Nuclear energy has been an important part of the U.S. generating mix for more than 50 years. Many of the units still in operation today (which surpass 100,000 MW capacity) were built in the 1970s and 1980s and continue to provide a plurality of the country’s non-emitting electric generation.
While the existing fleet has been maintained and enhanced over the years, a lot of research and development has been poured into creating a new generation of nuclear generating technologies that operate more efficiently, have passive safety features, and make a smaller footprint than the older facilities.
Meeting New Demand
Marcus Nichol, executive director of new nuclear at the Nuclear Energy Institute, said that the demand for new nuclear for electric generation in the U.S. is anywhere from 100 gigawatts to 300 GW by 2050. The 100 GW estimate comes from a survey NEI conducted of its members to assess future needs, and Nichol suggests that when factoring in all the other applications for advanced nuclear, such as microreactors for mining, the demand is much larger.
Driving this demand are a growing number of state and utility plans that view advanced nuclear as a key to being able to transition away from fossil fuels. Another driver, he noted, is the rapid load growth from data centers and manufacturing. And nuclear facilities, said Nichol, are designed to meet rapid increased in load growth.
Nichol said that many states have made moves in recent years in support of nuclear, whether that’s through repealing moratoria on building new nuclear, commissioning studies about its potential, or providing incentives to deploy new reactors.
Nichol noted that many of the roughly 30 advanced nuclear projects already in development in North America means that the U.S. is ahead of most countries in deploying the technology. He said that the interest in seeing these projects launch isn’t just within the U.S., but that other countries are also wanting to see the technology demonstrated in the U.S. before they deploy their own projects. Once the initial set of small modular reactors are deployed, Nichol said the pace of deployment will need to be between 10-20 reactors becoming operational per year.
Successful early deployments will improve the conditions for others to follow to help reach the projected demand, said Nichol. Part of this success is overcoming the barrier of simply being first.
“First of its kind of any technology is almost always more expensive,” he said. For advanced nuclear, part of what drives costs is whether the regulatory environment or market structures make the economics less favorable. He said the lack of policies at the federal and state level to address some of the risks involved with advanced nuclear is part of what contributed to the cancellation of NuScale’s Carbon Free Power Project. Nichols doesn’t see that cancellation as having affected the momentum for SMRs, though. He also recognizes that every project has contributed to the mutual understanding of how to deploy such projects.
“The industry is actually being proactive to help reduce the risk for future projects,” he shared. This includes sharing construction best practices and other lessons from previous projects that can inform development of implementation guides.
A particular project he is watching closely is Ontario Power Generation’s Darlington project, which plans to have four SMR units when completed. He said site work is already underway for the first unit and that it has “cleared all of the business case hurdles.”
“There are a lot of opportunities for public power to play in advanced reactors,” said Nichol. “Public power has a lot of choices about how they incorporate it into their portfolios. Some may find it is better to go on their own and partner with an experienced operator. Others may want to partner with other public power providers to share risk. Others may look at it and see if they can be a power offtaker.”
In any case, said Nichol, “It's important to start thinking through those decisions early, to be able to figure out the strategy. Companies could find out overnight that the policy environment has been created for [advanced nuclear] to make a lot of sense, so they should be able to act quickly.”
A New Era
The latest nuclear capacity to come online in the U.S. are two new units at Plant Vogtle in Georgia. Before the new Vogtle units came online in 2023 and 2024, there had only been one other new nuclear facility opened in the U.S. since the 1990s. The new Vogtle units, 3 and 4, are also the first in the U.S. to use the advanced AP1000 reactor, which has a simplified design, smaller footprint, and enhanced safety features compared to more traditional reactors.
MEAG Power is a 22.7% owner of plant Vogtle, meaning that the Georgia-based joint action agency has been involved in the major development decisions for Units 3 and 4 on behalf of its member communities participating in the project.
Jim Fuller, president and CEO of MEAG Power, said that getting the units built and operational is not only a major step forward for the nuclear industry, but comes at a time when demand for electricity is accelerating.
“At the time we were considering involvement in the Plant Vogtle expansion in 2005-2006, there were growing concerns over reliance on fossil fuels and natural gas prices were hitting record-highs. In addition, our future sources of baseload generation were facing uncertainty,” he said, explaining that some of their existing nuclear units were facing operating license expirations in the 2030s, and that federal climate legislation and regulation meant rising costs and potential closure if its coal resources.
“Back then, excitement built around a renaissance of nuclear power in the U.S. as a key solution to these challenges,” he said. “We’re seeing that same enthusiasm rise again for nuclear.”
Not that the Vogtle project has been without challenges.
“The project has faced numerous challenges including multiple changes in the lead contractor, the bankruptcy of Westinghouse, four changeovers in the presidential administration, and the impact of COVID-19 on the workforce and supply chains,” shared Fuller. “Our role through it all has been supporting the long-term interests of our participant communities and helping find ways to overcome these obstacles to keep the project moving forward.”
Before deciding to join the project, Fuller said MEAG conducted careful analyses of the short and long-term energy needs of each community. MEAG Power also held more than 500 meetings with elected officials from its 49 participant communities to talk through the potential benefits and risks.
“The consensus was that while there was no risk-free choice from available sources of sustained baseload power, the expansion of Plant Vogtle — 500 MW of emissions-free energy in our portfolio for 60 to 80 years — would best meet the future needs of the majority of our participant communities,” he said.
Fuller noted that MEAG Power also undertook many risk mitigation measures, including ensuring such measures were part of its engineering, procurement, and construction contracts. It also took steps to mitigate financial risk.
“One of the ways we shared risk was through power purchase agreements, which enabled us to spread debt payments among partners for the first 20 years, and meet our projected power needs,” explained Fuller. “We also were able to obtain commitments for almost three-quarters of our projected capital needs through low-cost public capital raises and Department of Energy loan guarantees.”
Fuller noted that the units are financed through its initial 40-year operating license, and, at the end of that time frame, “the original debt issued to construct the units will be paid off, and we expect the units to continue to operate for an additional 20-40 years.”
Since signing onto the project, Fuller said MEAG now has another financial benefit of being able to monetize the value of production tax credits to third party project partners, which tax-exempt entities could not previously do on this type of project until the passage of recent federal legislation.
“Favorable economics are crucial to building large-scale nuclear, given the size and scope of costs required,” advised Fuller. “Communities evaluating advanced nuclear must consider the ownership structure, the cost of capital and available financing options, in addition to current and future load needs, when deciding what level of participation would be best.”
He advised that “anyone interested in developing new advanced nuclear should go into the project with their eyes wide open. Take great care in the ownership structure, as co-owners, while providing benefit through a shared risk arrangement, must be fully committed to the project and have the capital resources necessary to support the project. The size and scale of these projects exposes you to the risk of having to shoulder the debt service responsibility on the substantial capital investments over the life of the units with the risk of having to endure sunk costs should the units not operate.”
“While the discussion in today’s nuclear conversations often centers around SMRs, there is still a great deal of uncertainty involved in being a ‘first mover’ into this technology,” said Fuller. “In the future, we expect communities to continue to consider large-scale nuclear facilities provided the federal government provides supporting policies and risk mitigation measures.”
“Risk mitigation is a crucial factor to the success of any new nuclear initiative. Based on our experience from our nuclear expansion efforts, I would urge interested public power agencies to diversify construction and operating risk, size participation only to their own needs, and set up your capital funding plans up front as much as possible to mitigate interest and credit risk during the construction phase.”
A Clear Case
In Washington state, efforts are moving ahead in developing small modular reactors.
Greg Cullen, Energy Northwest’s vice president for energy services and development, said that the joint operating agency first got pulled into looking at advanced nuclear projects back in 2010. He said that some of its member utilities, along with investor-owned utilities in the region, put together a consortium that funded a study on whether the agency should be looking at advanced nuclear.
Then, the Washington state legislature passed the Clean Energy Transformation Act, which called for the shuttering of coal-fired facilities by 2025, and for a system that is at least 80% clean by 2030 and 100% clean by 2045.
“That was the point when we started pivoting, because it became more and more clear that we were going to need something like [nuclear],” said Cullen. Energy Northwest commissioned a study from Energy and Environmental Economics in 2019, looking at different scenarios that will allow the region to have sufficient capacity to meet peak loads. The study laid out a clear case for nuclear as part of the Pacific Northwest’s energy future.
“It was almost $8 billion per year cheaper to have a system with new nuclear in it than one that tried to meet it with wind and solar alone,” said Cullen. The results at the time seemed surprising, said Cullen.
“Too often, we tend to think in terms of comparing a megawatt-hour of wind or solar to a megawatt-hour of nuclear to say which is more expensive. But when you look at it from that system perspective, particularly a capacity perspective and to make sure that you're going to be able to meet peak loads, it becomes clear very quickly that it's far more cost effective.”
In 2020, the Department of Energy created its Advanced Reactor Development Program to support funding for two new nuclear designs in the U.S. Cullen noted that as one of the only operators of a nuclear facility in the region, vendors with advanced nuclear designs saw Energy Northwest as an opportune partner to apply for the funding.
“Those three things came together for us to make it very clear that new nuclear will be a part of the mix,” said Cullen. Since, he said interest in advanced nuclear projects has only expanded.
The agency is now involved in a project near its Columbia Generating Station in Richland, Washington to develop a series of small modular reactors with X-energy. The project plans include up to 12 SMRs, for a combined capacity of 960 MW, with the first module slated to become operational in 2030. Cullen said that Energy Northwest also consults with development in other projects, including Terra Power’s Natrium design for a facility in Wyoming.
Energy Northwest’s projects are all participant-based, so members (and non-members) can decide whether to sign on. So far, 17 public power utilities have backed its project in Richland, plus an IOU.
Cullen acknowledged that being among the first to deploy advanced nuclear involves risks. “The risks are real, and we want to talk about and be frank about them. But what we are finding with a lot of our members is that the risks of not doing something like this are growing to be almost as big. If we don't have something like this, where is the power going to come from? How are we going to meet all these requirements?”
For context, Cullen said that Washington’s state energy strategy calls for developing about 138 GW of wind and solar by 2050, which would also require adding a lot of storage and transmission. “If we're trying to do it with just renewable resources and energy storage alone, we might end up paying a lot more, and having a lot of challenges, assuming we could even build everything that would be needed.”
