Designs for high-tech products, and the start-ups that offer them, will always outnumber the commercial successes. Ditto: many more power plants are proposed than actually get built, no matter what the technology.
This is an axiom of free-market economies, but in early November 2023 it became painfully obvious in the advanced reactor field. NuScale Power, the only advanced reactor that has made it through the licensing gauntlet, acknowledged that the consortium of utilities that was its intended launch customer had failed to put together a feasible package.
NuScale is publicly traded (ticker symbol, SMR), the only pure nuclear play on Wall Street, but investors had viewed the project’s prospects with skepticism for some time and delivered a punishing blow to the stock price. (The financial consequences didn't end there. NuScale announced in early January that it had laid off 154 employees, about 28 percent of its workforce. The company said it was transitioning from design work to commercialization.)
The first to feel the fallout may have been X-energy, which had been trying for months to go public, and before the NuScale plant cancellation had already lowered its estimate of its own value. X-energy gave up—at least for the near future—and secured some additional private financing, but insiders say that it laid off about 100 employees.
Oklo, which wants to build and operate microreactors, selling heat and electricity to customers, said in July 2023 that it would go public and so far has not announced any change of plans. But its announcement said that the transaction would close in late 2023 or early 2024.
Much of the progress in advanced reactors so far has been the publication of pictures of people in business suits shaking hands in front of a camera, flags in the background, and announcements of promises to study deployment. But there is still serious work going forward. NuScale, X-energy, and others are plowing ahead, recognizing that if big countries are committed to eliminating carbon emissions, or even just to getting the carbon out of their electricity systems, then some types of new reactors are inevitable.
The effects of these setbacks on other companies will vary. This shouldn’t be a surprise; if there is one word to characterize the advanced reactors in various stages of the journey to market, it is diversity. They differ not only in design but also in business approach. At this juncture, the end of 2023, it is hard to say how many will make it across what high-tech companies in other fields call the “valley of death,” the space between designing a new product and producing copies in commercial quantities.
There is a second characteristic: designs in flux. NuScale started out with 50-MW modules but now wants them to produce 77 MW; Oklo started at 1.5 MW but has gone to 15; and Holtec revised its plan for a 160-MW reactor by adding booster pumps to push output to 300 MW.
But here is the state of play, in rough order of their proximity to deployment.
GE Hitachi Nuclear Energy: BWRX-300
The key concept here is innovation married to iteration rather than starting with a clean sheet. GEH’s BWRX-300 is a water-cooled, water-moderated version of the familiar GE design but smaller, simpler, and intended to be easier to build. The company says that 80 percent of its components are already approved by the Nuclear Regulatory Commission for use in other designs.
The “X” in the name is a Roman numeral; it is the tenth version of the GE boiling water reactor.
The province of Ontario said in July that it was working with Ontario Power Generation, the provincially owned utility, to begin planning and licensing for three units in addition to one it is already developing, first announced in December 2021. Waiting in the wings are the Tennessee Valley Authority and Synthos Green Energy, a Polish firm, which have a joint agreement with OPG to help develop and license the design. OPG has started site preparation for a reactor that it expects to be completed by 2028. TVA plans to apply for a construction permit at its Clinch River site in late 2024. Both TVA and GEH are in preapplication interactions with the NRC. GEH has submitted eight topical reports detailing many areas of the design.
A key factor in the schedule for the BWRX-300 is that it uses a fuel already in production. So does NuScale, but most of the advanced designs require enrichments far above the 5 percent that is now common in water-moderated, water-cooled power reactors. And the higher enrichments are not commercially available at the moment, except from Russia, which American companies have said they will not buy.
The builders plan to use “steel bricks,” composites of steel and concrete, rather than concrete with rebar. The system is intended to make construction much faster.
To the extent that the BWRX-300 succeeds in the marketplace, it would demonstrate two important characteristics about nuclear energy: Iteration is easier than fundamental innovation, and incumbent companies retain the engineering talent, the utility contacts, and the licensing skills to move forward. But if light water is the only technology to move forward, it would demonstrate the limits of nuclear energy to decarbonize sectors of the economy that require higher-temperature heat.
Arguably close behind the BWRX-300 are two more technologically ambitious departures from current commercial technology, both flagship projects of the Department of Energy’s Advanced Reactor Demonstration Program (ARDP): the TerraPower Natrium reactor and X-energy’s Xe-100.
While all reactor developers are looking for ways to build with less capital expense, Natrium also attacks the other side of the problem: getting more revenue from a given number of megawatt-hours. The reactor churns out an amount of heat that would generate 345 MW of electricity, but actual electricity generation will vary between 100 MW and 500 MW, depending on wholesale prices on the grid. The longer-term idea is that this will depend on whether the sun is shining and the wind is blowing.
If successfully deployed, Natrium would demolish the idea that it is still appropriate to evaluate an electricity generator in terms of levelized cost of energy—that is, its total costs for capital, fuel (if any), operations, and maintenance, divided by the number of kilowatt-hours it produces. Solar is winning that battle, but the victory has limited meaning because during peak production hours, its production may be worthless, or worse than worthless. In June 2023, the California Independent System Operator reported that prices were negative 7 percent of the time, mostly driven by solar surpluses, and 214,000 megawatt-hours of potential electricity production was “curtailed,” meaning that the generators were unplugged. To make that much electricity in a 30-day month would require a 300-MW generator. (Some other months show less curtailment and fewer hours of negative pricing, but the problem gets worse over time as renewable deployment increases.)
Any reactor could be built to modulate its output, but reactors are expensive and owners want to maximize their production. And depending on design, variable operation creates wear and tear on the fuel and the reactor hardware. Natrium’s reactor is meant to run flat out, 24/7, and to dump heat into a giant tank of molten salt. The salt can run through a steam generator and produce steam at variable rates. The salt in the storage tank can vary from 238°C to 621°C and can store enough heat to produce nearly 1,000 megawatt-hours of electricity.
Natrium was committed to a seven-year deployment schedule as specified by the ARDP, under which it is one of two flagship projects. (The other is X-energy’s Xe-100.) However, it expects a two-year delay because of the unavailability of high-assay low-enriched uranium (HALEU), and it has previously identified regulatory approval as the long pole in the tent. In a presentation in February 2021, the company noted that “review time is the biggest issue.”
The companies said at the time that “guidance on non-LWR licensing is incomplete.” Three years later, that is still true.
Natrium has a demonstration site—in Kemmerer, Wyo.—where PacifiCorp operates the Naughton coal-fired plant. The plant had three units totaling 823 MW; one has been retired and two are scheduled to close in 2025. TerraPower intends to build the plant and then sell it to PacifiCorp. Among the challenges, in addition to fuel, is that the town of Kemmerer is not set up to house the thousands of workers who will be required during construction.
In the longer term, the Natrium design is best suited to a place with extreme variations in production from renewables. The poster child for that problem is California, and that is the place where a reactor-plus-storage project like this could profit most from the big swings in wholesale prices. But California remains allergic to nuclear projects.
TerraPower expects to apply for a construction permit by the end of March 2024. PacifiCorp has already announced that it is looking for sites for additional units. Among the possible sources of delay: Natrium needs HALEU fuel. The technology for HALEU production is in hand, but not the manufacturing capacity. And at the moment no fuel fabricator is licensed to process the uranium hexafluoride that comes out of an enrichment plant into fuel at that enrichment level.
TerraPower anticipates that it will take 62 months to build the plant, which suggests start-up in mid-2032 at the earliest.
Natrium has two prominent sources of money. It is one of two projects to win a 50/50 matching grant from the DOE under the ARDP. (The other is the Xe-100.) Congress has appropriated $3.1 billion for those two projects. And TerraPower’s big investor is Bill Gates.
Natrium is an advanced reactor but not a small modular reactor, which is defined by the DOE as being 300 MWe or less. It proves the point that not all advanced reactors are SMRs, and it joins Rolls-Royce in that category; that British company’s design is for a 470-MWe unit.
X-energy has a unique factor in its favor: a customer with extensive engineering experience, deep pockets, and a public commitment to decarbonization.
That customer is Dow, which announced plans in May 2023 for a cluster of four Xe-100s of 80 MWe each at its plant in Seadrift, Texas. The product could be electricity, or steam for chemical processing, or some of each. Oddly, the reactors could help decarbonize solar energy; one of the products produced at Seadrift is membranes for solar panels. (Solar energy has a lifetime carbon footprint far smaller than any fossil fuel, but substantially higher than nuclear.)
The Xe-100 is a pebble-bed design, which uses uranium particles coated with layers of heat-resistant materials, formed into spheres the size of billiard balls and more formally known as TRISO fuel. In October 2022, X-energy broke ground on a fuel fabrication plant in Oak Ridge, Tenn. It is supposed to be operational by 2025, but the design requires HALEU fuel.
As of late 2023, X-energy had not said when it would submit a license application to the NRC, although Dow said in its initial announcement in May that it was working with the company to prepare a construction permit application. The NRC’s “generic” schedule says that a construction permit takes 36 months to process. X-energy and its customer want to start building in 2026 and finish by “the end of this decade.”
But as with Natrium, although the Xe-100 was supposed to be on line in this decade, it too will be delayed two years at least because of the unavailability of HALEU fuel.
X-energy wanted to be the second publicly traded advanced reactor company. In December 2022 it laid out a plan to go public in a deal worth $1.8 billion; then it cut its valuation in September to just over $1 billion. In October, it dropped the idea. The company did get additional funding from the firm that it was going to merge with to become public, Ares Acquisition Corp., and from Kamal Ghaffarian, the entrepreneur who has funded much of X-energy’s work.
Dropping a plan to go public was not surprising, given that Wall Street was souring on NuScale (see the section on VOYGR on the next page). Venture capital, where the money comes from before a company goes public, can be relatively patient as new ideas work their way into commercial products, but stock market investors are not.
An extended courtship with Utah Associated Municipal Power Systems (UAMPS), a consortium of public power agencies across the West, led NuScale to diversify its product line. The original concept was 12 power modules, but the company now offers four- and six-packs as well.
UAMPS was aiming for a VOYGR-6 configuration. It stressed to its members that they should be ready for federal limits on carbon emissions, and that subscribing to the project would leave them well prepared for new regulations. The project had the promise of a site at Idaho National Laboratory and numerous interested parties. A supply chain was already in place, because NuScale’s low-enriched uranium fuel closely resembles Westinghouse fuel, except the assemblies are about half the height. The design had been approved (although for 50-MW modules, and NuScale is seeking an amendment to approve running them at 77 MW). NuScale planned to submit an application for a combined operating license in January 2024.
But UAMPS could not sign up members or outsiders for all 462 megawatts. One problem was rising costs, because of the jump in prices for steel and concrete. And another was that federal regulations did not develop as predicted.
NuScale had already placed an order with Doosan Enerbility for long-lead-time parts, and Doosan has begun fabrication. Doosan is an investor in NuScale. Recently NuScale announced that it was working with Standard Power, which wants to build facilities for data processing companies, to deploy reactors. The centers would be in Ohio and Pennsylvania, but precise locations or timing have not been specified. Standard Power would supply the electricity.
NuScale also opened a control room simulator at the University Politehnica in Bucharest, Romania, one of several European countries where the company is hoping to find customers.
NuScale was the first reactor developer to go public, at $10 a share in May 2022, but Wall Street appears to have cooled on its prospects; in late 2023 it sometimes traded for under $3.
After these four come several more reactor projects that are further away from commercialization, and most do not have customers in hand.
Kairos Power: KP-FHR
The companies that want to build new reactors differ not only in their designs but also in their approaches. NuScale, X-energy, and Natrium all want their first product to be a full-scale commercial reactor. In contrast, Kairos plans a series of test facilities.
One reason may be that Kairos is more of a design departure. Like X-energy’s Xe-100, Kairos’s fluoride salt–cooled, high-temperature reactor uses TRISO fuel pebbles, but it is not cooled by pressurized gas. The TRISO spheres will float in a low-pressure bath of fluoride salt coolant, allowing for very high temperatures at low pressures. Because of the heat capacity of the fuel and the coolant, there is a very large thermal safety margin.
Kairos wants to iterate its way to a commercial product. It is starting with the nonnuclear Engineering Test Unit in Albuquerque, N.M., to test the coolant. It began loading the coolant, FLiBe, a mixture of lithium fluoride and beryllium fluoride, in November. Kairos is also planning a series of test reactors near Oak Ridge, Tenn. The first, called Hermes, is a 35-MWt test reactor. The company submitted an application for a construction permit in September 2021, becoming the first in decades to do so for a test reactor. NRC staff completed its safety evaluation in June 2023, and Kairos plans to have Hermes in operation by 2026.
It submitted an application in July 2023 for Hermes 2, twin 35-MWt nonpower reactors. Construction could begin in July 2024, with the first unit to be finished in late 2027.
Kairos also distinguishes itself from others in the new reactor field by trying to internalize as much of its supply chain as possible.
The company has support from the ARDP under the category of “risk reduction,” for work meant to advance the technology but not to bring it to the stage of commercial deployment. Kairos has recruited Bruce Power, Constellation Energy, Southern Company, and TVA as advisors.
Westinghouse Electric Company announced plans in May 2023 for an AP300, a quarter-scale copy of its AP1000, a passively safe pressurized water reactor. The company plans to start construction in 2030 and have the smaller reactor running within three years.
At the time of its announcement, Westinghouse submitted a “regulatory engagement plan” to the NRC. How long it will take to license is uncertain; in its submission, Westinghouse said that “the AP1000 design documentation and licensing basis will be leveraged extensively and used as the baseline for the creation of the AP300 SMR to the extent practicable.” The design is a smaller reactor vessel and a single steam generator.
Near Augusta, Ga., the second of two AP1000 models is now nearing completion at Vogtle nuclear power plant. With AP1000 plants already operating in China and some planned for Europe, the AP300 would appear to be able to take advantage of an already-running supply chain.
In October, Westinghouse said that its plant had been selected to participate in a competitive technology selection process in the United Kingdom called Great British Nuclear. Whether the American entry would actually be chosen over a “hometown” entry by Rolls-Royce is not clear.
Holtec International makes dry casks for spent fuel and heat exchangers for nuclear and nonnuclear use, and it decommissions old reactors. It is distinguished from other start-ups because it has in-house heavy manufacturing capability and is already familiar with some NRC licensing procedures. It owns the sites of old reactors, with access to cooling water and the grid, already zoned industrial. One candidate site for the SMR-300 is the old Oyster Creek reactor in Toms River, N.J., which Holtec is tearing down. Another is the Palisades plant in western Michigan, which was shuttered in May 2022 and sold to Holtec for decommissioning, but the company is seeking to restart it. Holtec says it would also like to build two SMR-300s there.
Prelicensing activities for the SMR-300 with the NRC have begun, but Holtec has not said when it will submit a license application. The company says it has invested $400 million in the reactor design, and it is seeking a $7.4 billion DOE loan to build them.
Holtec has a deal with Hyundai Engineering and Construction and two South Korean financial institutions to provide financial backing for the SMR-300. Holtec and Energoatom, which operates Ukraine’s commercial reactors, signed an agreement to draw up plans for construction of up to 20 of the SMRs in Ukraine. But at least for the near future, Ukraine has more pressing problems on its hands.
Oklo: Aurora Powerhouse
Oklo says it is “currently targeting” an output between 15 MWe and 50 MWe for its Aurora Powerhouse, a liquid metal–cooled fast reactor. It has four projects on the drawing board: an initial reactor at INL using recycled fuel from the DOE; a pair of reactors at the site of Centrus Energy’s new enrichment plant in southern Ohio, which would supply electricity to the centrifuges and use the HALEU the plant will produce (and where the two companies have announced a memorandum of understanding to buy each other’s products); and a unit at Eielson Air Force Base, southeast of Fairbanks, Alaska.
Under the 2019 National Defense Authorization Act, the Pentagon is supposed to demonstrate a microreactor by the end of 2027. In August 2023, the U.S. Air Force announced its “intent to award” a contract to Oklo, but in November it reversed that, apparently because there is a potential competing bidder, Ultra Safe Nuclear.
Oklo’s lead plant, in Idaho, is targeted for operation in 2026 or 2027, the company says. But in March 2020, the NRC refused to docket Oklo’s first license application, saying that it was not sufficiently complete and that the company had not properly responded to requests for additional information. As of late 2023, the company had not reapplied. Keeping to the original schedule would at this point require exceptionally fast approval by the NRC, followed by glitch-free construction.
The company says it has “nonbinding indications of interest” to build over 50 power plants with a combined output of 700 MWe.
A program run by the Defense Department’s Strategic Capabilities Office to develop a “transportable” microreactor that can be shipped in standard containers, set up in three days, operated for weeks or months, left to cool for seven days, and then shipped out again, Project Pele has selected a consortium led by BWX Technologies (which makes nuclear cores for naval propulsion reactors) to build and deliver a lead unit by 2024. The design is a high-temperature, gas-cooled reactor that will run on HALEU and put out 1–5 MW of electricity. A prototype will be delivered to INL in 2024, according to BWXT. The prototype does not require an NRC license.
The design could be used in the civilian world for remote mining operations or communities or for places that need a reliable backup power source.
Westinghouse got a boost when SaskPower, the provincial utility in Saskatchewan, Canada, said it would pay C$80 million (about $59 million) toward the cost of an eVinci microreactor.
The factory-assembled eVinci is designed to be delivered by truck and quickly set up, on a two-acre site. It can run on a single core of TRISO fuel for eight years of full-power operation, which is probably 10 calendar years.
The reactor can make 5 MW of electricity or 13 MW of high-temperature steam. Saskatchewan’s long-term interest in this model may be the latter because it could be used for steam flood of “tar sands” deposits. Heat to liberate heavy oil from sand is currently provided by natural gas, giving the oil a very high carbon footprint.
The C$80 million works out to C$16,000 per kilowatt of electric capacity, if electricity is to be the product. But the cost for the first-of-a-kind unit could be more; Westinghouse testified in West Virginia that the initial installation would cost $90 million to $120 million. Follow-on units would be substantially less.
Ultra Safe Nuclear: Micro-Modular Reactor
USNC’s design is for a 15-MWt reactor using the company’s proprietary Fully Ceramic Microencapsulated (FCM) fuel pellets, moderated with graphite and cooled by gas. An adjacent salt tank, somewhat like Natrium’s, will store heat. That tank, using technology borrowed from the solar thermal industry, will buffer the reactor from load changes.
The company announced in June that it would construct a $232 million plant in Gadsden, Ala., to build modules for the plant. Construction is to begin in 2024. USNC and the University of Illinois–Urbana-Champaign have a plan for a microreactor that would fit into the campus’s existing steam system, replacing the conventional boilers, which used to run on coal but now use natural gas. Finding funding has been an issue, though.
USNC, a start-up, also recently announced a joint venture with Framatome, an established uranium processor and fuel fabricator, to make fuel.
Demonstrations and Experiments
Molten Chloride Reactor Experiment
A joint project of Southern Company and TerraPower, MCRE, a 500-kWt nonpower reactor, will be built at INL. As a DOE project, it does not need an NRC license, but it is supposed to advance the construction of TerraPower’s proposed Molten Chloride Fast Reactor. The MCRE is supposed to be on line by 2026.
Abilene Christian University
The university submitted an application in 2022 to build a molten salt research reactor, which was the first for a new research reactor on a university campus in 30 years—and the first ever for a molten salt model. The project is a cooperative effort with the University of Texas–Austin, Texas A&M University, and the Georgia Institute of Technology. ACU has submitted a construction permit application for the reactor, with a power rating of 1 MWt. Construction would take between 6 months and 48 months, the university says.
Matt Wald is an independent energy writer and consultant. He is a former policy analyst at the Nuclear Energy Institute and for decades was the energy reporter at the New York Times.