Nuclear energy has a strange political profile. It produces no carbon dioxide during operation, runs around the clock regardless of weather, and by almost every measure kills fewer people per unit of energy than any other power source. Yet it also faces some of the best-organized and best-funded institutional opposition of any energy technology on the planet. Understanding who funds that opposition, and why, is genuinely useful — not because it invalidates every argument critics make, but because money and motivation always matter when evaluating who is saying what about whom.

The anti-nuclear movement started as a genuine grassroots response to Cold War weapons anxiety and the accidents at Three Mile Island and Chernobyl. That history is real, and the fear it generated was understandable. But the landscape has shifted dramatically. Many of the organizations now leading opposition to nuclear energy are not small activist groups running on donations and passion. They are large, professionally staffed nonprofits with annual revenues in the hundreds of millions of dollars. And some of their biggest donors have financial interests in the energy sources that compete most directly with nuclear power.

This piece is about following the money — and then honestly examining what the anti-nuclear arguments actually say, where they have force, and where they don’t.

The funding picture: big philanthropy, fossil fuels, and an asymmetric fight 💡

The scale of organized anti-nuclear opposition in the United States is larger than most people realize. In July 2025, the Capital Research Center, a conservative watchdog nonprofit, published an analysis examining more than 300 nonprofits that oppose nuclear energy. The combined annual revenue of those organizations, reported in IRS filings, exceeded $3.3 billion. Their January 2026 update put the number above $3.4 billion, or roughly $9.3 million per day flowing into anti-nuclear advocacy organizations. The Capital Research Center is conservative-leaning, and its framing is explicitly pro-nuclear — that’s worth knowing. But it’s working from publicly reported IRS filings, not invented numbers.

The largest organizations on that list include names most people associate with mainstream environmentalism:

• World Wildlife Fund, World Resources Institute, and the Natural Resources Defense Council — all with recent annual revenues above $100 million each

• The Sierra Club, with recent annual revenue of $173 million, which remains “unequivocally opposed to nuclear energy” according to its own website

• The Environmental Defense Fund and the Rocky Mountain Institute, both of which have opposed nuclear energy while advocating for renewables and gas as transition fuels

• The League of Conservation Voters, which spent more than $33 million in federal independent expenditures in the 2022 election cycle alone

The donor side is where the conflicts of interest become harder to dismiss. According to InfluenceWatch, from 2020 through 2023, Bloomberg Philanthropies gave at least $80 million in grants to nonprofits that have opposed nuclear energy, including the Sierra Club Foundation, the NRDC, the Rocky Mountain Institute, and 350.org. The John D. and Catherine T. MacArthur Foundation gave at least $60 million to anti-nuclear organizations during the same period. The Tides Foundation and the Sixteen Thirty Fund, part of the Arabella Advisors network, are also listed as major contributors.

On the fossil fuel side, the picture is less about direct donations to environmental groups — which would be bizarre optics — and more about industrial lobbying against nuclear specifically. The Daily Beast reported on the American Petroleum Institute’s documented strategy to oppose nuclear power subsidies as natural gas became the dominant electricity competitor. API’s members are increasingly natural gas producers, and nuclear’s around-the-clock reliability is the main threat to gas’s role as a “baseload” power source. Environmental Progress, the pro-nuclear advocacy organization founded by Michael Shellenberger, has tracked claims that the Sierra Club has received over $136 million from natural gas and renewables interests and that the NRDC has more than $70 million directly invested in fossil fuel and renewable energy companies — though these figures are contested and Environmental Progress has its own strong pro-nuclear agenda.

I’d be cautious about any single source here. The truth is probably messier than either side presents it. What seems undeniable is that the pro-nuclear advocacy community is dramatically outgunned financially. The Nuclear Energy Institute, the main trade association for the nuclear industry, reported annual revenue of $57.3 million — less than one-third of the Sierra Club alone.

The arguments critics actually make 🔬

It would be unfair to stop at the money and imply the opposition has nothing substantive to say. Several of the anti-nuclear arguments are genuinely serious and worth engaging with directly rather than dismissing.

Cost is the strongest objection. The NRDC’s 2023 issue brief on SMRs argued that “arguments in favor of SMRs are largely theoretical” because “none have yet been constructed in the United States” — and therefore claims about cost savings from modular factory production remain unproven. This is a fair point. A University of Pennsylvania analysis published in April 2025 noted that there are only three operating SMRs in the world — two in Russia and one in China — and that these saw cost overruns of 300% to 400% according to a JP Morgan energy paper. NuScale’s canceled project in 2023, which saw estimated costs soar past $20 million per megawatt, is the critics’ exhibit A.

The Breakthrough Institute, which is firmly pro-nuclear, acknowledges the complexity in its April 2026 analysis: large reactors are also extremely hard to build in liberalized markets, and the Idaho National Laboratory has found that cost estimates for non-light-water SMR designs “are highly uncertain.” Nobody has the definitive answer yet, because commercial SMRs haven’t been built at scale in the West.

Waste is a real, unsolved problem. The NRDC argues that SMRs may produce more radioactive waste per unit of energy than conventional large reactors because of their smaller, neutron-leakier cores. A 2022 paper in Proceedings of the National Academy of Sciences by researchers including former NRC chair Allison Macfarlane reached a similar conclusion. The Breakthrough Institute — again, pro-nuclear — concedes in a March 2026 analysis that nuclear waste remains “a wicked problem” driven more by political dysfunction than engineering failure, but a wicked problem nonetheless. The United States still has no permanent repository for high-level nuclear waste after decades of trying.

Proliferation concerns are taken seriously by serious people. The Union of Concerned Scientists’ Ed Lyman, writing in Crain’s Detroit Business in March 2025, argued that some SMR designs require high-assay low-enriched uranium fuel that poses “higher nuclear proliferation and nuclear terrorism risks than the uranium fuel existing reactors require.” The Congressional Research Service has made similar observations. This is not a fringe claim — it’s a genuine engineering and security concern that applies to specific reactor designs, not all of them.

What’s worth noticing is that the most serious anti-nuclear critics have shifted their ground. The NRDC no longer claims nuclear is categorically dangerous; it argues nuclear is economically uncompetitive against renewables and batteries. That’s a different argument, one that can be tested empirically rather than fought through fear.

Where the arguments run thin 📈

The anti-nuclear case has real weaknesses too, and it’s worth naming them plainly.

The cost-competitiveness argument often compares solar and wind at their best to nuclear at its worst:

• Solar and wind are priced as standalone generation sources, without the full cost of the storage and grid balancing they require

• Nuclear’s reliability — the EIA reports a capacity factor of about 92% versus solar’s 23% — is worth real money on a grid that needs 24/7 power

• The NRDC’s comparison of renewables to nuclear rarely prices in the cost of making a renewables-heavy grid reliable across a whole year, including cloudy winters and calm periods

The argument that nuclear is too expensive is also undermined by a simple observation: the same foundations and organizations opposing nuclear power have spent decades blocking the regulatory reforms and financing structures that would have made it cheaper to build. Opposing nuclear and opposing the conditions for nuclear to become economically competitive are not independent positions.

The claim that SMRs are purely a distraction from renewables, deployed frequently by groups like the Union of Concerned Scientists, runs into a problem that the Information Technology and Innovation Foundation’s April 2025 report addresses directly: some applications — remote communities, industrial heat, grid reliability — are poor fits for solar and wind and excellent fits for nuclear. Treating all energy contexts as interchangeable flattens real differences. Is “just build more renewables” an adequate answer to a remote Arctic community running diesel generators?

The proliferation concern, while legitimate for specific designs, is sometimes applied as a blanket objection even to reactors using standard low-enriched uranium fuel. That’s not technically honest.

The harder question: who benefits? 🌍

Following the money doesn’t determine who is right. But it does inform how you should weight what you hear. When the NRDC argues against nuclear while holding investments in energy funds that include natural gas companies, that conflict should be disclosed and considered, whether or not it determines the conclusion. When the American Petroleum Institute organizes against nuclear power subsidies on behalf of companies that produce the electricity source most threatened by nuclear’s reliability, that’s not environmentalism — it’s competitive interest dressed up as concern.

None of this means nuclear energy is without problems. Cost uncertainty is real. The waste storage deadlock is real. The financial case for first-of-a-kind SMRs involves genuine risk that developers and governments are still figuring out how to allocate, as former DOE loan program head Jigar Shah noted bluntly in a 2025 interview. These are legitimate debates. If you’re tracking the nuclear market professionally, SMRbrief Pro gives you the structured database to go deeper than any single article can, including the regulatory, financial, and project-level data behind the stories that advocacy organizations on both sides tend to simplify.

What makes the funding picture uncomfortable is that both the environmental groups opposing nuclear and the fossil fuel interests quietly pleased by that opposition end up in the same place: nuclear power doesn’t get built, gas plants do. The Sierra Club may believe sincerely in an all-renewables future. The American Petroleum Institute is not so conflicted. The question worth asking, when you see a well-funded campaign against a specific energy technology, is not just “what are they saying?” but “who else benefits if they succeed?”

The shifting ground 🚀

The anti-nuclear coalition has a problem that money can’t fully solve: some of its most prominent longtime members have defected.

Stewart Brand, co-founder of the Whole Earth Catalog and a counterculture icon, became publicly pro-nuclear. The documentary Pandora’s Promise featured prominent environmentalists who changed their minds. The IAEA, which can hardly be accused of pro-fossil-fuel bias, projects that global nuclear capacity could roughly double to 950 gigawatts by 2050 in its high case, with SMRs making a meaningful contribution. The European Commission is allocating €15 million for SMR safety research in its 2026-2027 work program, hardly the behavior of an institution that sees nuclear as finished.

The once-unified environmental opposition to nuclear has fractured. A growing number of climate scientists and energy analysts — including many who identify as progressive — now argue that opposing nuclear while claiming to fight climate change is a contradiction that the physics of the energy transition will eventually force into the open.

The anti-nuclear movement spent roughly fifty years building enormous institutional infrastructure. That infrastructure still exists, still receives billions in annual funding, and still has real political power. But the intellectual core of the argument — that nuclear power is too dangerous, too expensive, and too slow to matter — is under more serious challenge than at any point since the 1970s. Given that context, does the funding picture you’ve just read change how you evaluate the next anti-nuclear argument you encounter?

Picture the hamlet of Ambler, Alaska. No roads connect it to anywhere. Summer barges bring in supplies — including the diesel fuel that powers everything from the lights to the water treatment plant. When the barge window closes, the fuel that didn’t arrive doesn’t arrive until next year. In August 2023, diesel prices in communities like Ambler and Kobuk exceeded $15 per gallon, according to reporting by the Alaska Beacon. Electricity in some of these villages costs more than $1 per kilowatt-hour, compared to the U.S. national average of roughly 12 cents. The villagers aren’t getting ripped off. They’re simply paying the true cost of moving fuel to places that physics and geography conspire to make brutally difficult to reach.

This is the diesel trap. And it’s not a small problem. In Canada alone, over 300 remote communities depend on diesel generators, many of them accessible only by ice road or air. Nearly 200 remote Alaskan communities run almost entirely on diesel power. The Canadian federal government has poured C$443 million into its Clean Energy for Rural and Remote Communities program since 2018, trying to chip away at a dependency that, if anything, has grown more expensive and more complicated to sustain. Solar helps in summer. Wind helps when it blows. But neither solar panels nor wind turbines can carry an Arctic village through four months of polar darkness and minus-40-degree temperatures on their own.

Which is where a genuinely strange idea enters the conversation: what if nuclear power, in miniaturized form, is actually the most practical solution for places where practicality is everything?

The diesel problem is bigger than the fuel bill 🔋

It’s tempting to frame the remote diesel problem as purely economic — and the numbers are bad enough on their own. A northern Ontario household, according to Pembina Institute analysis, pays more than $3,000 per year in energy costs, more than twice the national average. Some Yukon households hit $4,500. In Alaska, energy bills run 33% higher than the national average even before accounting for the most isolated communities.

But the cost is only part of the misery. Consider what else comes with diesel dependence:

• Fuel spills: Every delivery, every storage tank, every aging generator line is a potential contamination event in ecosystems that are already under pressure from warming temperatures

• Supply chain fragility: A bad ice year, a barge breakdown, or a geopolitical shock in global oil markets sends ripples straight to communities that have no alternative

• Noise and air quality: Diesel generators run constantly, often poorly maintained, pumping fumes into villages that are frequently small and enclosed

• Aging infrastructure: Kathairos notes that “most diesel generators in operation are aging,” creating a ticking maintenance clock for communities that can’t easily source parts or technicians

The U.S. Department of Energy confirmed that there are hundreds of isolated U.S. communities, primarily in Alaska and island territories, with microgrid power systems ranging from 200 kilowatts to 5 megawatts, and that the cost of electricity is “sometimes more than $1/kWh” — varying directly with the price of oil. These aren’t edge cases. They’re the normal reality for hundreds of thousands of people, many of them Indigenous, who have simply never had access to reliable, affordable power.

Does this sound like a situation that a few more solar panels might fix? Or does it sound like a problem that needs a fundamentally different kind of energy source?

What microreactors actually offer ⚡

The nuclear industry has spent years being loudly uninterested in small-scale power. The economics of traditional reactors favor gigawatts, not megawatts — you build big to spread the fixed costs. But microreactors are a genuinely different category. These are nuclear reactors producing roughly 1 to 20 megawatts of electricity, factory-assembled, and designed to be transported by truck, rail, or ship in a single unit.

Two things make them relevant to remote communities in particular:

• Long refueling cycles: The Idaho National Laboratory explains that next-generation microreactors are designed to operate years without refueling, in the same way nuclear submarines run for years on a single fuel load. Westinghouse’s eVinci microreactor, for instance, is designed to produce 5 MW for eight years between refuelings. Compare that to diesel, which needs daily replenishment.

• Passive safety: Unlike earlier reactor generations, microreactor designs use gravity and natural convection for cooling rather than active pump systems. The DOE defines a microreactor as a system that, by design, “uses passive safety systems to avoid overheating or a meltdown” without needing a large workforce of specialized operators. That’s important in communities where finding qualified diesel mechanics is already a challenge.

According to ScienceDirect analysis, microreactors become cost-competitive with diesel generators when diesel fuel costs exceed $1.50 per liter — a threshold that is already routinely surpassed in Alaska’s most remote communities. The same analysis found that microreactors are “significantly cheaper than a 100% renewable and battery system” in these contexts. The Nuclear Energy Institute estimates electricity costs from first-generation commercial microreactors at $0.14 to $0.41 per kilowatt-hour, with costs expected to fall to $0.09 to $0.33 as the technology matures. That’s potentially competitive with what remote communities already pay.

For SMRbrief Pro members, the full project-by-project intelligence on who is building what, where, and at what stage of licensing is exactly the kind of structured data that makes comparisons like these actionable rather than theoretical.

The Eielson experiment and what it means for civilian communities 🌍

The most concrete proof of concept for Arctic nuclear microreactor deployment isn’t happening in a civilian village. It’s happening at Eielson Air Force Base near Fairbanks, Alaska — and the military’s willingness to go first matters more than most people realize.

In June 2025, the U.S. Air Force issued a Notice of Intent to Award a 30-year, fixed-price contract to Oklo, Inc. for a 5-megawatt Aurora Powerhouse microreactor at Eielson. Oklo would build it, own it, and operate it. The Air Force buys the power under a long-term purchase agreement. As Air & Space Forces Magazine reported, the base currently runs on an almost 80-year-old coal plant, with power demand jumping from 10-12 megawatts in summer to 18-19 megawatts in winter when F-35s and Arctic operations ramp up.

Why does this matter for civilian remote communities?

• The military’s motivation mirrors the civilian one: energy resilience in a place with limited external supply, extreme weather, and a genuine strategic need for reliability

• The 30-year fixed-price contract structure is directly portable to civilian utilities that need predictable long-term energy costs

• Nancy Balkus, deputy assistant Air Force secretary for energy, specifically said the Eielson project will create a playbook “so that what we do at Eielson can be repeated at any other DOD base in Alaska or in the Lower 48”

• The project validates Arctic deployment logistics — permafrost, seismic activity, short construction seasons — which are exactly the conditions civilian northern communities face

Alaska’s Governor Mike Dunleavy has been explicit about the connection. After the state adopted new microreactor regulations in 2025 under Senate Bill 177, his office declared that “power from nuclear microreactors can be a game changer that reduces both the cost for electricity and carbon emissions” for rural villages, and set a goal of 10-cent electricity by 2030 — a price that diesel could never reach in communities that barge their fuel in.

The honest obstacles: this isn’t an easy sell 🔬

Here’s where intellectual honesty requires a pause. The case for microreactors in remote communities is genuinely compelling — the physics, the cost math, and the energy security argument all line up. But the barriers are real and, in some cases, not primarily technical.

Cost uncertainty is the first. The Nuclear Energy Institute’s cost range of $0.14 to $0.41 per kilowatt-hour for first-generation microreactors is projected, not demonstrated. First-of-a-kind nuclear projects have a well-documented history of cost overruns. A 2021 MIT CEEPR analysis found that microreactors would be cost-efficient in remote Alaskan communities if overnight capital costs stay below $15,000 per kilowatt electric — a figure within the anticipated range but one that the nuclear industry needs to prove, not just project.

Logistics and construction are a second set of challenges that Natural Resources Canada laid out candidly:

• Harsh permafrost conditions can destabilize foundations

• Short construction seasons compress the build window dramatically

• Specialized maintenance may only be reachable by air

• Lack of reliable communications infrastructure affects remote diagnostics

Regulatory and licensing timelines are slow even when the technology is straightforward. Oklo’s own history at Eielson — tentatively selected in August 2023, rescinded in September 2023, re-selected in June 2025 — illustrates that the path from “approved vendor” to “operating reactor” has plenty of places to stall.

And then there is the community consent question, which may be the most important one of all. McMaster University researchers writing in 2025 argued that “meaningful community engagement with Indigenous communities is required” and that “consultation is needed to understand the needs and goals of the community.” The IAEA’s Deputy Director General Mikhail Chudakov put it directly at a June 2026 stakeholder workshop: deploying SMRs “is not only a question of engineering, financing, safety or construction — it is also a question of transparently engaging an array of interested parties, including the communities that host these facilities, whose consent is vital.” A technically perfect reactor that the community doesn’t want solves nothing.

Where this is probably headed 🚀

The remote communities nuclear story is real, not speculative — but it’s playing out on a timeline measured in years, not months. A few things are reasonably clear.

The military will go first. Eielson is the test case for Arctic microreactor deployment. If Oklo’s Aurora performs as projected — 10 years between refuelings, passive safety in extreme cold, reliable power without a fuel supply chain — the playbook for civilian adaptation becomes much shorter. The EIA has confirmed that the Department of the Army is also launching its own microreactor program, with nine bases being evaluated for siting. These are real projects, funded, with companies selected.

Canada will be an early civilian market. Canada’s 2026 nuclear strategy commits C$40 million specifically to assess microreactor feasibility for remote military and northern operations. Natural Resources Canada has already mapped the opportunity: over 250 remote communities with high diesel costs, combined with growing mining activity in places like Ontario’s Ring of Fire, where power demand is far beyond what wind and solar alone can realistically deliver.

The economics will clarify as demonstration projects run. Right now, microreactor economics in remote settings are compelling in theory and uncertain in practice. The Westinghouse eVinci, Radiant Kaleidos, and Oklo Aurora are all moving through testing at Idaho National Laboratory. The cost data that comes out of those projects — real construction costs, real operating costs, real reliability numbers — will answer the question that no financial model can: whether first-of-a-kind nuclear actually beats diesel at the prices communities can afford.

The diesel trap has been sprung on remote communities for decades. Nuclear microreactors won’t spring everyone free at once — the first one in an Arctic civilian community probably won’t arrive until the late 2020s at the earliest. But the trajectory is changing, and faster than most people outside this sector have noticed. Whether your community pays $1.20 per kilowatt-hour for diesel-generated power or you’re a policymaker trying to figure out how to keep northern infrastructure funded, the next five years of microreactor deployment will be worth watching closely. What would it actually take to convince an isolated community that a small nuclear plant in their backyard is safer than the generator they’ve been running for the last 40 years?

Imagine you are the night-shift supervisor at a nuclear plant in 1979. A valve sticks open. Coolant bleeds out. Gauges give you contradictory readings. Your training didn’t cover this exact scenario. You make a reasonable call — and that reasonable call nearly turns Harrisburg, Pennsylvania into an exclusion zone. That was Three Mile Island, and according to the Nuclear Regulatory Commission, the partial meltdown happened because of “a combination of equipment malfunctions, design-related problems and worker errors.” Note what comes first on that list: the equipment and the design. The humans were working inside a system that was already stacked against them.

Seven years later at Chernobyl, the IAEA confirmed a reactor with a fundamental instability at the core of its physics — a positive void coefficient that actually increased power output as coolant boiled away. No operator, however skilled, could fully compensate for a reactor trying to run away from itself. The disaster that followed killed 28 people within weeks from acute radiation syndrome and released radioactive material across Europe.

Those two accidents defined nuclear safety thinking for the next four decades. The lesson wasn’t “build better operators.” It was “build reactors that can’t fail catastrophically even when everything else does.” Modern Small Modular Reactors are the most serious attempt yet to answer that challenge — and the engineering gap between a 1970s plant and a 2020s SMR design is bigger than most people realize.

The original problem: active safety was only as good as its power supply

The reactors of the 1970s relied on what engineers call active safety systems. These are systems that require something to happen — a pump to start, a valve to open, a diesel generator to fire up — in order to prevent an accident. That might sound fine, but it creates a chain of dependencies that can snap at any link.

At Three Mile Island, a stuck relief valve allowed coolant to drain for hours while instruments misled operators into thinking the reactor was fine. At Fukushima in 2011, the backup diesel generators that were supposed to power the cooling pumps sat in a basement that flooded within an hour of the tsunami. The World Nuclear Association notes that Fukushima’s three reactors were “written off after the effects of loss of cooling due to a huge tsunami were inadequately contained.” Three separate reactors. One flooding event. The active safety infrastructure couldn’t survive the scenario it was designed to handle.

The problem with active safety systems is structural:

• They require electrical power, which can be lost

• They depend on mechanical components that can jam, corrode, or fail at the worst moment

• They create complexity, and complexity creates failure modes nobody anticipated

• They put enormous cognitive and procedural load on human operators during the moments when humans are most likely to make mistakes

The engineers designing modern SMRs looked at this record and concluded that any safety system requiring external power or active human intervention is a liability. What they built instead is categorically different.

Passive safety: letting physics do the work 🔬

The defining innovation in modern SMR design is passive safety — the use of natural physical forces to shut down and cool a reactor without any external input. Gravity. Convection. The simple fact that hot water rises and cool water sinks. These forces don’t need a power supply. They don’t need an operator to notice something is wrong. They just work, all the time, according to the same thermodynamics that has governed the universe for 13 billion years.

As the small-modular-reactors.org analysis explains, passive safety “relies on natural forces, such as gravity, convection, and evaporation, to prevent or mitigate the consequences of accidents” and “stands in contrast to active safety systems, which require mechanical or electrical components to function and may be susceptible to failure or human error.”

Here’s what that looks like in practice in leading designs:

• Natural circulation cooling: In many SMR designs, the primary coolant circulates without pumps. Heat from the core warms the coolant, which rises; it then cools at a heat exchanger and falls back down. The loop keeps moving as long as there is heat — which means it keeps moving whenever it needs to most.

• Gravity-driven emergency injection: When pressure drops inside the reactor vessel, coolant tanks positioned above the core release water through gravity alone. No valves to open, no power needed, no human decision required. The tank empties into the core automatically.

• Passive containment cooling: The containment structure itself can reject heat to the surrounding air or a water pool through natural convection, without any fan or pump.

NuScale’s design, which became the first SMR to receive standard design approval from the U.S. NRC, demonstrates what this means in practice: the reactor can safely shut down and cool indefinitely with no operator action, no AC or DC power, and no additional water supply. Indefinitely. That is not a claim you could have made about any commercial reactor operating in the 1970s. Do you think that level of safety independence should change how close we’re willing to site nuclear plants to cities?

The physics inside the fuel itself ⚡

Passive safety isn’t only about the cooling loops and containment systems. Some of the most important safety advances in modern SMR design are baked into the physics of the reactor core itself — into what happens when the temperature rises.

The technical term is negative temperature coefficient of reactivity. In plain language: when the reactor gets too hot, the chain reaction automatically slows down. The physics of the fuel and moderator are arranged so that rising temperature reduces the efficiency of fission. No operator input, no control rod insertion, no safety system actuation. The reactor self-corrects.

This is the opposite of the Chernobyl RBMK’s positive void coefficient, where steam bubbles forming in the coolant increased reactivity. The Heritage Foundation’s analysis of the accident noted that this “contributed to rapid loss of control of the Chernobyl reactor core’s power.” The core wanted to run away, and the operators couldn’t stop it in time.

Modern SMR designs — particularly TRISO fuel designs — take the inherent safety idea further than most people expect:

• TRISO (tristructural-isotropic) fuel embeds uranium inside multiple ceramic layers, each one a miniature containment structure

• According to StarCore Nuclear’s analysis, TRISO fuel can withstand temperatures above 1,600°C, far beyond any temperature a properly operating reactor would reach

• If the reactor somehow overheated severely, the ceramic layers keep radioactive fission products locked inside each tiny fuel particle

• There is no fuel melt in the traditional sense, because the fuel is already in a form designed to survive extreme heat

Molten salt reactors take yet another approach, using fuel dissolved in fluoride salt that operates at low pressure. Because there’s no pressurized water to flash to steam, an MSR with a leak doesn’t create an explosive pressure event. The salt cools and solidifies. The fuel stays put. Research from ScienceDirect confirms that molten salt reactors feature “an inherent safety with strong negative temperature coefficient of reactivity” and “passive decay heat cooling” — two of the most important properties a reactor can have.

From design to consequence: shrinking the emergency zone 🌱

One of the most concrete ways to measure how much safer modern SMR designs are is to look at what regulators are willing to accept around them. In the United States, conventional large nuclear plants require an Emergency Planning Zone with a 10-mile radius. That’s the area where emergency sirens must be in place, where evacuation routes must be designated, where local governments must pre-plan for potential radiation releases. It exists because, in a severe accident at a large reactor, the consequences could extend that far.

NuScale has already changed this calculus. The U.S. NRC validated a methodology that allows NuScale’s SMR to operate with an Emergency Planning Zone limited to the site boundary — not 10 miles, not 2 miles, but the fence line of the plant itself. This doesn’t mean the NRC lowered its safety bar; as the NRC’s advisory committee confirmed, the methodology provides “the same level of protection to the public as the 10-mile radius EPZs used for existing U.S. nuclear power plants.” The smaller zone reflects a real reduction in accident consequence potential, not a regulatory shortcut.

What does a site-boundary EPZ actually mean in practice?

• No mandatory evacuation sirens for surrounding communities

• No required emergency drills with local governments and FEMA

• The ability to site SMR plants closer to industrial users, data centers, and cities

• Dramatically lower ongoing compliance costs for plant operators

• A fundamentally different public conversation about nuclear siting

The South Korean i-SMR design, described in a 2025 ScienceDirect paper, has achieved a core damage frequency of 1E-9 — meaning a one-in-a-billion chance of core damage per reactor-year of operation. Compare that to earlier Generation II reactors, whose core damage frequencies were often in the range of 1E-4 or worse. That is a five-order-of-magnitude improvement in core safety. If you’re tracking these design specifications across the full competitive landscape, SMRbrief Pro turns the nuclear intelligence in this article into a searchable, filterable, always-updated resource you can act on.

Underground, modular, and harder to break 🔬

The safety story doesn’t end at the reactor physics. Several modern SMR designs take the additional step of burying the reactor module underground, adding a layer of physical protection that no 1970s plant ever had.

Analysis from Tunneling Online published in early 2026 notes that underground siting “enhances security and resiliency by reducing exposure of safety-critical systems” and provides “favorable conditions for protection against extreme weather, impact hazards, terrorism attacks, and reduces seismic effects.” Holtec’s SMR-300, currently in the licensing pipeline, incorporates below-grade siting as a core design feature — and it’s already noted by Holtec itself that the protected area around an SMR-300 is “much smaller than that of a standard nuclear power facility because the risk associated with its operation is minimal.”

There’s also the sheer simplicity argument. Many 1970s reactor designs had:

• Large, complex primary coolant loops running through multiple buildings

• Hundreds of active valves, pumps, and instrumentation systems

• External emergency power systems (diesel generators, batteries) that had to survive whatever disaster was affecting the reactor

• Operator procedures running to thousands of pages for abnormal conditions

Modern integrated SMR designs — where the reactor core, steam generators, pressurizers, and primary coolant all live inside a single pressure vessel — eliminate entire categories of piping failures. A large-bore pipe break causing loss of coolant was one of the “design basis accidents” that 1970s safety systems were built around. In a fully integrated SMR design, that pipe doesn’t exist. You can’t break a pipe that isn’t there.

The IAEA’s latest briefing on SMR safety confirms that these designs “display an enhanced safety performance through inherent and passive safety features” — and critically, that this simplification is part of why they can be economically viable. Smaller emergency zones, simpler safety systems, factory fabrication: each feature that makes an SMR safer also tends to make it cheaper to build and license. That’s a combination the 1970s nuclear industry never managed to achieve.

The honest caveat is that most of these designs are still on paper or in early licensing. The safety case is theoretically compelling — and backed by serious engineering. But as any nuclear watcher knows, the distance between a certified design and an operating reactor can stretch for years, across regulatory revisions and cost overruns that test even the most patient investors. The physics is sound. The question now is whether the industry can actually build these things. What aspect of modern SMR safety do you find most convincing — or most in need of further proof before you’d want one in your neighborhood?

Nuclear energy has a long and occasionally brutal tradition of optimism outrunning reality. The SMR era is no exception. Over the past two decades, a series of projects that promised to rewrite the economics of nuclear power quietly — and not so quietly — collapsed under the weight of ballooning costs, missing customers, and the particular cruelty of being first-of-a-kind. The graveyard, as one nuclear engineering conference recently called it, is “filled with brilliant designs that couldn’t actually be built — or cost three times the estimate.”

That’s not a reason to give up on SMRs. The technology getting built right now — TerraPower in Wyoming, Ontario Power Generation’s BWRX-300 at Darlington, the microreactor programs multiplying across the U.S. military — is meaningfully different from the projects that collapsed. But the lessons from the failures are worth knowing. Anyone who dismisses the graveyard as ancient history, or waves it away as “that was then,” is probably building the next tombstone.

This is a tour of what went wrong, and what the industry learned by living through it. 🪦

The mPower experiment: too clever, not enough customers

Long before NuScale became the name everyone associates with SMR failure, Babcock & Wilcox was the company everyone was watching. Its mPower reactor — a 195 MW integral pressurized water reactor developed through a joint venture with Bechtel called Generation mPower LLC — was, by 2012, the publicly anointed front-runner. The New York Times called mPower the leader in the SMR race. The U.S. Department of Energy selected it for a five-year cost-share agreement, committing up to $226 million in federal support. The Tennessee Valley Authority signed on to explore permitting at its Clinch River site in Oak Ridge.

And then it started to unravel. Not dramatically. Slowly, the way bad nuclear projects usually die.

• In 2013, Babcock & Wilcox tried to sell a majority stake in the mPower joint venture and couldn’t find a buyer

• In February 2014, after mPower posted an $87 million operating loss in 2013, the company slashed investment to just $15 million annually

• The official reason: “inability to secure significant additional investors or customer engineering, procurement and construction contracts”

• By March 2017, Bechtel withdrew from the joint venture entirely, citing the failure to find a utility willing to site the first reactor or an investor willing to put up capital

Babcock & Wilcox paid Bechtel a $30 million settlement to walk away. The DOE had disbursed $111 million of its planned $226 million; that money is gone. The Wikipedia article on B&W mPower captures the end with merciless brevity: “The development project was terminated.”

What killed mPower? Not the engineering. The design was technically sound, NRC-approvable, and conventional enough to be licensable. What killed it was a customer problem. B&W built a product that utilities could not yet convince themselves to buy, in a market that had no experience pricing long-term commitments to first-of-a-kind nuclear technology. The lesson it left behind is one the industry should have absorbed completely by 2023. It didn’t. 💡

The NuScale CFPP: a masterclass in cost creep

If mPower is the forgotten cautionary tale, the NuScale Carbon Free Power Project is the one that made international headlines and caused NuScale’s stock to lose a third of its value in a single day. 📉

The basic facts are by now well documented. Utah Associated Municipal Power Systems (UAMPS) teamed with NuScale to build six 77-MWe power modules at the Department of Energy’s Idaho National Laboratory site, targeting operation by 2029. The DOE backed it with a $1.4 billion cost-share award. NuScale’s design became the first SMR ever certified by the U.S. Nuclear Regulatory Commission. As recently as 2022, this was widely described as the project that would prove commercial SMRs were real.

Then the cost estimates arrived. The trajectory, per NuScale’s Wikipedia entry and documented by multiple analysts, looked like this:

• 2015: $3.1 billion estimated cost for twelve modules generating 720 MW

• 2018: $4.2 billion, design resized to 60 MW per module

• 2020: $6.1 billion, timeline pushed to 2030

• 2023: $9.3 billion for just 462 MW — construction cost up 75% in 18 months

By January 2023, the target power price had jumped from $58/MWh to $89/MWh — a 53% increase — making NuScale’s electricity more expensive per megawatt than the notoriously costly Vogtle reactors in Georgia. Utilities did the math and flinched. Subscription levels — UAMPS needed 80% commitment from its municipal member utilities to proceed — stayed well short of that threshold. On November 8, 2023, UAMPS and NuScale mutually terminated the project. Utility Dive reported NuScale CEO John Hopkins said: “Once you’re on a dead horse, you dismount quickly. That’s where we are here.”

The clean-energy think tank Clean Air Task Force wrote a useful post-mortem noting that while the cancellation was painful, the project had still yielded something: NuScale’s regulatory journey produced the first-ever reduction in Emergency Planning Zone requirements for an SMR and demonstrated reduced control room staffing requirements — achievements that benefit every subsequent SMR developer, not just NuScale. The costs of the CFPP were, in part, the industry’s tuition. 🔬

That’s a generous reading. The blunter one is that the project underestimated first-of-a-kind risk at almost every turn. Construction costs for novel nuclear projects have a documented tendency to balloon; a 2014 academic study analyzed 180 nuclear projects worldwide and found 175 exceeded their initial budget by an average of 117%. CFPP behaved exactly as the historical data predicted.

X-energy and the SPAC misfire

The NuScale debacle sent ripples through the entire SMR sector, and the X-energy/Ares Acquisition Corporation SPAC merger is the clearest example. 💊

X-energy, a Maryland-based developer of the Xe-100 high-temperature gas-cooled reactor using TRISO fuel, had announced in December 2022 a deal to go public by merging with Ares Acquisition Corporation (NYSE: AAC), a special-purpose acquisition company. The deal initially valued X-energy at roughly $2 billion. By June 2023, under amended terms, that valuation had been revised down to $1.8 billion. By October 31, 2023, the deal was dead.

The stated reasons were:

• “Persistently volatile public market conditions”

• “Peer-company trading performance” — meaning NuScale’s collapse scared investors away from the whole sector

• A mutual judgment that the risks of becoming a public company outweighed the benefits given the climate at the time

Neither party paid a termination fee. X-energy went back to raising private capital, and Wikipedia’s X-energy entry notes directly that the SPAC collapse was triggered partly by NuScale’s CFPP cancellation and its “effect on the market.” One domino hit another.

The postscript is instructive. X-energy survived, raised $235 million from existing investors in December 2023, secured a massive Amazon commitment for up to 5 gigawatts of power by 2039, and went public in May 2026 at $23 per share — 15 times oversubscribed — in what was described as the largest nuclear IPO on record. The lesson from the X-energy SPAC failure is, I think, simpler than the lesson from NuScale: market timing matters, and 2023 was a terrible year to go public in nuclear. The technology was not the problem. The macroeconomic moment was. 🚀

The BWRX-300: alive but expensive — and the warning it carries

The GE Vernova Hitachi BWRX-300 is not a graveyard story. Construction began at Ontario Power Generation’s Darlington site in May 2025; the first unit is now on track for late 2029. But the BWRX-300’s cost trajectory is close enough to past failures that it deserves to be in any honest discussion of what can go wrong.

When GE Hitachi first pitched the BWRX-300 around 2018, the promise was $700 million per 300-MW unit — roughly $2,250/kW — low enough to compete with natural gas. That estimate is now, generously speaking, a historical curiosity.

Ontario’s final investment decision in May 2025, approved by the provincial government, set the budget for the first unit at $7.7 billion Canadian (about $5.6 billion USD), per World Nuclear News’s detailed cost breakdown. The total projected cost for all four Darlington units is $20.9 billion Canadian in 2024 dollars. The first unit alone costs roughly US$15,000/kW — a number that puts it in the same range as Vogtle, widely cited as the most expensive power plant ever constructed. 🏗️

The IEEFA, in its May 2024 analysis titled SMRs: Still Too Expensive, Too Slow and Too Risky, tracked the cost-per-kilowatt for the BWRX-300 design from $2,883/kW in 2020 to a range of $7,408 to $12,347/kW by 2023 — before a single unit had been poured.

What distinguishes the BWRX-300 from the mPower and NuScale stories is that Ontario Power Generation went ahead anyway. OPG is publicly owned and takes a long view. It expects the second, third, and fourth units to cost dramatically less than the first as construction processes normalize. That logic is plausible — every mature reactor fleet started with an expensive first-of-a-kind unit — but it requires faith in future cost reductions that the industry has promised, and failed to deliver, before.

Do you think the “fleet economics” argument — that FOAK costs will fall sharply by the third or fourth unit — is credible given the history? The answer probably tells you more about your priors on nuclear than any individual data point.

What the graveyard actually teaches us

Look across mPower, the NuScale CFPP, the X-energy SPAC, and the BWRX-300 cost blowout, and a few patterns emerge clearly. ⚡

First: the customer problem comes before the engineering problem. Every failed or struggling project has had adequate technology. What it has lacked is committed buyers at the price the technology actually costs. The subscription model UAMPS used for CFPP — where municipal utilities had to commit before the first concrete was poured — is probably not viable for first-of-a-kind nuclear. You’re asking risk-averse public utilities to underwrite an experiment. The commercial structure has to evolve before the economics can follow.

Second: first-of-a-kind costs are not first-estimates costs. The 2014 study finding that 175 of 180 nuclear projects worldwide exceeded budget by an average of 117% isn’t ancient history. It’s the base rate. Every estimate for a novel nuclear design should be read as a lower bound, not a target. Projects that treat early cost numbers as gospel — and stake their subscription models on them — will be surprised.

Third: negative contagion is real. The X-energy SPAC didn’t fail because of X-energy’s technology. It failed because NuScale’s collapse scared the public markets. The industry’s projects are more interconnected than developers usually admit. One high-profile failure poisons the financing environment for everyone.

Fourth: what looks like failure sometimes isn’t. NuScale’s CFPP produced NRC design certification — still the only one any SMR has — and regulatory precedents that reduce Emergency Planning Zone requirements for the entire next generation of designs. The mPower project trained a workforce and produced engineering data that informed other designs. The industry paid a steep tuition, but it did learn.

The projects now under construction — Darlington, TerraPower’s Natrium in Wyoming, the military microreactor programs — carry the marks of these lessons. They have better-defined customer commitments. They have more government backing to cushion first-of-a-kind risk. Whether that’s enough to avoid the next tombstone in the graveyard is the question the 2030s will answer.

What failure do you think the SMR industry is still repeating today — and which previous mistake do you most clearly see in the projects now moving forward?

Africa holds roughly 18% of the world’s uranium reserves, according to a 2025 study published in ScienceDirect. It produces about 14% of global uranium output, with Namibia, Niger, and South Africa among the top mining nations. All that fissile potential sits underground while more than 500 million people on the continent still have no reliable electricity. The gap between what Africa has and what Africa needs is so absurd it almost reads as satire.

That’s starting to change. More than 20 African countries are now exploring nuclear power in some form, according to the IAEA’s June 2025 Outlook for Nuclear Energy in Africa, developed specifically for South Africa’s G20 presidency. Some are building. Some have signed agreements and are planning. Others are circling the idea, watching their neighbors move, and keeping their options open. Understanding who is where in this process matters enormously — both for the countries themselves and for the SMR vendors, financiers, and technology suppliers trying to figure out where to focus.

This is the current map. 🗺️

Egypt: the one that’s actually happening ⚡

If you want to see Africa’s nuclear future in concrete form — literally — you look at Egypt’s Mediterranean coast, about 320 kilometers northwest of Cairo. That’s where the El Dabaa Nuclear Power Plant is under construction, four VVER-1200 reactors built by Russia’s Rosatom at a cost that has climbed to roughly $30 billion. Russia is financing approximately 85% of the project through a state loan, which is the kind of arrangement that secures influence for decades.

Progress at El Dabaa has been steady and significant through 2025 and into 2026:

• The reactor pressure vessel for Unit 1, weighing 340 tonnes and manufactured over 41 months in St. Petersburg, arrived in Egypt in late October 2025 and was installed in November

• As of mid-2025, more than 25,000 workers were active onsite daily, the majority Egyptian nationals

• The inner containment shell for Unit 2 has progressed through multiple tiers of installation

• A new on-site training center has opened to begin building Egypt’s operational workforce

The World Nuclear Association reports that Rosatom’s director general expects all four units to be operational by 2030, with the first unit beginning commissioning in 2026. When it comes online, it will be the first Generation III+ reactor on the African continent. Egypt is not dabbling in nuclear. This plant is happening.

What’s interesting is that even as El Dabaa progresses, Egypt is already looking sideways at SMR technology. Egypt’s Prime Minister met with Rosatom chief Alexey Likhachev in April 2026 and specifically noted Egypt’s interest in expanding cooperation to include small modular reactors, according to Daily News Egypt. A country building one of Africa’s biggest energy infrastructure projects is already thinking about what comes next. That’s not a bad sign at all. 🔬

South Africa: the experienced hand making a comeback

South Africa is the only African country with an operating commercial nuclear plant. The Koeberg Nuclear Power Station near Cape Town has been running since the 1980s, and both units are now cleared to operate until 2044 and 2045 respectively, following licence extensions approved in 2025. No other country on the continent has four decades of operational nuclear experience. That’s a significant asset.

But Koeberg is old technology, and South Africa’s government is now moving aggressively to build on that foundation. The country’s Integrated Resource Plan 2025, approved in October 2025, calls for 5,200 MW of new nuclear capacity by 2039, with the first 1,200 MW online by 2036. The site at Duynefontein, adjacent to Koeberg, has received full environmental approval. That’s a $128 billion national energy investment framework with nuclear at its core.

The most fascinating piece of South Africa’s nuclear story is the revival of the Pebble Bed Modular Reactor program. South Africa originally developed the PBMR — a helium-cooled, TRISO-fueled high-temperature SMR — from the 1990s until 2010, when the government cut funding and put it into care and maintenance. In November 2025, Cabinet lifted that status and transferred the technology from Eskom to Necsa, the country’s nuclear energy corporation. Necsa immediately announced plans to identify an international partner to co-develop and operate South Africa’s first SMR demonstration reactor at Pelindaba.

The long-term ambition here is striking. South Africa’s energy minister has stated publicly that the goal is for South Africa to become a leading supplier of SMRs across Africa, replacing decommissioned coal units and powering off-grid industrial sites across the continent. A country that runs its own nuclear plant and owns the IP on a mature SMR design is not the same as a country that just signed an MoU with Rosatom. South Africa has real options — and a genuine shot at becoming Africa’s nuclear technology hub rather than just another customer. 🌍

That said, the PBMR still needs another estimated R30 billion ($1.75 billion) to commercialize, on top of the R10 billion already spent. Environmental groups have challenged the expansion plans in court before and may do so again. The path is clearer than it’s been in 15 years, but it isn’t straight.

The serious aspirants: Ghana, Kenya, and Rwanda 🚀

Three countries stand out in the second tier: not yet building, but meaningfully further along than most.

Ghana probably has the most credible near-term SMR story in sub-Saharan Africa. The country operates a research reactor, has developed nuclear regulatory infrastructure with IAEA support, and in 2024 signed commercial agreements with both US-based NuScale (for its VOYGR-12 SMR) and China National Nuclear Corporation (for a large reactor), giving it a genuinely diversified technology portfolio. In January 2025, NuScale opened an operator training simulator center in Ghana — the first of its kind on the continent. Ghana is also part of the US-led FIRST program (Foundational Infrastructure for Responsible Use of Small Modular Reactor Technology), which helps countries build the regulatory, workforce, and supply chain foundations for SMR deployment. The World Nuclear Fuel Report 2025 forecasts Ghana having 1 GW of nuclear capacity operational by 2038.

The catch for Ghana — and it’s a significant one — is financing. Ghana’s sovereign credit rating and fiscal position mean it cannot fund a nuclear project domestically, and external financing for nuclear in Africa remains genuinely difficult. Ghana may end up being the proving ground where the nuclear finance model either gets cracked or fails visibly.

Kenya is moving with more institutional methodicalness than almost anyone else. Kenya’s Nuclear Power and Energy Agency has published a timeline, confirmed a site in Siaya County, and is targeting construction starting in 2027 and commissioning by 2034. In May 2025, Kenya hosted Africa’s first IAEA-led SMR School — a signal of serious policy intent, not just aspirational rhetoric. Kenya has signed cooperation agreements with the US, South Korea’s KHNP, China, Russia, and Slovakia. By late 2026, it expects to issue a formal Request for Proposal, with multiple major vendors already in the running. Keeping four superpowers at the table simultaneously is unusual diplomatic maneuvering, and I think it’s working to Kenya’s advantage — competitive pressure between vendors tends to produce better terms.

Rwanda is the most interesting wildcard. It has signed agreements with US-based NANO Nuclear Energy, Canadian-German firm Dual Fluid, and Russia’s Rosatom on nuclear cooperation, and as recently as May 2026, Rwanda signed a new nuclear MoU with Russia at the Nuclear Energy Innovation Summit in Kigali. Lassina Zerbo, chair of the Rwanda Atomic Energy Board, was candid with Energy Intelligence at the World Nuclear Exhibition in Paris in late 2025: “None of the African countries today is ready financially to go immediately in implementing the nuclear power plant.” Rwanda’s 2030 target for an SMR is ambitious to the point where skepticism is warranted. But Rwanda is building institutional capacity deliberately, sending students to Russia for nuclear engineering degrees, and cultivating multiple supplier relationships simultaneously. That’s smart positioning, whatever the timeline turns out to be. 💡

The watching-and-waiting group

A meaningful number of African countries — including Uganda, Nigeria, Morocco, Algeria, and others — are somewhere between early exploration and active planning, without the clear execution milestones of the group above.

Uganda acquired land in Buyende for East Africa’s first nuclear plant and signed a contract in May 2025 with South Korea’s KHNP for a 26-month site evaluation to support an 8,400 MW target by 2040. That’s an enormous number for a country whose current grid is measured in hundreds of megawatts. Uganda has ambition; what it needs is a credible financing architecture.

Nigeria is the most financially capable of the aspirants but arguably the most organizationally fragmented. The Nigeria Atomic Energy Commission head Anthony Ekedegwa has publicly noted the lack of meaningful US engagement in his country and said that Russia and China are both offering partnerships. Nigeria passed the second reading of its Nuclear Energy Development Bill in late 2025. A minister advocated for SMRs over large reactors in May 2025. The pieces are moving, but slowly and without the kind of centralized coordination that Ghana and Kenya have developed.

Morocco operates a research reactor and has signed agreements with France, Russia, and China on nuclear cooperation. In 2024 it announced plans to cooperate with France on building an experimental reactor. Morocco’s approach — cultivating multiple Western and Eastern partnerships simultaneously — is diplomatically balanced and probably sustainable long-term.

The honest summary of this watching-and-waiting group is that many of them have signed enough MoUs to wallpaper a government ministry, without yet having the regulatory infrastructure, grid capacity, or financing structure to turn those agreements into poured concrete. That’s not a condemnation — this is genuinely difficult work, and nuclear programs routinely take 15-20 years from first serious commitment to first power. But there’s a real risk of MoU fatigue, where agreements pile up without any getting consummated.

Does your country or region have a stake in how Africa’s nuclear race plays out? Consider how the technology choices African nations make now will lock in fuel dependencies, maintenance relationships, and geopolitical alignments for 60 to 100 years.

The geopolitics no one can ignore 🌱

Africa’s nuclear development is not happening in a vacuum. It’s happening inside one of the most active geopolitical competitions of the 2020s, and that shapes almost every decision.

Russia has signed nuclear energy partnerships with at least 20 African countries through Rosatom, according to the Energy for Growth Hub’s June 2025 analysis. The El Dabaa model — Russia finances, builds, supplies fuel for the entire life cycle, and trains operators for the first decade — creates exactly the kind of long-term structural dependency that critics of Rosatom’s Africa strategy point to. Al Jazeera noted in its June 2026 reporting on Rwanda’s Rosatom MoU that Russia’s nuclear outreach is explicitly tied to broader strategy for continental influence.

China approved 11 new domestic reactor projects in 2024 alone and has deals with at least four of the six African countries that have reached IAEA’s Phase 2 nuclear development milestones. At the 2024 Forum on China-Africa Cooperation, China and Nigeria agreed to expand nuclear cooperation. China’s Belt and Road Initiative now increasingly includes what Beijing calls “nuclear energy” or “green” components.

The United States has leaned on its FIRST program and the annual US-Africa Nuclear Energy Summit — hosted in Nairobi in 2024 and in Rwanda in 2025 — to compete. The Ghana NuScale agreement is the most concrete US commercial deal on the continent. But the American Enterprise Institute argued in October 2025 that the US is still losing ground to China and Russia and needs to scale up urgently if it wants to remain competitive.

The key financing challenge tying all of this together is stark. The IAEA noted in its 2025 outlook that African clean energy investments account for only about 2% of the global total, constrained by sovereign debt and credit rating concerns. A 2025 partnership between the IAEA and the World Bank offers some hope of multilateral financing beginning to flow. But a 100-MW SMR at current costs of $2–3 million per megawatt runs over $200 million — before the grid upgrades, regulatory infrastructure, and workforce training that have to accompany it. Most African nations cannot self-finance. Whoever solves the African nuclear finance problem owns the market.

The smarter African governments, I think, are the ones playing multiple suitors simultaneously: keeping the Americans, Chinese, and Russians all believing they have a real shot, and using that competition to extract better terms. Kenya is the clearest example of this strategy in practice. The question is whether any country can maintain that balancing act long enough for commercial SMRs to actually become available — which most projections put at the early 2030s at the earliest.

What’s your read on Africa’s nuclear future: will the financing problem get solved in time for SMRs to matter, or will the continent end up primarily connected to large Russian and Chinese conventional reactors by default?

For most of nuclear energy’s history, building a reactor meant finding a river first. That was the deal: you need massive amounts of water to cool the core, so you park the plant next to a lake, a river, or an ocean, and you pump millions of gallons through the system every day. The Union of Concerned Scientists puts it plainly — nuclear plants sit on shorelines “not for the scenic views,” but because they need bodies of water to absorb the waste heat they constantly generate. For every three units of energy a conventional reactor produces, two are discharged to the environment as waste heat. That’s an enormous amount of thermal baggage to manage, and you need a river to do it.

The problem is that rivers are fickle. In the summer of 2022, France learned this the hard way when drought and record heat pushed river temperatures so high that its nuclear plants had to cut output or shut down entirely. That summer was Europe’s driest in 500 years, and by August, as many as 32 of France’s 56 reactors were offline. France — a country that normally exports electricity to its neighbors — found itself importing more power than it shipped out. A 2023 French Court of Auditors report concluded that such shutdowns could become three to four times more frequent by 2050. Climate change is systematically attacking one of nuclear power’s core assumptions.

Small modular reactors are being designed to break that assumption entirely. The physics and engineering behind modern SMR designs are genuinely different from the reactors of the 1960s, 1970s, and 1980s. Some don’t need rivers at all. Some can operate in deserts. And the reasons why matter enormously for where clean power can actually go in the coming decades.

Why old nuclear plants are so thirsty in the first place

Traditional nuclear plants use water in two distinct roles. The first is as a coolant and moderator inside the reactor vessel itself, where water slows down neutrons to the speed needed to sustain fission. The second is in the condenser, where the steam that spun the turbine gets cooled back into water so it can cycle through the system again.

It’s that second step — the condensing — that demands so much water. As the Breakthrough Institute explains, older coastal plants typically used “once-through” cooling: seawater flows in through filters, passes through tubes in the condenser, and gets pumped back out into the ocean slightly warmer. A large reactor required staggering flow rates. According to historical research published via Project MUSE, the small 581 MWe Ginna plant in New York needed 6,000 gallons of water per second, while the two reactors at Calvert Cliffs in Maryland required 20,000 gallons per second each. The two reactors at South Africa’s Koeberg station pulled 40 cubic meters of seawater per second from the Atlantic.

That’s why, as the MUSE researchers note, virtually all large nuclear plants ended up on coastlines or riversides. It wasn’t a design preference. It was a physical necessity. You either had access to a giant, continuous water source, or you didn’t build.

The World Nuclear Association documents how this water dependence created real operational vulnerabilities, not just theoretical ones:

• In mid-2010, the Tennessee Valley Authority cut output at three Browns Ferry reactors in Alabama to 50% to keep river water below 32°C — at a cost of roughly $50 million to ratepayers

• That same week, Rhine and Neckar river temperatures in Germany approached the critical 28°C threshold, threatening nuclear plant closures

• In August 2012, Connecticut’s Millstone station shut down one unit because Long Island Sound seawater exceeded 24°C

These aren’t edge cases. They’re what happens when a technology is fundamentally coupled to environmental water conditions, and those conditions get increasingly extreme.

How SMR designs cut the water cord

The newer SMR designs attack the water problem at multiple levels, and the approaches vary quite a bit depending on whether a design uses water, molten salt, sodium, or gas as its primary coolant. 🔬

Water-cooled SMRs don’t escape the need for some water, but they’ve substantially reduced how much they need and, more importantly, where it has to come from. Many designs use passive safety systems — gravity and natural convection rather than powered pumps — which reduces the scale of cooling infrastructure required. According to energy.sustainability-directory.com, passive systems in SMRs rely on:

• Natural circulation, where heated coolant rises and cooled coolant sinks without any pump

• Gravity-driven water delivery from tanks positioned above the reactor core

• Conduction of heat directly through the reactor vessel wall into surrounding structures or air

The NuScale Power Module, the first SMR to receive design certification from the U.S. Nuclear Regulatory Commission, was planned with dry air cooling for its Idaho deployment. No river required. The condensate cycle can close using cooling towers or air-cooled condensers rather than a natural water body — you lose a few percentage points of efficiency, but you gain the ability to put the plant wherever it makes sense economically and strategically, not wherever there happens to be a river.

Holtec’s SMR-300 is particularly explicit about this. The company has built an optional Air-Cooled Condenser (ACC) system directly into the design, which it says enables operation in “arid environments” and “water-challenged locales.” In May 2026, Holtec announced that its SMR-300 was selected for the Green River Advanced Nuclear Project in Utah — a desert state. That choice wasn’t arbitrary; the ACC system makes it viable where a conventional plant simply could not go.

Non-water coolants change the rules completely ⚡

Then there are the designs that don’t use water as their primary coolant at all, and these are the ones that really scramble conventional nuclear geography.

TerraPower’s Natrium reactor, now under construction at Kemmerer, Wyoming under a construction permit issued by the NRC in March 2026, uses liquid sodium as its primary coolant rather than water. As Wyoming Public Media reported, sodium cooling is safer than traditional water cooling “compared to the traditional nuclear plant cooling method of water that requires much higher pressure.” Sodium carries heat at much lower pressures, which dramatically simplifies the primary circuit. Kemmerer sits in the high desert of southwest Wyoming, far from any major water body — and that’s entirely fine for a sodium-cooled reactor. The U.S. Department of Energy confirmed the NRC’s December 2025 safety review came in ahead of schedule and 11% under budget. This is a real project, breaking real ground.

Molten salt reactors are even more radical. Designs like Terrestrial Energy’s Integral Molten Salt Reactor (IMSR) operate at high temperatures and low pressure, using fluoride salts that are liquid at operating temperature. According to Wikipedia’s molten-salt reactor article, the IMSR is specifically designed as a deployable SMR with high-temperature output suited to industrial heat markets beyond just electricity. When things go wrong with a molten salt reactor, the salt freezes — it’s a passive safety mechanism baked into the physics, not an engineered response. Decay heat removal in some designs uses nitrogen, with air as a backup. Not a drop of river water involved.

Gas-cooled designs like X-energy’s Xe-100 use helium as the coolant. The UN Scientific Advisory Board’s December 2025 brief on SMRs notes that these systems “offer the potential for higher thermal efficiencies and improved fuel utilization.” The Xe-100 uses TRISO fuel — essentially tiny spheres of nuclear fuel encased in multiple layers of ceramic protection. Those fuel pebbles can withstand the heat of an accident without external cooling, which means the reactor can potentially be sited, cooled, and operated with far less dependence on environmental water. 🌱

The siting freedom this actually creates

Here’s why this matters beyond engineering curiosity. The water constraint has historically shaped not just where nuclear plants were built, but who got access to nuclear power at all.

Landlocked regions, arid countries, remote industrial sites, military bases in the middle of nowhere — all of these have historically been out of the running for nuclear power because you couldn’t get enough water there. SMRs are changing that geographic calculus in concrete ways. The U.S. Energy Information Administration reported in April 2026 that the U.S. Army’s Janus Program has already selected nine military bases as potential microreactor sites, including Fort Bragg, Fort Campbell, and Fort Hood. The Air Force is planning its first microreactor at Eielson Air Force Base in Alaska, working with Oklo’s sodium-cooled Aurora design.

None of these are riverside installations in the traditional sense. The Wikipedia article on nuclear microreactors notes they can be installed underground, underwater, or in other remote locations — a 15-megawatt reactor designed to go a mile underground in a borehole, like Deep Fission’s concept, doesn’t need a cooling tower or a river at all. The Earth itself is the heat sink. 🏗️

The practical geography of SMR deployment, based on what’s actually happening in 2026, looks something like this:

• Desert industrial sites — Holtec’s Utah project, using air-cooled condensers in water-scarce terrain

• Retired coal plants — TerraPower’s Wyoming site, where some existing infrastructure is reused but water access is minimal

• Remote military bases — Army’s Janus Program microreactors, prioritizing energy resilience over geographic convenience

• Off-grid communities — Alaska, Canada, and island nations where diesel dependence is costly and water supply uncertain

The common thread: all of these locations were previously inaccessible to nuclear power. That’s a meaningful expansion of where clean, reliable, carbon-free baseload power can actually go.

Have you thought about which industries or regions stand to gain the most from nuclear power freed from water constraints? The answer might surprise you.

One honest caveat about water ♻️

It’s worth being clear that not all SMRs are water-independent, and some water-cooled SMR designs still depend on external water for their condenser loops — they’ve just reduced the volume required compared to conventional plants. The World Nuclear Association notes that the Holtec SMR-160 and B&W mPower designs “use dry cooling or can do so,” while other water-based SMR designs retain some water dependence for their steam condensers. The IAEA and UN Scientific Advisory Board are also careful to distinguish between light-water SMRs, which still use water as their primary coolant, and Advanced Modular Reactors (AMRs), which use liquid metals, gases, or molten salts.

Even among designs that still need water for their secondary loop, the requirement is far smaller than conventional plants. Passive safety systems mean the reactor can shut down safely without the emergency water flows that Fukushima’s reactor required when its cooling pumps lost power. The sheer reduction in required flow rates opens up smaller rivers, groundwater wells, or even closed-loop water systems that would have been unworkable for a 1,000 MWe conventional plant.

The broader point, though, is directional: the technology trajectory is clearly toward water independence, not away from it. Sodium, salt, helium, and air-cooled water systems all point the same direction. The question for the industry isn’t whether SMRs can eventually break free of water constraints. It’s whether they can get to commercial scale fast enough to matter — which is a different problem entirely, and one the industry is working urgently to solve.

Given that climate change is simultaneously making water-dependent nuclear plants less reliable and increasing demand for reliable zero-carbon power, that urgency seems well-placed. What’s your take on whether water independence should be a harder requirement for future nuclear licensing, rather than just a design option?

Nothing in this article is financial advice. These are research notes, not recommendations. Do your own due diligence, understand the risks, and consider speaking with a qualified advisor before putting money into any of these names.

The nuclear energy trade has been one of the stranger rides in recent investment memory. Stocks exploded on AI power demand narratives in 2024, gave back enormous chunks of those gains through 2025 and early 2026, then started recovering as real milestones — NRC approvals, construction starts, billion-dollar contracts with tech giants — began landing. The sector is now in that uncomfortable middle zone where the narrative is strong but the revenues are still mostly hypothetical, the timelines are long, and the valuation spread between the most speculative plays and the actual cash-generating businesses is wide enough to swallow a submarine.

What follows is a look at five names that consistently appear on nuclear and SMR watchlists right now: two pure-play SMR developers, one diversified energy giant with skin in the game, one profitable supply chain company, and one fund for investors who’d rather spread the bet. They represent meaningfully different risk profiles, which is the point. Choosing one over another isn’t just a question of how bullish you are on nuclear — it’s a question of what kind of uncertainty you’re willing to sit with. 📈

1. NuScale Power (NYSE: SMR) — the first-mover with regulatory proof

NuScale Power occupies an unusual position: it’s a pre-revenue company trading on narrative, but the narrative has a concrete regulatory foundation that no US competitor can match. In May 2025, the Nuclear Regulatory Commission approved NuScale’s uprated 77-megawatt design — the second NRC certification the company has received, and the only SMR design in the United States with that status. That matters because any competitor building a US reactor has to go through the NRC review process, which takes years and costs tens of millions. NuScale already has the answer sheet. 🔬

The commercial picture is developing, slowly. Romania’s Nuclearelectrica shareholders approved the six-module RoPower project at the former Doicești coal plant, with a mid-2026 go/no-go final investment decision looming as a major near-term catalyst. In the US, NuScale’s strategic partner ENTRA1 has a nonbinding agreement with TVA for a potential 6 gigawatt deployment — the largest SMR program ever proposed in the country. NuScale ended Q1 2026 with $1 billion in liquidity, giving it meaningful runway even as revenue remains thin.

The risks are not subtle:

• Revenue in 2025 was $31.5 million, down from $37 million in 2024 — the wrong direction

• Bank of America restarted coverage at Neutral with a $12 price target, flagging that real reactor revenue likely waits until the early 2030s

• The stock has been one of the most volatile names in the nuclear space, moving sharply on any news

• Fluor, a major early backer, has been systematically selling its NuScale stake — a signal worth taking seriously

NuScale is a binary-style investment. Either the Romania project secures its final investment decision and the TVA program firms up into real contracts, or it remains a company that has never built a reactor and is burning cash faster than it earns it. Northland maintained an Outperform rating with a $19 target even after trimming from $21, citing dilution concerns. The gap between the bull and bear cases here is genuinely extraordinary, which is exactly why it stays on every watchlist. 💡

2. Oklo (NYSE: OKLO) — Sam Altman’s nuclear bet, now making real progress

Oklo is the company that most cleanly represents the nuclear startup trade: charismatic leadership, OpenAI CEO Sam Altman as chairman, AI power deals with Meta and Switch already in place, and a fast reactor design that looks nothing like conventional light-water technology. It’s also, as of June 2026, making more concrete regulatory progress than its stock price suggests. ⚡

The NRC approved the Principal Design Criteria for Oklo’s Aurora powerhouse reactor in Q1 2026 — an accelerated milestone that directly strengthens the licensing timeline. The DOE selected Oklo for advanced negotiations under the Surplus Plutonium Utilization Program, which would give the company access to Cold War-era plutonium as reactor fuel. And subsidiary Atomic Alchemy received an NRC materials license in March 2026 to work with medical and industrial isotopes — Oklo’s first NRC approval of any kind and an early revenue pathway in a market worth over $7 billion globally.

The stock picture is complicated. Oklo raised $1.182 billion in a January 2026 equity offering, ending Q1 with $2.5 billion in cash. At a guided operational burn rate of $80 to $100 million per year, that’s theoretically decades of runway. But the stock trades at around $58 as of early June 2026 — down more than 70% from its 2025 highs — and Wolfe Research initiated coverage in May 2026 with a cautious Peer Perform rating and a fair value range of $51 to $71. Analyst consensus targets sit at roughly $89, implying significant upside from current levels if the milestones materialize.

Key catalysts to watch in the coming months:

• Whether Atomic Alchemy achieves criticality at its Groves Isotopes Test Reactor in Texas by July 2026, per DOE’s Reactor Pilot Program

• Progress on the Aurora reactor’s NRC licensing application

• Securing HALEU fuel access, which remains the single biggest operational blocker for widespread commercial deployment

• Firmness of the Meta and Switch power agreements as actual build timelines clarify

The thesis on Oklo is that it’s building not just a reactor but a full nuclear platform — isotopes, fuel recycling, reactor design — that could be worth far more than the current valuation if even half the pieces land. Whether that’s optimism or a story built on complexity to justify a price, I’m genuinely not sure. 🚀

3. GE Vernova (NYSE: GEV) — the infrastructure giant with real earnings today

If the first two entries made you nervous, GE Vernova is the antidote. This is a company with a $150 billion backlog as of end-2025 and growing, actual revenue, actual earnings, and a SMR program that currently costs it money but which investors are treating as long-term optionality rather than the core business. 🌍

The SMR angle is the BWRX-300, developed jointly with Hitachi. The first commercial BWRX-300 is under construction at Ontario Power Generation’s Darlington site in Canada, the only commercial SMR under active construction in the Western world. Ontario Power applied for an operating license in March 2026; the first unit is targeted to come online by 2029. In the US, GE Vernova and Hitachi were selected for a new US-Japan nuclear program involving BWRX-300 deployments in Tennessee and Alabama as part of a wider $40 billion bilateral energy initiative. TVA’s construction permit application is with the NRC; a DOE grant of $400 million went to accelerate the Clinch River deployment.

The stock has been the standout performer in nuclear energy over the past year, up roughly 75% in 2026 year-to-date as of late April amid surging gas turbine demand, grid equipment orders, and nuclear momentum. The SMR business is currently a drag on margins — management said so explicitly — and they don’t expect that to flip before the late 2020s. So what investors are buying is:

• The existing gas turbine and grid business, which is printing money

• Nuclear as long-duration optionality embedded in a profitable enterprise

• A company whose overall backlog grew $13 billion in just Q1 2026 alone

The valuation is not cheap at roughly 46 times forward earnings, pricing in a lot of the good news already. But unlike the pure-play SMR names, GEV isn’t a bet that ends at zero if the first reactor gets delayed. 💡

4. BWX Technologies (NYSE: BWXT) — the pick-and-shovel play with a moat

BWX Technologies is the name that sophisticated nuclear investors tend to mention when everyone else is arguing about Oklo and NuScale. That’s because BWXT is already profitable, generates real cash, and has a structural position in the nuclear supply chain that no competitor can easily replicate. As the only large commercial nuclear equipment manufacturing facility in North America, it’s one of the very few companies licensed to handle HALEU and TRISO fuel, manufacture naval reactor components, and produce specialized nuclear hardware at scale. ⚡

The numbers tell the story clearly:

• Total 2025 revenue: $3.1 billion, generating net income of nearly $330 million

• Backlog at end-2025: $7.3 billion — up 50% year over year

• Commercial operations revenue (nuclear components, fuel handling, medical): up 63% to $853 million in 2025, continuing into Q1 2026 with 121% year-over-year growth

• Analyst consensus on revenue and EBITDA CAGRs of 13% and 12%, respectively, through 2028

The SMR exposure is real but disciplined. BWXT signed a contract to manufacture the reactor pressure vessel for the BWRX-300 in January 2025. It signed a design contract for Rolls-Royce SMR steam generators in Q3 2025 and an agreement for future manufacturing. It provides engineering support to multiple SMR developers. This is the company that will likely make money whether NuScale, Oklo, GE Vernova, or some design not yet widely discussed wins the commercial reactor race — because someone has to manufacture the components, and BWXT is the only firm at scale to do it. 🔬

The stock is up nearly 100% over the past year. At roughly 31 times this year’s adjusted EBITDA, it’s not cheap by any standard measure. But a wide moat in a supply-constrained market with decades of contractual backlog tends to command a premium. The argument for owning BWXT is that it’s a nuclear play with a floor — the defense and government segment alone ($2.3 billion in 2025 revenue, $5.5 billion of the backlog) would keep the company healthy even if SMR deployment takes longer than expected.

Think of it as the boring answer that might actually turn out to be the right one. 📈

5. VanEck Uranium and Nuclear ETF (NLR) — spreading the bet across the whole chain

For investors who find the individual stock picking exercise genuinely daunting — and it is daunting — the VanEck Uranium and Nuclear ETF (NLR) offers a way to hold a diversified slice of the nuclear economy without committing to a single company’s execution risk. It tracks the MVIS Global Uranium & Nuclear Energy Index and spreads across uranium miners like Cameco, reactor operators and utilities like Constellation Energy, and reactor technology and services names including BWXT. 🌱

The performance has been striking. According to a May 2026 analysis, NLR gained 18% year-to-date and 98% over the prior 12 months as of late April 2026. That’s not a quiet corner of the market.

Why NLR rather than the purer Sprott Uranium Miners ETF (URNM), which was up 26% YTD and 119% over the same period? A few reasons worth thinking through:

• URNM is heavily concentrated in uranium miners, with Cameco at a 20.2% weighting and significant exposure to Kazakh jurisdictional risk through Kazatomprom

• NLR’s weighting toward utilities and reactor technology companies like Constellation Energy and BWXT gives it less sensitivity to uranium spot price swings

• URNM pulled back 3% in a single session in April 2026 on no company-specific news — a reminder that pure miner exposure amplifies volatility in both directions

• NLR pays an annual distribution (0.55% 30-day SEC yield in early 2026), which URNM does not

Neither is the obviously superior choice in all market conditions. URNM makes more sense if you have a strong view on uranium prices specifically. NLR makes more sense if you want exposure to the nuclear buildout without that commodity layer on top. Both carry more volatility than a broad equity index, and neither has a track record through a full SMR deployment cycle because that cycle hasn’t happened yet. ♻️

The broader nuclear ETF universe, including the Global X Uranium ETF (URA), gives investors additional options, but NLR remains the go-to for balanced nuclear sector exposure that includes the reactor builders and operators alongside the miners.

So here’s the question that matters: are you buying the technology, the fuel, the manufacturing infrastructure, or the idea that all of them win together? Each of these five positions bets on a different part of that answer — and having clarity on which part you believe in most is probably the most useful investment decision you can make in this space right now.

Hydrogen is having a complicated moment. The molecule everyone agreed was essential for deep industrial decarbonization has spent the last few years colliding with economic reality: it’s expensive to make cleanly, difficult to store, awkward to transport, and the infrastructure to use it at scale barely exists. Green hydrogen — made by running electricity through an electrolyzer to split water — currently costs somewhere between $3.50 and $6 per kilogram at most facilities, against grey hydrogen (made from natural gas, no carbon capture) sitting at roughly $1 to $2 per kilogram. That’s a brutal gap for any industrial buyer trying to make a business case.

SMRs enter this picture not as a silver bullet, but as something more interesting: a source of power that has structural advantages for hydrogen production that solar and wind simply don’t. The argument is worth making carefully, because it’s not obvious, and the hype-to-substance ratio in the hydrogen space has been appalling for years. So let’s get specific.

Why electricity source matters more than most people realize

When you run an electrolyzer, you need electricity, and lots of it. Electricity is 55 to 70 percent of the total cost of producing green hydrogen. That number, from a March 2025 techno-economic analysis published in Cell Reports Sustainability, is the load-bearing fact in any honest discussion of nuclear hydrogen economics. It means that the cheaper, cleaner, and more reliable your electricity source, the more competitive your hydrogen becomes. 💡

Renewables have made enormous strides on cost — solar PPA prices below $20 per megawatt-hour are now achievable in high-resource markets — but they carry a problem that compound math punishes over time: they’re intermittent. An electrolyzer idling for half the day because the sun isn’t shining is a very expensive piece of capital equipment producing nothing. Capacity factor matters enormously for the economics. Nuclear reactors run at 90-plus percent capacity factors, operating essentially around the clock, year-round. Wind and utility-scale solar typically come in at 30 to 40 percent. That difference doesn’t just affect output volume — it affects the effective cost per kilogram of hydrogen produced from every dollar of electrolyzer investment. 🔬

The DOE’s January 2025 blog post on the 45V Hydrogen Production Tax Credit made exactly this point, noting that nuclear’s high capacity factors allow it to ensure clean hydrogen production continues when renewable sources are unavailable — the stable baseload that an electrolyzer operator needs to justify the capital expenditure.

Key reasons why nuclear’s profile suits hydrogen production:

• Stable baseload output maximizes electrolyzer utilization, which dominates lifecycle cost

• No intermittency means no need for oversized electrolyzer capacity to compensate for low-production hours

• Process heat from higher-temperature reactor designs can reduce the electricity needed per kilogram

• Siting flexibility: SMRs can go near industrial hydrogen users, cutting transmission and transport costs

• Carbon-free by definition, qualifying for clean hydrogen tax incentives under the US 45V framework

The chemistry: more than one way to split water

Before getting into which SMR designs work best for hydrogen, it’s worth knowing that not all hydrogen production pathways are equal, and the reactor’s outlet temperature matters a lot. ⚡

The most mature approach is low-temperature electrolysis, using either alkaline electrolyzers or proton exchange membrane (PEM) systems. These use electricity only, work at temperatures a conventional light-water reactor handles comfortably, and are the basis for the demonstration projects Vistra and Xcel Energy are running at existing US reactors in 2025, supported by DOE funding. They’re proven. They work. The economics are not yet stellar, but they’re moving in the right direction.

The more exciting approach, and the one where SMR design choices really start to matter, is high-temperature steam electrolysis (HTSE). Running steam through a solid oxide electrolysis cell rather than liquid water through a conventional electrolyzer reduces the electrical energy required by roughly 15 to 30 percent, because some of the energy input comes as heat rather than electricity. NuScale published a detailed white paper in February 2025 describing its hydrogen simulator, which models configurations capable of producing more than 200 metric tons of hydrogen per day from a six-module plant — enough to supply nearly 5 million fuel cell passenger vehicles annually. The company has integrated this into its control room simulator so operators can dynamically manage the electricity/hydrogen split in real time. 🌱

Then there’s the pathway that gets the most attention in research circles but has yet to reach commercial scale: thermochemical water splitting. The sulfur-iodine cycle, first proposed by General Atomics in the 1970s, uses heat at around 850 to 900°C to drive a series of chemical reactions that split water into hydrogen and oxygen without any direct electrolysis. The iodine and sulfur recirculate; the only inputs are water and heat. Efficiency projections are as high as 50 percent — considerably better than electrolysis routes. The catch is that you need a reactor running at 900°C to drive it, which rules out conventional light-water reactors entirely. This is the domain of high-temperature gas-cooled reactors, where designs like the Japanese HTTR and China’s HTR-PM pebble-bed reactor operate. If any SMR in this class reaches commercial deployment, the thermochemical route becomes genuinely interesting at scale.

The “pink hydrogen” economics and what the tax credit changes

The industry term for hydrogen made with nuclear power is “pink hydrogen.” It’s a useful shorthand even if the colour-coding of hydrogen types has gotten slightly absurd. 🌍

The current production economics are sobering but improving. A October 2025 study published in International Journal of Hydrogen Energy evaluated five SMR designs — NuScale VOYGR-4, VBER-300, BWRX-300, i-SMR, and ACP100 — each coupled to a 50 MW alkaline electrolyzer. The calculated levelized cost of hydrogen spanned $6.17 to $8.29 per kilogram under current conditions, with a trajectory to $4.73 to $6.25 by 2030 to 2035 as reactor and electrolyzer costs decline. That’s still above grey hydrogen without carbon pricing, but the analysis highlights a useful point: electricity expenditure dominates at 83 to 87 percent of total cost, meaning a 10 percent reduction in the reactor’s LCOE drops hydrogen cost by about $0.50 per kilogram. The leverage is significant.

This is where the US 45V Clean Hydrogen Production Tax Credit enters as a potential game-changer. The Inflation Reduction Act established a 10-year credit of up to $3.00 per kilogram for hydrogen with the lowest lifecycle emissions — a category nuclear power cleanly qualifies for. The final rules, published in January 2025 by the IRS and Treasury, carved out explicit provisions for existing nuclear plants, acknowledging that new nuclear can’t be built fast enough to serve hydrogen projects on the timeline the market needs.

With the $3.00/kg credit applied:

• Pink hydrogen from SMRs becomes cost-competitive with unsubsidized grey hydrogen today

• The economics improve further as SMR capital costs decline with series production

• Industrial buyers have a credible, long-term price signal to plan against

• The credit window (expiring 2033) creates urgency around early deployment

Does that credit survive the current political environment? That’s the uncomfortable question. TD Cowen analysts in early 2025 publicly flagged that they expected “root-and-branch level changes” to 45V guidance under Republican leadership, with multiple legislative tools available to revise the rules. The Inflation Reduction Act’s tax credits have shown more durability than many expected, but the hydrogen credit specifically has been contested. Anyone building an SMR hydrogen business model purely on the $3.00/kg credit has a real policy risk embedded in their pro forma.

Which industrial sectors actually want this

The hydrogen economy’s cheerleaders have a habit of citing everything from trucking to heating as eventual hydrogen demand. That’s probably overstated. But a few sectors have a specific, pressing need for low-carbon hydrogen that nuclear is genuinely well-suited to serve. 🚀

Ammonia production is the most immediate. The Haber-Bosch process that makes ammonia — which in turn makes most of the world’s fertilizer — currently consumes about 1.8 percent of global energy and emits roughly 450 million tonnes of CO₂ per year. It runs on hydrogen made from natural gas. Replacing that hydrogen with nuclear-powered electrolysis is a direct substitution: same molecule, lower carbon, industrial scale. A 2025 preprint from researchers at the University of California, published and reviewed on Sciety, found that with First-of-a-Kind SMR capital costs and the 45V credit, 91 gigawatts of SMR capacity could be economically deployed in the US for industrial hydrogen production, targeting ammonia, steel, and refining before the credit expires in 2033. That number is striking. It’s also contingent on capital cost assumptions that may or may not hold.

Steel production is next in line. Direct-reduced iron using hydrogen, rather than coking coal, can produce steel with dramatically lower emissions. Europe’s HYBRIT project and others have demonstrated this at pilot scale, but the hydrogen volumes required for large-scale deployment are enormous and need to be cheap and available continuously. An SMR collocated at an integrated steel complex is one of the more genuinely compelling SMR applications precisely because it solves the reliability and transportation problem simultaneously.

Oil refining already consumes vast quantities of grey hydrogen for hydrotreating. The capacity to produce that hydrogen on-site with nuclear power rather than from a steam methane reformer running on natural gas is technically straightforward — it’s the same electrolyzer infrastructure, cheaper fuel input over time, and eliminates the CO₂ emissions from the reformer entirely.

Have you thought about which of these industrial sectors has the most realistic path to deploying nuclear hydrogen at scale in the next decade? The answer might not be the one most discussed.

The honest case for skepticism

I think the nuclear hydrogen story is compelling. I also think it’s easy to underestimate the obstacles. 📈

The core problem is the sequence: SMRs need to be built and proven before they can supply hydrogen, and the hydrogen economy needs hydrogen before it can develop the infrastructure that makes demand bankable. Those two things need to happen in rough synchrony, and neither is moving as fast as the charts in investor decks suggest. The LCOH projections cited above assume learning rates and capital cost reductions that require deployment volumes that don’t yet exist. It’s a classic chicken-and-egg problem with a nuclear-grade price tag.

The DOE’s Hydrogen Shot Initiative targets $1 per kilogram of clean hydrogen by 2031. That goal was set with electrolysis in mind, and achieving it requires electricity costs around $20 to $30 per megawatt-hour — territory solar achieves in the best locations, but not territory most SMRs will reach at first-of-a-kind costs. Nuclear’s advantage is reliability and industrial heat; its disadvantage is capital cost per unit of output. Those two facts together suggest nuclear hydrogen is probably not the cheapest path to clean hydrogen everywhere, but it is likely the right path for industrial users who need guaranteed, continuous supply near existing facilities not blessed with exceptional solar or wind resources.

That’s a real and large market. It’s not the only market, and nuclear advocates who claim it is overselling. The IAEA’s 2025 publication Developing a Roadmap for the Commercial Deployment of Nuclear Hydrogen is notably careful on this point, treating nuclear hydrogen as one of several production pathways rather than a monopoly solution.

Key uncertainties that will determine whether SMR hydrogen reaches scale:

• Whether SMR capital costs fall as quickly as vendors project in first-of-a-kind builds

• How durable the 45V hydrogen production credit proves to be under changing administrations

• Whether thermochemical pathways can be demonstrated at commercial scale with high-temperature SMR designs

• How quickly industrial hydrogen consumers can convert existing processes to accept new supply

• Whether hydrogen transport and storage infrastructure develops in parallel with production

The next few years will tell a lot. The Vistra and Xcel demonstrations at existing nuclear plants are producing real data that will either validate or complicate the economic models. NuScale’s hydrogen simulator work should eventually be tested against commercial-scale deployment. And the first wave of SMR deployments — from Kairos Power’s fluoride salt reactor in Tennessee to GE Hitachi’s BWRX-300 planned for Ontario — will establish actual capital costs rather than estimates.

If you’re tracking the SMR hydrogen story, the number worth watching is not the stock price of any hydrogen company but the actual installed cost per kilowatt of the first few SMR builds. That number, more than any policy change or research result, will determine whether pink hydrogen becomes commercially meaningful before 2035 or quietly retreats to the category of “promising but not yet.”

If you follow the SMR space even casually, you’ve seen the IAEA’s name pop up in press releases, policy briefs, and conference agendas. The International Atomic Energy Agency is everywhere. But most coverage treats it as backdrop — a logo stamped on a document, a quote from Director General Rafael Mariano Grossi, a mention of “international safety standards.” That’s a shame, because what the IAEA actually does is far more interesting than its reputation as a bureaucratic stamp of approval. It’s simultaneously the world’s nuclear cop, nuclear trainer, nuclear librarian, and — increasingly — nuclear matchmaker for the SMR industry. Understanding its real function is essential if you want to understand why the global SMR pipeline looks the way it does in 2025.

Start with the origin story, because it’s a good one. The IAEA was born in 1957, the direct offspring of President Eisenhower’s famous “Atoms for Peace” speech to the UN General Assembly in December 1953. The Cold War was at full boil, nuclear terror was very real, and Eisenhower’s gambit was to channel the atom toward electricity and medicine rather than warheads. The resulting agency was given a mandate that sounds almost paradoxical: promote atomic energy and control it at the same time. That tension is baked into the IAEA’s DNA, and it shapes everything the organization does today — including its work on SMRs.

What the IAEA actually is

People often assume the IAEA is a regulatory body that tells countries what they can and cannot build. It’s not. The IAEA has no direct enforcement power over member states. What it has is moral authority, technical expertise, and — when it comes to nuclear safeguards — a legally binding verification role under the Nuclear Non-Proliferation Treaty. That distinction matters a lot once you start looking at how the organization actually functions. 🌍

The IAEA does four things well. First, it runs the global nuclear safeguards system — the inspections regime that verifies countries are not diverting peaceful nuclear material toward weapons. Second, it sets safety standards that member states are expected to follow. Third, it provides technical assistance to countries developing or expanding nuclear programs. Fourth, it acts as an information hub, maintaining databases like ARIS (the Advanced Reactors Information System) that track every SMR design on the planet.

None of these are small jobs. Right now, more than 1,300 facilities and locations worldwide are under IAEA safeguards. The safeguards team — over 800 people at headquarters alone — uses tamper-proof seals, surveillance cameras, environmental sampling, and good old-fashioned physical inventory checks. Think of it as a global nuclear audit, every year, everywhere. One IAEA inspector described the work as similar to a bank audit: you compare what’s in the accounting records against what’s physically present. Except the stakes are considerably higher than an overdraft. 🔬

The safeguards challenge for SMRs

Here’s where it gets genuinely complicated. Traditional safeguards were designed around large light-water reactors at fixed sites with predictable fuel cycles. SMRs break most of those assumptions. 🚀

Consider the range of designs now in development. The Nuclear Energy Agency’s July 2025 SMR Dashboard identified 127 distinct SMR designs globally, of which 74 had enough public information to analyze. Of those 74, 51 are already in pre-licensing or licensing processes across 15 countries. The designs range from conventional pressurized water reactors scaled down to 50 MW, to molten salt reactors, high-temperature gas-cooled reactors, and fast-spectrum designs that use enrichment levels traditional plants never approached. Some are designed to be factory-built and shipped to site. Others are designed to float on barges in the Arctic.

Safeguarding a module-based reactor where fresh fuel arrives and spent fuel leaves on a different schedule than anything the existing inspection regime was built around — that’s a real problem. Some SMR designs use high-assay low-enriched uranium (HALEU), enriched to between 5% and 20%, which requires different accounting controls than the standard fuel the inspection system was optimized for. A floating reactor in international waters raises questions about jurisdiction that the existing frameworks were never designed to answer.

The IAEA is working on all of this, though “working on” is doing some heavy lifting in that sentence. The agency has published technical documents on “Safety, Security and Safeguards by Design in Small Modular Reactors”, which pushes the idea that safeguard considerations should be embedded at the design stage rather than bolted on afterward. That’s the right approach. Whether the inspection infrastructure can keep pace with 127 designs in 18 countries is a harder question.

Key safeguards challenges the IAEA is actively addressing:

• Novel fuel types that require new accounting and verification procedures

• Modular, factory-built designs where “the facility” isn’t a fixed location

• Designs using HALEU, which carries higher proliferation sensitivity than standard fuel

• Floating and offshore reactors with complex jurisdictional questions

• New coolants (molten salt, gas, liquid metal) that change how material flows are tracked

The NHSI: the most important initiative nobody’s talking about

If the safeguards work is the IAEA’s defensive job, the Nuclear Harmonization and Standardization Initiative — NHSI, pronounced as an acronym that only nuclear insiders use — is its offensive play for the SMR era. 🌱

The core problem NHSI addresses is embarrassingly basic: if a company designs an SMR and wants to sell it in multiple countries, it currently has to get regulatory approval in each country essentially from scratch. Every regulator uses different codes, different safety analysis methods, different documentation formats. This isn’t just expensive and slow — it kills the economics of the factory-built, mass-produced model that makes SMRs theoretically cheaper than large reactors. You can’t serialize production if every unit requires a bespoke licensing campaign.

NHSI, launched in 2022, runs on two parallel tracks. The regulatory track is building frameworks for:

• Sharing safety review information between national regulators so work doesn’t get duplicated

• A multinational pre-licensing joint review process where regulators from different countries evaluate a design together

• A collaborative review process that lets regulators work in parallel during ongoing national licensing

• Mechanisms for leveraging one country’s completed review when another country starts its own

The industry track, meanwhile, has pulled in more than 200 contributors from over 30 countries and is working on harmonized user requirements, common approaches to codes and standards, and shared experimental data. As IAEA Director of Nuclear Power Aline des Cloizeaux put it at the 2025 binding.energy conference: “We don’t build reactors — but we help the world build them better.”

By mid-2025, NHSI had moved into Phase II, focused on implementing Phase I’s recommendations rather than just developing them. Three technical documents capturing Phase I’s regulatory work are expected to be published in 2025. That’s slow by startup standards. It’s remarkably fast by international treaty organization standards, and the work is genuinely complicated. Harmonizing national regulatory frameworks without compromising national sovereignty or safety standards is the kind of problem that looks simple until you actually try it. ♻️

The SMR School and the newcomer country challenge

Here’s a dynamic that gets undercovered in Western SMR coverage: the countries most interested in deploying SMRs in the next decade are not primarily the US, UK, or France. They’re countries like Kenya, Ghana, Jordan, Poland, Thailand, and Mongolia — nations with limited or no existing nuclear infrastructure, policy frameworks still being written, and regulatory bodies that may not yet have staff trained in nuclear licensing.

About 30 “newcomer” countries are actively considering or advancing toward nuclear power, and many of them have specifically identified SMRs as the path in — precisely because a 100 MW SMR is a more realistic starting point than a 1,200 MW gigawatt-class plant. This is actually one of the more compelling arguments for SMRs that often gets lost in debates about economics and timelines: smaller reactors lower the minimum viable grid size and the upfront capital requirement. A country with a peak electricity demand of 500 MW can’t meaningfully integrate a traditional large reactor, but it can integrate two or three SMR modules. 💡

The IAEA’s response to newcomer demand is the SMR School program, launched in 2025. The inaugural session was hosted by Kenya in May 2025, drawing 28 officials, policy makers and managers from Kenya, Ghana, Niger, Nigeria, Uganda and Zambia. A second SMR School followed in Thailand in September 2025, focused on Asia. Future schools are planned for Latin America.

The curriculum covers:

• Energy planning and how SMRs fit into national grids alongside renewables

• Technology development and the current state of available designs

• Legal frameworks and the regulatory infrastructure a country needs before it can license a reactor

• Safety, security and safeguards obligations under international law

• Economics, financing models, and how to structure agreements with vendors

This matters enormously for the long-term SMR market. A country that goes through this process with IAEA guidance is more likely to end up with a functional regulatory framework — which means fewer surprises, fewer delays, and fewer political reversals once construction starts. And for vendors, a customer country that understands what it’s buying and has the institutional capacity to oversee it is a vastly better commercial partner than one that doesn’t.

Does the IAEA process move fast enough? Probably not, by the timelines SMR advocates tend to cite. The IAEA’s milestone approach — a structured framework guiding newcomer countries from initial exploration to actual operation — estimates 7 to 10 years for a first-of-a-kind SMR in a newcomer country, dropping to 4 to 5 years for subsequent units. That’s a long runway for technology companies accustomed to software development cycles. But it’s also probably realistic for an industry where the downside of rushing the regulatory process is a meltdown, not a bad product review.

What this means for the SMR industry

The IAEA is not an obstacle to SMR deployment. That’s worth stating plainly, because the agency sometimes gets cast in that role by people frustrated with the pace of nuclear regulation. The NHSI’s entire purpose is to speed up licensing. The SMR School’s purpose is to expand the addressable market. The safeguards-by-design work is trying to solve the inspection problem before hundreds of novel reactors get built, rather than after. 📈

The more honest tension is this: the IAEA is a consensus organization with 178 member states, and consensus organizations move slowly. NHSI has over 200 industry contributors and has been operating since 2022. Its Phase I results are being published in 2025. For comparison, a software API standard might get from proposal to adoption in six months. That speed mismatch is a structural feature of international governance, not a bug the IAEA can fix.

What the IAEA can do — and increasingly is doing — is create the connective tissue that the global SMR market needs. A database of every SMR design with standardized technical specifications. A forum where regulators in a dozen countries can share safety review findings. A curriculum that turns energy ministers in sub-Saharan Africa into informed buyers of nuclear technology. A safeguards architecture that can actually handle modular, factory-built, fuel-flexible reactors operating on four continents. None of that is glamorous work. None of it generates headlines like a reactor groundbreaking or a funding round. But without it, the SMR market would be a collection of isolated national experiments rather than a coherent global industry.

The IAEA’s 2024 SMR report puts the current situation accurately: the agency’s unique role is in “catalysing technology development and deployment in Member States” — not building reactors, not licensing them, but creating the conditions in which building and licensing becomes possible at scale. ⚡

The question worth sitting with is whether the pace of that institution-building is keeping up with the pace of design development. With 127 designs globally, 51 in active licensing processes, and an 81% rise in SMR financing announcements since 2024, the commercial side of the industry is accelerating fast. The governance infrastructure is accelerating too — just not at the same speed. That gap is probably the single biggest systemic risk in the SMR sector right now, more than any individual technology question. How do you think that gap gets closed — does the IAEA need to move faster, or does the industry need to slow down and wait for the rules to catch up?

When people talk about small modular reactors, they almost always talk about electricity. Megawatts. Grid decarbonization. AI data centers. The conversation stays firmly in the domain of kilowatt-hours, and that’s understandable — power generation is what nuclear does most visibly.

But there’s a second application that doesn’t get nearly the same attention, despite a track record stretching back to 1973 and growing urgency in 2026. Nuclear desalination — using reactor-generated heat and electricity to pull drinkable water from the sea — is older than most people realize and more ready for SMR integration than the coverage suggests. According to the IAEA’s own accounting of nuclear cogeneration history, reactors in India, Japan, and Kazakhstan have accumulated over 200 reactor-years of operational experience in desalination. This isn’t a concept. It’s a proven process that never got the commercial scale it deserved — partly because cheap fossil fuels made it unnecessary for most of the 20th century.

That calculus is changing fast. More than two billion people currently lack reliable access to safe drinking water, according to the World Nuclear Association’s August 2025 report on desalination. By 2050, nearly half the world’s population is expected to live in water-stressed regions. And the countries most desperate for clean water are overwhelmingly the same countries baking under intense sun with long coastlines — precisely the places where nuclear desalination makes technical and economic sense. 🌊

This is the dual-use case nobody in the SMR industry is shouting about loudly enough.

The physics of why this works

Nuclear reactors produce two things: electricity and heat. Traditional power plants throw away the heat. They convert roughly a third of their thermal output into electricity and dump the rest into rivers, oceans, or the air. It’s a known inefficiency baked into every conventional nuclear design, one that policymakers and engineers have tolerated because electricity was the point.

Desalination needs both electricity and heat, depending on which process you use. Thermal desalination, including multi-stage flash distillation (MSF) and multi-effect distillation (MED), uses direct heat to boil seawater and collect the condensed freshwater. Reverse osmosis (RO) uses high-pressure pumps powered by electricity to push seawater through semi-permeable membranes that block salt. RO now accounts for roughly 85% of global desalination plants because it’s more energy-efficient than thermal methods per cubic meter of output.

An SMR can feed both. 💡 It can dedicate electrical output to drive RO systems while simultaneously routing waste heat into thermal desalination units. Or it can do RO exclusively, with the nuclear plant’s baseload electricity running the pumps 24 hours a day without intermittency, which is exactly the kind of always-on power that solar-driven RO struggles to deliver.

The key advantages of pairing SMRs with desalination come down to:

• No carbon emissions: nuclear desalination has lifecycle carbon emissions two to three orders of magnitude lower than fossil-fuel-powered plants, per a 2022 peer-reviewed study in Desalination journal

• Reliability: unlike solar or wind-powered RO, an SMR runs at full capacity regardless of weather — membranes and pumps work best under steady-state conditions, not variable loads

• Cogeneration efficiency: heat that would otherwise be wasted gets a second job, improving the overall economics of the plant

• Siting flexibility: SMRs are smaller than conventional reactors, which means they can be built closer to coastal communities that need water rather than centralized far from demand 🔬

The World Nuclear Association’s desalination resource page notes that nuclear cogeneration plants have been built and operated in Bulgaria, Canada, Germany, Hungary, India, Japan, Kazakhstan, Russia, Slovakia, Switzerland, and the United States. Almost 500 reactor-years of combined operational experience in various cogeneration applications, and the safety record is essentially clean. Design precautions to prevent the transfer of radioactivity into desalted water have proven effective in every deployment.

NuScale’s triple play: water, power, and hydrogen

The most detailed recent blueprint for SMR-driven desalination comes from NuScale Power, whose research announced in mid-2025 lays out a system that’s genuinely clever in how it chains outputs together.

According to NuScale’s announcement and a detailed analysis in Power magazine, a single 77-MW NuScale Power Module (NPM) coupled to a reverse osmosis system could yield approximately 150 million gallons of clean water per day without generating carbon dioxide. Scale that up to a 12-module plant and you get enough desalinated water for a city of 2.3 million residents, with surplus electricity to power 400,000 homes on top.

That’s an impressive headline number. The part that makes it genuinely interesting, though, is what NuScale plans to do with the brine. 🧬

Brine is the concentrated salt waste that comes out the back end of every desalination plant. It’s an environmental problem: dense, hot, chemically concentrated, and bad for marine ecosystems when dumped carelessly. The standard approach is to dilute it before ocean discharge, which adds cost and energy. NuScale’s researchers, working with the U.S. Department of Energy’s Pacific Northwest National Laboratory (PNNL), developed a novel process that extracts an inert salt from the brine stream and uses it as industrial feedstock for hydrogen production.

The approach skips water electrolysis entirely. It’s a hydrothermal chemical decomposition process, which means it uses heat rather than electricity to drive the chemistry. Per NuScale CTO Dr. José Reyes: “What we have found is a win-win-win aimed at addressing water scarcity, brine remediation, and hydrogen production.”

The three-output model looks like this:

• Clean water: reverse osmosis membranes powered by nuclear electricity produce freshwater

• Electricity surplus: power goes to homes, industry, or data centers

• Green hydrogen: brine waste feeds a novel low-energy hydrogen production process 💊

Whether this scales commercially is genuinely uncertain. NuScale’s research was presented at the World Petrochemical Conference in spring 2025 and represents a promising research direction, not a deployed product. But the basic logic — that an SMR can power desalination while turning its waste stream into a commodity — is sound enough to take seriously.

Where the need is most pressing

Water scarcity and coastlines overlap in uncomfortable ways across the Middle East, North Africa, and South Asia. These are the places where SMR-plus-desalination makes the most immediate economic argument, and the numbers are stark.

Saudi Arabia powers its desalination plants using roughly 300,000 barrels of oil daily, according to the Atlantic Council. The kingdom supplies 70% of its drinking water through desalination. Kuwait gets 90% of its drinking water from desalination. Oman, 86%. The UAE, 42%. These countries are not running fossil fuels through their desalination plants as a temporary measure — they’re running them because there’s no other large-scale option available. They’re literally burning oil to make water. ♻️

Nuclear changes that equation. The IAEA’s September 2025 report on nuclear desalination in the Arab region identifies Jordan as one of the most advanced active cases. Jordan classifies 75% of its land as arid desert and has been working with the IAEA to evaluate using SMRs to pipe drinking water from Red Sea desalination plants up to Amman. Khalid Khasawneh, Commissioner for Nuclear Power Reactors at the Jordan Atomic Energy Commission, said that nuclear desalination “offers competitive prices for fresh water to end consumers, in comparison with imported energy sources.”

Think about that for a second. Jordan — a landlocked country except for its tiny Red Sea coastline — is seriously planning to build an SMR at the coast, desalinate seawater, and pump the water uphill to its capital. That’s the kind of infrastructure ambition that only makes sense when the alternative is continuing to buy expensive imported water in a country where groundwater is already critically depleted.

The IAEA hosted a technical meeting on nuclear cogeneration applications in April 2025, with participants from Egypt, Jordan, and Kuwait. SMR-powered desalination is also under consideration in Saudi Arabia and Egypt, per a 2026 analysis from ORF Middle East. The interest is real and growing, not theoretical. 🌍

A 2025 research paper in ScienceDirect specifically examined integrating SMRs into the UAE’s existing desalination infrastructure, noting that by 2026 a demonstration project in Texas was planned to show how high-temperature reactor technologies could be coupled to desalination for cogeneration applications.

Have you thought about which regions might leapfrog conventional energy infrastructure entirely by combining SMRs and desalination in a single deployment?

The honest challenges

Positivity about SMR desalination needs to be tempered by honest accounting of what’s actually hard here.

The first challenge is cost. Desalination is already expensive. Nuclear is expensive upfront. Combining them means two complex, capital-intensive systems that both need to be financed, permitted, constructed, and operated simultaneously. The economics get better at scale and over long time horizons — nuclear’s low operating costs shine over a 20-to-40-year plant life — but the initial capital requirement is a real barrier for many of the developing nations most desperate for water.

The second challenge is the same regulatory timeline problem that haunts all SMRs. A country like Jordan planning to build an SMR for desalination still needs to develop its entire nuclear regulatory framework essentially from scratch, with IAEA support. That takes years before a single module gets ordered.

The third challenge is brine management, which NuScale’s hydrogen approach addresses partially but doesn’t fully solve at scale. Desalination produces a lot of brine. Larger plants produce more. Ocean disposal regulations are tightening globally, and the environmental pressure on coastal desalination to handle brine responsibly adds cost that doesn’t always feature in optimistic projections.

The fourth is water security in conflict zones. The Middle East’s dependence on desalination has already proven to be a vulnerability: attacks on desalination plants have created humanitarian crises in Yemen, Gaza, and other conflict-affected areas, per MIT Technology Review’s April 2026 reporting. A nuclear-powered desalination plant is a more hardened target in some ways, but also a higher-value one. The security calculus is not simple.

What’s your view on whether these obstacles are dealbreakers or engineering problems that scale and time will solve?

Why this matters beyond the obvious markets

The SMR-desalination case doesn’t depend solely on the Middle East to be strategically important. Water stress is spreading to regions that didn’t expect it a generation ago: the American Southwest, northern India, southern Europe, northern China.

California’s Carlsbad desalination plant, which opened in 2015 and provides about 10% of San Diego County’s potable water, runs on roughly 40 MW of electricity. That’s well within the range of a single SMR module. As water stress moves inland and solar-driven RO runs into the same intermittency problems at scale that solar runs into everywhere, nuclear-backed desalination may start looking attractive in developed markets that currently dismiss it. 🚀

The XPRIZE Water Scarcity competition, a $119 million initiative to accelerate low-cost desalination technologies, reflects a recognition that the world needs better answers faster than the current pace of innovation provides. SMRs aren’t competing with XPRIZE-style membrane innovation — they’re potentially the power source that makes that innovation viable at the scale and reliability the world needs.

The IEA’s data suggests global desalination capacity needs to grow at roughly 5.6% annually through 2030 to meet projected water demand. That’s a lot of electricity and heat. Some of it will come from solar. Some from grid power. And if the SMR industry executes on even a fraction of its current plans, some of it will come from modular reactors co-located with plants that turn the ocean into drinking water.

That’s a use case worth tracking as closely as the data center deals. Possibly more so — because data centers serve shareholders, but desalination serves the billion-plus people who don’t have reliable clean water today.

Something extraordinary happened in April 2026: the IEA published a report finding that the pipeline of conditional offtake agreements between data center operators and SMR projects had grown from 25 gigawatts at the end of 2024 to 45 gigawatts today. In 16 months, the industry doubled its nuclear commitments. That’s not a trend. That’s a panic buy.

The reason is straightforward: AI is consuming electricity at a pace the grid was never designed to handle. Data center electricity demand jumped 17% in 2026, and AI-focused facilities grew even faster, according to the same IEA report. The five biggest tech companies, Amazon Web Services, Google, Meta, Microsoft, and Equinix, poured more than $400 billion into data center capital expenditure in 2025 alone — a figure the IEA notes now exceeds global investment in oil and gas production combined. And demand is set to increase by another 75% in 2026.

The grid is not keeping up. Grid interconnection queues in many U.S. regions now stretch five to ten years, according to Shumaker, Loop & Kendrick’s analysis of the nuclear-AI intersection. Northern Virginia, home to the largest concentration of data centers on earth, has utilities openly warning that substations and high-voltage lines are approaching their limits. PJM Interconnection — the grid operator covering much of the U.S. Mid-Atlantic — has issued warnings about summer peak capacity shortfalls.

So hyperscalers are looking off-grid. And nuclear, specifically SMRs, is starting to look less like an idealistic long shot and more like the only option with the right profile. Whether the industry can actually deliver in time is a very different question.

Why renewables alone can’t do this

Hear me out before dismissing this section as pro-nuclear boosterism. The problem with solar and wind for data centers is not that they’re bad. It’s that AI workloads don’t care what the weather is doing. 🌤️

A large-scale AI training run consumes electricity continuously. When you’re spending millions of dollars in compute time to train a frontier model, you cannot pause for cloud cover over a solar farm in Texas. Nuclear SMRs operate at capacity factors exceeding 92%, compared to roughly 25–30% for solar and 30–40% for wind, per market research cited by Data Center Dynamics. That gap is the whole ballgame. You can’t battery-storage your way out of it when you’re drawing hundreds of megawatts around the clock.

There are other mismatches worth naming:

• Solar and wind require vast land areas; a single SMR plant occupying a few acres can match what a solar farm covering many square miles would produce

• AI data centers have “rapid and large swings in demand,” per the IEA, which strains the technical capabilities of on-site gas plants trying to track load

• Renewable energy certificates (RECs) are increasingly failing to satisfy corporate sustainability commitments, because they allow companies to claim clean power while actually drawing from fossil sources 24/7

• Grid interconnection backlogs of 5–10 years mean that even if a utility agrees to add renewable capacity, hyperscalers can’t count on timely access to transmission

None of this means renewables are useless for data centers. They’re already covering enormous swaths of data center load, and the Brookings Institution’s April 2026 analysis notes that Big Tech accounted for 43% of all clean energy power purchase agreements globally in 2024. But renewable PPAs work beautifully for general corporate sustainability targets and don’t work well for the specific, non-negotiable uptime requirements of a 100,000-GPU AI training cluster. ⚡ That’s where nuclear steps in.

The deals that changed the conversation

The shift in nuclear’s reputation happened fast, and it happened because a few big bets got placed very publicly.

Microsoft committed to a 20-year, 835-megawatt power purchase agreement to restart Three Mile Island, targeting 2028 — a move that felt almost deliberately provocative given Three Mile Island’s history. The deal with Constellation Energy is worth an estimated $16 billion over its life. Microsoft has also assembled an internal nuclear team, hiring directors of atomic technology from Ultra Safe Nuclear and the Tennessee Valley Authority.

Amazon went further. AWS backed 5 gigawatts of X-energy SMR capacity through a $500 million direct investment, signed an agreement with Energy Northwest in Washington state to fund four Xe-100 reactors producing 320 MW with expansion potential to 960 MW, and committed $20 billion to convert the Susquehanna nuclear site into an AI data center campus. Matt Garman, CEO of AWS, said plainly that “nuclear is a safe source of carbon-free energy that can help power our operations.” 🔬

Google made history in October 2024 with what the industry called the first corporate SMR purchase agreement — a 500 MW deal with Kairos Power for a fleet of molten-salt reactors, with the first unit targeted for 2030. Kairos has already received construction permits from the U.S. Nuclear Regulatory Commission for two demonstration facilities in Oak Ridge, Tennessee.

Switch, the data center colocation developer, signed a non-binding master agreement with Oklo for 12 gigawatts of advanced nuclear power through 2044 — described by Power Magazine as one of the largest corporate power agreements in history. And X-energy, Amazon’s SMR partner, recently completed a record-breaking $1.02 billion nuclear IPO on Nasdaq, with the offering 15 times oversubscribed. The company failed to close a $1 billion SPAC merger in 2023. In two years, the entire investment thesis shifted.

What’s worth noting is that these aren’t just press releases. They represent genuine financial commitments with 20-to-30-year terms. That kind of contract forces both parties to treat nuclear not as a backup plan, but as core infrastructure. 📈

What makes SMRs actually fit for this job

Beyond the philosophical appeal of always-on, carbon-free power, there’s a specific technical compatibility between SMR architecture and data center needs that’s worth unpacking.

Traditional large nuclear plants are engineered for bulk baseload power delivery into the grid. They’re designed to run at full capacity continuously, with output distributed across regions. Data centers need something different: dedicated, on-site generation that bypasses grid congestion entirely, scales incrementally as the campus grows, and doesn’t compete with surrounding communities for electricity.

SMRs are sized for exactly this. The BWRX-300 produces 300 MW. NuScale’s VOYGR-6 configuration delivers 462 MW. X-energy’s Xe-100 produces 80 MW per module. These outputs map directly onto the power requirements of large hyperscale campuses — and crucially, a single operator can deploy multiple modules over time, expanding capacity as racks fill up rather than overbuilding on day one. 💡

The colocation benefit is real too. Last Energy, a startup building commercial SMRs in Europe, argues that on-site generation means:

• No dependence on transmission and distribution systems that were built decades ago for very different loads

• No competing with local residential and commercial ratepayers for grid capacity

• Potential for waste heat recovery to power on-site cooling systems (a major data center operating cost)

• Fixed-price long-term contracts, typically 20–30 years, that protect against electricity price volatility

The refueling interval is also quietly impressive: SMRs typically refuel every three to seven years, compared to the annual refueling shutdowns conventional reactors require. For a data center operator modeling 10 years of operating costs, that matters.

The honest case against betting on SMRs now

I’d be doing readers a disservice if I only presented the bull case. The honest version is messier.

The only commercial SMRs operating today are in Russia and China. Canada’s first commercial SMR project, the BWRX-300 at Ontario Power Generation’s Darlington site, is under construction and not expected to be operational until around 2030. In the United States, no commercial SMR has ever generated a single watt of electricity for a paying customer. ⚠️

Licensing is genuinely slow. The Nuclear Regulatory Commission’s Atomic Safety and Licensing Board recently allowed formal opposition to an X-energy SMR project in Texas on financial-qualification grounds, per Data Center Knowledge’s March 2026 coverage. Lux Research estimated that first-of-a-kind SMRs could cost nearly three times more than natural gas — $331/MWh versus $124/MWh — when factoring in cost overruns and delays. Even optimistic projections don’t see broad SMR deployment before the early 2030s.

Meanwhile, the data centers that Google and Amazon are building right now need power right now. The solution for the immediate gap, not the 2035 solution, is largely natural gas. The IEA itself notes that data center developers are “advancing a large number of projects with onsite natural gas-based power generation” as a bridge while longer-term solutions mature. That’s a carbon problem that 45 GW of SMR offtake agreements doesn’t solve today.

There’s also the question of whether many of those agreements survive contact with reality:

• Some are conditional and non-binding frameworks, not signed PPAs

• Regulatory approval timelines can and do slip

• Community opposition, seismic studies, water rights, and site-specific engineering can each add years

• SMRs require roughly 15 million gallons of water daily per site for cooling — not a trivial constraint

The data center industry seems to be pricing in a version of the future where SMR licensing gets significantly faster and costs compress through manufacturing scale. That may happen. It may not. Does your risk model handle both scenarios?

What this means for where nuclear goes next

Here’s what I think the data center-nuclear nexus actually changes, beyond the obvious deal flow. 🚀

The IEA’s Key Questions on Energy and AI report makes a point that doesn’t get nearly enough attention: “the momentum behind AI could accelerate the commercialization of new energy technologies.” That’s a polite way of saying that hyperscaler demand might do for SMRs what smartphone demand did for lithium-ion batteries — fund the manufacturing scale-up that makes the technology cheap enough to deploy broadly.

NuScale’s modules. X-energy’s Xe-100. Kairos Power’s molten-salt design. GE Hitachi’s BWRX-300. These designs are all chasing the same vision: a factory-built reactor, shipped to site, assembled like an industrial product rather than hand-built like a cathedral. If Amazon and Google collectively commit to 5–10 GW of capacity, they generate the order volume that justifies factory investment. That factory investment drives down per-unit costs. Lower costs open the technology to customers who aren’t named Amazon.

The analogy to Wikipedia’s account of learning curve economics in manufacturing is direct: every doubling of cumulative production typically yields a fixed percentage cost reduction. Nuclear has never had the production volume to ride that curve. It might finally be getting it.

What none of this resolves is the gap between the paperwork and the power plant. 45 gigawatts of offtake agreements is not 45 gigawatts of generating capacity. It’s a bet that the industry figures out how to build these things faster than it has historically managed to do. The data center industry is wagering enormous sums on that bet being right.

Whether you think that’s a rational calculation or motivated reasoning probably depends on how long your investment horizon is — and how much you trust an industry where the first commercial deployment is still four years away. What’s your read: are the hyperscalers leading a genuine nuclear renaissance, or buying very expensive optionality on a technology that may arrive too late?

March 11, 2011 didn’t just destroy a power plant. It destroyed a national consensus. When the earthquake and tsunami triggered meltdowns at Fukushima Daiichi, Japan shut off all 54 of its reactors and swore — loudly, officially, repeatedly — that it would wean itself off atomic energy. Public support for nuclear power, which had sat at 62% before the disaster, collapsed overnight. By mid-2011, nearly three-quarters of Japanese voters wanted an immediate or gradual phase-out. The backlash felt permanent.

It was not permanent. In February 2026, TEPCO — the very company that caused Fukushima — fired up Unit 6 of the Kashiwazaki-Kariwa Nuclear Power Station in Niigata Prefecture, the world’s largest nuclear plant by installed capacity. The reactor achieved commercial operation in April 2026. This wasn’t a quiet technical milestone. It was a loud, politically charged reversal of the post-Fukushima order, and it raises a genuinely important question: what changed?

The short answer is: almost everything. Energy prices, geopolitics, climate commitments, and a tsunami of AI-driven electricity demand all converged to make nuclear look a lot less scary than it did when the rubble was still warm. But the longer answer is more complicated, more interesting, and honestly more honest about the gap between Japan’s ambitions and its current reality.

The policy shift that nobody called small

In February 2025, Japan’s cabinet approved its Seventh Strategic Energy Plan — and the most significant thing about it wasn’t what it added, it was what it deleted. For the first time since 2011, the government removed the phrase “reducing nuclear dependency as much as possible” from its official energy policy. That phrase had sat in every iteration of Japan’s energy plan since the Fukushima accident. Deleting it was, in policy terms, the equivalent of tearing down a memorial plaque.

The new plan is explicit: nuclear power should supply around 20% of Japan’s electricity by 2040, up from just 8.3% in 2024. Renewables should reach 40–50%. Fossil fuels, currently generating around 70% of Japan’s power, drop to 30–40%.

A few things stand out about this plan:

• It permits new reactor construction for the first time since 2011

• It replaces the goal of “minimizing” nuclear with “maximizing” the use of existing plants

• It acknowledges, unusually, that there are two scenarios — one where nuclear and renewables dominate, and one where they fall short, requiring continued fossil fuel use

• The 20% nuclear target for 2040 is actually a decade-long retreat from the prior plan’s identical target for 2030, which was missed by a mile

That last point matters. The Council on Foreign Relations’ analysis of Japan’s post-Fukushima energy position notes that Japan’s latest plan “explicitly acknowledges the need for flexibility” — which is a diplomatic way of saying nobody is fully confident any of this will happen on schedule. Ambition and arithmetic are two very different things.

The economics that made nuclear inevitable

Here’s a number worth sitting with: $70 billion. That’s roughly how much Japan spent on liquefied natural gas and coal imports in 2024 alone, according to OilPrice.com analysis of Japan’s energy position. Japan imports 60–70% of its electricity resources. For a country with almost no domestic fossil fuel reserves, that’s not an energy policy — it’s a permanent invoice.

The Ukraine war made everything worse. When Russian gas flows to Europe tightened after 2022, LNG became a seller’s market globally. Japan, which uses LNG for roughly a third of its power generation, got squeezed badly. The Institute for Energy Economics and Financial Analysis tracks Japan’s LNG exposure closely and found that Japan’s total fossil fuel import bill nearly doubled between 2021 and 2022, pushing the trade deficit to a record ¥20 trillion ($155 billion). Even after moderation, fossil fuel imports in 2025 remained well above pre-2022 levels. The yen’s depreciation made every barrel and every tanker shipment more expensive in local currency terms.

Nuclear power doesn’t eliminate Japan’s energy insecurity. But it reduces it in a specific and appealing way: 🏭 once a reactor is running, the marginal cost of electricity is low and stable, not subject to LNG spot prices or Strait of Hormuz disruptions.

Then AI arrived and made the problem even more urgent:

• Japan’s data center electricity consumption was 19 TWh in 2024

• By 2034, that figure is projected to reach 57–66 TWh — a tripling in a single decade

• This boom is driven by $28 billion in investments by hyperscalers including Google, Microsoft, and Oracle

• Japanese data centers will account for 60% of total power demand growth through 2034, per Wood Mackenzie analysis

A country that already struggles to generate enough clean power is being asked to power a continental-scale AI buildout. 💡 Something had to give.

The restart reality check

Here is where honesty becomes important. Japan’s nuclear “revival” is real, but it is not going as fast as the headlines suggest. The numbers tell a sobering story:

• Before Fukushima: 54 reactors generating roughly 30% of Japan’s electricity

• Technically operable fleet today: 33 reactors

• Currently operating: 15 reactors

• Received restart approval but still offline: 3

• Under regulatory review: 6

• Never filed a restart application: 8

The Diplomat put this starkly on the 15th anniversary of Fukushima: Japan’s nuclear story is “a widening gap between political ambition and physical reality.” The capacity factor for restarted plants reached a respectable 80.5% in 2024 — showing that plants that are running do run well — but getting plants approved and running is the problem that nobody has solved. 🔬

Restart costs run $700 million to $1 billion per unit, regardless of the reactor’s size or age. Safety upgrades mandated by Japan’s Nuclear Regulation Authority (NRA) are extensive and genuinely time-consuming. Some plants face local opposition that no cabinet minister can override by decree. The Shika-2 reactor, for instance, sits close to the epicenter of the devastating 2024 Noto Peninsula earthquake and faces obstacles that have nothing to do with political will.

The East Asia Forum’s assessment was blunter: “the nuclear revival is more wishful thinking than reality.” That’s harsh, maybe slightly unfair given the actual restarts that have happened, but the direction of the critique is fair. A government that previously promised 20% nuclear by 2030, failed, and then promised the same target by 2040 needs to explain why a decade of extra time will produce results that the previous decade didn’t.

What has actually changed is that the political cost of not restarting is now higher than the political cost of restarting. That’s a meaningful shift. It just doesn’t make engineering go faster.

Public opinion: a reluctant thaw

The moment that best captures Japan’s changed mood didn’t happen in Tokyo. It happened in Kariwa, a village of about 4,200 people next to the Kashiwazaki-Kariwa plant, where Mayor Shinada Hiroo expressed what the Christian Science Monitor described as “unwavering trust in the people who run the nuclear facility.” The mayor’s trust isn’t naive — it’s conditional and relational. TEPCO, he noted, has started paying “more attention to local matters.” That’s a different kind of accountability than regulatory compliance. It’s the slow, unglamorous work of rebuilding a relationship that was shattered.

Still, opinion is far from settled. When the Niigata prefectural assembly approved the bill clearing the way for Kashiwazaki-Kariwa’s restart in December 2025, 60% of Niigata residents didn’t think the conditions for restart had been met, and nearly 70% were worried about TEPCO’s ability to operate the plant safely, per Reuters reporting. Ayako Oga, 52, who fled the Fukushima disaster and still lives in Niigata with what she describes as PTSD-like symptoms, told Reuters: “We know firsthand the risk of a nuclear accident and cannot dismiss it.” 😔 Her old home is still inside the exclusion zone.

That’s the unresolved tension at the center of Japan’s nuclear revival. You can change a government policy document in a morning. Changing lived experience takes generations. The official acknowledgment that “there is no such thing as absolute safety” — uttered by nuclear officials as a statement of philosophical honesty — lands very differently in a town where the next exclusion zone would be someone’s actual neighborhood.

What does appear to be genuinely shifting is the attitude of younger Japanese. Reuters reported on engineering students in Fukushima prefecture who see nuclear power as a technology with a future, not just a source of trauma. Whether that generational shift translates into sustained public support for new construction is a real question — one worth watching closely. 🌱

Where SMRs fit into Japan’s nuclear future

Japan’s current restart push is almost entirely about existing large reactors, not next-generation technology. The country’s 7th Strategic Energy Plan does permit new reactor construction, but the plan’s focus is on making the most of plants already built. SMRs, according to Climate Scorecard’s 2025 analysis of Japan’s nuclear sector, are “projected for 2040 or later.” That’s a long runway.

But Japan is not sitting on the SMR sidelines. In March 2026, GE Vernova and Hitachi signed a formal Memorandum of Understanding to explore deploying the BWRX-300 SMR across Southeast Asia, specifically to incorporate Japanese suppliers into the SMR supply chain. The signing happened at the Indo-Pacific Energy Security Ministerial in Tokyo, in the presence of U.S. and Japanese government officials — which is less a coincidence and more a signal. Japan wants to be a supplier nation in the coming SMR era, not just a customer. 🚀

Hitachi GE Vernova’s BWRX-300 technology is already under construction at Ontario Power Generation’s Darlington site in Canada — on track to become the first SMR deployed in the Western world. Japanese companies including Mitsubishi Heavy Industries, Toshiba Group, and IHI are also in conversations about supporting U.S. reactor construction through up to $100 billion in potential partnerships announced via Japan’s nuclear cooperation framework.

The IEA’s roadmap for nuclear’s new era is explicit that SMRs — alongside large new conventional builds — could allow Japan to “reclaim technology leadership” in nuclear energy alongside Europe and the United States. That framing, “reclaim,” is deliberate. Japan was a major nuclear technology exporter before Fukushima. It wants that role back. Whether SMR economics cooperate is still genuinely uncertain. ⚡

The harder question for Japan is whether the domestic political path to new-build nuclear — not just restarts — is actually open. Permitting new construction in a country where every township near a potential site has veto-adjacent influence is a different challenge than permitting it on paper in a cabinet document. What’s your read: is Japan’s nuclear push a genuine energy transition or an elaborate game of kicking the fossil fuel dependency further down the road?

If you live within a few miles of a proposed small modular reactor site, you probably have a lot of questions. Whether the project actually proceeds depends, to a degree that surprises most people, on what you and your neighbors do during a specific window of legal process. Not on a petition. Not on a hashtag. On a formal federal licensing procedure with well-defined opportunities to intervene, comment, and push back.

This is not the same as having a veto. Let’s be clear about that upfront. The federal government’s nuclear licensing system doesn’t give a community the right to simply say “no” and end the conversation. But the process is more substantive than a rubber stamp, and recent changes to both federal law and state-level legislation have made the community side of the equation more complex and, in some cases, more consequential than ever.

Here’s how it actually works.

The federal process and where public input lives

Every commercial SMR built in the United States requires a license from the Nuclear Regulatory Commission (NRC). This is non-negotiable, regardless of what state or county wants. The NRC’s authority over nuclear licensing is federal and supersedes state law on the core safety and design questions. But federal law also requires the NRC to follow the National Environmental Policy Act (NEPA), and that’s where the public gets meaningful traction. 🏛️

When an applicant submits a construction permit application, the NRC publishes a Notice of Intent to prepare an Environmental Impact Statement (EIS), a document that evaluates the project’s effects on land, water, air quality, local ecosystems, and the surrounding community. According to the NRC’s own environmental review guidance, the NRC then:

• Publishes a draft EIS for public comment before finalizing it

• Holds public scoping meetings to let residents and local agencies flag the environmental questions they want studied

• Must respond in the final EIS to every substantive comment received

• Consults with tribal, state, and local agencies throughout the process 🔍

The NRC also convenes a formal Atomic Safety and Licensing Board (ASLB) hearing for each major licensing action. Under Section 189 of the Atomic Energy Act, members of the public can submit written statements, give oral testimony, or petition to intervene as full parties in the proceeding. Intervening as a full party is a much stronger position than simply filing a comment: intervenors can challenge specific technical or environmental claims, submit expert witnesses, and request access to applicant documents. ⚖️

This is where projects have actually been slowed or modified. Legal interventions during the licensing process are one of the mechanisms that kept the nuclear industry legally accountable after Three Mile Island, and the framework remains in place today.

What recently changed, and what it means for communities

The ADVANCE Act of 2024, signed into law with an overwhelming 88-2 Senate vote and 393-14 in the House, directed the NRC to streamline its licensing process significantly. Harvard Law Review’s analysis of the ADVANCE Act notes that while the law cuts fees for advanced reactor applicants and sets tighter timelines for technical reviews, it preserves mandatory hearings before construction can begin, and it doesn’t eliminate the environmental review process. 📋

Then in April 2026, the NRC finalized a Generic Environmental Impact Statement (GEIS) for new reactor licensing, which went into effect in May 2026. What this means practically: environmental impacts that are common across reactor types and sites, things like general air quality effects or seismic considerations, can now be evaluated generically rather than being re-studied from scratch for every project. Site-specific impacts still require individual analysis, and the public comment process for those site-specific findings remains intact.

The honest read is that these reforms reduce some redundancy in the process, but they don’t gut public participation. 🔎 Here’s what has not changed:

• Site-specific environmental issues still require project-specific public review

• Mandatory NRC hearings remain before construction permits are issued

• The right to petition for full intervenor status remains

• NEPA compliance, including consultation with local and tribal governments, is still required

• State and local agencies must still be notified and consulted during the review 🌍

What has changed is the timeline. The ADVANCE Act set a target of 18 months for the NRC to complete technical safety reviews, and two years for completing environmental assessments and public hearings. Faster proceedings mean that community groups opposing or wanting to shape a project need to engage earlier and more substantively than in the old era of decade-long licensing marathons.

The state layer, which is where it gets complicated

Federal licensing is the floor, not the ceiling, and state laws introduce a genuinely variable second layer of authority. 🗺️ Some states have nuclear moratoriums, some are actively removing them, and a small number have started experimenting with formal consent mechanisms.

As of early 2026, the Nuclear Energy Institute’s tracker lists the following state-level positions: ⚖️

• States with full nuclear moratoriums that predate SMR technology, including California, Minnesota, and Oregon

• States that have partially lifted moratoriums for specific sites or technologies

• States that are actively passing new SMR-friendly legislation in 2025 and 2026

• Connecticut, which in 2025 passed Act 25-173, enabling communities to “opt in” to hosting advanced reactor facilities through a local vote, while also establishing a Site Readiness Funding Program

That Connecticut law is interesting because it’s one of the first state-level mechanisms that gives communities a formal yes/no role, not just input into a federal process. If other states follow, it may shift the community question from “can we slow or stop this?” to “do we want this and what do we want in return?”

The R Street Institute’s analysis of state and local permitting restrictions makes a nuanced point: states can impose additional environmental requirements through NEPA-facilitated compliance, which can indirectly affect siting decisions even without explicit anti-nuclear laws. A state with a stringent groundwater protection regime, for example, forces any applicant to address those requirements in the EIS, giving state regulators a real voice in the process. 🌊

What communities actually do in practice, from Kemmerer to Oak Ridge

Theory and practice diverge in interesting ways once real communities get involved. The TerraPower Natrium project near Kemmerer, Wyoming, offers one of the more instructive current examples. When the NRC held a public scoping meeting on the project’s environmental review, local residents showed up with very specific concerns: groundwater contamination risks, potential impacts on the Colorado River Basin watershed, how long radioactive waste would be stored on-site, and what would happen if an archaeological site was discovered during construction. Wyoming News reporting from those meetings captured the texture of a community that is cautiously supportive of the economic opportunity but genuinely worried about the technical details. 🏔️

These aren’t objections that can be waved away. The NRC’s process requires the agency to document and respond to each one. If the draft EIS doesn’t address groundwater effects adequately, a commenter can flag that deficiency, and if the NRC fails to address it substantively in the final EIS, that becomes grounds for a legal challenge.

The Kairos Power Hermes demonstration reactor in Oak Ridge, Tennessee, went through a similar community engagement process before receiving its construction permit in December 2023, the first permit for a non-light-water reactor in more than 50 years. ⚛️ Oak Ridge’s existing status as a nuclear community, home to the Oak Ridge National Laboratory, probably helped public acceptance. The same dynamic likely wouldn’t apply in a community with no prior nuclear relationship.

That community familiarity effect is real and documented. A 2025 poll cited by WSP’s nuclear engagement analysis found that while 65% of UK respondents say nuclear should remain part of their country’s energy mix nationally, only 22% would support construction of a nuclear plant in their own area. Opposition specifically to a local facility runs at 37%. That gap between national support and local acceptance is the defining political challenge for the entire SMR deployment agenda. 📊

What communities can actually do: a practical guide

If an SMR is proposed near you, the tools available in the U.S. context are more specific than “write to your congressman.” 💬

• Participate in NRC scoping meetings: These happen early in the EIS process and are your best chance to identify the specific environmental questions you want studied. Comments at this stage actually shape what gets analyzed. 🔬

• File written comments on the draft EIS: Once the draft is published, there’s a formal public comment period. Comments must be substantive to receive written responses, so specific and technical beats vague and emotional.

• Petition to intervene in the ASLB hearing: This is the most powerful individual option. To intervene, you need to demonstrate “standing” (that you’re genuinely affected) and raise an “admissible contention” that disputes a specific factual claim in the application. Environmental groups like the Union of Concerned Scientists have used this mechanism successfully in past licensing proceedings.

• Engage your state regulatory agencies: States are consulted during the federal EIS process and may have their own environmental review requirements. Your state’s environmental protection or natural resources agency may have independent authority over aspects like water use or land impact.

• Monitor state legislation: If your state is considering SMR-related legislation, the window to shape community consent provisions is before a project is proposed, not after. 📋

• Negotiate community benefit agreements: If a project proceeds, many communities have successfully negotiated formal agreements with developers covering local hiring requirements, economic benefits, and operational transparency. These aren’t part of the NRC process, but they’re legally enforceable contracts. 🤝

The IAEA’s March 2025 event on SMR stakeholder engagement noted a specific concern: meaningful global SMR deployment would require hundreds of local communities to host reactors, and “not-in-my-backyard” dynamics are an underappreciated constraint on deployment timelines. Vendors and developers who treat community engagement as a box-checking exercise rather than a genuine negotiation are going to discover this the hard way.

The communities that have gone well so far, Kemmerer being the clearest example, share a common thread: the reactor was arriving in the context of a dying coal economy, meaning residents saw the plant as a replacement for something they were already losing. In communities without that existential economic pressure, the negotiation looks quite different.

What does your community actually want from an SMR developer before you’d say yes? That’s not a rhetorical question, it’s the question that will determine whether hundreds of planned projects get built or stall.

Here is a number worth sitting with: in Afghanistan in 2007, one American soldier or civilian was killed or wounded for every 24 fuel resupply convoys. According to the UC Institute on Global Conflict and Cooperation, roughly 900 of those convoys ran that year alone. The fuel wasn’t going into jets or tanks. Much of it was running diesel generators to keep the lights on, the radios live, and the air conditioners churning at forward operating bases. Fuel to make electricity. Electricity that a small reactor could have provided without a single convoy.

That’s the whole case, right there. Everything else is detail.

The U.S. military has known about its energy problem for years, done occasional things about it, and never really solved it. Most bases at home still pull power from the civilian grid. Abroad, they run on diesel that costs up to $15 per gallon delivered and requires an unbroken chain of trucks through hostile territory to keep flowing. President Trump signed Executive Order 14299 in May 2025, titled “Deploying Advanced Nuclear Reactor Technologies for National Security,” which mandated a working reactor on a U.S. military base by September 30, 2028. That’s not a vision statement. That’s a deadline.

The vulnerability that diesel created

The problem goes deeper than convoy casualties, though those alone should have settled the argument years ago. 🛡️

Most U.S. military bases are directly connected to the civilian electricity grid, which is a large, complex, and genuinely fragile piece of infrastructure. A U.S. Department of Energy study from 2017 concluded that a serious grid failure was a matter of “when,” not “if,” and the grid’s vulnerability to both cyberattacks and physical attacks on transformers has not improved dramatically since then. Defense News published an assessment in early 2025 noting that the military faces two distinct energy failures waiting to happen: the civilian grid going down, and the diesel backup system failing because its fuel supply gets cut.

Neither of these is hypothetical. The consequences include:

• Command and control systems going dark when grid power fails 📡

• AI-enabled targeting and radar arrays losing power during a conflict

• Communications infrastructure failing at exactly the moment it’s needed most

• Patriot missile batteries and other air defense systems running on generators that depend on the same fuel convoys they’re there to protect 🚛

The Atlantic Council’s analysis from May 2026 frames it plainly: the Department of Defense has a target of achieving 99.9% energy availability for critical missions by 2030. That standard allows for less than nine hours of downtime per year. With current infrastructure, that target is something between aspirational and delusional. 💡

The military has tried solar and wind. Useful in the right contexts, genuinely not suitable as primary power for a base running 24/7 surveillance, logistics, and weapons systems regardless of weather. What it needs is baseload power that doesn’t require a supply chain to operate. That is exactly what a nuclear reactor provides.

What Project Janus actually is

In October 2025, Secretary of the Army Dan Driscoll and Secretary of Energy Chris Wright jointly announced Project Janus, the Army’s formal program to put nuclear microreactors on military bases. ⚛️ The following month, the Army named nine candidate installations:

• Fort Benning, Georgia

• Fort Bragg, North Carolina

• Fort Campbell, Kentucky

• Fort Drum, New York

• Fort Hood, Texas

• Fort Wainwright, Alaska

• Holston Army Ammunition Plant, Tennessee

• Joint Base Lewis-McChord, Washington

• Redstone Arsenal, Alabama

These weren’t picked arbitrarily. The Army evaluated them on mission criticality, existing energy infrastructure, resiliency gaps, and suitability for reactor deployment, according to statements from the Army at the time. Fort Wainwright in Alaska is worth a particular look: it’s remote, cold, and expensive to supply, making it precisely the kind of installation where eliminating the fuel dependency matters most. 🌨️

Janus builds on Project Pele, a 1.5-megawatt gas-cooled demonstration microreactor whose core is now under construction at Idaho National Laboratory, expected to begin producing electricity in 2028. The program is structured as a public-private partnership, meaning commercial vendors own and operate the reactors on Army installations under military oversight, following a contracting model borrowed explicitly from NASA’s Commercial Orbital Transportation Services program.

The Defense Innovation Unit issued its solicitation for reactor designs in November 2025, seeking designs up to 20 MWe. ⚙️ Companies pre-qualified under the broader Advanced Nuclear Power for Installations program include BWXT, Westinghouse, Kairos Power, Oklo, X-energy, and Radiant Industries, among others. The Air Force is running a parallel track, having selected Eielson Air Force Base in Alaska for a microreactor pilot and announced its intent to award a contract to Oklo for a 5-megawatt sodium-cooled reactor under a 30-year fixed-price arrangement.

Why the military is a better first customer than the grid

The commercial SMR market faces a genuine chicken-and-egg problem: reactors need to get cheaper to attract customers, and they get cheaper by getting built in volume, but they can’t build in volume without the customers. The military, with its unique combination of capital, patience, and regulatory authority, may be the best entity alive to break that loop. 🔑

Consider what the military brings that commercial buyers cannot: 🏛️

• Long time horizons: The Army is explicitly thinking about 2030 and beyond, not quarterly earnings

• Independent regulatory authority: The Army can operate nuclear reactors under its own regulatory framework, distinct from the NRC’s civilian licensing process, which compresses timelines significantly 📋

• Predictable demand: A base draws a known amount of power continuously, making sizing and contracting straightforward

• Tolerance for first-of-a-kind costs: The commercial market killed NuScale’s Utah project when costs rose. The military makes different calculations about value

• Strategic urgency: The threat to diesel supply chains is real and quantified, not a hypothetical 🚨

There’s also a spillover effect worth taking seriously. Neutron Bytes, which covers nuclear developments in depth, noted in October 2025 that if military microreactor deployment takes off alongside civilian AI data center demand in the 2030s, the combined economic effect on the U.S. nuclear supply chain could be significant, though both sectors competing simultaneously for the same fabrication capacity could also push costs up. The history of advanced technology programs suggests the military’s early adoption creates the production base that later makes civilian deployment cost-effective. That is more or less exactly how GPS, the internet, and aircraft manufacturing all worked.

The real obstacles, honestly assessed

None of this means it’s straightforward. There are genuine obstacles, and pretending otherwise would be a mistake. 🔧

Fuel supply is probably the biggest. ⚠️ Many advanced reactor designs require high-assay low-enriched uranium, or HALEU, which is enriched to between 5% and 20% uranium-235. The OECD Nuclear Energy Agency reported in September 2025 that more than half of the SMR designs planning to use HALEU had not progressed beyond non-binding agreements with national laboratories about fuel supply. The U.S. nuclear industry has warned openly that some SMR deployment timelines could slip by years if HALEU production doesn’t scale. Centrus Energy launched commercial HALEU enrichment in Ohio in late 2025, and Urenco USA produced its first batch of enriched uranium above 5% in New Mexico around the same time, but the supply chain is still early.

There are also real questions about:

• Security at the installation: A reactor is not a diesel generator, and hardening protocols for small reactors on military bases are still being developed

• Operator training: Janus is structured so commercial companies run the reactors, which means military personnel are not reactor operators, raising questions about continuity during deployment and conflict 👷

• Community relations: All nine candidate bases sit near civilian communities, and the Army has explicitly committed to “transparency with host communities” as part of the program

• The 2028 deadline: Getting a reactor licensed, built, and operating in under three years is aggressive. Project Pele, a demonstration reactor, has been in development since 2020 and won’t produce power until 2028 at the earliest. The compressed timeline for Janus reflects political will more than a technical schedule

To be fair, the designs being evaluated for Janus mostly use standard low-enriched uranium fuel, not HALEU, which sidesteps the fuel supply problem for the initial wave. Oklo’s Aurora uses metal uranium fuel with a different supply chain dynamic entirely. So the HALEU constraint matters more for second- and third-generation commercial SMR builds than for the first military installations.

What success actually looks like here

If Project Janus delivers an operating reactor at, say, Fort Wainwright by late 2028, a few things happen simultaneously. ⚡

The Army gets actual data on what it costs and what it takes to run a microreactor under military conditions, data that is currently unavailable anywhere. 📊 The commercial supply chain gets an anchor customer and a production run that justifies investment in manufacturing capacity. The NRC and the Army’s own nuclear oversight bodies develop the regulatory precedents that future civilian deployments will rely on. And the broader case for SMR deployment in difficult environments, from remote industrial sites to island communities, gets a proof point that no simulation or white paper can match. 🌏

The U.S. Energy Information Administration’s latest survey of SMR development, updated in April 2026, notes that DOE has allocated $900 million to accelerate SMR deployment and is running a parallel Energy Reactor Pilot Program through commercial vendors. The military deployments and the civilian deployments are moving in parallel now, feeding the same supply chain. If both arrive in the 2028-2030 window as planned, the economics of the third and fourth units will look substantially different from the first.

None of this is guaranteed. The history of large technical programs inside the U.S. government contains a sobering number of over-promised, under-delivered projects with 2028 milestones that somehow became 2035 milestones. But the drivers here are different from, say, a Pentagon software procurement. The fuel convoy death toll is a documented, quantified cost that is not going away. The grid vulnerability is real and worsening. And the reactor designs are not conceptual, they’re physical hardware with known supply chains being fabricated right now in Idaho.

The question isn’t whether the military has good reasons to want nuclear power on its bases. It obviously does, and has for decades. The question is whether the combination of political will, commercial urgency, and available technology that exists in 2026 is finally sufficient to get it there.

Based on everything visible right now, I think the answer is probably yes. For the first time in a long time, “probably” feels like more than optimism.

What’s your read on the most likely obstacle? HALEU supply, regulatory timing, cost overruns, or something nobody is talking about yet?

Most people have a vague sense that nuclear energy involves atoms, heat, and something dramatic. They’re right on all three counts. But the actual journey, from the fission of a single uranium nucleus to the alternating current entering your wall socket, is one of the most satisfying chains of cause and effect in all of engineering. Every step follows logically from the last. Nothing is magic. And once you understand it, you’ll never look at a light switch the same way.

Small modular reactors work by the same fundamental physics as every nuclear plant ever built. What makes them different isn’t the science. It’s the scale, the manufacturing approach, and some genuinely clever engineering choices built around passive safety. But before we get to what’s new, you need to understand what’s foundational.

Step one: the fuel, and why it’s extraordinary

Everything starts with uranium. Not the science-fiction glowing green stuff. The real thing is a dull, heavy metal that looks unremarkable in a drawer. But inside its nucleus sits an almost absurd amount of stored energy, and the isotope uranium-235 is particularly ready to give it up.

Before uranium goes anywhere near a reactor, it goes through a multi-step preparation process:

• It’s mined from ore deposits, primarily in Kazakhstan, Canada, and Australia

• It’s converted and enriched to increase the concentration of U-235 from its natural level of less than 1% to around 3-5% for light-water reactors

• The enriched material is pressed and baked into small ceramic cylinders called fuel pellets, roughly the size of a pencil eraser

• Those pellets are stacked inside sealed metal tubes called fuel rods, made from a zirconium alloy

• Hundreds of fuel rods are bundled together into a fuel assembly, which slots into the reactor core

Now here is the statistic that stops people cold every time. ⚛️ According to the Nuclear Energy Institute, a single uranium fuel pellet weighing about ten grams, fitting easily on your thumbnail, contains as much energy as one ton of coal, 149 gallons of oil, or 17,000 cubic feet of natural gas. 💡 That’s the proposition. That’s why nuclear engineers sound slightly evangelical when they talk about their fuel.

An SMR core holds far fewer assemblies than a large conventional reactor, reflecting its smaller output. 🔬 The NuScale Power Module, for example, produces 77 megawatts of electricity ⚡ from a compact reactor vessel that fits in a swimming-pool-sized containment module. The GE-Hitachi BWRX-300 tops out at 300 megawatts, comparable to a mid-sized gas plant, but from a core you could park in a decent-sized warehouse. The physics doing the work inside that core is what we cover next.

Step two: fission, and the chain reaction that makes it run

Here’s where it gets genuinely interesting. ⚡

When a slow-moving neutron strikes a U-235 nucleus, the nucleus becomes unstable and splits, a process called fission. It breaks into two smaller atoms, releases two or three new neutrons, and critically releases an enormous burst of energy as heat. According to the U.S. Energy Information Administration, those free neutrons then strike other U-235 nuclei, which split and release more neutrons, which strike more nuclei. This is the chain reaction: a self-sustaining cascade of splitting atoms, each one adding to the heat output.

Left completely unchecked, a chain reaction like this produces a bomb. Inside a reactor, the whole point is to keep it controlled, running just fast enough to produce steady heat, not fast enough to run away. Three mechanisms manage this:

• Control rods, typically made of boron or silver, absorb neutrons. Push them deeper into the core, and the reaction slows. Pull them out, and it accelerates. Push them all the way in and the reactor shuts down. The Rolls-Royce SMR design runs control rods through three separate coolant loops to manage this with redundancy.

• The moderator, usually ordinary water, slows neutrons down to the speed where fission is most efficient. Water does double duty here: it moderates the reaction and carries heat away from the core.

• Passive physics kicks in if something goes wrong. If coolant temperature rises, the water’s density drops and it becomes a less effective moderator, which automatically slows the reaction. No operator action required. 🛡️ This is called a negative temperature coefficient, and it’s one of the reasons modern SMR designs are sometimes described as “walk-away safe.”

The GE-Hitachi BWRX-300 takes this principle even further. 🔩 Rather than using mechanical pumps to circulate coolant through the core, it relies entirely on natural circulation. Hot water rises through a chimney-like structure in the reactor vessel, cooler water falls back down around the outside, and the density difference keeps the loop running on pure physics. No pumps means fewer things that can fail.

The net result of all this controlled fission is straightforward: a lot of heat. 🌡️ And heat, in the end, is all a nuclear reactor actually produces. Everything else is about what you do with it.

Step three: making steam, the pressurized water path

Now we need to turn heat into motion, and the intermediate step is steam. 💧 This is where nuclear power and coal power look almost identical at the level of a process diagram. The physics of generating electricity hasn’t fundamentally changed since the 19th century: you boil water, use the steam to spin a turbine, and the spinning turbine drives a generator. ♨️

Most SMR designs, including the Rolls-Royce SMR and NuScale, are pressurized water reactors (PWRs). Here’s how the heat transfer works in a PWR:

• The coolant water in the primary loop flows through the reactor core, absorbing heat from the fuel rods

• This water reaches temperatures around 300 degrees Celsius but doesn’t boil because it’s kept under extreme pressure, roughly 155 times atmospheric pressure, maintained by a device called a pressurizer

• The hot, pressurized water passes through a steam generator, where it transfers its heat to a completely separate secondary loop of water

• That secondary water does boil, producing high-pressure steam

• The steam expands through the blades of a turbine, spinning it at high speed

• A condenser then cools the steam back into water, and the cycle repeats

The two water loops never actually mix. The primary loop, which passes through the reactor and picks up some radioactivity, stays entirely contained. The secondary loop, the one making steam and spinning the turbine, is clean. This separation is one of the core safety features of PWR design.

The IAEA puts it plainly: the reactor coolant warms to produce steam, the steam spins turbines, and the turbines activate an electric generator to create low-carbon electricity. Strip away the engineering jargon and that’s genuinely the whole story.

The GE-Hitachi BWRX-300 works somewhat differently, as a boiling water reactor (BWR). Rather than a separate steam generator, the water in the reactor vessel itself boils, and the steam goes directly to the turbine. ⚙️ Fewer components, simpler system. Though it means the steam that touches the turbine has been in the reactor, which requires some additional containment thinking. Either way, steam spins the turbine.

Step four: from spinning turbine to alternating current

The turbine is spinning. Now what? 🔌

The turbine shaft connects directly to a generator, essentially a large electromagnet rotating inside a set of coils. By the principle of electromagnetic induction, discovered by Michael Faraday in 1831 and still the basis of virtually all electricity production on Earth, the rotating magnetic field induces an electrical current in those coils. ⚡ This is what a generator does: it converts mechanical rotation into electrical current.

The electricity produced this way is alternating current (AC), typically at a frequency of 50 or 60 Hz depending on the country. At this stage, the voltage is relatively low and not suitable for long-distance transmission. So before it goes anywhere near the grid, it passes through a step-up transformer, which raises the voltage dramatically, from perhaps a few thousand volts to hundreds of thousands, for efficient transmission across power lines. 📡

Have you ever stopped to wonder how many transformations the current in your wall outlet has gone through? The number is higher than most people expect.

A single 300 MWe SMR running at a 90% capacity factor, the typical figure for nuclear plants, notably higher than wind or solar, generates roughly 2.4 terawatt-hours of carbon-free electricity per year. That’s enough to power around 200,000 homes, according to analysis published by Sustainability Atlas. Nuclear plants run about 92% of the time. The best-performing offshore wind farms average closer to 45-50%.

Step five: what the grid sees, and why SMRs matter to it

The electricity leaves the step-up transformer, joins the high-voltage transmission grid 🔋, and at some point gets stepped back down by another transformer before entering the distribution network that reaches your neighborhood. By the time it hits your wall socket, multiple voltage transformations have occurred and the power has traveled, in many cases, hundreds of kilometers. 🌍

What the grid actually needs, and struggles to get from renewable sources, is firm, dispatchable baseload power: electricity available 24 hours a day, 7 days a week, regardless of whether the sun is shining or the wind is blowing. This is exactly what nuclear produces, and it’s precisely why there’s renewed interest in SMRs from energy-hungry tech companies.

The numbers tell the story:

• Global electricity demand is projected to grow 75% by 2050, according to the IEA’s World Energy Outlook 2024, driven by EVs, heat pumps, and data centers

• A single large AI training cluster can demand 500 megawatts of continuous power, roughly two large SMRs worth of output

• The Department of Energy has allocated $900 million specifically to support initial SMR deployment, targeting designs ready for the 2030s

• Nuclear fission companies raised $1.3 billion in equity funding in 2025 alone, the highest annual total on record

The modular approach matters here too. Rather than commissioning a single massive reactor and waiting a decade for it to come online, an operator can deploy one SMR module, add a second as demand grows, and build out capacity incrementally. The physics in each module is identical; the output just scales up. This is the logic that makes the factory fabrication model viable: build the same module hundreds of times, drive down costs through repetition, and ship the finished unit to the site rather than constructing a one-of-a-kind structure from scratch.

Not every SMR project has gone smoothly. NuScale’s VOYGR project for the Utah Associated Municipal Power Systems was cancelled in 2023 after cost estimates rose substantially, a useful reminder that the engineering is proven while the economics are still being worked out. 📊 The gap between “the technology works” and “the technology is cheap” is real, and honest. But the IEA projects global SMR capacity could reach 120 GW by 2050 with strong policy support, and the investment dollars flowing in suggest a lot of smart people believe the cost curve will bend.

The full picture: six grams to gigawatts

So let’s run the chain one more time, end to end. ⚛️

A uranium pellet weighing six grams sits inside a fuel rod in the reactor core. A slow neutron strikes a U-235 nucleus. The nucleus splits, releasing heat and more neutrons. 🔬 The chain reaction sustains. The coolant water absorbs the heat. In a PWR, that hot pressurized water transfers its energy to a secondary loop in the steam generator. Steam forms. Steam expands through a turbine, spinning it at thousands of RPM. The turbine drives a generator, a rotating electromagnet inside copper coils. Alternating current flows. 💡 A step-up transformer raises the voltage for transmission. Power lines carry it across a region. A step-down transformer lowers it for local distribution. You flip a switch, and a light comes on.

The chain from atom to light switch is about 15 steps long. Every step converts energy from one form to another: nuclear binding energy to heat, heat to steam pressure, steam pressure to mechanical rotation, mechanical rotation to electrical current. Some energy is lost at each conversion, which is why an SMR that produces 900 megawatts of thermal power might deliver only 300 megawatts of electricity. The thermal efficiency of a steam cycle is typically around 30-35%.

The remarkable thing isn’t the losses. It’s that one fuel pellet you could hold between two fingers contains enough energy to run a house for 25 years. A reactor full of those pellets, running for 18 months before a refueling outage, produces as much electricity as over two million tonnes of coal would. And it does it without any stack emissions, without any carbon, and with a vanishingly small accident risk in a modern SMR with passive safety systems.

Think about that the next time you make coffee. How much do you know about where the electrons in your mug’s heating element actually came from, and does knowing the full chain make the coffee taste any different?

Walk into any standard commercial insurance broker’s office and ask for coverage against a nuclear accident. You will be shown the door almost immediately. Every property and liability insurance policy in the United States explicitly excludes nuclear incidents. Not reluctantly, not with caveats. Just: no. This isn’t some informal convention — it’s baked directly into the legal architecture created when the nuclear industry was born. To get a reactor licensed in America, you don’t go to Lloyd’s of London or Travelers or Chubb. You go to two specialized organizations that exist for exactly this purpose, backed by a federal framework that has been quietly renewed every few years since 1957, and which most Americans have never heard of.

That framework is now under more scrutiny than at any point in a generation. The Price-Anderson Act is getting updated for SMR-era economics. New private insurers are entering the nuclear space for the first time in decades. Swiss Re is publicly acknowledging that essential insurance products for SMR transportation and operation simply don’t exist yet. And a debate that has simmered for decades — about whether government-backed liability limits constitute an invisible subsidy that skews energy markets — is getting louder as nuclear asks for more investment and more public trust. If you want to understand whether the SMR buildout can actually happen at scale, understanding the insurance question is not optional.

The Price-Anderson Act: the deal that made commercial nuclear possible

The year is 1957. The Atomic Energy Commission is trying to commercialize nuclear power, and it runs into a wall: no private utility will build a reactor, because no private insurer will cover the liability risk at a reasonable cost. The technology is new, the worst-case scenarios are genuinely terrifying, and the insurance industry simply doesn’t know how to price something it has no actuarial history for. ⚖️

Congress’s solution was the Price-Anderson Act, signed into law that same year. The deal it struck was blunt but functional: limit the nuclear industry’s liability exposure so that private capital could flow in, in exchange for a government backstop if things went really wrong. The structure it created has two layers:

• Primary insurance: Each reactor site must carry the maximum liability insurance available in the private market, currently set at $500 million per site as of January 2024, up from $450 million

• Secondary layer (industry self-insurance): If primary coverage is exhausted, every licensed reactor operator contributes to a shared pool — up to approximately $158 million per reactor in retrospective assessments — creating a total pool currently exceeding $16 billion

• Federal backstop: Any damages above the pool get paid by Congressional action, with no defined upper limit

The act has been extended five times. Most recently, as part of the Further Consolidated Appropriations Act of 2024, Price-Anderson’s authority to indemnify new reactors was extended to December 31, 2065, giving a 40-year runway. In practice, this means that for any SMR developer seeking a license in the United States, the liability framework is now secure through the middle of this century. That certainty matters enormously when you’re trying to attract private capital to a $3 billion construction project. 🏛️

What Price-Anderson does not do — and this is the part that critics won’t let go — is cover what a truly catastrophic accident might actually cost. The Fukushima disaster caused damage estimates exceeding $90 billion. The Price-Anderson pool covers only the first $16.1 billion. The gap between those two numbers is, depending on your perspective, either a responsible limitation on tail-risk or a massive hidden subsidy that makes nuclear look artificially cheap compared to energy sources whose full liability costs are uninsured by the government. Supporters of the system point out that in 70 years, not a single nuclear incident has produced claims above the primary layer. Critics point out that Fukushima happened and Japan is still paying for it.

NEIL and ANI: the two organizations insuring all of America’s nuclear plants

Forget the competitive marketplace you might imagine. When it comes to nuclear property insurance in the United States, there is effectively one provider. Nuclear Electric Insurance Limited (NEIL), a mutual insurer founded in 1980 in direct response to the Three Mile Island accident, underwrites essentially the entire nuclear utility property insurance coverage in the country. It holds assets exceeding $5 billion and a surplus of over $4 billion as of 2024. AM Best affirmed its A (Excellent) rating in June 2025, describing its balance sheet strength as “strongest.” Its stated mission includes the goal of maintaining resources sufficient to cover two full-limit policy losses simultaneously. 🔬

NEIL’s coverage structure includes:

• Up to $1.5 billion per occurrence for property damage at operating plants

• Up to $2.75 billion per occurrence for construction-phase builders’ risk coverage

• An additional $1.25 billion available exclusively for nuclear perils above the base limit

• A retrospective premium mechanism allowing NEIL to assess members up to 10 times their annualized premium in an extreme loss event (a mechanism that has never been triggered)

Notably, NEIL took an underwriting loss in 2024 — not from a nuclear incident, but from wildfire events affecting member plant sites, illustrating that nuclear property risk doesn’t arrive only in the forms you expect.

For public liability insurance, a separate organization handles things. American Nuclear Insurers (ANI) writes the primary liability policy, the Facility Form Policy that satisfies the Price-Anderson Act requirement. All U.S. commercial reactor operators get their primary liability coverage from ANI. The annual premium runs roughly $1 million per single-reactor site, with discounts for multiple reactors sharing the same $500 million site limit. ANI also administers the retrospective insurance program — the second tier — and manages reinsurance relationships with international nuclear pools. 💡

This highly concentrated structure exists because nuclear risk is genuinely unlike any other property or liability risk class. The combination of potential severity, political sensitivity, and the legal exclusion of nuclear events from all standard policies created a market that private insurers largely exited in the 1970s, leaving NEIL and ANI to fill the gap. The question now is whether that structure is adequate — or even appropriate — for an era of factory-built reactors deployed at dozens of sites simultaneously.

The SMR wrinkle: liability rules that help, and gaps that don’t yet have answers

Here is where the insurance picture for SMRs gets genuinely interesting, and a little complicated. The good news is that Price-Anderson’s treatment of SMR liability is actually favorable compared to large reactors, in ways that weren’t obvious when the act was written. ⚡

Under current rules, a multi-SMR plant is treated as a single reactor for the purpose of retrospective premium assessments, as long as the total plant capacity doesn’t exceed 1,300 megawatts and each individual SMR is rated between 100 and 300 megawatts. This means that in the event of a severe release from a six-unit SMR plant — say, a facility using six 120-megawatt units — the liability for the secondary pool is $165.9 million, not six times that. Compare that to what six large reactors would owe, and the savings are substantial.

For micro-SMRs rated below 100 megawatts, the framework is even simpler: only the primary insurance layer applies, with coverage ranging from $4.5 million to $74 million depending on capacity and local population density. Total public liability for sub-100-megawatt reactors is capped at $560 million. The Clyde & Co legal analysis from April 2026 calls these “proportional liability and insurance requirements more suitable for smaller-scale installations.” That’s an understatement — for developers of small-footprint reactors targeting remote or industrial sites, these numbers represent a very different risk profile from traditional nuclear.

The harder problem is what Swiss Re’s Francois Keime described bluntly in October 2025: “There is no product existing yet for the transportation of the small modular reactors. There is no product yet that looks at the different liabilities topics between the constructor, the transporter, the land owner, and then the operator.” This gap matters because factory-built SMRs change the physical risk timeline in ways traditional insurance doesn’t account for. A large light-water reactor stays at its site. A fueled, transportable SMR module — of the type some battery-style designs envision shipping to sites and returning for refueling — has liability exposure at the factory, in transit, during installation, in operation, and on its way back. Who is responsible at each stage, and how much, is genuinely unsettled. 📋

New entrants: why commercial insurers are starting to pay attention

The nuclear insurance market has been quietly closed to most private commercial insurers for decades. That’s starting to shift, and the shift is worth watching carefully. 🚀

The clearest signal came in October 2025, when Tokio Marine GX and Northcourt, an MGA within the Optio Group, launched NC Fusion — the Lloyd’s market’s first dedicated insurance facility for nuclear fusion technology. With initial capacity of $100 million, NC Fusion was explicitly designed to get ahead of commercial deployment rather than react to it. Ben Kinder, Chief Underwriting Officer at Tokio Marine GX, described the logic directly: “The insurance market has historically responded to innovation after it arrives. With nuclear fusion, we’re taking a different approach, positioning ourselves ahead of commercial deployment to ensure insurance coverage doesn’t become an obstacle when this technology is ready to scale.”

That framing is worth sitting with. The traditional nuclear insurance structure reacted to Three Mile Island by creating NEIL. It reacted to growing capacity needs by incrementally expanding coverage limits. NC Fusion represents something different: a proactive bet that nuclear technology is going to need insurance products that the current specialized pool system isn’t designed to provide, and that commercial insurers who move early will capture the market.

Several factors are drawing commercial insurers in now that weren’t present before:

• SMR passive safety features — designs like NuScale’s that physically cannot sustain a chain reaction without active cooling — reduce the tail-risk scenario that drove conventional insurers out in the first place

• Factory manufacture creates quality control standards and actuarial data that custom-built one-off reactors never generated

• Scale of deployment is now projected to be large enough that insurers can build real portfolios rather than concentrating catastrophic exposure on a handful of sites

• Mainstream energy investment — from tech giants like Microsoft and Google — signals that the risk is being assessed favorably by sophisticated capital, which other capital tends to follow

Marsh’s March 2026 podcast on SMR insurance risks notes that “the insurance market is adapting to new construction and operational models through increased stakeholder collaboration, early risk advisory involvement, and innovative coverage solutions.” WTW’s global head of nuclear, Kate Fowler, has made the point that a nuclear construction project is essentially identical to any other large construction project right up until the moment fuel goes in the reactor — and conventional construction insurers are perfectly capable of covering the first phase. The nuclear-specific coverage questions only become acute for the last six to twelve months of construction.

The subsidy question that keeps coming back

If you spend enough time in energy policy circles, you will eventually hit the argument that Price-Anderson is a massive hidden subsidy for nuclear power, and that if operators had to carry the full actuarial cost of a catastrophic accident at commercial rates, reactors would be uneconomic to build. This isn’t a fringe position — it appears regularly in rigorous policy analysis and is shared by organizations like Environment America and the Natural Resources Defense Council. 🌍

The counter-argument from nuclear supporters is equally direct: the $16 billion pool has never been tapped above the primary layer in 70 years of U.S. commercial nuclear operation, the TMI accident cost only $71 million, and the social cost of the alternative — burning coal and gas for decades longer while the grid decarbonizes — is also enormous and also isn’t fully priced. Whether you call Price-Anderson a subsidy or a reasonable liability framework for a low-accident-frequency, high-consequence technology probably depends more on your prior views on nuclear power than on the actuarial math.

What’s harder to dismiss is the international comparison. France’s 57-reactor fleet has operated under its own liability structure. South Korea has built and operated reactors at scale. The United Kingdom joined the Convention on Supplementary Compensation for Nuclear Damage effective January 2026, which creates a multilateral liability system that supports SMR vendors operating across borders — explicitly including U.S. firms deploying in the UK. These international frameworks suggest the liability question is manageable at scale, not a fundamental barrier. The real question for SMRs specifically is whether the gap Francois Keime identified — the absence of transportation, multi-party, and operational liability products for modular designs — gets filled by private commercial insurers, by an expanded NEIL, or by new international pooling arrangements before the first commercial SMR fleet starts moving modules around.

What’s your view: is the insurance market’s emerging interest in nuclear a sign that the private sector is genuinely confident in SMR safety, or is it mostly an opportunistic bet on a sector where government backstops mean the real downside risk never arrives?

The Nuclear Regulatory Commission is probably the most consequential agency you’ve never thought much about. It decides whether new reactors get built. It sets the safety rules those reactors must follow. It approves the designs, the sites, the fuel, the emergency planning zones, the operator training programs. If an SMR developer wants to put a reactor online in the United States, every path runs through the NRC. Every single one.

That makes the NRC enormously powerful, and right now, it’s under more pressure than at any point since it was created in 1974. The nuclear industry says it’s too slow. Safety advocates say any speed-up is reckless. The Trump administration ordered a “wholesale revision” of its structure and culture. Congress passed bipartisan reform legislation. A new regulatory framework for advanced reactors just took effect in March 2026. And career NRC staff are — according to multiple recent reports — genuinely worried about whether the agency can maintain its independence. If you care about whether SMRs actually get built in America, and built safely, you need to understand how this agency works and why the debate around it is so heated right now.

From atomic watchdog to nuclear gatekeeper

The NRC didn’t always exist. Before 1974, nuclear power in the United States was regulated by the Atomic Energy Commission, a body that combined both the promotion and the oversight of nuclear technology in a single organization. You might think that sounds like a conflict of interest, and you’d be right. Congress thought so too, which is why it passed the Energy Reorganization Act of 1974 and split the AEC in two: the Energy Research and Development Administration (which eventually became the Department of Energy) handled promotion and development, while the newly minted NRC took over safety and licensing. 🏛️

Under the AEC’s watch, the United States had built 54 reactors that were operating by 1974, with 70 more under construction or licensed. Costs in 2025 dollars ran under $3,000 per kilowatt, and the median construction time was about six years. That sounds almost impossible compared to modern timelines, and the nuclear industry never tires of pointing it out.

What happened next is a genuinely contested historical question. After the NRC took over, new regulations introduced in the 1970s and early 1980s tripled construction costs and timelines, according to an analysis in The National Interest, resulting in the cancellation of most projects then in progress. The reasons include:

• Post-Three Mile Island regulatory changes applied retroactively to plants already under construction

• An adjudicatory hearing process that allowed opponents to delay projects for years

• Design-change requirements issued during construction, forcing expensive rework

• Per-hour fee charges to applicants, creating massive unpredictability in licensing costs

In the 50 years since the NRC was created, it has licensed exactly two reactors from start to finish — Vogtle Units 3 and 4 in Georgia — projects that required more than 14 years and ran billions of dollars over budget. The original fleet, licensed under the old AEC system, is still operating safely, with many reactors now approved for 80-year service. France, for comparison, built 55 of its 57 reactors in 15 years using standardized designs and consistent safety procedures. South Korea regularly completes large reactors in five years. The NRC’s defenders will say those are unfair comparisons. But the gap is hard to dismiss. ⚛️

How nuclear licensing actually works

Walk into the NRC’s official licensing process and you’ll find something that resembles a choose-your-own-adventure game designed by people who love regulatory certainty more than readable prose. There are currently two main pathways for licensing new reactors, under 10 CFR Part 50 and 10 CFR Part 52, and as of March 2026 there’s a new optional third pathway called Part 53. Each has its own rules, timelines, and application types.

The old Part 50 framework — the one most new reactor applications have historically used — grants construction permits but not operating licenses. Those come later, separately. The Part 52 framework, introduced in 1989, improved this by combining construction and operating authorization into a single Combined License (COL), but it’s still built entirely around light-water reactor technology. If you’re building a sodium-cooled fast reactor like TerraPower’s Natrium, or a molten salt reactor, or an air-cooled microreactor, you’re trying to fit an inherently new thing into a regulatory framework that wasn’t built for it. 🔧

The key steps in the current licensing process look roughly like this:

• Early site permit (ESP): Secure site approval before committing to a specific design

• Design certification: Get the reactor design itself reviewed and approved, independent of site

• Combined license (COL): The merged construction and operating authorization

• Mandatory hearing: Mandatory public adjudicatory process, even absent formal opposition

• Inspections, tests, analyses: Verification work before actual fuel loading is allowed

Each stage involves staff review, public comment periods, possible contested hearings before the Atomic Safety and Licensing Board, and Commission votes. The Sidley Austin analysis of Part 53 notes that the new framework lists eight distinct types of license applications. Eight. That’s the streamlined version. The NRC also charges applicants by the hour for staff review time, which was running at $318 per hour until the ADVANCE Act cut the rate for advanced reactor applicants to $148 — a meaningful improvement, but still a billing model that turns regulatory uncertainty into a direct financial liability. 📋

Why critics say the NRC is broken — and where they disagree

The criticism of the NRC comes from two directions, and the two sides don’t agree on what exactly is wrong.

The first argument, dominant in the nuclear industry, goes roughly like this: the NRC was designed to regulate massive one-of-a-kind light-water reactors, using safety rules written in the 1970s, and it has never fundamentally updated its institutional architecture to deal with mass-produced, passively safe, modular designs. The Breakthrough Institute published a sharp analysis in February 2026 arguing that the NRC’s problem isn’t how cautious it is — it’s how it’s structured. The agency spent decades optimizing for a single objective — accident prevention — while being asked to govern a system where multiple objectives now matter simultaneously. The result, according to that analysis, is a regulator that became “extraordinarily good at answering one question — ‘Is this safe enough?’ — and institutionally incapable of answering another — ‘Does this regulatory choice serve the general welfare better than the alternatives?’” ⚠️

The second argument comes from safety advocates and some former NRC officials, and it goes in the opposite direction: the agency is under political pressure to move faster than is wise, and the independence it needs to make hard safety calls without political interference is genuinely at risk. Allison Macfarlane, who served as NRC chair during the Obama administration, put it plainly in a recent ProPublica investigation: “The regulator is no longer an independent regulator — we do not know whose interests it is serving. The safety culture is under threat.”

Both arguments contain real information. The NRC was built for a technology that barely resembles today’s SMR designs. And the NRC is under extraordinary external pressure right now. These facts don’t cancel each other out — they coexist uncomfortably, which might be why the debate around this agency is so hard to resolve. What’s your read on how much the structural critique and the independence critique are actually in tension with each other?

Also worth understanding: one of the most contested aspects of NRC regulation is the linear no-threshold (LNT) model, the assumption that any radiation exposure, no matter how small, carries some cancer risk proportional to dose. Trump’s May 2025 executive order directly challenged this, directing the NRC to reconsider its reliance on LNT. Critics of LNT argue it’s scientifically outdated and that it drives enormous compliance costs for risks that may be negligible. Defenders argue that challenging it opens a door to weakening protections that public trust in nuclear power depends on. This is not a simple call, and watching the NRC navigate it over the next few years will tell us a lot.

The reform avalanche: ADVANCE Act, Part 53, and the executive orders

The pace of change at the NRC since 2024 is genuinely remarkable. It’s worth laying out what has actually happened, because the timeline is easy to lose track of. 🚀

The ADVANCE Act — Accelerating Deployment of Versatile, Advanced Nuclear for Clean Energy — was signed into law by President Biden in July 2024 with near-unanimous Senate support. Among other things, it changed the NRC’s mission statement for the first time in the agency’s history, explicitly directing it to regulate in a manner that does not “unnecessarily limit” nuclear energy development. That’s not a small thing. For decades the NRC had treated consideration of nuclear’s benefits as outside its remit, focusing exclusively on risk minimization. The ADVANCE Act said: weigh both sides.

By December 2025, the NRC had met 30 of its 36 planned ADVANCE Act deliverables. Then, in March 2026, it finalized Part 53 — a risk-informed, technology-inclusive regulatory framework applicable to any reactor type, not just light-water designs. This is the first new licensing framework since 1989 and the first update to reactor licensing standards since 1956. Key practical changes Part 53 brings:

• Performance-based criteria replace prescriptive technology-specific requirements

• Common design reviews allow multiple sites using identical designs to be reviewed together

• Design certification terms extended from 15 to 40 years

• Factory fuel loading options for modular designs that move significantly prefabricated

• Flexible siting criteria that open industrial sites, data center campuses, and remote locations

Then came President Trump’s executive orders in May 2025, including one requiring a “wholesale revision” of the NRC’s structure, directing it to reduce staffing (in consultation with DOGE), establish an expedited pathway for designs already validated by the DOE or Department of Defense, and adopt science-based radiation limits. A separate executive order set a target of expanding American nuclear capacity from 100 GW today to 400 GW by 2050 — a four-fold increase in 25 years.

New NRC Chairman Ho Nieh, appearing before the House Energy and Commerce Subcommittee in April 2026, described the agency’s new posture in plain terms: “Enabling is really a mindset. It’s not a shortcut. It’s not a compromise. It’s just how we fulfill our safety authorities to benefit the American people.”

The independence question no one can cleanly answer

Here is where I think the story gets genuinely complicated, and where I’d caution against any simple narrative — whether the cheerful “NRC is finally fixed” version or the alarmed “safety is being gutted” version. 🔬

ProPublica’s April 2026 investigation documented some deeply unsettling specifics. The Trump administration fired a Democratic NRC commissioner — something that raised direct legal questions about the independence of the commission structure. NRC lawyers withdrew from proceedings before the Atomic Safety and Licensing Board, citing “limited resources” — the first such withdrawal in over 20 years, the judge noted. Career staffers told ProPublica that DOGE officials had unusual internal influence and that some employees were afraid to voice dissenting views. The budget for the NRC is proposed to be cut by nearly $80 million in fiscal year 2027.

At the same time, it’s fair to ask whether all of that staff time was well spent. The NRC’s own internal data shows that since 2016, Commission voting timelines have lengthened dramatically, procedural timeliness goals are met in only a small minority of cases, and the coordination failures at the Commission level are genuinely measurable. Some of what’s being cut may be unnecessary process. Some of it may be necessary protection. The honest answer is that it’s probably both, and distinguishing between them requires exactly the kind of independent technical expertise that’s now under strain.

The March 2026 policy integrity report on the NRC’s legal authority over SMRs concludes that collaborative reform — among developers, the NRC, and users — is preferable to letting courts or executive orders determine the regulatory future of American nuclear power. That seems right to me. The nuclear industry has the most to lose if the reform effort discredits the safety case for SMRs. History suggests that major nuclear accidents don’t just harm the plant involved — they set the whole industry back by decades. No one in this sector should be comfortable with a regulator whose independence is genuinely in question.

So here’s the question that matters most for anyone tracking the SMR industry in 2026: Can the NRC move fast enough to license the first wave of commercial SMRs on a timeline that keeps developers solvent and investors interested — while maintaining enough institutional rigor that a serious incident doesn’t hand the anti-nuclear movement its most powerful argument in a generation?

Kemmerer, Wyoming, population 2,500, has been through this before. The Naughton coal-fired power plant opened in the 1960s and became the town’s spine — jobs, tax base, identity. Then ExxonMobil’s gas plant arrived in the mid-1980s. Then the gas and oil booms. Then the busts. Kemmerer knows the boom-and-bust rhythm so well it might as well be in the town charter. So when TerraPower, the nuclear company backed by Bill Gates, announced in 2021 that Kemmerer was its pick for the Natrium advanced reactor — a $4 billion sodium-cooled demonstration plant right next to the retiring Naughton plant — the reaction was not quite jubilation. It was something closer to cautious, weather-beaten hope.

“It’s given us all hope. A lot of hope,” said Phillip Viviano, owner of Rosie’s Pizzeria and Sports Bar, to WyoFile in early 2025. He added that you could see the community go from yellow lawns to green lawns, to people painting houses and putting new roofs on. That’s the power of anticipation in a small town. One announcement, and the whole place exhales. But Kemmerer is also the perfect stress test for the question that matters most as coal communities face closure after closure: when an SMR actually moves in, what changes, what doesn’t, and who gets left behind?

The infrastructure inheritance that nobody talks about

Here is something the energy transition narrative almost always skips: coal plants are expensive to build, and much of what they built can be reused. Transmission lines, cooling water intakes, electrical switchyards, administrative buildings, access roads — all of it has value. A 2024 analysis by the Bipartisan Policy Center found that reusing coal plant infrastructure can cut SMR construction costs by 17% to 35%. That’s not rounding-error savings. On a $4 billion project, that’s potentially $1.4 billion back in the budget. 🏗️

The U.S. Department of Energy estimates there are opportunities to add up to 174 gigawatts of new nuclear capacity at retiring coal plant sites across the country. Eighty percent of evaluated coal plants already have the basic physical characteristics needed for repowering. That figure matters because it means the coal-to-nuclear argument isn’t just political theatre — it’s a genuine economic case built on sunk infrastructure costs.

What specifically transfers to the new plant:

• Steam turbines and generator equipment (often compatible with nuclear steam sources)

• High-voltage transmission infrastructure and grid connections

• Cooling water systems and intake permits

• Site permits, environmental studies, and community approvals already completed

• Skilled workers who understand high-temperature, high-pressure plant operations

The World Economic Forum’s 2024 nuclear framework makes the point plainly: SMRs can slot into coal plant footprints without requiring a total overhaul of the local economy. That “slot in” language is probably a little optimistic, but the core physics of it is right. You are not building from nothing. You are converting. And that distinction makes a massive difference to the timeline, the budget, and the community.

The job math: more numbers, harder questions

The job creation case for coal-to-nuclear sounds great on paper. A 2022 DOE study — updated by an information guide in 2024 — found that replacing a coal plant with a comparably sized nuclear plant generally increases long-term jobs, local income, and local revenues. The same study found that employment in the region could increase by more than 650 permanent jobs spread across the plant, supply chain, and surrounding community, with additional annual economic activity of $275 million. 💼

TerraPower’s Natrium project in Kemmerer specifically promises:

• 1,600 construction jobs at peak building activity

• 250 permanent operating jobs when the plant goes online around 2030

• 40 additional permanent jobs at the nuclear training facility

• Indirect job growth in services, housing, and retail throughout the construction period

Romania’s Doicesti project — a former coal plant site about 90 kilometers northwest of Bucharest where NuScale’s technology is being deployed — tells a similar story. The Final Investment Decision taken in early 2026 estimates nearly 200 permanent jobs, 1,500 construction jobs, and 2,300 manufacturing and component assembly jobs over the plant’s 60-year life.

Those numbers look good. But ask the coal miner eating dinner at Rosie’s Pizzeria and you’ll hear the other side. “They’re going to bring their own people — I mean, it’s a nuclear plant. You don’t just go from running earth-moving machinery to running a nuclear plant.” He has a point. The DOE’s own information guide concedes that while most coal plant roles have “direct or similar matches” at nuclear plants, reskilling is required. It isn’t automatic. And reskilling takes time that displaced miners don’t always have. 🔧

The IEA’s 2025 World Energy Employment report adds a broader warning: nuclear and grid-related professions face some of the steepest demographic challenges in the entire energy sector, with retirements outnumbering new entrants by 1.7 to 1. The industry needs people. But it needs trained people, and the training takes years. Are you curious whether your community could realistically bridge that gap in time? That answer depends heavily on how early the retraining programs start — Western Wyoming College’s new nuclear degree program, launched in anticipation of Natrium, is exactly the kind of early-mover action that makes the difference.

The boom problem nobody likes to talk about

Small towns are not designed for sudden population surges. This is maybe the least-discussed consequence of a major energy project arriving in a community of 2,500 people, and it’s genuinely complicated to manage. 🏘️

At peak Natrium construction, Kemmerer expects between 1,200 and 1,600 workers to arrive. That’s roughly doubling the town’s population. The city administrator, Brian Muir, has said directly that while he’s grateful for the growth, it’s also an enormous stress. The town needs approximately $10 million in road repairs. The wastewater treatment plant needs at least $45 million in upgrades. Then, in 2025, Wyoming’s state legislature slashed property taxes, carving tens of thousands of dollars out of the town’s operating budget right when the demand for services is about to explode.

Then there’s the bust problem on the back end. As Kemmerer businessman Seth Snyder told WyoFile: “We know we’re going to see a large amount of people come in. We have to hire more cops to patrol our streets. Then we’re going to plateau and people are going to leave once construction is done. Now we have to fire cops. So it’s a really difficult situation to be in.”

The challenges stack up fast:

• Housing prices surge before workers even arrive, pricing out long-term residents

• Service businesses cannot find enough staff to handle current demand, let alone the construction wave

• Infrastructure gaps in water, sewer, and roads need expensive fixes before the economic benefit materializes

• State revenue cuts arrive at the worst possible moment, shrinking municipal budgets right when they need to grow

This is not unique to Kemmerer. Any coal town receiving a large industrial project faces the same paradox: you need to spend money you don’t yet have, on infrastructure for people who aren’t there yet, to support an economy that won’t pay off for five to ten years. The communities that navigate this best are the ones that plan early, pursue federal infrastructure grants aggressively, and phase housing construction ahead of worker arrivals rather than scrambling to catch up.

What the real transition gap looks like

The distance between “coal town” and “nuclear town” is not just measured in years of construction. It’s measured in skill certifications, community college curricula, and the willingness of mid-career miners to go back to school. 📚

The DOE’s Coal-to-Nuclear Transitions information guide is honest about this. It flags an “operations gap” — the period between when a coal plant closes and when the nuclear replacement comes online, which can stretch several years. During that gap, tax revenue drops, some workers leave for other regions, and the community’s economic base thins out precisely when it needs to stay stable.

At Kemmerer, the coal mine laid off 28 workers in March 2025 and shifted from three shifts to two, ending 24-hour operations. The Naughton plant itself fully converted to natural gas at the end of 2025, putting related coal jobs in question. TerraPower won’t be operational until around 2030. That’s five years of transition pressure on a community of 2,500, with some workers eligible for nuclear retraining and others — particularly older miners — facing a harder math.

What makes the retraining case realistic rather than wishful:

• Most coal plant operators already work with high-pressure steam, complex process control, and emergency shutdown systems — the core skill set of nuclear operations

• Trade apprenticeships in pipefitting, electrical work, and instrumentation transfer directly

• The IEA estimates that half of workers displaced from fossil fuel sectors have skills applicable to clean energy with targeted on-the-job training

• DOE’s 2025 Energy Workforce Advisory Board formally recommended pilot programs to accelerate the coal-to-nuclear pipeline, citing nuclear’s severe shortage of qualified operators

The CSIS analysis of global workforce transitions offers a sobering counterpoint from Poland, where an 80% reduction in coal jobs since the 1990s was accompanied by retraining programs that ultimately failed to place most workers in new jobs. The difference in Kemmerer — the one that might make it work — is that the replacement employer is arriving before the coal jobs fully disappear, not years after. That sequencing is rare. When it works, it’s the difference between a managed transition and a ghost town.

The broader template: why Kemmerer matters beyond Wyoming

Kemmerer is a test case, and the nuclear industry knows it. 🌐 If Natrium comes online on schedule in 2030, if the local retraining programs produce qualified operators, if the housing boom doesn’t price out long-term residents and the infrastructure upgrades get funded — Kemmerer becomes the proof of concept that the coal-to-nuclear story can actually be told.

Nearly a quarter of the current U.S. coal-fired fleet is scheduled to retire by 2029. That’s hundreds of communities facing the same version of Kemmerer’s question. In Romania, the Doicesti project is making the same argument for Central Europe’s coal belt. In Poland, GE Hitachi’s BWRX-300 is advancing with a coal replacement mandate embedded in the plan. The Rolls-Royce SMR programme targets 40,000 regional UK jobs and £52 billion in economic benefit by 2050, with explicit prioritization of retired coal and gas plant sites. A University of Texas at Austin study published in October 2024 projected that an SMR industry in Texas alone could employ an annual average of 148,000 people over 26 years, generating $50.6 billion in new economic output.

These numbers exist because someone had to go first. Kemmerer, Wyoming — a town of 2,500 people that refused to go quietly — is that first. Whether it becomes a model or a cautionary tale depends on decisions being made right now: about infrastructure funding, retraining program timing, housing policy, and whether state and federal governments treat the transition gap as a problem to solve or a budget line to cut.

What’s your read — does the coal-to-nuclear story depend on getting the workforce transition right first, or is the infrastructure argument strong enough to carry the economics even without a perfect skills match?

Romania is not the first country that comes to mind when you think about nuclear ambition. The country runs two aging CANDU reactors at Cernavodă, operates on a grid that still leans heavily on fossil fuels, and has spent the better part of two decades in failed negotiations with one foreign partner after another over its energy future. European partners tried in 2009 and quit. China tried in 2015 and got booted in 2020. Now the Americans are in, and unlike every arrangement before this one, something appears to actually be moving.

On February 12, 2026, shareholders of Romanian state nuclear operator Nuclearelectrica approved the Final Investment Decision for a 462-megawatt SMR plant at a former coal site in Doicești, about 90 kilometers northwest of Bucharest. The technology: six NuScale Power Modules at 77 MW each, designed and certified in the United States. The project company, RoPower Nuclear, describes this as the most advanced SMR project at the European level. Romania’s Energy Minister Bogdan Ivan called it “the transition from the analysis phase to the implementation phase.”

That is the good news. The rest of the story is more complicated, and it is worth understanding precisely, because Romania’s bet on American nuclear technology is not just a construction story. It is a strategic statement that carries implications well beyond a single plant on a de-industrialized river valley in Dâmbovița County.

How Romania stopped trusting Beijing and started calling Washington

The Doicești project did not happen in a vacuum. To understand why Romania chose American SMR technology, you have to understand what it chose instead, and why. 🌍

Romania’s only nuclear plant, Cernavodă, uses Canadian CANDU technology — pressurized heavy water reactors commissioned in 1996 and 2007. Plans to build two more units at Cernavodă (Units 3 and 4) stalled for years. By 2013, China General Nuclear Power Corporation (CGN) had signed a memorandum of understanding to build them. Six years of negotiations followed. They went nowhere. In January 2020, Romanian Prime Minister Ludovic Orban announced the partnership with CGN was not going to work. By May 2020, Romania formally terminated the agreement.

The timing was not coincidental. In August 2019, the US Justice Department had placed CGN and several subsidiaries on a trade blacklist, accusing them of acquiring advanced American technology for military use. And in that same month, Romanian President Klaus Iohannis and then-US President Trump had signed a joint statement in Washington that, reading between the lines, left very little ambiguity about what Romania’s “strategic partners” wanted to see happen to CGN’s involvement in Romanian nuclear infrastructure.

This sequence matters for the Doicești story:

• Romania removed a Chinese state company from its most sensitive energy infrastructure under American pressure

• Within months, it signed an intergovernmental agreement with the US on nuclear cooperation

• The NuScale MOU with Nuclearelectrica began in March 2019, the same month the geopolitical winds changed

• The US Export-Import Bank eventually issued letters of interest for up to $3 billion in project financing

What looks like a commercial technology choice is also a geopolitical alignment, and no one on either side is pretending otherwise. The US Embassy in Romania explicitly calls the country “a key partner to support regional energy security” in its December 2025 strategic dialogue statement. The Heritage Foundation described SMR cooperation as an opportunity to counter “the malign political influence of Russia” in Central and Eastern Europe. Romania is on NATO’s eastern flank, neighbors Ukraine, and has zero interest in energy infrastructure controlled by Moscow or Beijing. American nuclear technology, with American financing, is therefore not just a power source. It is a strategic anchor. ⚛️

Think about that the next time someone tells you SMR contracts are purely about megawatt economics.

What the Doicești project actually involves

Setting aside the geopolitics for a moment, what is Romania actually building? 🔬

The site is the former Doicești coal-fired power plant, which has already had its old infrastructure removed. The plan is to build six NuScale VOYGR-6 modules on that footprint, with a combined output of 462 megawatts electric. That is enough to power roughly 400,000 Romanian homes and meaningfully reduce the country’s remaining coal dependence.

The engineering team is substantial:

• Fluor Corporation, the US engineering giant, serves as main contractor for the FEED (Front-End Engineering and Design) work

• NuScale Power is a subcontractor to Fluor, which is an interesting reversal of what you might expect from the technology licensor

• Samsung C&T, the South Korean construction and engineering conglomerate, is also involved in the FEED phases

• Studsvik Scandpower from Sweden has been contracted for nuclear fuel analysis software (CMS5), bringing in a fourth country’s industrial base

The construction timeline targets the first module in commercial operation in 2033, with subsequent units following. The FEED Phase 2 study was completed in late 2025, producing what NuScale CEO John Hopkins described as the data needed for the final investment decision: an updated cost estimate, schedule, and the safety analyses required for licensing.

Romania’s nuclear tech director Dan Șerbănescu noted that NuScale’s technology builds on half a century of light-water reactor experience, which matters more than it might seem — regulators and operators working with a technology that shares DNA with existing fleet designs start from a more solid knowledge base than a genuinely novel reactor type. What the plant adds on top of that familiar foundation is passive safety systems: the NuScale module does not require external power or active cooling intervention to prevent meltdown, a characteristic that significantly reduces the complexity of the emergency planning zone. That has implications for where you can put these things, and in a densely populated European country with strong public opinion on nuclear safety, it matters a lot. 🛡️

The FID and what it does, and does not, mean

Here is where a dose of realism is useful, because the FID announcement made headlines across Europe, and some of that coverage was rosier than the situation warrants.

The Nuclearelectrica shareholder approval on February 12, 2026 is explicitly conditional. The official documents describe a set of conditions whose fulfillment is mandatory for the project’s feasibility. Romanian Prime Minister Ilie Bolojan was admirably blunt about this at the announcement: “Given the very large amount of money, the complexity of such projects and the technology being in early days, I estimate we will not see the investment immediately.” 📋

The financial picture makes his caution understandable:

• Total project cost is estimated at up to $7 billion by the Romanian government

• The US government commitment is reported to cover approximately $4 billion of that — through a combination of EXIM Bank financing and DFC support

• The remaining financing gap requires Romanian government support, private investors, and potentially EU funds

• The pre-EPC phase, expected to last about 15 months, will nail down the Class 2 budget estimate and the contractual structure before any major construction begins

There is also an ownership complexity worth noting. RoPower Nuclear is currently owned 50/50 by Nuclearelectrica and Nova Power & Gas (part of E-Infra). Reports as of late 2025 suggest a restructuring in which South Korean firm DS Private Equity (DSPE) may take a stake, with Nuclearelectrica’s share dropping to 46.5%. Whether that restructuring closes cleanly will affect the financing timeline.

What the FID genuinely does is move the project past a critical decision point that previous proposals to Romania never reached. All those European partners in 2009? They never got here. China never got here. The fact that a formal, shareholder-approved investment decision exists, with a detailed engineering basis from a completed FEED study, is real progress. It does not guarantee construction starts on schedule, but it is not nothing. 💡

Does Romania’s conditional FID represent the model other European countries should follow, or is it a cautionary tale about how political alignment can move faster than project economics?

Why the rest of Europe is paying close attention

Romania may seem like an unlikely lead actor in Europe’s nuclear future, but that framing underestimates the country’s role in a specific regional dynamic. Romania is a member of the Three Seas Initiative, the grouping of Central and Eastern European countries sitting between the Baltic, Adriatic, and Black seas, many of whom are urgently looking for energy infrastructure that does not depend on Russian gas or Chinese capital. 🌍

The stakes are clear:

• Poland is building its first nuclear program, also with American technology (Westinghouse)

• Czech Republic is proceeding with a Westinghouse PWR at Dukovany

• Bulgaria, Slovenia, and Slovakia are all in various stages of nuclear expansion or extension discussions

• None of these countries wants to be the second one to commit to a new technology before someone else has proven it

Romania, if Doicești actually gets built and operates as designed, becomes the proof of concept for the entire region. Energy Minister Bogdan Ivan was direct about this: the shareholder meeting documents frame the FID as consolidating Romania’s position “at the forefront of the new European nuclear industry.” That framing is deliberate. Romania wants to be first, and being first comes with serious strategic benefits — preferred supplier relationships, accumulated regulatory expertise, and the geopolitical prestige of showing the region how to build energy independence on American technology.

This is also, it bears saying, exactly what US energy diplomacy has been seeking for years. The US-Romania Strategic Dialogue statement from December 2025 commits both countries to continued cooperation on SMR deployment, Cernavodă Units 3 and 4, and Black Sea energy development with American companies. The whole package, taken together, describes a country that has comprehensively reoriented its energy infrastructure around a Western technological and financial framework. That did not happen by accident.

The question Romania’s nuclear bet ultimately raises is this: if Doicești operates on schedule in 2033 and delivers power at the projected cost, how quickly do the other Three Seas countries sign their own NuScale agreements, and what does that mean for the global nuclear supply chain that will have to build all of them?

The moment Sam Altman merged his SPAC with a nuclear startup named Oklo, it was clear something had shifted. Not just in who was funding nuclear energy, but in how these companies think about selling it. Nuclear used to be built by utilities for utilities, financed by regulated ratepayers, blessed by governments, and measured in decades. Then a group of engineers who grew up watching Tesla tear apart the car industry decided to apply the same logic to atoms.

The comparison is not just a slide deck flourish. The specific strategic moves that made Tesla successful — selling direct to customers, owning the supply chain end to end, building iteratively and learning in public, and securing early adopters wealthy enough to absorb first-generation premiums — are playing out in nuclear right now. Some of it is working. Some of it still needs to survive contact with a regulatory body that does not operate on Silicon Valley timelines. But the intent is unmistakable, and it is worth understanding precisely.

The direct model: skipping the utility altogether

Tesla did not sell cars through dealerships. It sold them directly to drivers, cutting out the middleman and controlling the full customer relationship. Oklo is attempting the same move in nuclear energy. Instead of building reactors and handing them to a utility, Oklo builds, owns, and operates its reactors, then sells power directly to customers under long-term contracts — what the company calls a “power-as-a-service” model. 💡

The implications are significant:

• Utilities are not in the transaction at all

• Oklo captures the margin from electricity sales rather than a one-time reactor sale

• Customers like data centers get a predictable, locked-in power price for decades

• Oklo can co-locate its Aurora Powerhouse directly on a customer’s site, eliminating grid interconnection costs

As of early 2026, Oklo has a customer pipeline of roughly 14 GW, including a supply agreement with data center giant Switch and a deal with Meta to supply 1.2 gigawatts to AI operations in Ohio. These are not letters of intent. They are structured agreements that include upfront funding from customers to accelerate construction.

This is, pretty explicitly, the Tesla pre-order model. Early adopters commit capital before the product ships, which funds the factory, which proves the concept for the next wave of buyers. It worked for cars. Whether it works for reactors, which have a dramatically longer build cycle and a much more complex regulatory environment, is the actual bet being placed here.

Think about what this means for the traditional nuclear industry: the assumption that utilities are the only viable customer for nuclear power has not just been questioned. It has been discarded. 🔬

Is this model genuinely viable, or is a 12-GW pipeline of signed contracts just optimism dressed in legal formatting?

Vertical integration: owning the supply chain like Apple owns its chips

Tesla builds its own battery cells, its own motors, its own software, and as of recently, its own chips. The point is not just cost control. It is speed. Every time you depend on an external supplier, you introduce a schedule risk you cannot manage. Kairos Power, the California nuclear startup that just became the only US company actively building an advanced SMR, understood this early. 🏭

According to E&E News reporting from July 2025, Kairos argues that vertically integrating its supply chain, doing everything from fuel fabrication to welding reactor vessels internally, gives it a better shot at staying on schedule. That is not a boast. It is a lesson learned from watching every other nuclear project fall apart when a single specialty subcontractor missed a deadline and the whole critical path unraveled.

Kairos’s vertical integration list is striking:

• Fuel fabrication from its proprietary TRISO pebble fuel in-house

• Reactor vessel welding performed internally rather than contracted out

• Iterative reactor designs built at the same Oak Ridge, Tennessee, site, so infrastructure and personnel carry forward between projects

• A direct revenue agreement with Google locked in before the first commercial reactor operates, providing financial certainty while construction advances

Oklo takes vertical integration a step further by closing the fuel cycle entirely. In March 2025, Oklo acquired Atomic Alchemy and subsequently announced plans for a $1.68 billion nuclear fuel recycling facility in Oak Ridge, Tennessee. The plan: convert the 80,000+ tons of spent nuclear fuel sitting at US reactor sites into HALEU to power its own Aurora reactors. That is not just vertical integration. That is turning a waste liability into a feedstock. Tesla wished it could recycle old cars into new battery cells this cleanly. ⚡

The strategic logic is identical in both industries: when you own the whole stack, you control your cost trajectory, and you build institutional knowledge that competitors cannot easily replicate.

Big Tech as the early adopter: who plays the role of the tech crowd that bought Teslas first

Tesla’s first customers were wealthy early adopters who could absorb a $100,000 price tag for a car that proved the concept for everyone who came after. SMR startups have found a customer base that is even more strategically useful: technology companies with virtually unlimited energy appetite, strong balance sheets, genuine carbon commitments, and the patience to fund first-of-a-kind builds. 🚀

The deal-making here has been extraordinary in scale:

• Google and Kairos Power signed what Google described as the world’s first corporate agreement to purchase nuclear energy from multiple SMRs, targeting 500 MW by 2035, with Hermes 2 targeted for 2030 at the Tennessee Valley Authority grid

• Meta announced agreements for 6.6 GW of nuclear energy projects in 2026, including the Oklo partnership

• Oracle announced a gigawatt-scale data center powered by three SMRs, with CEO Larry Ellison stating construction permits were already secured

• Microsoft signed a 20-year agreement to restart Three Mile Island at 835 MW, while also backing Oklo

These deals change the economics in a specific way. The tech companies are not just buying power. They are, as Google’s head of data center energy Amanda Peterson Corio said to CNBC, actively trying to help commercialize the technology: “We want to see how we can take this from something small to something bigger that we can deploy at scale.” That is a customer funding your learning curve. No nuclear company in history has had that.

It is also worth noting what kind of customer this is. A data center operator running on nuclear does not vary its load the way a grid operator does. It runs at near-constant draw, 24 hours a day, 365 days a year. That is the ideal customer for a baseload nuclear reactor, and it is exactly the profile that makes nuclear competitive against wind and solar in this specific application. The alignment between what SMRs produce and what AI infrastructure needs is probably the most consequential commercial development in nuclear’s history.

The iterative build strategy: failing fast, then failing less

Here is something Tesla did that is deeply unfamiliar in nuclear: it built cars that were not quite right, sold them to customers, used the feedback, and built better ones. The original Roadster was barely viable. The Model S was the first real product. The Model 3 was the one that changed the world. Each generation funded the next and taught lessons the previous one could not.

Kairos Power has adopted this strategy more explicitly than any other SMR developer. Its Hermes 1 reactor in Oak Ridge is a 35-megawatt thermal demonstration plant, deliberately non-power-producing, designed purely to prove the fluoride salt cooling technology and stress-test the supply chain. The Nuclear Regulatory Commission issued a construction permit for Hermes 1 in December 2023, the first non-water-cooled reactor approved for construction in over 50 years. 🔩 Then in November 2024, the NRC approved Hermes 2, a two-unit power-producing plant at the same site.

Kairos CEO Mike Laufer told CNBC that Hermes 2’s core purpose is to create a standardized reactor design that drives down the cost of future deployments. Each iteration is a learning vehicle, not a revenue vehicle. The Google deal is structured the same way — Google and Kairos bear the financial risk of the first-of-a-kind build, while TVA provides the revenue stream through a power purchase agreement. Future customers inherit a cheaper, better-proven design.

This is genuinely novel in nuclear. The traditional approach was to design everything perfectly on paper, then build it once and hope. Kairos builds small, learns expensively, and applies those lessons to the next build. The risk of the approach is that each build still takes years and costs hundreds of millions of dollars. This is not software iteration. You cannot ship a patch to a reactor. But the principle of structured learning across a product line, rather than treating every build as a unique custom project, is real progress.

Where the Tesla playbook could still break down

None of this means the outcome is guaranteed. And I think it is worth saying clearly where the analogy strains under pressure. 📈

Tesla’s most powerful advantage was speed. A car takes roughly 30 hours of manufacturing labor to build. A reactor takes years of construction and a regulatory process that the NRC measures not in sprint cycles but in 18-month review windows. The iterative model that works beautifully in software, and even in automotive, faces a different physics in nuclear:

• Regulatory review of a new reactor design cannot be accelerated just because your customer has deep pockets

• HALEU fuel, required by Kairos, Oklo, and TerraPower’s Natrium reactor, is still not available at commercial scale in the United States, and no tech company checkbook can manufacture that supply chain overnight

• First-of-a-kind construction costs are genuinely high; Kairos’s first commercial units will not benefit from learning-curve cost reductions until multiple reactors are built

• The NRC’s licensing process, even on an accelerated timeline, still requires years that Tesla’s product cycles simply do not

The Bloomberg feature on Oklo from October 2025 noted that critics worry Oklo’s political connections and fast-moving ethos could pressure the NRC to approve designs before they are fully proven. That is a real concern. The nuclear safety record is excellent precisely because the regulatory process is slow and rigorous. The goal is not to remove oversight. It is to rationalize it for new reactor types that have fundamentally different risk profiles than the 1970s designs the current framework was built around.

The SMR startups that will succeed are probably the ones that internalize both sides of this. Move fast where you can: supply chain, factory setup, customer agreements, software. Move carefully where you must: safety case, regulatory submission quality, fuel cycle planning. Kairos, which got its Hermes 1 permit in 18 months after submitting what the NRC described as a thorough application, seems to understand this distinction. Others that assume the Tesla playbook transfers wholesale to a nuclear regulator may find the analogy has limits.

The question worth sitting with is this: when the first American SMR actually produces commercial power, which company will own that moment, and will their approach look more like Silicon Valley’s or more like the traditional nuclear industry’s?