Wyoming is a coal state. It’s an oil and gas and trona and bentonite and — tenuously — uranium state. And with the help of a Bill Gates-fronted technology company, it could soon become a nuclear state.
Five months have passed since nuclear developer TerraPower and Rocky Mountain Power, Wyoming’s largest utility, revealed plans to build a 345-megawatt demonstration reactor at one of four retiring Wyoming coal plants. They’re partnering with the federal government, which will pay half the costs, up to a $1.6 billion ceiling, but that money comes with a time limit: The plant must be operational by 2028.
It’s an ambitious target. Achieving it would be groundbreaking. No U.S. nuclear project has been completed on schedule, or on budget, in decades.
Still, to communities faced with impending, irreplaceable job losses, the proposal offers a lifeline. Leaders from Glenrock, Gillette, Rock Springs and Kemmerer have all asked TerraPower the same question: “How do we make sure it’s built here?”
In short, they can’t. Enthusiasm doesn’t hurt, but as long as the infrastructure meets TerraPower’s standards, the decision comes down to factors like geology, seismology, meteorology and hydrology, in accordance with the standards of the Nuclear Regulatory Commission (NRC) — the independent federal agency that evaluates and authorizes nuclear development.
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Retirement dates are a consideration, too. Even though the nuclear facility will be built separately, the chosen coal plant must be shut down before the reactor starts up. While the Naughton and Dave Johnston coal units are already scheduled to close by 2027, Rocky Mountain Power plans to keep the Jim Bridger and Wyodak plants operating through the late 2030s.
But all four plants will close eventually, and each loss will cost local jobs — many of which the project promises to restore — and eat away at the state’s baseload electricity supply.
“There’s a need to put something on the grid following those coal plant retirements,” said TerraPower CEO Chris Levesque. “To put something on the grid that runs 24/7, that can up its power when wind and solar are curtailed.”
TerraPower believes a new generation of nuclear plants can meet that emerging need. In collaboration with fellow nuclear developer GE Hitachi, the company “reinvented what a reactor can be,” Tara Neider, senior vice president of TerraPower and the project’s director, said during a presentation last September, before the company picked Wyoming for its first plant.
“We largely started by blowing away what a reactor looks like and breaking it into its individual parts,” Neider said. “Then we started putting it back together. And nothing was considered sacred.”
Out of the partnership came a minimalist design called Natrium — the Latin word for sodium — after the liquid metal that flows through the reactor’s core. Rooted in ideas developed in the 1960s, but adapted to the modern energy market, Natrium is now poised to become Wyoming’s first-ever nuclear power plant.
A troubled history
Unlike Natrium, all operating U.S. nuclear plants are cooled with water. These commercial light water reactors fall into two main categories: Boiling water reactors and pressurized water reactors.
Inside the core of each plant, uranium-235 atoms — the only isotope of uranium able to undergo nuclear fission — are split apart, releasing heat, like other fuels do when combusted. The fission reaction is used to heat water, which turns to steam and spins a turbine to produce electricity.
Both types of light water reactors circulate water through the core. In boiling water reactors, some of the water is allowed to turn to steam; in more commonly used pressurized water reactors, the water is used to heat a secondary water system, where the steam is produced.
Nuclear reactors operate at temperatures much hotter than the boiling point of water, which must be pumped through the core at a very high pressure to prevent it from boiling away. Sodium, in contrast, is solid at room temperature, and has a relatively low melting point of 208°F — a few degrees shy of water’s boiling point — but won’t boil until it reaches 1,621°F, eliminating the need to keep the coolant highly pressurized.
Heavy piping and containment are required for high-pressure systems. In theory, the lower pressure required for sodium cooling would also come with lower costs.
Sodium reactors are no longer used in the U.S. The technology, however, has been part of nuclear development since the emergence of the industry. It cooled the first nuclear power plant to publicly supply electricity to the U.S. grid, the Sodium Reactor Experiment, which operated in California between 1957 and 1964, according to the Department of Energy. The plant was down for much of 1959 and 1960, after a coolant flow blockage caused a partial meltdown.
Sodium was used even earlier to cool the Experimental Breeder Reactor I (EBR-I), the first U.S. nuclear plant, which began operating in 1951 at what is now the Idaho National Laboratory. In 1955, a coolant flow test triggered an unexpected partial meltdown of the reactor core. EBR-I was permanently shut down in 1963.
Yet another sodium prototype, Michigan’s Fermi-I, came online in 1963. In 1966, it suffered a partial meltdown also caused by a coolant blockage. After nearly four years of cleanup, the reactor was restarted in 1970, but closed again in 1972.
In the wake of those repeated accidents, and with few more recent projects to build upon, some experts have questioned the merit of further sodium development. Just one U.S. sodium reactor has evaded major accidents.
The successor to EBR-I, the 20-megawatt Experimental Breeder Reactor II (EBR-II), began operating in 1965. This time, researchers’ intentional efforts to force a meltdown — including a simulation of total cooling pump failure — were unsuccessful, demonstrating the efficacy of built-in passive cooling systems. The plant was decommissioned in 1994.
Only Russia has demonstrated a commercial-scale sodium fast reactor that’s still operating today. The U.S., meanwhile, has stuck with trusted light water reactors. But in an electricity market dominated, increasingly, by cheaper natural gas and renewables, and with nuclear’s reputation tarnished by high-profile accidents at Three Mile Island and Fukushima, the established technology is struggling.
“Nuclear companies and nuclear projects have not embraced innovation and new technology as much as they could,” Levesque said.
The short road ahead
TerraPower’s seven-year timeline is not negotiable. It’s a condition of the Advanced Reactor Demonstration Program established by Congress in 2020, a year after the passage of the Nuclear Energy Innovation and Modernization Act pushed the NRC to accelerate its licensing process.
“The leadership of the NRC will be the first to remind you, their first job isn’t schedule,” Levesque said. “It’s safety, and protecting people and the environment. But they know, if nuclear energy is going to have a place in the future — and we really need it to, because we have all these challenges with energy demand and climate — they know we need to reform.”
Most operating U.S. nuclear plants came online in the 1970s and ‘80s. The country’s reactor count, which peaked at 112 in 1990, has fallen to 93; still, nuclear power continues to supply 19% of total electricity generation, and remains the largest carbon-free electricity source.
With battery storage still limited, and Western hydropower at risk from climate change-fueled droughts, decarbonizing economies don’t have many commercial, zero-emissions technologies that can provide a steady supply of electricity. A typical light water reactor can produce roughly three times more electricity than TerraPower’s 345-megawatt proposal, an output comparable to a large coal plant. But existing models, which can cost tens of billions of dollars to build and take more than a decade to license, have proven uneconomical to keep constructing in the U.S.
In the past, “there just hasn’t been the need for super-efficient fast reactors,” said George Imel, a professor of nuclear engineering at Idaho State University and researcher at the Idaho National Laboratory, a federal nuclear research facility. “They are more efficient, and they’re more versatile and more flexible, but the light water fleet basically started from the U.S. nuclear submarine program, where they focused on pressurized water reactors. And that led to the development of an industry based around that.”
The “futurists” who founded TerraPower in 2006, including businessman and philanthropist Bill Gates, recognized “that the world needed a clean and scalable source of power,” Levesque said. “A lot of the predictions on what would be happening with energy, and the need for more emission-free sources, that’s all coming to bear.”
They thought about pursuing nuclear fusion, he said, but they didn’t think it’d be ready in time. So they focused on fission instead.
TerraPower had the Natrium design ready when the Department of Energy (DOE)’s Advanced Reactor Demonstration Program arrived. After it won the federal funding, the company turned to its established partnerships, which included Rocky Mountain Power. Just as Gates had anticipated, the utility was in the market for new baseload power sources that could replace its retiring coal fleet and balance a grid increasingly dependent on renewables.
But Natrium promised more than consistency. Its familiar turbine-driven electricity generation model would enable displaced coal workers to take jobs at the new facility, a possibility the University of Wyoming is already preparing to help with. And it would come equipped with a novel energy storage system designed to accommodate the intermittency of wind and solar.
Natrium is DOE-backed; it’s not yet NRC-approved. Before the plant can start up, it needs two key NRC permits: licenses for construction and for operation. TerraPower expects to apply for the construction license in a couple of years, and the operating license about a year before the plant is finished.
In the meantime, the federal infrastructure bill — which allocates continued funding to the Advanced Reactor Demonstration Program — includes $6 billion in subsidies for existing nuclear reactors, intended to extend the plants’ lifetimes until a new generation of nuclear power is ready.
How Natrium works
Natrium uses liquid sodium — the metal, not the salt — as a coolant. The sodium is pumped through the core, drawing heat away from the fuel rods and transferring it to a tank of nitrate salt (in that case, the salt, not the metal).
For the most part, TerraPower’s sodium-cooled fast reactor resembles other sodium-cooled models, including GE Hitachi’s PRISM design. The molten salt is what makes Natrium unique.
Nuclear plants are relatively inexpensive to operate, but costly to shut down and restart. Like light water reactors, Natrium is designed to run continually at maximum output. The liquid sodium circulating through its core functions like coolant water in a pressurized water reactor, carrying heat from the core to a secondary system. But because sodium can burn on contact with water, TerraPower added an intermediary loop of molten salt, which doubles as a giant battery. Plant operators will be able to control how much heat gets transferred from the molten salt battery to the water that’s used to generate electricity.
Separating the coolant from the electricity production system allowed TerraPower to decouple the reactor, dubbed the “nuclear island,” from the turbine and generator. Only the nuclear island must comply with more stringent NRC standards; the rest doesn’t have to meet those requirements, minimizing expenses.
“I think in the past, the nuclear industry was so focused on the licensing process that we kind of forgot about the economics,” Neider, the project director, said. “We lost sight of that. We were able to set our own costs because we were different from everyone else. But now we realize that has hurt the industry.”
The reactor itself is intended to operate at a constant 345 megawatts. When demand is low, surplus energy can be stored in the molten salt battery, reducing electricity output; when demand is high, or other power sources are offline, that additional energy can be released, increasing total output to 500 megawatts for up to 5.5 hours. It’s a tool adapted from concentrated solar power systems, which use sunlight to heat water, and rely on molten salt storage to maintain electricity generation when clouds pass by.
Natrium’s modular design makes its capacity even more flexible. Multiple reactors can be built together, or added later, upping output to accommodate increased electricity demand.
It also requires a different type of fuel. U-235, the fissile isotope used in nuclear reactors, makes up about 0.7% of natural uranium. Today’s light water reactors usually use uranium that’s enriched to 3–5% U-235. Many newer designs, including Natrium, require high-assay low-enriched uranium (HALEU), which is enriched to about 20% U-235.
The plant uses that fuel more efficiently, however, reducing nuclear waste by two-thirds, Leveseuqe said. With no existing federal repository for radioactive materials, TerraPower plans to store the plant’s waste onsite, in dry casks that have been used successfully elsewhere for decades.
HALEU comes with an increased risk of nuclear proliferation, but it’s viewed as less of a concern than highly enriched uranium or plutonium-producing reactors. Still, some in the industry believe that the dangers posed by the Advanced Reactor Demonstration Program overshadow the technology’s potential benefits.
Opportunity or hazard?
In March of this year, a few months before TerraPower and Rocky Mountain Power announced their partnership, nuclear expert Edwin Lyman published a report that urged the DOE to suspend the Advanced Reactor Demonstration Program. In its place, he wrote, the agency and Congress “should consider focusing nuclear energy R&D on improving the safety and security of (light water reactors), rather than on commercializing immature (non-light water reactor) designs.”
And a few months after the big reveal, nuclear critic and former industry executive Arnie Gundersen wrote an open letter to Bill Gates that harshly criticized TerraPower’s plan to circulate sodium through the Natrium reactor, given the technology’s meltdown-riddled history.
Lyman’s biggest concern is the artificial time pressure imposed by the DOE. By setting a seven-year limit, he argued, the agency is barring TerraPower from testing a Natrium prototype before building a commercial, grid-connected version of the plant.
According to his report, “the DOE concluded that a commercial-scale demonstration PRISM reactor was ready to be built because the design was based on (EBR-II).” Because of the substantial modifications made to the Natrium design, he’s not convinced the NRC will see it that way.
Both Lyman and Gundersen are worried about what could happen if Natrium is built according to the DOE’s schedule — though neither thinks it’s likely to get done on time.
“These first-of-a-kind reactors — and when I graduated [50 years ago], there were 20 reactors that were operating — every one of them had problems that knocked their socks off for as long as a year,” Gundersen said. “The concept that a sodium-cooled reactor, which has never been successfully operated in the U.S., is going to start up and work like a champ, has no historical basis.”
But Imel, from the Idaho National Laboratory, is among those who believe that Natrium is ready for commercial demonstration.
“As I understand, it’s going to be a fairly small reactor, and small is always easier to do,” he said. “The fact that it’s commercial, I don’t think really has too much bearing on whether it’s feasible to do or not.”
While the NRC has yet to weigh in, TerraPower — with the backing of the DOE — is confident that Natrium’s built-in safety systems mitigate the shortfalls of earlier sodium-cooled fast reactors.
The control rods that can halt fission are “failsafe,” Levesque said, because they drop with gravity. In case of a shutdown, chimneys around the reactor are designed to maintain airflow, dissipating the residual heat that caused the Fukushima accident in 2011. The sodium coolant will retain radioactive materials, he said, while the low-pressure system will prevent the coolant, and the contaminants it contains, from being pushed outward.
Sodium burns on contact with air, as well as water, meaning coolant leaks can be more dangerous in sodium-cooled reactors than in light water reactors. The molten salt intermediary eliminates the possibility of sodium mixing with water, but because the tubes are still surrounded by air, TerraPower’s engineers studied how EBR-II avoided leaks, Levesque said.
One perceived security risk that TerraPower has yet to address is the plant’s reliance on that more highly enriched uranium. An Ohio demonstration project is currently the only domestic source; for the foreseeable future, most will have to be imported from Russia.
A second uranium era
Nuclear would be a new power source for Wyoming, but it’s not a new industry. The state’s uranium producers have weathered the turbulent international market for more than 60 years.
The Wyoming uranium industry flourished as nuclear took off in the 1960s and ‘70s, but the partial meltdown at Three Mile Island in 1979 caused demand to flatline, flooding the international uranium market and sending domestic production into free-fall. Years later, as interest in nuclear began to creep upward once again, the Fukushima accident had a similar effect on the industry.
At its peak, uranium production created roughly 5,000 jobs in Wyoming alone. Forty years later, with more than 90% of the nuclear fuel used in light water reactors now imported from Canada, Australia, Russia and Kazakhstan, Wyoming is home to half of the country’s 225 remaining uranium workers.
If the first Natrium project succeeds, TerraPower plans to build many more, potentially starting with other retiring Wyoming coal plants that meet NRC requirements. Other companies, interested in following in TerraPower’s footsteps if the venture succeeds, are watching closely.
The prospect of a Wyoming nuclear industry has led to speculation that Natrium, and other projects like it, could revitalize the uranium sector. But the reality is more complicated.
“It’s not just uranium,” said Glen Murrell, director of the Wyoming Energy Authority. “It’s the milling and enrichment and the fuel manufacturing. That piece is actually not really established at all in the United States, so that’s a big problem, because if you mine [uranium] here in Wyoming, where are you going to actually get it processed?”
Industry believes that a federal subsidy for uranium production, coupled with the imposition of tariffs on imported nuclear fuel, is the best place to start.
“It’s not a free market,” said Travis Deti, executive director of the Wyoming Mining Association. “You’re competing with state-sponsored entities. And if we’re going to compete, you need state help, you need the help of the federal government.”
TerraPower has expressed interest in using domestically-sourced uranium in the future — but has said that it currently plans to import fuel, at least for the first Natrium facility.
To have any chance of reviving the U.S. uranium industry, Natrium needs to be operational by 2028. If that can be done, state leaders say, it’ll be done here.
“TerraPower got a head start simply by picking Wyoming,” Murrell said. “If you put this in Santa Barbara, you would probably get a lot of pushback. That’s not going to really happen in Wyoming, because they’re much more accepting of the energy sector.”