part because mining supports thousands of workers and their families each year.”

Chirag Lala, director of energy at the nonprofit Center for Public Enterprise, said he views the permitting reform issue as one of efficiency — making sure that community-level input flows upward in a way that lends itself to the best decision-making possible.

“The problem isn't stakeholder engagement,” Lala said. “And I do think there are some groups engaged in the permitting reform debate who either explicitly or border on suggesting that stakeholder engagement is the problem. It’s very much not.”

In an ideal world envisioned by CPE, Lala said there would be “a lot more” automatic permissions for projects, categorical exclusions, and “situations where public agencies are often in a privileged position to either gain the permitting and siting permissions that they need, or certainly to choose certain types of private projects that can get automatic or expedited permissions.”

“But, crucially, we don't see the fact that these communities need and want to raise certain concerns about how investment processes are going as itself the obstacle,” Lala said. He said existing permitting processes are what “is not servicing their needs in that respect.”

Lala suggested that issues such as environmental justice concerns, pollution cleanup and the employment of local workers can be addressed by policy mechanisms other than the permitting process itself. 

“But I think there is also just quite a bit of distrust out there over what the terms of permitting reform will be, and where they will head from here,” Lala added.

Both Lala and Stapp suggested that “veto power” legal mechanisms like injunctions have the potential to threaten community benefit agreements reached between communities and developers, even when the “veto power” is being exercised by a third party like an environmental group. 

In a process with no backstop authority, Lala said, “when different groups engage in that process, they do so knowing that just the very fact that they are filing a particular piece of paper, raising a particular objection, or attending a particular meeting could in and of itself create enough friction for a project not to go through.”

“Whereas if you have an entity that can intervene in the process at a certain point and just say, ‘Look, this is going through, everybody has said what they needed to say’, that changes certain actor incentives in that process,” he said.

Rogers-Wright, however, said he fears a shift to a more unilateral decision-making process would disenfranchise those who are directly impacted by those decisions.

“When you don't have a voice, when you're not a part of the process, you tend to be sacrificed,” he said. “If you speed the process up, that means you're going to be reducing [input] vastly — and that's already problematic, right? It’s not like so-called public participation is at an optimal level.”

TerraPower plans to begin construction this summer at the site of what’s now expected to be the United States’ first commercial advanced nuclear power facility near a coal-fired power plant in Kemmerer, Wyoming. 

Though TerraPower’s reactor isn’t expected to begin operations until 2030, Wyoming began laying the groundwork for TerraPower in March 2020, when Gov. Mark Gordon, R, signed a bill allowing small modular reactor capacity to replace coal generation capacity. State laws streamlining advanced reactor deployment and enabling up to $150 million in matching funds for a range of energy technology deployments followed in 2022 and 2023.

“Wyoming has done a terrific job” to support advanced nuclear deployment, David Terry, president of the National Association of State Energy Officials, said in an interview.

Wyoming was an early mover on advanced nuclear, but industry experts say other states are catching up. State legislatures considered about 200 nuclear-friendly energy bills in 2023 and have already looked at about 130 this year, said Christine Csizmadia, senior director for state governmental affairs and advocacy at the Nuclear Energy Institute.

“It used to be maybe five to ten [state] bills each year that would even mention nuclear,” Csizmadia said in an interview.

In addition to Wyoming, Michigan and Virginia stand at the forefront of resurgent state interest in nuclear energy. Michigan put $150 million last year toward Holtec’s potential restart of the recently shuttered Palisades generating station, which subsequently received a $1.5 billion conditional loan commitment from the U.S. Department of Energy. Virginia’s recent pro-nuclear moves include state funding for an energy “career cluster” and a state-supported energy lab that could enable deployment of advanced nuclear reactors near former coal mines. 

These states’ efforts point the way for policymakers elsewhere to attract emerging nuclear technologies and the skilled workers they need to operate, Terry said.

“There are no regional voters, only state and local voters” he said. “So states need to [enact state-specific policies] that bring jobs and attract investment” within their borders. 

Four pathways for state nuclear policy

State nuclear policy generally takes one of four complementary forms, Csizmadia said:

Moratoria repeal and advanced nuclear regulation

Six state legislatures have lifted freezes on new nuclear facilities since 2016, leaving 10 states with bans still on the books. Hawaii and Rhode Island could lift their nuclear bans this year, Csizmadia said. State legislatures may also need to update regulations to allow specific advanced nuclear demonstration projects to proceed as proposed, said Betsy Smith, policy specialist for environment, energy and transportation at the National Council of State Legislatures, in an email to Utility Dive.

Including nuclear in clean energy standards

Several states have recently enacted or expanded clean energy standards that incorporate nuclear energy, rather than remaining silent on nuclear or specifically excluding it, Csizmadia said. They include Michigan, Minnesota, North Carolina and Utah, according to NEI’s state policy tracker. 

Exploring nuclear development

This is the broadest and most active category at the moment, encompassing technology feasibility studies, working groups and stakeholder councils commissioned and funded by state governments, Csizmadia said. Recent and ongoing examples include Michigan, Kentucky, Tennessee, Ohio and South Dakota, among other states. “Some of these states lack existing commercial nuclear power facilities and want to see if it’s feasible for them,” Csizmadia said. 

Financial support or incentives

Some states have committed significant funding to nuclear energy beyond the relatively modest cost of nuclear feasibility studies, Csizmadia said. At $150 million, Michigan’s commitment to support Palisades’ restart was the most significant toward a single nuclear project in the past several years. But other states, including Virginia (up to $10 million), Tennessee ($50 million) and Wyoming (up to $150 million in matching funds for a broad range of technologies that includes nuclear) have recently enacted or proposed sizable financial commitments for nuclear.

States can lay the groundwork for new or revitalized nuclear industries by including nuclear in clean energy standards and repealing bans, NASEO’s Terry said.

But even with tangible financial commitments from elected and appointed officials, pro-nuclear state policies’ payoff can take years to arrive, Virginia Department of Energy Director Glenn Davis said in an interview. 

Virginia began its “moonshot” journey with the creation of the Virginia Nuclear Energy Consortium’s predecessor organization in 2013, gained momentum with a flurry of pro-nuclear laws passed last year and now aims to have its first SMR online in 2032 while “leading the nation in new nuclear development,” Davis said.

The role of energy communities and industrial sites

TerraPower’s first commercial reactor will sit a mile or two from the Naughton coal-fired power plant in a community with a “high energy IQ,” TerraPower Director of External Affairs Jeff Navin said in an interview earlier this month. 

It’s the first commercial advanced nuclear project to take advantage of what the DOE believes is a tremendous opportunity to transition coal communities toward nuclear and other low-carbon energy technologies — a key focus for Wyoming and other states. The DOE predicts that a larger coal-to-nuclear project could directly create over 100 additional jobs at the plant and indirectly support several hundred more, a lifeline for energy communities in a decarbonized future.

However, David Eskelsen, spokesperson for Rocky Mountain Power, which partnered with TerraPower on the Kemmerer reactor, cautioned that the utility’s consideration of other coal-to-nuclear conversions is “in the very early stages of feasibility study and not certain at this point.” Eskelsen noted that Rocky Mountain Power’s resource planning process “does not pick specific projects, but rather a portfolio of resource types over a 20-year planning horizon.”

Still, with declining coal revenues and volatile oil and gas prices, Wyoming is adopting an “everything we have” mentality around energy, Wyoming Energy Authority Executive Director Rob Creager said in an interview..

“We are a strong coal state that has seen challenges with the coal markets,” Creager said. 

Wyoming is also working to support nuclear suppliers and upstream businesses in and around fossil-dependent communities, with the mindset of “‘How can we get [nuclear] done from cradle to grave,” he added. 

In August, the Wyoming Energy Authority earmarked $10 million in state matching funds to support potential partnerships between nuclear fuel and components supplier BWXT Technologies and two Wyoming companies, including Gillette-based heavy equipment manufacturer L&H Industrial. 

Using nuclear as an economic revitalization tool is a priority for other historically fossil-dependent states, such as Virginia, where the southwestern coal patch is a focus of advanced nuclear efforts.

The Virginia Department of Energy’s Davis pointed to the recently announced Microsoft-Google-Nucor 24/7 clean electricity RFI as an opportunity for advanced nuclear power in southwestern Virginia, where a state-funded feasibility study last year identified seven promising SMR sites on or near decommissioned mine lands and the state-supported Energy DELTA Lab will “deploy innovative and clean energy technologies,” including nuclear, that could support hyperscale data center and low-carbon hydrogen production clusters.

By supporting clean local and behind-the-meter generation, the lab’s work could help reduce the need for new transmission lines in the already-congested PJM Interconnection region, Davis said.

“That challenge is easier to solve with behind-the-meter energy generation,” he said.

Building a nuclear workforce

Workforce development is an important piece of pro-nuclear state policy, experts and officials say. In part, due to the unique skills and sometimes extensive training required for key nuclear roles, there’s “healthy competition between states to set up these early [advanced nuclear] projects” as states work to attract existing nuclear-industry workers and train new ones at local colleges and universities, Creager said. 

“I joke with my friends in other governors’ offices that I’ll tell you what we’ve done [in Wyoming], but I’m not sure I’ll tell you what we’re going to do next,” he added.

Even places like Virginia, with BWXT’s world headquarters, several commercial nuclear generating stations, a world-class nuclear engineering program at Virginia Tech and “40 [naval] reactors sitting off the coast,” need to invest in nuclear workforce development, Davis said.

He cited the state legislature’s move in 2019 to create an “energy career cluster” that includes nuclear and the Virginia Nuclear Innovation Hub’s expected partnerships with the University of Virginia, Virginia Tech, Virginia Commonwealth University and Liberty University. The Nuclear Innovation Alliance expects the cluster to “support the next generation of engineers, experts and technologists.”

States can turn to the federal government for help on skilled workforce development, NASEO’s Terry said. The DOE’s Nuclear Energy University Program supports “higher-skill areas” like nuclear engineering, while the Inflation Reduction Act and Infrastructure Investment and Jobs Act include funding for nuclear higher education, he noted.

By contrast, state energy offices tend to take the lead on establishing technician-type roles, Terry said. 

In states farther along in the process of attracting advanced nuclear generation, workforce development can happen in partnership with — or even at the initiative of — the operators themselves. TerraPower is “moving as fast as possible” to stand up nuclear education programs at the University of Wyoming’s School of Energy Resources and several community colleges across the state, Creager said.  

TerraPower hopes to retain at least some of the Naughton workforce to staff its Kemmerer reactor, Navin said last month. More than existing transmission infrastructure and water rights, the presence of skilled workers who understand the energy business was a key factor in TerraPower’s siting decision, he added.

The workforce synergies between prior and potential future site operations are even stronger in southwest Michigan, where the Palisades nuclear facility’s closure affected nearly 600 employees, said Kara Cook, chief of staff of the Michigan Department of Energy, Great Lakes and Environment. 

Many Palisades employees left the area after the plant closed in 2022, in some cases to find work at other nuclear facilities, Cook said. But now that the decommissioning process is on hold, some are returning or even coming out of retirement to help with worker retraining, she added. 

Like TerraPower in Wyoming, Holtec is taking the lead on workforce development at Palisades, conducting training exercises in “an amazing simulator that is an exact replica of their operations room,” Cook said. 

“Every state is different”

Wyoming, Michigan and Virginia have each made progress in establishing, expanding or revitalizing their nuclear industries, but the examples they set may not apply everywhere.

In some states, policymakers remain ambivalent about nuclear energy. A legislative proposal to repeal Oregon’s nuclear moratorium failed last year amid grassroots opposition, while a Colorado Energy Office official expressed skepticism about a proposed coal-to-nuclear conversion at the Comanche 3 coal-fired generator in Pueblo, which is set to retire in 2031.

“Current evidence suggests the high costs of nuclear makes it unlikely to be a major contributor to generation in Colorado any time soon,” Colorado Energy Office Communications Manager Ari Rosenblum said in an email. Rosenblum cited a recent analysis showing Colorado’s least-cost grid decarbonization pathway to be “significant wind, solar and storage and using gas generation as a reliability and capacity resource.”

North Dakota policymakers and utility officials, meanwhile, are looking to stand up a $1.4 billion carbon capture and sequestration project to curtail emissions at the state’s third-largest coal-fired power plant as soon as 2028 — before TerraPower’s Kemmerer reactor is expected to come online. 

“We looked at carbon capture [rather than coal-to-nuclear] because we have better resources for it here in North Dakota than anywhere else,” including favorable local geology and seismic stability, Ben Fladhammer, communications manager for plant operator Minnkota Power Cooperative, said in an interview.

“Every state is different and they deserve the right to choose,” NEI’s Csizmadia said. But for states that are serious about supporting next-generation nuclear, she has some straightforward advice for policymakers: “Start planning today.”

“If you commit to a reactor today, it’ll take eight to ten years to happen,” she said.