BasicsTwo KLT-40S reactors rated at 35 MWe each sit on a 21,500-tonne barge in the Arctic port of Pevek, and they have fed a Russian grid since 2019. That is the entire floating nuclear fleet. One vessel, one country, one operator. The Akademik Lomonosov spent most of its life looking like a Rosatom quirk that the rest of the industry watched from a safe distance.

The distance is shrinking. The IAEA launched its ATLAS initiative in Washington on August 26 and 27, and the US Nuclear Regulatory Commission signed an offshore jurisdiction pact in July. Rosatom, for its part, finished the second reactor for its first repeat-order barge in the past few days. Whether floating plants go mainstream comes down to which clock runs faster: the shipyards or the rulebooks.

Thirteen years for one barge

The Akademik Lomonosov is a non-propelled vessel, 144.4 metres long and 30 metres wide, with a crew of 69. It also took 13 years to build against a plan of four, according to Bellona, which has criticized the project since construction began. That number says more than any megawatt rating, because it is the real price of doing this for the first time.

• Reactors: two KLT-40S units at 150 MWt each, about 70 MWe combined

• Fuel: low-enriched uranium averaging 14.1% enrichment, on a three-year refuelling cycle

• Service record: moored at Pevek on September 14, 2019, commercial since 2020, and more than 1.2 billion kWh delivered by May 2026, per World Nuclear News

• Licence: ten years from Rostechnadzor, issued in June 2019 and running to 2029

• Grid role: Interesting Engineering reports the barge now carries 60% of the Chaun-Bilibino load, up from 20% in 2020

Russia was not first. The US built the MH-1A on a converted Liberty ship, and it reached criticality in 1967. In the 1970s, PSE&G and Offshore Power Systems planned the Atlantic Nuclear Power Plant, four Westinghouse 1,150 MWe pressurized water reactors floating off New Jersey. It was canceled in 1978. Russia is simply the country that finished.

Baimskaya is the real test

One barge is a demonstration. Four is a business. Rosatom is building four PEB-106 floating units for the Baimskaya copper project in Chukotka, each with two RITM-200S reactors and 106 MWe of output, moored at Cape Nagloynyn. The mine needs about 300 MWe, so three units run while the fourth covers refuelling and maintenance, World Nuclear News reports.

The money is public, which is rare. The World Nuclear Association lists a Rosatom commitment of over RUB 150 billion ($2.1 billion) and an electricity price of RUB 6.45/kWh, about 8 cents, indexed for inflation. That is the first commercial price signal the floating sector has produced.

• Hulls: a $226 million contract with China’s Wison (Nantong) Heavy Industries for the first two 19,100-tonne hulls, with the other two at Baltic Shipyard in St. Petersburg

• Arrival: the first Chinese hull reached St. Petersburg quietly in March 2026, according to the Barents Observer

• Reactors: the first RITM-200S came off the line at ZiO-Podolsk in May 2026, and the second followed this week, completing the PEB-106 set

• Schedule: the original contract called for delivery in early 2027, and Rosatom CEO Alexey Likhachev now points to 2028 to 2029

Look at the hull line again. A state nuclear giant with a working reference plant could not find shipyard capacity at home and hired a Chinese yard. If that is the experience of the incumbent, what happens to a startup with a design on paper? For the broader picture of what Beijing builds on its own soil, SMRbrief’s look at China’s SMR program covers the 125 MWe Linglong One on Hainan. Delivery dates here have already moved once and might move again.

Korea, Denmark and the molten salt crowd

Outside Russia, every floating design is still a design. Three are worth knowing.

• BANDI-60: a 200 MWt/60 MWe block-type pressurized water reactor from Kepco E&C, paired with an HD Korea Shipbuilding & Offshore Engineering barge, which earned approval in principle from ABS in October 2023

• Seaborg CMSR power barge: two to eight 100 MWe compact molten salt reactors per barge, with a 24-year life, backed by a consortium of KHNP and Samsung Heavy Industries

• Core Power and TerraPower MCFR: a molten chloride fast reactor adapted for marine use, with Southern Company in the team and a $30 million investment from HD Hyundai in TerraPower since November 2022

Seaborg’s calendar deserves a skeptical read. Its commercial power barge production date moved from 2026 to 2028 in roughly a year, and nothing found in this research shows a finished prototype, so treat the 2026 prototype date as stale. Core Power claims floating plants would cost half as much and build 70% faster than land plants. That is a company estimate, and no operating plant has tested it. Every project, deal, company, and regulatory event we cover is logged, verified, and searchable in SMRbrief Pro, where the barge designs sit next to their land-based cousins, which is the comparison that matters when cost claims arrive.

Regulators are moving before the reactors

The paperwork is where the Western push is furthest along. On July 21, the NRC and the newly formed Marine Minerals Administration signed an MOU covering nuclear projects on the Outer Continental Shelf. The MMA only existed from July 10, when Interior merged the Bureau of Ocean Energy Management and the Bureau of Safety and Environmental Enforcement. NRC Office of Advanced Reactors Director Jeremy Bowen said the deal creates “a clear framework for how our agencies will work together”.

• US: the NRC also signed an MOU with the Coast Guard in late June, and a draft maritime licensing white paper is targeted for fall 2026, per ANS Nuclear Newswire and Holland & Knight

• No applicants: no offshore nuclear project has been approved or proposed on US waters

• IAEA ATLAS: 28 member states signed the launch statement, and commercial participants are expected to pay 25,000 euros a year, with waivers available

• IMO: the maritime body is revising its 1981 code for nuclear merchant ships, with adoption envisioned for 2030

The hard questions are legal. Who licenses a reactor built in one country, flagged in another and moored in a third? Which state answers for the spent fuel? Bellona also raises the security angle: a floating plant can sail away from a threat, but a reactor tied up at a remote mine is a conspicuous target with exposed moorings and power connections. Does mobility make a reactor safer in wartime, or just easier to find?

What mainstream would take

Three things have to happen, and none has yet. A second Russian generation has to run at Baimskaya. A customer outside Russia has to sign. And a licensing route has to exist that a lender will underwrite. The first is a shipyard problem, the second a commercial one, and the third is what ATLAS is for.

Grid interconnection waits of five to ten years in some regions, covered in SMRbrief’s piece on how SMRs could solve the data center energy crisis, are the kind of problem a factory-built plant delivered by tow is meant to sidestep. The pitch remains a pitch. No floating unit has been sold to a buyer of that kind.

• PEB-106 lead unit: reactor and turbine installation at Baltic Shipyard, with delivery guided to 2028 to 2029

• NRC white paper: the draft maritime licensing document due this fall

• Lomonosov licence: the 2029 expiry, a natural test of whether Rostechnadzor and Rosatom treat the barge as a permanent asset

• IMO code: the 2030 target for the nuclear merchant ship rules

• First foreign buyer: Rosatom is marketing a 100 MWe export unit with a 60-year life, and no named customer turned up in this research

The Lomonosov’s licence and the first PEB-106 delivery land in the same year. If the new barge arrives on time and the old one gets renewed, floating nuclear stops being a curiosity. If either slips, the next question is whether the West’s shipyards can do better than Russia’s did. Which side of that bet would a utility take?

InvestmentsOklo is down 49% in 2026 and trades 80% below its record high. NuScale Power is down 43% and sits 86% below its peak, according to a Benzinga tally from Sept. 20. Short interest is 17% at Oklo and 16% at NuScale, and the Financial Times estimates short sellers have made more than $2 billion this year. That is a sell-off, not a verdict. Some of the technology and some of the milestones are real. The job is sorting them from the noise, and three red flags do most of the sorting. 🔬 (Prices here are as of Sept. 20 and move daily.)

Red flag one: the stock is the funding source

Oklo booked $1.2 million of second-quarter revenue against a six-month net loss of $81.6 million. It ended June with $3.0 billion in cash and securities, per its 10-Q for the period ended June 30, and the company said on its earnings call that $1.9 billion of that came from at-the-market stock sales this year. On Sept. 11 it set up another ATM for up to $1 billion with 10 banks, including Goldman Sachs and J.P. Morgan. Shares fell 7% to $37.09, near the 52-week low of $36.61, Benzinga reported. Benzinga also puts the share count at about 185 million, up from 122 million in 2024, a 52% increase. 📉

NuScale has the same shape at a different scale. It reported $75,000 of second-quarter revenue against $1.9 billion in liquidity, according to 24/7 Wall St’s coverage of the UBS downgrade to Sell. UBS cited timeline and cash burn.

The cash is real, and that matters. Oklo raised its 2026 guidance to $120 million to $150 million of operating cash use and $400 million to $500 million of capital spending, so $3.0 billion covers years. The risk is dilution, not survival. When the share price is the funding source, every drop makes the next dollar more expensive.

What to check in any pre-revenue developer’s latest 10-Q:

• Runway: cash against guided burn (Oklo’s ceiling is roughly $650 million in 2026 for operations plus capex)

• Share count: this year against last year

• ATM capacity: the size of open programs relative to market cap

• Revenue source: Oklo’s second-quarter revenue came mainly from recent acquisitions, not reactor sales

How many quarters does a company last if its stock falls another 50%? Fair question to ask before the answer arrives on its own.

Red flag two: gigawatts on non-binding paper

ENTRA1 Energy and the Tennessee Valley Authority signed a non-binding agreement on Sept. 2, 2025 for up to 6 GW of NuScale capacity, as NuScale’s 10-Q describes it. At 77 MWe per module, that is roughly 78 modules. ENTRA1 would finance and own the plants and sell the output to TVA under future power purchase agreements, ANS Nuclear Newswire reported. A year later, NuScale’s Aug. 5 results release says ENTRA1 is still in discussions with TVA toward a definitive PPA. ⚡

The Romanian project has more paper. RoPower would put six NuScale Power Modules (462 MWe) at a former coal plant site in Doicești, and the Fluor-led FEED Phase 2 study finished in late 2025. Nuclearelectrica shareholders approved the next phase with conditions, and NuScale says it is working to meet them. That is progress, and it is also not a construction contract.

The same pattern shows up elsewhere. NANO Nuclear’s latest 8-K points to advanced discussions with a prospective customer building a multi-gigawatt data center pipeline. In December 2025, an Oklo spokesperson told Neutron Bytes it was too early to put numbers on power purchase agreements and described its data center and oil and gas agreements as non-binding MOUs. That is nine months old, so check whether it has changed. Every project, deal, company, and regulatory event we cover is logged, verified, and searchable in SMRbrief Pro, which turns the signed-versus-announced check into a filter.

Phrases that usually mean no contract yet:

• “Up to” a capacity figure

• Non-binding, MOU, or letter of intent

• “Advanced discussions” or “continues to advance”

• “Framework” with no price per megawatt-hour attached

Red flag three: the schedule runs through someone else’s fuel and license

Oklo’s first Aurora powerhouse is a 75 MWe sodium-cooled fast reactor at Idaho National Laboratory, targeting a 2028 startup. Its 10-K says HALEU and plutonium-based fuels are not available at scale. In May 2026, DOE selected Oklo for advanced negotiations in its Surplus Plutonium Utilization Program, but the 10-Q says any use of that material still depends on DOE authorization, regulatory approvals, and material availability. Neutron Bytes, an independent nuclear blog, estimates plutonium-derived fuel is a mid-2030s story at the earliest.

HALEU has a nearer date. Centrus signed a letter of intent to supply Oklo’s planned 1.2 GW Ohio campus, with deliveries starting in 2029, and DOE awarded $900 million for HALEU enrichment in January. SMRbrief’s HALEU glossary entry covers the details. A 2029 delivery date sits after a 2028 startup target, which is the kind of gap worth noticing. 🇺🇸

On licensing, Oklo’s regulatory page describes the INL plant as running under an in-progress DOE authorization that is meant to convert into an NRC commercial license.

NuScale flips the profile. Its CEO says the technology runs on fuel that is proven and available today. The 77 MWe NuScale Power Module received NRC standard design approval in May 2025. A design approval is not a site, a construction permit, or a buyer. The five reactor types SMRbrief has laid out carry very different fuel and licensing profiles, and a light-water design like NuScale’s skips the fuel problem entirely.

Dependencies to map before believing a date:

• Fuel: enrichment level, supplier, and contracted delivery date

• License: which NRC or ONR step is complete, and which is next

• Customer: a signed PPA or EPC contract, not an MOU

• Financing: who pays for the first plant if the stock is down 50%

What real progress looks like

Rolls-Royce SMR is the benchmark, though it is not a pure-play stock. Its 470 MWe PWR has a UK government contract for three units at Wylfa, signed in April 2026, with $3.4 billion allocated to the contract and wider program. The regulators’ guidance page shows the design in Generic Design Assessment Step 3, expected to finish by December 2026. A final investment decision is still ahead, and that gap is stated openly. 📈

Smaller pieces of real progress exist too:

• Oklo: the Groves isotope facility reached first criticality on Aug. 5, 2026, roughly 11 months after the site was greenfield

• NANO Nuclear: the NRC accepted the KRONOS MMR construction permit application on May 20, 2026, with about a 12-month review expected

• NuScale: the Highly Integrated Protection System contract awarded to Paragon moves the supply chain from planned to purchased

Even NANO’s own filings tell readers to keep expectations in check: initial KRONOS operation is targeted around 2030 to 2031, and the company says the unit is not a near-term commercial power product.

So which of the gigawatts in a portfolio has a price, a regulator’s date, and a fuel delivery attached to it?

BasicsConcernsEvery meltdown argument ends up as a fight over three place names. Three Mile Island in 1979 was an equipment fault plus confused operators. Chernobyl in 1986 was a reactor with a physics flaw. Fukushima Daiichi in 2011 was a tsunami that drowned the backup power. Different failures need different fixes, and lumping them together as “nuclear accidents” is the first myth, the one that makes every later debate worse.

SMRs do not remove risk. As SMRbrief has reported on the data center energy push, no commercial SMR has yet sold a watt to a paying customer in the United States. The designs below are approved or under review, not proven over decades of operation. But five common meltdown assumptions do break down when applied to designs from NuScale, X-energy and Rolls-Royce SMR. Here is where each one stands as of late September 2026.

Myth 1: a power failure means a meltdown

The three Fukushima Daiichi units that melted were not undone by the earthquake. They shut down on schedule. Then a 15-metre tsunami flooded the site, disabled 12 of 13 backup generators and knocked out the heat exchangers that dump decay heat to the sea, according to the World Nuclear Association’s account. Fission stopped. Heat did not. Without pumps, the cores boiled dry.

Large plants need electricity to survive their own shutdown. The NuScale Power Module is built to need none. Each 77 MWe module sits in a water-filled pool, and NuScale says it shuts down and cools itself with no operator action, no AC or DC power and no added water, as described in a design paper in Frontiers in Energy Research. The NRC approved that uprated design in May 2025, per the Department of Energy. SMRbrief’s glossary of SMR terms notes NuScale is still the only company holding an NRC design certification or standard design approval.

• Reactor: NuScale Power Module, pressurized water, 250 MWt (77 MWe) per module

• Plant configuration: VOYGR-6, six modules, 462 MWe

• Regulator: US NRC, standard design approval, May 2025

• Most advanced overseas project: RoPower in Romania, up to six modules at the former Doicesti coal site with Nuclearelectrica (June 2025 reporting, so check for updates)

Passive is not the same as invulnerable. Gravity and density differences are weak forces, and the passive safety literature flags that weak driving forces can make these systems harder to prove in the first hours of an accident. That is why regulators test them instead of taking vendors at their word. Insurers are paying attention too, and SMRbrief covered how passive designs change the tail risk that pushed underwriters out of nuclear in the first place.

Myth 2: fuel always melts when cooling fails

Conventional fuel is uranium oxide in metal tubes. Overheat it and the cladding reacts with steam to make hydrogen, which is what blew apart the outer buildings at Fukushima. X-energy’s Xe-100 attacks the fuel itself. It runs on TRISO particles: a uranium kernel wrapped in three layers of carbon and ceramic, packed into billiard-ball-sized pebbles and cooled by helium. The Department of Energy says TRISO fuel cannot melt in a commercial high-temperature reactor. Idaho National Laboratory backed that with a test that held irradiated TRISO at up to 1,800 degrees Celsius for more than 300 hours, beyond predicted worst-case accident conditions, with full retention of fission products.

The flagship project is Long Mott Generating Station: four Xe-100 modules, 800 MWth and 320 MWe, at Dow’s Seadrift Operations in Calhoun County, Texas. The NRC finished its environmental assessment in May 2026 with a finding of no significant impact, and the final safety evaluation is targeted for November 2026, per POWER’s reporting on the NRC dashboard. That date may have moved, so check the NRC docket.

• Reactor: Xe-100, helium-cooled high-temperature gas reactor, 80 MWe per module

• Fuel plant: TX-1 in Oak Ridge, Tennessee, which received the first-ever NRC Part 70 HALEU fuel fabrication license in February 2026

• Fuel timeline: TX-1 operations expected in the first half of 2028, per X-energy’s July 2026 NRC briefing

• Open item: the 13-month irradiation test of TRISO-X pebbles at INL started in November 2025, so qualification data for this exact fuel is still coming

The safest fuel is also the priciest. X-energy’s illustrative lifetime cost for a four-reactor Xe-100 plant runs $1.66 billion to $2.18 billion, with $1.095 billion to $1.25 billion of it fuel, per a February 2026 amended registration statement. Would you pay that premium for a core that does not melt?

Myth 3: operators have to save the day

Three Mile Island is remembered as a technology failure, but the Department of Energy’s summary pins it on equipment failure and operator error together. A relief valve stuck open. The control room indicator said it had closed. Operators, unaware they were losing coolant, made choices that made it worse. About one-third of the core melted, yet the vessel and containment held and the accident left no detectable health impacts, according to the World Nuclear Association.

• A feedwater failure tripped the turbine and the reactor, as designed

• The relief valve opened as designed, then stuck open for more than two hours

• Instruments told operators the valve had reclosed

• Confused decisions in the control room turned a manageable transient into a partial meltdown

The design goal of passive systems is to take those decisions out of the first hours. Cooling that runs on natural circulation does not wait for an operator to diagnose anything. The worst thing a confused operator can do is nothing, and in a passive design that is the correct response. Modern designs have added passive systems specifically to cut the risk of compounding human error, a trend the same passive safety literature documents.

Operators still matter for security, maintenance and everything outside the emergency window. The claim is narrow: the first response does not depend on someone reading a misleading gauge correctly at 4 a.m.

Myth 4: any reactor can run away like Chernobyl

Chernobyl’s RBMK pairs a graphite moderator with boiling water coolant. When steam forms, less neutron-absorbing water remains, and reactivity rises. That is a positive void coefficient, and at Chernobyl it pushed power to around 100 times the rated capacity, per the World Nuclear Association’s RBMK appendix. Light-water designs work the opposite way. Boil the water and the reaction slows, because the water is the moderator.

Here the honest answer is that SMRs inherit this fix rather than invent it. Every Western light-water reactor already has a negative void coefficient. What SMRs add is variety that removes the mechanism entirely.

• NuScale module: light-water PWR, water is both moderator and coolant

• Rolls-Royce SMR: 470 MWe PWR, in Step 3 of the UK’s Generic Design Assessment

• Xe-100: helium coolant, so there are no steam voids to form at all

• RBMK: graphite plus boiling water, a combination found in no other power reactor

The myth still earns a place on this list because it drives more public opinion than any engineering paper. Next time someone calls an SMR a smaller Chernobyl, ask which moderator they mean. Most conversations end there.

Myth 5: every plant needs a 10-mile evacuation zone

Existing US plants plan around a plume exposure zone of about 10 miles and an ingestion zone of about 50 miles, per an NRC emergency preparedness presentation. In November 2023 the NRC finalized 10 CFR 50.160, effective December 18, 2023. It lets SMR and advanced reactor applicants size the plume zone to the accident consequences and prove readiness through performance-based drills. Where the zone stays on site, local first responders are not required to join radiological exercises.

NuScale went first. The NRC’s Advisory Committee on Reactor Safeguards concurred with staff that NuScale’s methodology gives the same protection as a 10-mile zone and can produce a zone at the site boundary, per Nuclear Engineering International. The approval covers only the NuScale design.

• Legacy rule: roughly 10-mile plume zone for large light-water plants

• New rule: scalable zone, effective December 18, 2023

• Payoff: plants can sit next to industrial customers, housing or a former coal site

• Open question: a 2023 NRC rulemaking document noted the agency has never licensed a commercial plant with a site-boundary zone, and FEMA and state agencies raised concerns

This is the myth with the most work left. A smaller zone needs a site-specific case, and neighbors will want to see it. Every project, deal, company, and regulatory event we cover is logged, verified, and searchable in SMRbrief Pro, including each of these zone decisions as they land.

The next checkpoints are concrete. The NRC’s final safety evaluation for Long Mott’s four Xe-100 modules is targeted for November 2026, and the UK’s assessment of Rolls-Royce SMR’s 470 MWe design is expected to finish by the end of 2026, per the Office for Nuclear Regulation. Both dates may have slipped, so check the regulators’ pages. When those decisions land, which of the five myths do you expect to die first, and which will survive anyway?

Global RaceChina runs a 210 MWe SMR plant that has sold power since December 2023. Canada has committed C$20.9 billion to four BWRX-300 units. Poland plans 24. ⚡ Those three numbers show how differently governments define a bet on small reactors. The five countries below each have money on the table, a regulator engaged, and a named site. None has a Western SMR producing power yet. 🌍 Facts are current as of September 20, 2026, and each section flags what might have moved.

How a bet is counted

A study is not a bet. Four tests separate the two, and the five countries in this article pass at least three:

• Money: a committed budget, not a feasibility fund

• Regulator: a licence or permit in hand, or a design in formal review

• Site: a named location with land secured

• Owner: a utility or state body that will operate the reactor

Romania, the Czech Republic, and Sweden are all doing serious work, but their projects sit earlier in the process than the five below. 🔍 The countries are ordered by how much hardware already exists, not by how much they spend. Which one would readers back to put an SMR on its grid first? The replies are open. 📊

The five bets

1. China: the only country with SMRs on the grid

China’s HTR-PM at Shidaowan, Shandong, pairs two 250 MWt pebble-bed reactors with one 210 MWe turbine. World Nuclear News reports that it entered commercial operation in December 2023. 🏭 SMRbrief’s breakdown of the five SMR reactor types explains why a gas-cooled pebble bed and a water-cooled design are different machines.

• HTR-PM: owned by a consortium led by China Huaneng (47.5%), with CNNC’s engineering arm at 32.5% and Tsinghua University at 20%

• Linglong One: a 125 MWe ACP100 integral PWR at Changjiang, Hainan, with first concrete poured July 13, 2021

• Status: World Nuclear News still lists Linglong One in pre-commissioning this month, so the first-half 2026 commercial target has passed

2. Canada: the furthest along in the West

Ontario Power Generation is building a 300 MWe BWRX-300, the first of four planned at Darlington. 🇨🇦 The CNSC issued the construction licence in April 2025 and lifted the first regulatory hold point on March 30, 2026.

• Budget: C$20.9 billion (about US$15 billion) for four units, approved by Ontario in May 2025

• Operating licence: OPG applied on March 25, 2026, and the hearing date is not yet set

• Target: first unit complete by the end of the decade

3. United Kingdom: a contract before a design approval

Great British Energy - Nuclear and Rolls-Royce SMR signed a contract on April 13, 2026 for three reactors at Wylfa on Anglesey, Wales, totaling at least 1,400 MW. 🏴 The design is a 470 MWe PWR.

• Regulator: the Office for Nuclear Regulation lists the design in Step 3 of the Generic Design Assessment, and that step covers the design, not the Wylfa site

• Money: £2.5 billion allocated to GBE-N for the program, with a final investment decision expected in 2029

• Early works: GBE-N is now testing the market for £1.1 billion of Wylfa site work

• Export: Rolls-Royce SMR also lists up to six units in the Czech Republic

4. Poland: the biggest fleet on paper

Orlen Synthos Green Energy holds decisions-in-principle for up to 24 BWRX-300 reactors at six sites. 🇵🇱 GE Vernova Hitachi and OSGE signed the Polish generic design agreement on February 24, 2026, and the first unit at Włocławek is targeted for 2032.

• Ownership: a 50/50 joint venture between state-controlled Orlen and SGE

• Subsidy: OSGE applied in June 2026 for a contract for difference covering 14 units

• Caution: Orlen’s own 2025 statement aimed for at least two units, 0.6 GW, by 2035, which is a slower pace than the 2032 date

5. United States: the most projects, the least concentration

The US has no single national program. It has several parallel ones. 🚀 TerraPower started nuclear construction on the 345 MWe Natrium sodium-cooled fast reactor at Kemmerer, Wyoming on April 23, 2026, after the NRC voted the construction permit on March 4.

• TVA: NRC staff recommended a construction permit for the BWRX-300 at Clinch River in June, and a decision is close

• X-energy: four 80 MWe Xe-100 modules at Dow’s Seadrift site, with the permit expected in the first quarter of 2027

• DOE pilots: four DOE-authorized test reactors reached criticality by July 4, though all are zero-power units, not power plants

Where the bets can fail

Schedules are the first weak point. Linglong One misses its first-half 2026 date. The UK design assessment, expected to end in August 2026 as of last November, now points to December 2026. ⏳ Poland’s 2032 target sits next to a slower 2035 statement from its own lead partner. Every one of these dates is a forecast, not a fact.

Cost is the second. Divide Ontario’s US$15 billion by 1,200 MWe and the result is about US$12,500 per kilowatt, with shared infrastructure included. That is the number every other government is implicitly betting it can beat. 💰 Want to know how this fits into the broader market picture? SMRbrief Pro has the answers. The gap between the first unit and the fourth is where these programs will be judged.

The third is plain first-of-a-kind risk. Only China has run a small reactor long enough to produce operating data at commercial scale. 📈 Everyone else is still building the first.

• Schedule: licence steps and commissioning dates keep moving

• Cost: first units carry the price of learning

• Delivery: a design approval is not a running plant

If the first Western SMR to sell power lands in Ontario in 2030 at $12,500 per kilowatt, do Poland and the UK still buy?

InvestmentsGE Vernova booked $0.6 billion in net income in the second quarter of 2026. NuScale Power booked $75,000 in revenue. Both are in this race, and that gap is most of the story. ⚡ No publicly traded company earns a profit from an operating SMR today, because no Western SMR operates. The real contest is which of the five below first sells power or heat above its cost, and which one has the cash to last until then. 💰 All figures come from second-quarter 2026 filings and earnings releases unless noted.

What profitable means when nothing runs yet

A reactor company earns a profit when three things line up. Each one is a gate, and each company below sits at a different one. 🔍

• License: an NRC construction permit in hand, then an operating license

• Fuel: HALEU or standard low-enriched uranium under contract

• Price: a customer paying enough for power or heat to cover the capital bill

The price gate is the hard one. Lazard’s 2026 report, summarized by Utility Dive, puts new-build nuclear at $175 to $255 per MWh unsubsidized, against $40 to $98 for utility-scale solar. ⚖️ That is nuclear in general, not an SMR-specific number, but no SMR developer has published a price that closes the gap. So the first profitable SMR probably sells to a buyer that values firm power: a data center, a chemical plant, a utility with a coal retirement. Which matters more to a shareholder in this sector, a signed customer or a cash cushion? Readers are welcome to argue it out in the replies. 📊

The five contenders

1. GE Vernova (NYSE: GEV): the only profitable one

GE Vernova’s second-quarter release reports $11.1 billion in revenue, $0.6 billion in net income, a $176 billion backlog and $13.1 billion in cash. Those numbers come from Power and Electrification, not reactors. 🏭 The SMR is a side bet inside a very large business.

• Reactor: BWRX-300, a 300 MWe boiling water reactor built with Hitachi

• Canada: OPG holds a CNSC construction licence for the first of four units at Darlington, a C$20.9 billion program, and applied for an operating licence on March 25, 2026

• United States: NRC staff recommended a construction permit for TVA’s Clinch River unit in June, and Blue Energy filed the first part of its Texas application on September 16

GE Vernova wins on staying power. A slow SMR year costs it little.

2. NuScale Power (NYSE: SMR): certified, but customer-less

NuScale is the only company with an NRC-approved SMR design, the 77 MWe VOYGR module, in plants of up to 12 modules. ⚛️ Its second-quarter results show revenue of $75,000, a net loss of $47.5 million and $1.9 billion in liquidity.

• Cash burn: $372.9 million used in operations in the first half, including a $259.9 million payment to ENTRA1, per the 10-Q

• TVA: ENTRA1 is still negotiating a power purchase agreement for up to 6 GW, and the collaboration agreement is nonbinding

• Romania: six modules at Doicesti, pending conditions attached to the Nuclearelectrica shareholder vote

Design approval is a license, not a customer. NuScale has the first and is still hunting the second. 📉

3. X-energy (Nasdaq: XE): revenue with a federal sponsor

X-energy went public on April 24, 2026 and raised about $1.1 billion net. Its second-quarter release shows $54.6 million in revenue and grant income, up 154%, a $110.0 million operating loss and $1,899.8 million in liquidity with no debt. 🚀 Most of that revenue is DOE-funded design work on the Xe-100, not power sales.

• Reactor: Xe-100, an 80 MWe high-temperature gas-cooled unit (SMRbrief’s breakdown of the five SMR reactor types covers how it differs from water designs)

• Project: four modules, 320 MWe, for Dow at Seadrift, Texas, under a 50/50 ARDP cost share

• Timeline: the 10-Q expects the NRC construction permit in the first quarter of 2027 and first commercial delivery in the early 2030s

4. Oklo (NYSE: OKLO): the biggest cash pile and a 2028 date

Oklo ends the quarter with $3.0 billion in cash and marketable securities, including $1.9 billion raised through at-the-market programs in 2026. Its year-to-date net loss is $81.6 million, softened by $44.5 million of interest income. 🔋 Second-quarter revenue is about $1.2 million, all from services.

• Reactor: Aurora, a liquid-metal fast reactor in the 15 to 100 MWe class

• Aurora-INL: DOE approved the preliminary documented safety analysis, and startup remains targeted for 2028

• Spending: 2026 operating cash use guidance rises to $120 million to $150 million, with capex of $400 million to $500 million

• Other assets: the Groves isotope reactor in Texas reached first criticality in early August, and a 1.2 GW Ohio campus for Meta is in development

The first Oklo revenue from a reactor-made product is likely to be isotopes in early 2027, not electricity in 2028.

5. NANO Nuclear Energy (Nasdaq: NNE): smallest reactor, longest road

NANO’s KRONOS MMR is a 15 MWe (45 MWt) high-temperature gas-cooled microreactor with molten salt storage. The NRC accepted the University of Illinois construction permit application on May 18, 2026, and the company expects the review to finish in 2027. 🎓

• Cash: $568.7 million as of March 31, 2026, plus an effective $900 million shelf that includes a $400 million ATM program (that is the latest figure found, so it may be stale)

• Customers: MOUs with Supermicro and others, but no binding power contract in the sources reviewed

• First unit: a research reactor, which is not a profit engine

Who gets there first

The order depends on which profit is meant. GE Vernova probably gets there first, but as a vendor. It sells reactors to OPG and TVA, and equipment margin arrives years before power revenue does. 🏁 Among the pure plays, Oklo has the most cash and the earliest date, though that date is a demonstration reactor. Timelines as filed:

• GE Vernova: Darlington unit 1 by the end of the decade, with OPG selling the power

• Oklo: Aurora-INL startup targeted for 2028

• X-energy: first commercial delivery in the early 2030s

• NuScale: no firm order until a TVA agreement is signed

• NANO Nuclear: research reactor construction targeted for mid-to-late 2027

Everything we report on ends up structured, sourced, and searchable in SMRbrief Pro, which is where the filing-by-filing detail behind this list lives. The next dates to watch are the NRC decision on Clinch River, the Long Mott safety evaluation due in November 2026, and any binding TVA power purchase agreement. 📅

If a portfolio manager had to pick one, does the profitable company with a side bet beat the one with $3.0 billion in cash and a 2028 date?

At 3 AM, a solar farm delivers 0 MW. ☀️ That is physics, not a knock on solar, but it frames the whole argument about clean power. The real test of a grid is the dead hours, when demand is low but never zero and hospitals, subway pumps, and server halls all keep drawing.

In the United States, that hour runs on nuclear, gas, wind, hydro, and a fast-growing battery fleet. Small modular reactors are not on that list yet. 🔌 The first BWRX-300 in Ontario and the first Natrium plant in Wyoming are under construction, with first power targeted around 2030. This article scores solar, wind, and SMRs on the one metric that counts at 3 AM: megawatts delivered when nobody is watching.

Capacity factors expose the 3 AM problem

Capacity factor is the share of a plant’s maximum output that it actually delivers over a year. EIA’s 2025 figures, compiled in a SUN DAY Campaign review of EIA data, are blunt:

• Nuclear: 91.0%

• Natural gas: 58.4%

• Wind: 34.2%

• Utility-scale solar PV: 24.4%

Those are annual averages, so they smooth over the daily shape of output. Solar’s 24.4% works out to roughly 12 hours of usable power and 12 hours of nothing. 🌙 Nuclear’s 91.0% is close to flat around the clock, which is why engineers call it baseload. Developers design SMRs for the same steady output. No Western SMR has logged a full year of operating data yet, so for now that number is a design target and not a track record. ⚛️

Batteries narrow the gap, then run out of hours

Batteries are the strongest rebuttal to the 3 AM argument, and the numbers are not small. 🔋 Amperon’s mid-2026 comparison of ERCOT and CAISO shows how fast the fleets grew:

• ERCOT (Texas): 20,948 MW of batteries, about 23% of the record 91,089 MW peak set in July 2026

• CAISO (California): 17,023 MW, about 33% of system peak

• CAISO average duration: roughly 3.8 hours at the end of 2025, per Modo Energy

• ERCOT merchant default: two hours, according to the same Modo analysis

The catch is duration. A four-hour battery that starts discharging at 7 PM is empty by 11 PM, four hours before the 3 AM test begins. GridStatus data shows CAISO storage discharging from dusk to dawn on average in April, but the same analysis credits mild temperatures and muted demand. A cold, still January night is a different exam. 🥶

Wind is supposed to cover that night, and often does. Sometimes it does not. During a Dunkelflaute in early November 2024, Clean Energy Wire reports renewables supplied 30% of German public electricity from November 4 to 10, while fossil fuels covered the other 70%. 🌬️ Germany’s weather service counts about two cases a year when combined wind and solar output falls below 10% of nominal for 48 hours. That is 2024 data, but the pattern is seasonal and old, not a fluke. Grid operators reading this are welcome to say in the replies whether four hours of storage is enough where they work.

Where the SMRs actually stand

Only two SMR fleets run commercially today, in Russia and China. Every Western project is still a construction site or a permit file. 🏗️ The status of the four that matter, as of September 20, 2026:

• OPG Darlington, Ontario: GE Vernova Hitachi’s 300 MWe BWRX-300, first of four planned units. The CNSC issued the construction licence in April 2025, lifted the first regulatory hold point on March 30, 2026, and received OPG’s operating licence application on March 25, 2026. The four-unit budget is C$20.9 billion, and the first unit is scheduled by the end of the decade.

• TerraPower Kemmerer, Wyoming: A 345 MWe sodium-cooled fast reactor with molten salt storage that lifts output to 500 MW. The NRC voted the construction permit on March 4, and TerraPower started nuclear construction on April 23, 2026.

• X-energy and Dow, Seadrift, Texas: Four 80 MWe Xe-100 modules, 320 MWe total. The NRC finished its environmental assessment in May, and X-energy’s 10-Q filing expects the construction permit in the first quarter of 2027 and first commercial delivery in the early 2030s.

• CNNC Linglong One, Hainan: The 125 MWe ACP100. Construction started in July 2021, and World Nuclear News still lists it in pre-commissioning this month, so the first-half 2026 commercial target has passed.

Natrium is the most relevant design for a 3 AM debate. Its molten salt tank does inside the plant what batteries do for solar, letting output rise for the evening ramp. 📅 Every project, deal, company, and regulatory event we cover is logged, verified, and searchable in SMRbrief Pro. For readers new to why sodium, gas, salt, and water reactors behave so differently, SMRbrief’s breakdown of the five SMR reactor types covers the differences.

The price of certainty

Lazard’s 2026 report, summarized by Utility Dive, puts unsubsidized costs like this: 💰

• Utility-scale solar: $40 to $98 per MWh

• Onshore wind: $37 to $99 per MWh

• Nuclear (new-build, not SMR-specific): $175 to $255 per MWh

That gap is real, and it is wide. Lazard also runs a firming analysis that adds storage equal to 50% of solar or wind capacity, four hours long. Four hours, again, does not reach 3 AM. 📉

The nuclear side has its own uncomfortable arithmetic. WNN puts Darlington’s four units at US$15 billion for 1,200 MWe, which divides out to about $12,500 per kilowatt, shared infrastructure included. Natrium’s reported cost of up to $4 billion for 345 MWe is roughly $11,600 per kilowatt. Neither number looks like the cheap, factory-built promise, and that deserves skepticism. Which figure should a city council weigh more, the $40 low end for solar or the 91.0% capacity factor for nuclear? Readers can make their case in the comments. ⚖️

The 3 AM verdict

Today, in North America, solar reaches 3 AM only through batteries, wind reaches it when the weather cooperates, and SMRs do not reach it at all. The steady overnight supply comes from existing large reactors, gas, hydro, and storage. ✅ Around 2030, if schedules hold, Darlington and Kemmerer add 645 MW of firm, round-the-clock capacity. That is meaningful for a region, but small next to the batteries already on the grid.

The honest reading is that the three are not rivals so much as different shifts. Solar and wind are the cheapest daytime energy, batteries cover the evening, and SMRs are the bet on the hours after that. 🌃 Four dates decide how good that bet looks:

• The CNSC hearing on Darlington’s operating licence, date to be announced

• The NRC’s final safety evaluation for Long Mott, targeted for November 2026

• Linglong One’s first criticality and grid connection

• Kemmerer construction progress toward its 2030 completion date

If the 3 AM test is the standard, which of these three would a city planner still be comfortable betting on in 2031? 🔭

RegulationConcernsGetting an NRC design certification used to be the finish line for a reactor company. Now it’s barely the starting gun. 🏗️ NuScale learned that the hard way when its Carbon Free Power Project collapsed in November 2023 despite being the only US-certified SMR design on the market. Certification didn’t save it. Cost did. Five real obstacles stand between today’s SMR industry and the fleet-scale future everyone keeps promising, and the companies actually solving them are worth naming specifically, not vaguely praised.

First-of-a-kind costs that eat the business case

The NuScale/UAMPS story is the industry’s cautionary tale, and it’s worth getting the numbers right. The Carbon Free Power Project started in 2021 with a target price of $58/MWh and a $5.3 billion construction estimate for six 77-MWe modules. By 2023, that had climbed to $89/MWh and $9.3 billion, roughly $20,000 per kilowatt, which put it in the same range as the very large reactor projects SMRs were supposed to undercut. 💸 Utah Associated Municipal Power Systems, a coalition of 50-plus small municipal utilities, couldn’t get enough of its members to sign subscriptions at the new price, and the project died.

• 2021 estimate: $58/MWh, $5.3 billion total

• 2023 estimate: $89/MWh, $9.3 billion total

• DOE had committed up to $1.4 billion in cost-share funding

• Industry estimates suggest 5 to 7 deployed units before costs reach Nth-of-a-kind territory

The lesson the rest of the industry took from this, correctly I think, is that customer structure matters as much as the reactor design. Meta has committed up to 6.6 GW across TerraPower, Oklo, Vistra, and Constellation. Google locked in 500 MW from Kairos Power. Amazon put $700 million into X-energy. These are companies that can absorb a first-of-a-kind cost overrun without a subscription vote, and SMR Intel’s own analysis of the NuScale collapse is blunt about why that structural difference matters more than any single technical achievement. On the government side, the DOE Loan Programs Office has kept working its Title 17 financing muscle, disbursing part of a $1.52 billion conditional guarantee toward restarting the Palisades plant in Michigan, alongside a re-announced Gen III+ SMR program offering $800 million for up to two projects.

Have you noticed how every surviving SMR deal now leads with the name of a deep-pocketed anchor customer before it mentions the reactor design? That’s not a coincidence. It’s the whole industry adjusting to what NuScale taught it.

Fuel that barely exists yet

Most advanced reactor designs run on HALEU, uranium enriched between 5% and 20%, and until recently the only commercial supplier at scale was Russia’s Tenex, which the US banned in May 2024. ⚛️ That left a real supply gap. Centrus Energy has been racing to close it at its Piketon, Ohio facility, producing more than 920 kilograms of HALEU from a demonstration cascade between October 2023 and mid-2025. In January 2026, the Department of Energy signed Centrus to a $900 million task order to move from demonstration to commercial-scale production, part of a broader $2.7 billion, ten-year DOE commitment to expand domestic enrichment.

• Centrus completed its final demonstration-contract HALEU delivery in mid-2026

• Oklo and Centrus announced a planned joint venture in March 2026 to secure Oklo’s own supply

• Radiant signed a direct HALEU purchase contract with Centrus for its Kaleidos microreactors, including prepayments to help fund new enrichment capacity

Radiant’s chief nuclear officer, Rita Baranwal, put the company’s logic simply: fuel gets built in parallel with the reactor, not after it. That’s a small sentence carrying a big strategic shift. Companies used to treat fuel availability as someone else’s problem. Now it’s a line item in the reactor development budget itself. 🔬

A workforce old enough to retire before the reactors are built

This challenge gets less attention than cost or fuel, and it probably shouldn’t. Roughly 40% of the existing nuclear workforce is expected to retire within the next decade, and the broader US construction and manufacturing sector was short about 600,000 workers as of April 2025, a gap that’s pushed craft wages up 20% since the pandemic. 👷 Nuclear engineering enrollment fell about 25% between 2012 and 2022 before finally reversing. That’s not a great pipeline to be counting on right as a dozen companies try to build first-of-a-kind reactors simultaneously.

• NEI launched NuclearWorks, a career-matching site aimed at students and career-changers

• Purdue launched an SMR-focused Nuclear Engineering Professional Credentials program in spring 2026, built as stackable modules rather than a full degree

• The University of Michigan reports undergraduate nuclear enrollment up 25% over five years

• DOE’s Savannah River Site apprenticeship program now spans 27 occupations

If you’re tracking the nuclear market professionally, SMRbrief Pro turns the nuclear intelligence in this article into a searchable, filterable, always-updated resource you can act on, which is genuinely useful when workforce announcements like these show up scattered across a dozen unrelated press releases. The honest read here is that credential programs and apprenticeships are the right long-cycle answer, but they won’t fully close a gap this size before 2030. Anyone promising otherwise is selling something.

A licensing process built for gigawatt plants, not shipping containers

The NRC’s traditional licensing pathways were designed around single, site-specific gigawatt-scale plants reviewed one at a time, which makes sense for Vogtle and makes no sense for a company trying to deploy fifteen identical 1-MWe units. 📜 The agency has been rewriting its own rulebook to catch up. Part 53, a technology-inclusive framework for advanced reactors, took effect in April 2026. Weeks later, the NRC proposed Part 57 specifically for microreactors of roughly 100 MWe or smaller, which would allow fleet-wide approval of identical designs and fuel loading at the manufacturing facility rather than only on-site.

• Part 53: technology-inclusive framework, effective April 29, 2026

• Part 57: proposed April 24, 2026, targets fleet licensing for microreactors

• Both trace back to the 2024 ADVANCE Act, which directed the NRC to speed up reviews and cut fees

• The Federal Register notice describes a goal of issuing operator licenses within six months to a year of application

This is genuinely the most encouraging fix on this list, but it’s still a proposal working through public comment, not a finished tool anyone has used yet. I’d watch the final rule closely before assuming it delivers the speed the industry is promising investors.

Nowhere permanent to put the waste

The United States still has no operating permanent repository for spent nuclear fuel. Yucca Mountain stalled in 2008, and consolidated interim storage keeps getting tied up in litigation. ♻️ Every new SMR built adds to a waste stockpile with no fixed final destination, which is a real problem even though the volumes involved are modest and, according to Argonne National Laboratory research, roughly comparable per unit of energy to a conventional reactor.

Deep Isolation is one of the more concrete answers taking shape. The company launched a full-scale, at-depth deep borehole demonstration program in January 2026 at a facility near Cameron, Texas, working with Halliburton, Amentum, and NAC International, using directional drilling technology borrowed straight from the oil and gas industry to place waste more than a thousand meters underground. In March 2026, Deep Isolation and Oklo published joint results suggesting the same borehole approach could handle waste from recycled advanced-reactor fuel specifically, not just legacy spent fuel.

• No permanent US repository exists as of 2026

• Deep Isolation’s Cameron, Texas demonstration launched January 2026

• The company also holds an ARPA-E SCALEUP award to field-test its Universal Canister System

• Finland’s Onkalo repository, opening this year, remains the only operational example worldwide

None of these five problems gets solved by a single company or a single piece of legislation. What’s changed is that each one now has a named entity actually working the problem instead of a slide with the word “someday” on it. Which of these five bottlenecks do you think breaks first, the fuel supply, the workforce, or the waste question?

Global RaceInvestmentsNobody wakes up one morning to find a reactor in their backyard. Site selection for small modular reactors follows a predictable trail of breadcrumbs: a retiring coal plant, a statehouse bill, a hyperscaler’s power purchase agreement, a permit application quietly working through the NRC’s docket. ⚡ If you’ve noticed two or three of these things happening near you in the last year, that’s not a coincidence. Here are seven concrete signals worth watching, with the specific projects and dollar figures behind each one.

A coal plant nearby is on its way out

This is the single strongest predictor. The Department of Energy identified 157 retired and 237 operating coal plant sites as candidates for a coal-to-nuclear transition, and found that 80% of them are good fits for reactors smaller than gigawatt scale. 🏭 The math is straightforward: reusing transmission lines, switchyards, cooling infrastructure, and even the office buildings can cut construction costs by 15% to 35%, according to the same DOE-sponsored study run by Argonne, Idaho National Laboratory, and Oak Ridge. PacifiCorp already acted on this logic. After evaluating four brownfield sites as part of its plan to shrink its coal fleet by two-thirds by 2030, the utility picked a location next to its retiring Naughton plant in Kemmerer, Wyoming, for TerraPower’s sodium-cooled Natrium reactor with molten salt storage.

• Regional emissions can fall by up to 86% when a coal plant is replaced by nuclear of similar size

• A converted site can add more than 650 permanent jobs

• Estimated annual economic activity gain: $275 million per converted site

• Local county tax revenue can rise by roughly 92%

Is there a coal plant near you with a retirement date already on the books? That date is doing more to determine your region’s nuclear future than most public hearings ever will. 🌱

Your statehouse just created a nuclear office or incentive fund

Legislatures move slowly until suddenly they don’t. Texas enacted HB 14 in June 2025, creating the Texas Advanced Nuclear Energy Office (TANEO) to give the state a dedicated point of contact for developers, building on a 2023 working group Gov. Greg Abbott ordered through the Public Utility Commission. 📜 Kentucky authorized up to $75 million in grants covering permitting, licensing, and project development, one of the more aggressive early-stage support programs any state has put on the table. Virginia’s State Corporation Commission approved up to $122 million in cost recovery for Appalachian Power to pursue site evaluation and SMR development, part of a five-year plan from the Virginia Nuclear Energy Consortium running through 2029. Utah’s legislature has spent two straight sessions building what officials there call a “permissive environment,” and Gov. Spencer Cox has been signing regional partnerships to match.

• Texas: TANEO plus a dedicated Advanced Nuclear Energy Office

• Kentucky: $75 million in permitting and licensing grants

• Virginia: $122 million approved for Appalachian Power’s site work

• Utah: two legislative sessions of nuclear-specific statute building

A hyperscaler is quietly locking up power in your service territory

AI data centers need power that doesn’t blink, and Big Tech has stopped pretending otherwise. 🚀 Google signed a master development agreement with Kairos Power in October 2024 for 500 MW across multiple reactors, with the first online by 2030. Amazon put $700 million into X-energy for up to 12 Xe-100 high-temperature gas reactors alongside a data center campus near the Susquehanna nuclear plant in Pennsylvania. Meta has committed to as much as 6.6 GW spread across TerraPower’s Natrium design, Oklo’s Aurora, Vistra, and Constellation. Microsoft locked in 835 MW through a $16 billion, 20-year power purchase agreement to restart Three Mile Island Unit 1, now renamed the Crane Clean Energy Center, targeted for 2027. As of this year, tracking by SMR Intel puts the combined hyperscaler commitment at roughly 9.8 GW across 13 announced deals. If a hyperscaler’s real estate team has been quietly touring substations in your county, that’s not idle curiosity.

You’re sitting on an NRC-banked site inching toward construction

TVA’s Clinch River site near Oak Ridge, Tennessee, holds the nation’s only early site permit issued specifically for SMRs, a 935-acre parcel approved for up to 800 MWe. TVA converted that early groundwork into a real construction permit application for a single BWRX-300 unit, built by GE Vernova Hitachi Nuclear Energy, and the NRC accepted the application for formal review in mid-2025. 🔬 In a safety evaluation report published in June 2026, NRC staff recommended the commission actually issue the permit, a real milestone rather than another study. A banked site like this compresses years off a project’s front end, since the environmental review and site-suitability work are already done. It’s worth remembering that TVA has no obligation to actually build anything just because it holds the permit, so a banked site is a strong signal, not a guarantee.

• Site: 935 acres, Roane County, Tennessee

• Permit type: early site permit, up to 800 MWe combined

• Reactor selected: single-unit BWRX-300, 300 MWe / 870 MWt

• Status: construction permit recommended by NRC staff, June 2026

A university or national lab nearby already runs test reactors

Reactor clusters don’t spring up in a vacuum. They form around institutions that already have a nuclear engineering program, a research reactor, or federal test infrastructure. Texas A&M University in College Station already operates a research reactor and announced plans to add up to four new SMRs to a 2,400-acre innovation campus called RELLIS, where Kairos Power, Natura Resources, Terrestrial Energy, and Aalo Atomics are all pitching designs. 🎓 Natura Resources separately plans a molten salt research reactor at Abilene Christian University’s NEXT Lab. At Idaho National Laboratory, the retrofitted EBR-II containment building known as DOME is testing reactor prototypes from Westinghouse, Radiant, and Ultra Safe Nuclear starting this year. None of this activity means a commercial reactor lands next door automatically, but it does mean the regulatory relationships, trained workforce, and testing infrastructure already exist locally, and developers notice that.

Neighboring states are forming nuclear compacts and workforce pipelines

Watch what governors sign, not just what legislatures pass. Idaho, Utah, and Wyoming signed a memorandum of understanding to collaborate on nuclear innovation and workforce training. The New York Power Authority signed its own MOU with Ontario Power Generation covering cross-border workforce development. Illinois’s governor directed the Illinois Power Agency and Illinois Commerce Commission to explore funding a dedicated nuclear training academy. 🤝 These agreements sound bureaucratic, sure, but they’re usually the precursor to something concrete: shared apprenticeship programs, cross-licensed technicians, and supply chains that span state lines. If you’re tracking the nuclear market professionally, SMRbrief Pro gives you the structured database to go deeper than any single article can, especially when these compacts start converting into actual site announcements months later.

Your utility’s IRP or PUC docket already says the word “nuclear”

The most boring-sounding signal is often the most reliable one. Integrated resource plans and public utility commission dockets are where real capital decisions get made, long before a press release goes out. Appalachian Power’s approved cost recovery in Virginia came directly out of a regulatory filing, not a marketing campaign. PacifiCorp’s Naughton-to-Natrium pivot in Wyoming traces straight back to its own IRP process. Texas’s PUC-convened working group spent over a year studying market rule changes before its November 2024 report reached lawmakers, and that report is what produced HB 14 seven months later. 💡 If your local utility has quietly added a line item for “advanced nuclear feasibility study” in its latest rate case, that line item usually shows up two or three years before a shovel does.

• Docket activity to watch: site evaluation cost recovery requests

• IRP language: any mention of “firm, dispatchable, carbon-free” capacity additions

• Public comment periods: often the first place a specific reactor vendor gets named

• Timeline: expect 2 to 4 years between docket mention and site announcement

None of these seven signs guarantees a reactor breaks ground in your county. Reactor projects miss deadlines constantly, and plenty of these signals fizzle before they turn into steel and concrete. But regions rarely get picked cold. Which of these seven boxes has your region already checked, and which one would actually move the needle?

BasicsGridEielson Air Force Base burns through as much as 800 tons of coal a day just to keep the lights on in interior Alaska. That single fact explains why the Pentagon, a handful of Canadian utilities, and a growing list of nuclear startups have all landed on the same idea at roughly the same time: if you can shrink a reactor down to the size of a shipping container, you can solve an energy problem that solar panels and diesel trucks never really could. ❄️ Remote bases and remote communities share the same headache. They sit at the end of a fuel supply chain that’s expensive, vulnerable, and occasionally just doesn’t show up. Here are five concrete ways small modular reactors and their smaller cousins, microreactors, are being aimed at that problem right now.

Fixed nuclear batteries at forward operating bases

Oklo is building the clearest example of this model at Eielson Air Force Base, where the Defense Logistics Agency reissued a Notice of Intent to Award in June 2025 after a 2023 pause tied to acquisition rule questions. Under the deal, Oklo would design, build, own, and operate an Aurora powerhouse delivering up to 5 MWe of electricity plus heat under a 30-year, fixed-price power purchase agreement, supplementing (not replacing, at least at first) the base’s aging coal plant. 🔋 The Aurora is a liquid sodium-cooled fast reactor descended from the old Experimental Breeder Reactor-II, fueled by recycled HALEU. The Air Force has been explicit about why Eielson matters as a template: World Nuclear News reported that officials see the pilot shaping how the Pentagon powers Arctic infrastructure more broadly. Worth noting: this timeline has already slipped once, and first-of-a-kind reactor projects rarely arrive exactly on schedule, so treat any 2027 completion date with a healthy dose of skepticism.

• Reactor: Oklo Aurora, liquid metal-cooled fast reactor

• Capacity: up to 5 MWe plus heat

• Structure: 30-year fixed-price PPA, commercially owned and operated

• Regulator: U.S. Nuclear Regulatory Commission

Would you trust a startup that’s never operated a commercial reactor to keep your base’s power on through an Arctic winter? The Air Force apparently would, twice over.

The Army’s fleet strategy for stateside bases

This is the biggest bet on the table so far. The Army’s Janus Program committed up to $2.2 billion across five vendors and five installations on August 26, and it’s explicitly designed as a fleet play, not a one-off demo. 🛡️ Antares Nuclear got Fort Bragg, North Carolina, with its 100 kWe-to-1 MWe R1 reactor deployed in three-unit clusters. BWXT Advanced Technologies landed Fort Campbell, Kentucky, targeting a 20 MWe version of its BANR design with construction starting in late 2028. General Atomics Electromagnetic Systems took Fort Hood, Texas. Westinghouse Government Services got Fort Drum, New York. And Radiant Industries disclosed the largest single commitment, up to $750 million to deploy 15 factory-built, 1 MWe Kaleidos microreactors by 2030, starting with a three-unit installation at Fort Benning, Georgia.

The Army says it eventually wants more than 20 reactors running across installations, with a September 30, 2028 deadline for the first unit to go live. As Army.mil detailed in its announcement, the goal is baseload power that doesn’t depend on a commercial grid a hostile actor could target. 🚀

Reactors you can ship in a box, for the places with no grid at all

Fixed-site bases are one thing. Project Pele, launched by the Pentagon’s Strategic Capabilities Office back in 2020, tackles the harder problem: powering forward or austere locations that don’t have infrastructure to plug into in the first place. BWXT won a $300 million contract in June 2022 to build a transportable, high-temperature gas-cooled reactor generating 1 to 5 MWe, fueled with TRISO particles and small enough to move in standard 20-foot shipping containers. It’s now being assembled and tested at Idaho National Laboratory’s Critical Infrastructure Test Range Complex, and the Department of Energy has said it could become one of the first advanced reactors to operate in the U.S. as early as this year.

• Design: high-temperature gas-cooled reactor, TRISO fuel

• Portability: fits inside 20-foot shipping containers, plane-transportable

• Output: 1 to 5 MWe, “always-on” without refueling for years

• Testing site: Idaho National Laboratory

The strategic logic is blunt: a mobile reactor means a forward base doesn’t need a fuel convoy at all, which is exactly the kind of vulnerability commanders have been trying to eliminate for decades. 📦

Retiring the diesel generator in the Canadian north

Head north of the border and the use case flips from military to humanitarian and economic. Canada’s remote communities typically need around 5 MWe each, while remote mines need 15 to 45 MWe, and almost all of that currently runs on trucked-in diesel. 🇨🇦 ARC Clean Energy, working through Global First Power with Ontario Power Generation and USNC, has been demonstrating a 5 MWe gas-cooled Micro Modular Reactor at Chalk River, Ontario, aiming for a 2026 start, though I’d flag that timeline as one to watch rather than bank on. Prodigy Clean Energy signed a memorandum of understanding with Des Nëdhé Group, an Indigenous economic development corporation, to explore shipyard-built Transportable Nuclear Power Plants outfitted with Westinghouse’s eVinci microreactor, a 5 MWe, 13 MWth unit designed to run roughly eight years without refueling. Meanwhile the Saskatchewan Research Council is backing its own eVinci pilot with CAD 80 million in provincial funding, targeting 2029.

Ottawa’s national nuclear strategy leans into this pattern deliberately, calling for a Canadian-designed microreactor finalized by 2035 and deployed in a remote community by the late 2030s, with the Canadian Nuclear Safety Commission handling licensing start to finish. The Pembina Institute has documented that clean energy projects, mostly renewables so far, have already displaced 140 million litres of diesel in remote Canada. Nuclear is aiming at what’s left of that gap, and Indigenous ownership stakes are shaping up to be a defining feature of how these projects actually get built, not an afterthought bolted on for optics.

The regulatory unlock making all of this possible

None of the above works at scale without a licensing process built for it, and the NRC just rewrote its rulebook twice in one year. Part 53, a technology-inclusive framework for advanced reactors, took effect April 29, 2026. Then on April 24, 2026, the NRC proposed Part 57 specifically for microreactors of roughly 100 MWe or smaller, allowing fleet-wide approval of identical reactor designs, fuel loading at the manufacturing facility, and even general licenses to construct parts of a facility before every detail is finalized. NRC Chairman Ho Nieh put it plainly: “They’re small machines, they’re simple machines.” Comments on Part 57 closed June 15, 2026, and the Federal Register notice lays out a process meant to issue operator licenses within six months to a year, a fraction of the time traditional reactors have taken.

This regulatory shift is really the connective tissue between everything above: it’s why Radiant can promise 15 units by 2030, why the NRC can even entertain fleet licensing for the Army’s five-base rollout, and why Canadian regulators are borrowing from the same playbook. Every project, deal, company, and regulatory event we cover is logged, verified, and searchable in SMRbrief Pro, which is genuinely the fastest way to track which of these forty-plus company-site pairings is actually hitting its dates versus which one is quietly slipping.

None of these five paths is a sure thing yet. Reactor projects have a long, unglamorous history of missing their first deadline, and every one of these programs is still short of commercial operation. But the direction is unmistakable: the places furthest from a power grid, whether that’s a forward operating base or a fly-in Cree community, are turning out to be where nuclear’s smallest machines get their first real test. Which of these five deployments do you think crosses the finish line first?

Global RaceData center-linked nuclear offtake agreements have grown from roughly 25 GW in late 2024 to nearly 45 GW today, and almost none of that growth came from wind or solar. The reason is simple math. ⚡ A single AI training cluster can draw as much power as a mid-sized city, hyperscaler capital spending is on track to hit $600 billion to $700 billion in 2026 alone, and solar-plus-battery still can’t guarantee power at 3 a.m. on a cloudy week. Nuclear can, and small modular reactors promise to deliver it without a decade-long permitting fight for a gigawatt-scale plant. 🔋

What’s interesting isn’t that Big Tech wants nuclear power. It’s that Google, Amazon, Meta, and Microsoft have each landed on a different answer for how to get it. Some are buying equity in reactor developers outright. Others are restarting mothballed giants while hedging with SMR options on the side. Here’s how each company is actually placing its bet. 📊

Google bets on Kairos Power for round-the-clock power

Google signed the tech industry’s first multi-reactor SMR purchase agreement in October 2024, committing to buy power from a fleet of Kairos Power small modular reactors totaling up to 500 MW, with the first unit online by 2030 and the rest following through 2035. Kairos’s KP-FHR design cools TRISO fuel pebbles with molten fluoride salt, running at low pressure instead of the high pressure a conventional reactor needs, a genuinely unusual engineering bet for a company better known for search ads. 🧪🔥

The deal stopped being theoretical in mid-2025. Kairos, Google, and the Tennessee Valley Authority struck an agreement under which Kairos’s Hermes 2 plant in Oak Ridge will feed up to 50 MW into the TVA grid serving Google data centers in Montgomery County, Tennessee, and Jackson County, Alabama, making TVA the first US utility to buy power from a Generation IV reactor. Google senior director Michael Terrell called nuclear part of the company’s effort to “commercialize a broad portfolio of advanced clean electricity technologies.” 🌍

What makes Google’s approach distinct:

• One reactor developer, one long-term relationship, rather than a scattered portfolio

• A named utility offtaker (TVA) instead of a purely behind-the-meter arrangement

• Molten salt cooling, a genuine departure from the light-water reactors most utilities already operate

• A firm 2030 first-power target, unusually specific for a first-of-a-kind design

Which strategy do you think ages better: Google’s single-partner bet or the multi-vendor approach the next three companies are running?

Amazon spreads its wager across X-energy, Energy Northwest, and Dominion

Amazon has taken the opposite approach from Google: diversify early and often. 🎯 The company holds an equity stake in X-energy and backs the deployment of more than 5 GWe of X-energy’s Xe-100 reactors across the US by 2039. The first project, called Cascade, is a four-unit, 320-MWe plant with Energy Northwest in central Washington, targeting construction by 2030, a genuinely aggressive timeline for a first-of-a-kind design. 🏗️

Amazon didn’t stop there. It signed a separate memorandum with Dominion Energy to explore a 300-MW SMR near Dominion’s existing North Anna nuclear station in Virginia, where power demand is projected to climb 85% over the next 15 years. And in June 2026, Amazon layered a 17-year, $18 billion power purchase agreement with Talen Energy on top of its existing arrangement, drawing up to 1,920 MW from Talen’s existing Susquehanna plant while the two companies explore building new SMRs within Talen’s Pennsylvania footprint. ⚙️ Every project, deal, company, and regulatory event we cover is logged, verified, and searchable in SMRbrief Pro, which is genuinely the only way to keep Amazon’s overlapping nuclear commitments straight in your head.

The logic behind Amazon’s spread-the-risk model:

• Equity in X-energy gives Amazon a seat at the table on reactor design and supply chain decisions

• Existing large reactors (Susquehanna) cover near-term load while SMRs mature

• A separate Dominion relationship hedges against any single developer’s schedule slipping

• Amazon also joined a strategic collaboration with Korea Hydro & Nuclear Power and Doosan Enerbility aimed at mobilizing up to $50 billion for Xe-100 supply chain buildout

Meta swings the biggest bat yet: 6.6 GW across three partners

Meta waited longer than its peers to make a nuclear move, then made the largest one on record. 🐘 On January 9, 2026, Meta announced agreements covering up to 6.6 GW of nuclear capacity through 2035, split across three very different partners: Vistra for output from existing operating plants, plus TerraPower and Oklo for next-generation SMR capacity. It’s the largest corporate nuclear commitment in US history, full stop. 📈

The structure is deliberately layered. Vistra’s existing reactors, including Davis-Besse in Ohio, supply power now and give Meta a reason to back license extensions that keep those plants running past 2037. TerraPower’s Natrium design, already under construction in Kemmerer, Wyoming, and Oklo’s Aurora microreactor fill in the next decade as they clear licensing. Meta paired the nuclear push with a separate May 2026 deal alongside Enbridge for 365 MW of solar and a 1,600 MWh battery in Wyoming, suggesting the company sees nuclear and storage as complements rather than either-or bets. 🔌

Why the three-partner blend matters:

• Combines firm power today (Vistra) with next-generation capacity later (TerraPower, Oklo)

• Spreads regulatory risk across two very different SMR technologies: sodium-cooled fast and Oklo’s compact fast reactor

• Sets a template other hyperscalers are likely to copy rather than negotiate from scratch

• Signals confidence that at least one of the two SMR developers clears NRC licensing on schedule

Microsoft hedges between a restarted giant and a portfolio of new reactors

Microsoft moved first, and its bet looks the most conservative on paper even though it’s anything but small. 🏢 In September 2024, Microsoft signed a 20-year power purchase agreement for the full 835 MW output of Constellation’s Three Mile Island Unit 1, since renamed the Crane Clean Energy Center. Constellation is investing $1.6 billion to bring the plant back online, now targeted for 2027, a year ahead of the original schedule. ⚛️

That restart isn’t Microsoft’s whole nuclear strategy, just its most visible piece. The company has also committed more than $1 billion toward a broader roughly 2.5 GW nuclear portfolio that includes relationships with X-energy, Dominion, and Talen, spreading its bet across an existing large reactor and a bench of SMR developers at the same time. Constellation CEO Joe Dominguez said the Crane restart puts the company “on track to make history ahead of schedule.” 🧊

The pattern in Microsoft’s approach:

• One large, low-technology-risk restart locks in firm power for the early 2030s

• A parallel SMR portfolio keeps optionality open if any single next-gen design stalls

• Pennsylvania’s PJM grid gets the near-term supply while newer designs work through licensing elsewhere

• The $1.6 billion restart cost is a known number, unlike first-of-a-kind SMR construction budgets

Four companies, four different mixes of existing reactors and unproven SMRs, and one shared bet that nuclear beats waiting on the grid. Which of these four strategies would you put your own capital behind?

ProjectsPlenty of SMR coverage is still speculative. This roundup isn’t. Every project below has a signed permit, a construction crew, or a regulator’s stamp attached to it right now, in 2026, not a hoped-for date five years out. 🏗️ Some are sodium-cooled, some run on molten salt, one is a familiar boiling-water design shrunk down and factory-built. What they share is dirt actually moving.

Pick any one of these and you’re watching a different bet on how nuclear gets built cheaper and faster. Here are the five worth tracking this year, with the numbers that actually matter. ⚛️

TerraPower’s Natrium reactor breaks ground in Kemmerer, Wyoming

TerraPower started construction on April 23, 2026, at Kemmerer Unit 1, its flagship Natrium plant in southwestern Wyoming. The design is a 345-MWe sodium-cooled fast reactor paired with a molten salt heat storage system that can push output to 500 MWe on demand, essentially letting the plant behave like a dispatchable battery. 🔋

The Nuclear Regulatory Commission issued the construction permit in early March 2026, its first approval for a commercial non-light-water reactor in more than 40 years and its first commercial reactor approval of any kind in nearly a decade. Bechtel is the engineering and construction partner, and TerraPower CEO Chris Levesque said the company is “building the next generation of America’s energy infrastructure.” The site sits next to a retiring coal plant, which is deliberate: TerraPower wants to reuse grid connections and a trained workforce rather than start from a blank field, a much cheaper first-mover strategy than it sounds. 📈⚡

What makes Kemmerer worth tracking:

• First utility-scale advanced reactor construction in the US, not a demonstration unit

• Sodium coolant runs at low pressure and high temperature, a genuine departure from light water

• Integrated molten salt storage decouples heat generation from electricity output

• Bill Gates-founded TerraPower is self-funding a large share of the project alongside Department of Energy support

Kairos Power’s Hermes goes from salt tanks to poured concrete in Oak Ridge

Kairos Power’s Hermes reactor, a 35-MWt demonstration unit cooling TRISO fuel pebbles with FLiBe, a molten mixture of lithium and beryllium fluoride salts, has moved well past paperwork. 🧪 The company has completed its first safety-related concrete pour at the Oak Ridge, Tennessee, site, anchored on 51 large-diameter piers drilled roughly 40 feet into bedrock, which is a very unglamorous way to describe a genuinely novel reactor. 🧊

Hermes received its construction permit from the NRC in December 2023, the first approval for a non-light-water reactor design in the US in decades, and the company has spent the years since proving out the technology at full scale before pouring a single yard of concrete on the actual reactor. 🔬 Its Engineering Test Unit in Albuquerque logged more than 2,000 hours of pumped salt operations, the largest FLiBe system ever built, before Hermes construction even began.

Why Hermes matters beyond Oak Ridge:

• Non-power demonstration reactor, so no grid connection risk clouds the safety case

• Near-atmospheric pressure operation means a much lighter, cheaper containment structure

• FLiBe production has its own dedicated Kairos facility in Ohio, a first for the US supply chain

• Success here directly informs Kairos’s planned commercial KP-FHR fleet

Which of these five reactors do you think has the toughest remaining hurdle: fuel supply, financing, or the regulator’s final sign-off?

OPG’s BWRX-300 lowers its first reactor foundation in Ontario

Ontario Power Generation is arguably ahead of everyone on this list. Its first GE Vernova Hitachi BWRX-300, a 300 MWe boiling-water SMR, is under construction at the Darlington site east of Toronto, and in May 2026 crews lowered the reactor’s basemat into a 35-meter-deep excavated shaft, a genuinely photogenic milestone for an industry not known for them. 🇨🇦🏗️ The Canadian Nuclear Safety Commission granted the construction license in April 2025, and OPG reached its final investment decision the following month.

This is the first-of-a-kind deployment of the BWRX-300, and OPG plans three more units at Darlington after this one, Canada’s first new nuclear build in more than 30 years. OPG chief projects officer Subo Sinnathamby, who previously led Darlington’s CANDU refurbishment, described the pace by saying the team got its construction license in April and its investment decision in May, “and we’ve been off to the races since.” The BWRX-300 has also cleared step two of its UK Generic Design Assessment, and the Tennessee Valley Authority has filed its own construction permit application for a BWRX-300 at Clinch River. 🔧

The specs that make Darlington the pace-setter:

• 300 MWe per unit, based on GE’s decades-proven boiling-water reactor lineage rather than an unproven coolant

• Four units planned at one site, testing whether a repeatable build gets cheaper each time

• Ahead-of-schedule, under-budget refurbishment track record from the same OPG team

• A design already exported into US, UK, and Polish licensing processes simultaneously

Every project, deal, company, and regulatory event we cover is logged, verified, and searchable in SMRbrief Pro, which is the fastest way to see how Darlington’s timeline stacks up against the other four projects here.

X-energy’s Xe-100 four-pack advances at Dow’s Seadrift plant in Texas

X-energy is building four Xe-100 high-temperature gas reactors, roughly 80 MWe each, at Dow’s UCC Seadrift chemical plant on the Texas Gulf Coast, the first grid-scale advanced reactor deployment at an industrial site in North America. 🏭 Dow subsidiary Long Mott Energy filed the construction permit application with the NRC in March 2025, and in May 2026 the agency completed its environmental review with a Finding of No Significant Impact, ahead of schedule, which is a genuinely rare phrase to type about a first-of-a-kind reactor project. ⚙️

The full construction permit is expected in the first quarter of 2027, with commercial operation targeted for the early 2030s. X-energy itself went public in 2026, raising roughly $1.1 billion in net proceeds on its Nasdaq debut under ticker XE, and CEO J. Clay Sell said the quarter’s results reflect “the progress we are making to commercialize advanced nuclear technology at scale.” The company also secured a Part 70 fuel fabrication license from the NRC this year, letting it manufacture its own TRISO-X fuel commercially rather than depend on outside suppliers. ⚗️

The details that separate Seadrift from a typical SMR pitch:

• Dow is eligible for 50% of the construction cost for the first four-pack, a Department of Energy risk-sharing arrangement

• The reactor supplies both electricity and industrial process steam, matching Dow’s actual plant needs

• Amazon has a parallel Xe-100 deal at Energy Northwest in Washington, part of a pipeline X-energy says could exceed 11 GWe across three customers

• Graphite supply is locked in through a new agreement with Germany’s SGL Carbon

Rolls-Royce SMR lands its first UK site at Wylfa

Rolls-Royce SMR finally has a home for its 470 MWe pressurized-water reactor. Great British Energy-Nuclear named Rolls-Royce SMR the preferred technology in June 2025, and in November 2025 the UK government confirmed Wylfa, on Anglesey in North Wales, as the site for the first three units, a combined 1.5 GW. 🇬🇧 A final investment decision is expected in 2029, with grid connection targeted for the mid-2030s, a timeline that’s honestly more aggressive than most of this list.

The design has cleared step two of its Generic Design Assessment with the Office for Nuclear Regulation, and it isn’t just a UK story. 🌍 Czech utility ČEZ selected Rolls-Royce SMR for up to 3 GW of new capacity back in October 2024 and took a 20% equity stake in the company, and in January 2026 Amentum was named delivery partner across the combined 4.5 GW UK and Czech pipeline. Roughly 90% of each plant is meant to be assembled in factory conditions before shipping to site, the core bet behind the whole modular premise. 🔩

What to watch as Wylfa moves forward:

• Site is a former Magnox nuclear plant already being decommissioned, with room for up to eight SMRs long-term

• Step three of the GDA, the most detailed technical review, is the next major regulatory gate

• The Czech and UK programs share one supply chain, so delays or wins in one country ripple into the other

• 2029’s final investment decision is the real test of whether financing keeps pace with the engineering

Five projects, four countries, three different reactor chemistries, and one shared question: which of them actually delivers first power on schedule?

BasicsSmall modular reactors spent decades as a PowerPoint slide. Nuclear engineers loved the concept. Utilities were polite about it. Then, in a tight window between 2022 and 2026, five separate problems that had blocked commercial SMRs for a generation got solved, more or less at the same time. None of them made headlines outside the trade press, but together they explain why construction is now underway in Wyoming and Tennessee, and why the industry finally has money behind it instead of just enthusiasm. This is the story of those five breakthroughs, what changed, and who forced the change. ⚛️

Each one is a different kind of engineering. Physics, regulation, chemistry, materials science, and, yes, spreadsheets. Skip any one of them and the whole stack collapses. Here’s how it came together.

Passive safety finally satisfies the regulators

For fifty years, reactor safety meant pumps, backup pumps, and diesel generators to run the backup pumps. NuScale Power’s VOYGR design broke that pattern by using convection and gravity instead of machinery. Each 77 MWe NuScale Power Module sits in a pool of water and cools itself through natural circulation, no operator action, no electricity, and no external water source required for at least 72 hours if things go wrong. It’s the kind of passive safety case regulators had never actually had to approve before. 🛡️⚙️

The US Nuclear Regulatory Commission certified the VOYGR design in 2022, making it the first SMR ever approved in the United States, and NRC staff cleared the larger 77 MWe module configuration in May 2025. That approval mattered because it proved a regulator built around large pressurized water reactors could actually bless a design that throws out the entire active-safety playbook. 💧

What passive safety actually removes from the plant:

• Emergency diesel generators and their fuel storage requirements

• Multiple redundant pump trains and the maintenance burden that comes with them

• Reliance on offsite power or operator intervention during the first three days of an event

• A large chunk of the containment and control-room complexity that drives up large-reactor costs

Have you noticed how much of the anti-nuclear argument from the 1980s rested on “what if the pumps fail”? That objection gets a lot quieter when there aren’t any pumps to fail.

A licensing rulebook built for reactors that aren’t giant

Regulation was arguably the bigger bottleneck than physics. 🏛️ The NRC’s rulebook was written for gigawatt-scale light-water plants, and every SMR developer had to argue, case by case, why their much smaller, differently cooled reactor deserved different treatment. That changed in March 2026, when the NRC finalized 10 CFR Part 53, a technology-inclusive, risk-informed framework built specifically for advanced reactors rather than shoehorned around the old one. The rule arrived more than a year ahead of the 2027 deadline Congress set in the 2019 Nuclear Energy Innovation and Modernization Act, and it followed the 2024 ADVANCE Act, which cut advanced-reactor fees and pushed the agency to move faster. 📜⚖️

The proof that the new posture works showed up in the construction permits, not just the paperwork. Kairos Power received a construction permit for its 35-MWt Hermes demonstration reactor in Oak Ridge, Tennessee, back in December 2023, the first non-light-water reactor construction approval in the US in decades. Then in March 2026 the NRC approved a construction permit for TerraPower’s Natrium plant in Kemmerer, Wyoming, its first approval for any commercial non-light-water reactor design in more than 40 years, and its first commercial reactor approval of any kind in nearly a decade.

What actually shifted at the agency:

• Reduced hourly fees for advanced-reactor applicants and pre-applicants

• A technology-inclusive licensing path instead of forcing every design into the light-water mold

• Faster review timelines, with TerraPower’s permit review compressed by roughly eight months

• New guidance for microreactors and for siting reactors on brownfield and retired fossil-fuel sites

The fuel that took a decade to catch up

You can certify the reactor and streamline the paperwork, and none of it matters if there’s no fuel. Most advanced SMR designs, including Kairos’s Hermes and X-energy’s Xe-100, run on HALEU, uranium enriched between 5% and 20%, well above the roughly 5% used in today’s commercial fleet. For years the only large-scale HALEU producers were in Russia and China, which is an awkward supply chain for a US industry the government is trying to build up. 🔬

Two things broke the logjam. First, the Department of Energy committed $2.7 billion over ten years in January 2026 to expand domestic enrichment capacity, on top of Centrus Energy’s Piketon, Ohio, facility, which had already produced more than 920 kilograms of HALEU by mid-2025. Second, and more concretely, X-energy received a Special Nuclear Material License from the NRC in February 2026 for its TX-1 facility, making it the first-ever Category II nuclear fuel facility licensed in the United States and clearing the way to commercially manufacture TRISO-X fuel, the tristructural-isotropic pebble design that encapsulates uranium in layers of graphite and silicon carbide. ⚗️

Why the fuel breakthrough matters this much:

• HALEU enables higher burnup and smaller cores, which is part of what makes an SMR small

• TRISO fuel’s ceramic coating is designed to contain fission products even at extreme temperatures

• A domestic Category II license removes a Russia- and China-shaped hole in the supply chain

• ASP Isotopes alone reports customer interest topping $30 billion for its laser-based HALEU enrichment process, a sign the demand side isn’t waiting around

If you want the fuller picture of who’s licensed what and when across every HALEU project in motion, SMRbrief Pro members can search, filter, and export the full intelligence picture behind developments like this one, which is more useful than trying to track it across a dozen NRC dockets yourself. 🧪

Coolants beyond water finally leave the lab

Light water is cheap and well understood, but it also caps how hot a reactor can run and forces heavy, high-pressure vessels. The SMR field’s answer has been to try coolants that don’t need pressure at all. Kairos Power’s Hermes reactor uses FLiBe, a molten mixture of lithium and beryllium fluoride salts, to cool a bed of TRISO fuel pebbles near atmospheric pressure, and the company has now completed the first safety-related concrete pour at its Oak Ridge site, anchored on 51 drilled piers sunk roughly 40 feet into bedrock. 🌡️

TerraPower took a different but related path. Its Natrium reactor at Kemmerer, Wyoming, pairs a 345-MWe sodium-cooled fast reactor with an integrated molten salt heat storage system that can push output as high as 500 MWe on demand, letting the plant act almost like a battery plugged into the grid. Construction officially began there on April 23, 2026, with Bechtel as the engineering and construction partner, and TerraPower CEO Chris Levesque called it the moment the industry had been “working toward for a generation.” Over in the UK, Rolls-Royce SMR’s 470 MWe pressurized-water design is working through the Office for Nuclear Regulation’s Generic Design Assessment, with roughly 90% of the plant meant to be built in factory conditions rather than poured on site. Three coolants, three regulators, one very busy decade. ❄️🏗️

A quick comparison of what’s actually under construction or under review right now:

• Hermes: 35 MWt, FLiBe molten salt coolant, TRISO pebble fuel, Oak Ridge, Tennessee

• Natrium: 345 MWe (boostable to 500 MWe), sodium-cooled fast reactor with molten salt storage, Kemmerer, Wyoming

• VOYGR: 77 MWe per module, light-water, passively safe, NRC-certified since 2022

• Rolls-Royce SMR: 470 MWe, light-water, in UK regulatory review, roughly 90% factory-built

That’s four genuinely different engineering bets running in parallel, on two continents, with three separate regulators watching. Which of these designs do you think reaches commercial operation first?

Hyperscaler cash de-risks the first-of-a-kind problem

None of the last four breakthroughs pay for themselves. A first-of-a-kind SMR plant can cost $1 billion to $3 billion, and utilities have historically been reluctant to shoulder that risk alone, which is exactly what killed NuScale’s original Idaho project when costs climbed from $3.6 billion to $9.3 billion. What changed the financing math wasn’t a new reactor at all. It was AI. 💰🔌

Data centers now need power at a scale and reliability that public grids increasingly can’t guarantee, so hyperscalers started signing long-term power purchase agreements that function as loan guarantees in disguise. Amazon signed a 1.92 GW agreement with Talen Energy, and Microsoft locked in 837 MW with Constellation Energy, part of a broader trend that has pushed data-center-linked SMR offtake agreements from roughly 25 GW in late 2024 to nearly 45 GW today. A creditworthy tech company promising to buy the power for twenty years turns a speculative reactor into a bankable asset, which is precisely the kind of revenue certainty that project financiers demand before they’ll touch a first-of-a-kind build. 📈

What the hyperscaler money actually unlocks:

• Revenue certainty that lets developers secure construction financing without waiting for a utility rate case

• A customer willing to pay a premium for round-the-clock, carbon-free power near their own facilities

• Enough deal volume that supply chains for TRISO fuel, forgings, and skilled labor can plan around real orders

• Political cover, since jobs and AI competitiveness make advanced nuclear funding an easier sell in Congress

Five breakthroughs, one narrow window, and a genuinely uncertain outcome, since cost overruns and construction delays have killed SMR projects before and could again. But for the first time, the physics, the paperwork, the fuel, the hardware, and the money are all pointing the same direction at once. Which of these five pieces would you bet on breaking first if something has to give?

ProjectsBasicsPlant Vogtle cost $36.8 billion to build two reactors. That is the number every SMR pitch deck is quietly reacting to, whether it says so or not. The traditional large-reactor model produced the most expensive power plant in human history, and the industry needed a different story to tell investors, regulators, and the public. Small modular reactors became that story. Whether they can actually deliver on it is a separate question, and a genuinely interesting one. 💡

Here is what is actually driving the “future of nuclear” label, and where the label is still ahead of the concrete. ⚛️

Traditional nuclear broke its own economics

Georgia Power’s Vogtle Units 3 and 4 were approved in 2012 at an estimated $14 billion. By the time Unit 4 entered commercial service in April 2024, the total price tag had climbed past $36.8 billion, more than double the original estimate, and both units arrived more than six years late. Westinghouse, the lead contractor, went bankrupt in 2017 partway through construction. 📉

That is not one bad project. It is the pattern. Big, bespoke, site-built reactors have run over budget and behind schedule on nearly every Western project of the last two decades, and ratepayers in Georgia are still covering the bill through monthly surcharges. SMR developers point to that record constantly, and fairly, because it is the single best argument for trying something structurally different: factory-built modules, standardized designs, and smaller individual price tags that do not sink a utility’s balance sheet if one project runs long. 🏗️

• Vogtle Units 3 and 4: $14 billion approved cost in 2012, $36.8 billion actual final cost

• Timeline: originally targeted for 2016 and 2017, actually completed in 2023 and 2024

• Contractor risk: Westinghouse bankruptcy in 2017 mid-construction

• The pitch: smaller, factory-built SMR units are supposed to cap that kind of downside risk per project

Worth sitting with: the case for SMRs is not really that nuclear got cheaper. It is that the old way of building nuclear became too financially dangerous for most utilities to attempt again.

AI data centers gave SMRs a customer with real money

Big Tech is not funding SMRs out of climate conscience alone. It is funding them because AI data centers need firm, round-the-clock power that the grid cannot supply fast enough. Across 13 tracked deals, the four major US hyperscalers have committed more than 9.8 GW of nuclear capacity to AI infrastructure as of May 2026, according to SMR Intel’s deal tracker. ⚡

Google signed the first corporate agreement to buy power from multiple SMRs, a Master Plant Development Agreement with Kairos Power for 500 MW of capacity by 2035, with the first reactor targeted for 2030. Amazon led a $700 million investment in X-energy for up to 12 Xe-100 reactors and is developing a four-unit, 320 MW project with Energy Northwest near Richland, Washington. Meta holds the largest single commitment by volume, up to 6.6 GW across agreements with TerraPower, Oklo, Vistra, and Constellation, though delivery stretches out to 2032 through 2035. 🚀

• Total hyperscaler nuclear commitment: 9.8 GW across 13 deals tracked through May 2026

• Google and Kairos Power: 500 MW KP-FHR agreement, first reactor targeted 2030

• Amazon and X-energy: $700 million investment, up to 12 SMRs planned

• Meta: up to 6.6 GW across four separate developers, the largest volume commitment of any hyperscaler

That demand is why the global SMR project pipeline reached 47 GW by the end of the first quarter of 2026, per Wood Mackenzie, with more than half of it sitting in the United States. A technology needs paying customers to become an industry, not just a good idea, and AI just handed SMRs their first real ones.

Regulators built a shortcut that only SMRs could use

Part 50 and Part 52, the NRC’s existing licensing frameworks, were written for large light-water reactors in 1956 and 1989. Every advanced design that did not fit that mold had to negotiate exemptions case by case, which is exactly why TerraPower’s Natrium reactor took years of pre-application work before it could even file for a construction permit. 🏛️

That changed on April 29, 2026, when the NRC’s new 10 CFR Part 53 framework took effect, more than a year ahead of the deadline Congress set in 2019. Part 53 is risk-informed, performance-based, and technology-inclusive by design, meaning a molten salt reactor or a sodium-cooled fast reactor no longer has to argue its way around rules built for pressurized water plants. It is optional. Developers can still use Parts 50 or 52 if that fits their design better. But for the first time, US regulators built a path with non-light-water SMRs specifically in mind, rather than forcing them to fit an old one. 🔬

• Part 50 and Part 52: original licensing frameworks, dating to 1956 and 1989, built around large LWRs

• Part 53: new optional framework, effective April 29, 2026, risk-informed and technology-inclusive

• Legislative origin: mandated by the 2019 Nuclear Energy Innovation and Modernization Act, reinforced by the 2024 ADVANCE Act

• Effect: non-light-water SMR designs can now be licensed without the exemption-heavy process older frameworks required

Britain and Canada are running their own versions of the same shift. The UK’s Generic Design Assessment and Canada’s Canadian Nuclear Safety Commission have both moved SMR-specific projects through construction licensing faster than any large reactor has managed there in decades, which tells you the regulatory bottleneck was never really about safety physics. It was about paperwork built for a different machine.

The buildout is already global, not theoretical

This is not one country making a bet. Russia’s Akademik Lomonosov has supplied power to the Arctic town of Pevek since 2020, still the only operating commercial SMR anywhere. China’s Linglong One, a 125 MWe reactor at the Changjiang site in Hainan Province, is targeting commercial operation in the first half of 2026, which would make it the world’s first land-based commercial SMR. Canada’s Ontario Power Generation is pouring concrete on a BWRX-300 unit at Darlington, the first new nuclear construction in Ontario in more than three decades. 🌍

The United Kingdom signed a firm contract in April 2026 to build three Rolls-Royce SMR units at Wylfa, backed by £2.6 billion in government funding. The United States holds the first NRC-certified SMR design, NuScale’s VOYGR, and broke ground on TerraPower’s Natrium reactor in Wyoming the same month the UK signed its Wylfa deal. Five countries, five different reactor technologies, all moving at the same time.

• Russia: only country with an operating commercial SMR since 2020

• China: closest to the next commercial milestone, targeting H1 2026

• Canada: first G7 nation with SMR construction actively underway

• UK and US: leading on funding commitments and regulatory certification, respectively

The label is still ahead of the delivery record

Here is the honest complication nobody selling an SMR wants dwelt on for too long: not one Western SMR design has actually generated commercial power yet. NuScale’s original Idaho project, the Carbon Free Power Project, collapsed in November 2023 after its target price climbed from $58 to $89 per megawatt-hour, and every cost estimate published since carries a first-of-a-kind premium that ranges from $80 to $180 per megawatt-hour, according to multiple 2026 techno-economic analyses. That is not cheap yet. It might not be cheap for a while.

The case for calling SMRs the future of nuclear rests on trajectory, not current pricing: shorter build times, smaller absolute financial exposure per project, a regulatory framework finally built for the technology, and a paying customer base that did not exist five years ago. Whether that trajectory holds depends entirely on whether Kemmerer, Darlington, and Wylfa actually finish on budget, something no Western SMR project has proven yet at scale. If you’re tracking the nuclear market professionally, SMRbrief Pro gives you the structured database to go deeper than any single article can, especially as these first-of-a-kind projects start reporting real construction numbers instead of projected ones.

So which milestone actually earns the label: the day a Western SMR connects to the grid, or the day one of them does it on budget?

Global RaceRussia has been running a small modular reactor commercially since 2020. China expects to connect its first land-based SMR to the grid before the end of 2026. Everyone else on this list is still building, financing, or licensing. That gap between operating and planning is the real story of the global SMR race right now, and it does not sort neatly along the lines most people assume. 🌍

Here are the five countries actually moving reactors from paper to steel, ranked by how far each one has gotten, not by how loud the marketing is. ⚛️

Russia: the only country with an SMR already on the grid

Rosatom’s floating plant Akademik Lomonosov has supplied power to the Arctic town of Pevek since 2020, and it remains the only operating small modular reactor on Earth. That first-mover status has not slowed the company down. Rosatom is now building a land-based follow-up: the RITM-200N, a 55 MWe pressurized water reactor adapted from the reactors that power Russia’s nuclear icebreaker fleet. 🚢

The RITM-200N project sits near Ust-Kuyga in the Republic of Sakha, also known as Yakutia, where Rostekhnadzor granted a construction license back in April 2023. Rosatom targets commissioning in 2028, and by mid-2026 the company reported preparatory work proceeding at full tilt, with worker camps and site infrastructure well underway. Russia is not stopping at home turf, either. In 2024, Rosatom signed the world’s first SMR export contract with Uzbekistan, a six-unit RITM-200N project, and it has eight RITM reactor units in production at its ZIO-Podolsk plant right now, split between icebreakers and floating power units. 📦

• Akademik Lomonosov: operating since 2020, the world’s only commercial floating nuclear plant

• Yakutia RITM-200N: 55 MWe land-based unit, licensed April 2023, commissioning targeted 2028

• Uzbekistan deal: six RITM-200N units, the first SMR export contract signed anywhere

• Baimsky Mining project: four floating power units at up to 106 MWe each, supplying an industrial mine site

Worth noting for anyone comparing notes across the industry: Rosatom’s advantage is decades of actual operating hours on small marine reactors, not paper studies. That track record is why land-based deployment moved this fast.

China: closest to the next commercial SMR anywhere in the world

China National Nuclear Corporation’s Linglong One, also called the ACP100, is a 125 MWe integrated pressurized water reactor under construction at the Changjiang site in Hainan Province. First concrete went down in July 2021, cold functional testing wrapped in late 2025, and CNNC is targeting commercial operation in the first half of 2026. That would make it the world’s first commercial land-based SMR to enter service. ⚡

Linglong One also has a paperwork distinction few designs can claim: it passed an IAEA generic reactor safety review back in 2016, the first SMR anywhere to clear that bar. Once running, CNNC expects the unit to generate enough electricity for roughly 526,000 households and cut carbon emissions by about 880,000 tons a year. That single project sits inside a much bigger buildout. In April 2025, China’s State Council approved construction of 10 new reactors across five coastal sites, a roughly ¥200 billion, or $27 billion, commitment, and China currently has close to 29 reactors under construction nationwide, nearly half the global total. 🏗️

• Linglong One (ACP100): 125 MWe, Hainan Province, commercial operation targeted H1 2026

• IAEA safety review: passed in 2016, the first SMR design to do so

• Supply chain: built almost entirely with domestic Chinese components, per CNNC technical reporting

• National buildout: roughly 29 reactors under construction across China, alongside a ¥200 billion coastal expansion approved in April 2025

Which raises the question every Western developer is quietly wrestling with: if Linglong One hits its 2026 target on a 58-month build, does that construction benchmark become the number every other country gets measured against? 📈

Canada: the first G7 country to start pouring SMR concrete

Ontario Power Generation is building the first of four planned GE Vernova Hitachi BWRX-300 reactors at its Darlington site, and it is the first new nuclear construction in Ontario in more than three decades. Each unit runs 300 MWe, with natural circulation cooling and passive safety systems built on the licensed ESBWR platform. The full four-unit project, once complete, is expected to deliver 1,200 MW and power roughly 1.2 million homes. 🔧

The Canadian Nuclear Safety Commission issued OPG a construction license for the first unit in April 2025, and the province backed the project with a CAD 20.9 billion investment approval. Progress has kept moving through 2026: OPG completed shaft excavation in March, and the CNSC lifted the project’s first regulatory hold point that same month after verifying the reactor building foundation met its commitments. OPG has also applied for a 20-year operating license, with a public hearing still to come. 🏭

• First unit: BWRX-300, 300 MWe, construction license issued April 2025 by the CNSC

• Full project: four units, 1,200 MW total, CAD 20.9 billion provincial investment approval

• Milestone: first regulatory hold point lifted March 30, 2026, following foundation verification

• Target: first unit online by the end of the decade, per OPG’s public schedule

Canada’s edge is not novelty. The BWRX-300 leans on an already-licensed reactor design, and OPG is reusing the same workforce that just finished refurbishing Darlington’s original CANDU units, ahead of schedule and CAD 150 million under budget. Execution discipline, not a new physics breakthrough, is what is actually moving dirt here.

United Kingdom: the funding and regulatory leader in Europe

Rolls-Royce SMR is the only design to reach Step 3, the final phase, of the UK’s three-step Generic Design Assessment, run jointly by the Office for Nuclear Regulation, the Environment Agency, and Natural Resources Wales. Its 470 MWe pressurized water reactor was selected as the UK government’s preferred SMR technology in June 2025, and in April 2026, Great British Energy-Nuclear signed a firm contract to build the first three units at Wylfa in North Wales. 💷

The money behind that contract is specific and public. The UK’s 2025 Spending Review allocated £2.6 billion toward the Wylfa program, and the National Wealth Fund separately committed up to £599 million to support Rolls-Royce SMR’s development. The three-unit Wylfa project is expected to deliver at least 1.4 GW of capacity, enough for roughly three million homes, and to support around 3,000 jobs at peak construction. Rolls-Royce SMR is also exporting the design: it signed a memorandum of understanding with ČEZ and the Czech government to prepare sites for up to 3 GW of capacity in Czechia. 🇬🇧

• Rolls-Royce SMR: 470 MWe PWR, the only design to reach GDA Step 3 in the UK

• Wylfa contract: three units, at least 1.4 GW combined, signed April 2026 with GBE-N

• Funding: £2.6 billion from the 2025 Spending Review plus up to £599 million from the National Wealth Fund

• Export: MoU with ČEZ for up to 3 GW of Rolls-Royce SMR capacity across Czech sites

If you’re tracking the nuclear market professionally, SMRbrief Pro gives you the structured database to go deeper than any single article can, especially once funding announcements start stacking up across multiple countries at the same pace they have this year.

United States: the deepest capital pool and the newest regulatory framework

The US holds two distinctions no other country can claim yet. NuScale Power’s VOYGR design became the first SMR design ever certified by the Nuclear Regulatory Commission, with the certification rule taking effect February 21, 2023. And TerraPower’s Natrium reactor, a 345 MWe sodium-cooled fast reactor paired with molten salt storage that can push output to 500 MWe for hours at a stretch, became the first commercial non-light-water reactor the NRC has approved for construction in more than 40 years. 🇺🇸

TerraPower received its construction permit for Kemmerer Unit 1 in Wyoming on March 4, 2026, and broke ground the following month. The project carries an estimated $4.0 billion price tag, with the Department of Energy covering $2 billion through its Advanced Reactor Demonstration Program. On the regulatory side, the NRC’s new Part 53 rule took effect April 29, 2026, creating a technology-inclusive, risk-informed licensing path built specifically for non-light-water designs like Natrium, rather than forcing every reactor through a framework written decades ago for large pressurized water plants. 🔬

• NuScale VOYGR: first NRC-certified SMR design, certification effective February 21, 2023

• TerraPower Natrium: 345 MWe baseline, 500 MWe peak, construction permit issued March 4, 2026

• Kemmerer Unit 1: $4.0 billion estimated cost, $2 billion DOE cost-share

• Regulatory shift: NRC’s Part 53 technology-inclusive rule, effective April 29, 2026

What the US has that Russia and China do not is a wall of private capital chasing data center demand, from Big Tech power purchase agreements to a wave of SMR-focused public listings. What it does not have yet is a single operating commercial SMR, or a construction timeline anywhere close to Linglong One’s. Which of these five programs actually reaches serial, repeatable deployment first: the one with the deepest pockets, or the one that has already proven it can build on schedule?

BasicsTerraPower poured its first structural concrete for Kemmerer Unit 1 on April 23, 2026, the first ground broken on a commercial non-light-water reactor in the United States in more than four decades, according to the U.S. Department of Energy. That single fact explains why the SMR-versus-traditional-nuclear question has moved from conference panels to actual capital allocation decisions. Utilities, tech companies chasing data center power, and finance ministries are all trying to work out which technology fits their timeline, their balance sheet, and their appetite for risk. ⚛️

The two categories share a fuel type and a regulator’s scrutiny. Almost nothing else lines up cleanly. Here are the five differences that actually decide whether a project moves from slide deck to poured concrete: size, build time, capital cost, safety architecture, and the regulatory path each one has to walk. 🔬

Power output sets every other number that follows

A traditional large reactor, the kind of unit Georgia Power just finished at Vogtle, generates 1,000 to 1,500 MWe per unit, per the U.S. Energy Information Administration. An SMR, by the International Atomic Energy Agency’s own definition, tops out around 300 MWe, though the label has stretched further in practice than the definition suggests. 📊

Three live projects show how much that range actually spans:

• NuScale Power’s VOYGR design: 50 MWe per module, with up to 12 modules stacked into one plant

• Rolls-Royce SMR: a 470 MWe three-loop pressurized water reactor, the largest design currently in serious regulatory review anywhere

• TerraPower’s Natrium: 345 MWe baseline output, boosted to 500 MWe for hours at a stretch using molten salt energy storage

• A conventional PWR or BWR fleet unit: 1,000+ MWe, with no ability to flex output up or down 📐

That gap is the root of everything else on this list. A smaller reactor means a smaller absolute check for any single project, even when the cost per kilowatt runs higher. It also means a smaller physical footprint and, in theory, a shorter path through licensing. Whether that theory holds up is where things get genuinely interesting.

Build time and modularity rewrite the construction playbook

A conventional nuclear plant gets built the way a cathedral gets built: on site, mostly bespoke, over roughly six to ten years, with cost overruns baked into nearly every Western project of the last two decades. SMR developers are betting on something structurally different: factory-fabricated modules, shipped to site, and assembled in a fraction of the time. 🏗️

The GLOBSEC think tank frames the advantage well. Instead of building one 1,200 MW conventional reactor, a developer could build four 300 MW SMRs, and the first one can start generating revenue while the other three are still under construction. That kind of phased commissioning is structurally impossible with a traditional single-unit plant, which has to be fully complete before it produces a single watt. ⏱️

Worth asking before backing either approach: does the organization footing the bill have the balance sheet for a single decade-long project, or does earlier revenue from a phased build matter more to the finance committee?

• Factory fabrication and quality control instead of weather-exposed, stick-built site construction

• Phased commissioning, where module one earns revenue while modules two through four are still going up

• A smaller crane, laydown yard, and peak workforce footprint on site

• A serial learning curve across repeat builds, which is the entire theory behind projected cost declines from first-of-a-kind (FOAK) to nth-of-a-kind (NOAK) units

The capital cost picture is genuinely mixed, and worth being honest about

This is the difference that gets oversimplified the most, usually in whichever direction serves the person making the pitch. The plain numbers do not cooperate with a clean story. 💰

The EIA puts the overnight capital cost of a new large light-water reactor at roughly $7,800 to $8,100 per kilowatt in 2024 dollars, per its own reporting on U.S. SMR development. SMR estimates, by contrast, are scattered: recent 2025 and 2026 analyses put first-of-a-kind units anywhere from $3,500 to $10,500 per kilowatt, depending on the design and how far along it sits on the learning curve. The International Energy Agency has even projected SMR overnight costs in the EU running around $10,000 per kW, against roughly $6,600 per kW for conventional nuclear. On a pure per-kilowatt basis, SMRs are not obviously cheaper yet, and anyone claiming otherwise is quoting a nth-of-a-kind number for a first-of-a-kind project. 📉

NuScale’s Carbon Free Power Project remains the cautionary tale everyone in the sector cites. Its target offtake price climbed from $58 to $89 per megawatt-hour before its municipal utility customers walked away in November 2023. TerraPower is trying to avoid a repeat with Kemmerer Unit 1, whose total project cost is estimated at $4.0 billion, with the Department of Energy covering $2 billion of that through its Advanced Reactor Demonstration Program. The context that makes news like this meaningful is exactly what SMRbrief Pro was built to provide.

• Large reactor overnight cost: roughly $7,800 to $8,100/kW in 2024 dollars, per the EIA

• SMR overnight cost estimates: $3,500 to $10,500/kW depending on design maturity and source

• First-of-a-kind SMR LCOE: roughly $80 to $180/MWh, against a projected $50 to $80/MWh once designs reach nth-of-a-kind production

• Kemmerer Unit 1 total project estimate: $4.0 billion, including $2 billion in DOE cost-share

Safety systems trade active machinery for passive physics

A traditional plant survives a loss-of-power event with active machinery: pumps, redundant emergency diesel generators, and layered backup power chains that utilities added after Fukushima Daiichi. Most SMR designs are trying to make that machinery unnecessary. 🛡️

The IAEA describes the shift plainly: SMR safety concepts generally rely more on passive systems and inherent characteristics, namely low power and low operating pressure, rather than active intervention. NuScale’s design leans on natural convection to cool the reactor, with no pumps, no offsite power, and no operator action required in the critical first hours of an incident. TerraPower’s Natrium takes a different route: a low-pressure sodium coolant loop, paired with a design that physically separates the nuclear island from the energy and storage island, keeping most of the plant’s systems away from anything radioactive at all. ⚡

• Passive cooling: gravity- and convection-driven, no pumps or grid power required, as in NuScale’s design

• Low operating pressure: reduces both the likelihood and the consequence of a breach compared with a pressurized 1,000+ MWe unit

• Decoupled nuclear and energy islands: TerraPower’s Natrium keeps non-nuclear systems physically separate

• Smaller core inventory: simply less total radioactive material on site to manage in a worst-case scenario

Which trade-off would readers actually take: active safety systems with sixty years of accumulated operating history, or passive systems that have barely run a handful of commercial fuel cycles?

Regulatory pathways and siting flexibility diverge by design

The U.S. Nuclear Regulatory Commission does not run one licensing track for nuclear plants; it runs several, and which SMR a developer builds decides which door it walks through. NuScale’s original design went through Part 52 design certification, the traditional light-water route, becoming the first SMR design the NRC ever certified. TerraPower’s Natrium, a sodium-cooled fast reactor, went through Part 50 instead, receiving a construction permit on March 4, 2026, the first the NRC has issued for a commercial non-light-water reactor in more than 40 years. A new, technology-inclusive Part 53 rule took effect April 29, 2026, built specifically to give non-light-water designs a risk-informed alternative path. 🏛️

Britain runs a different process entirely. The Office for Nuclear Regulation, the Environment Agency, and Natural Resources Wales jointly run a three-step Generic Design Assessment, and Rolls-Royce SMR is currently the only design to have reached Step 3, a status that followed its selection as the UK government’s preferred SMR vendor. Internationally, the IAEA continues pushing licensing harmonization so a design certified in one country does not have to restart the entire review in the next. 🌍

None of that paperwork matters if a plant cannot go where the power is actually needed. Because SMRs carry a smaller footprint and, in some cases, a smaller required emergency planning zone, they can be sited on retiring coal plants like Kemmerer, in remote communities too small for a 1,000 MWe unit, and increasingly next to the data centers driving the sharpest new demand for firm, round-the-clock electricity. 📍

• United States: Part 52 design certification for light-water SMRs, Part 50 construction permits for non-light-water designs like Natrium, and a new Part 53 technology-inclusive path live since April 2026

• United Kingdom: a three-step Generic Design Assessment run jointly by the ONR, Environment Agency, and Natural Resources Wales

• International: the IAEA works toward licensing harmonization so a certified design travels across borders without a full re-review

• Siting: retiring coal sites, remote grids, industrial clusters, and data center campuses are all now realistic SMR locations in a way they never were for a 1,000+ MWe plant

None of these five differences settles the SMR-versus-traditional argument on its own. The reactor that ultimately wins in any given market probably will not be the cheapest per kilowatt on paper. It will be the one whose owner can actually finance, build, and license it on the timeline promised to investors, regulators, and the town next door. Which of these five variables would you least want to get wrong on a first-of-a-kind project?

BasicsAsk five people how long it takes to build a small modular reactor and you’ll get five different answers, mostly because they’re each describing a different clock. There’s the licensing clock, which starts the moment a developer files paperwork with a regulator. There’s the construction clock, which starts when excavators show up. And there’s the clock most journalists actually mean when they say “build,” which runs from the day a company picks a site to the day the reactor delivers its first megawatt to the grid. Conflate those three and you get the wildly different numbers floating around right now, everything from “18 months” to “a decade.” 🕐

The good news is 2026 finally gave the industry enough real data points to stop guessing. TerraPower has a construction permit in hand. GE Vernova Hitachi has steel going into the ground at Darlington. Kairos Power just had to ask regulators for more time. Here’s what each of those actually tells you about how long this takes.

The five phases every SMR timeline goes through

Before comparing projects, it helps to know what’s actually being measured. Every SMR, regardless of reactor type or country, moves through the same broad sequence, though the length of each phase varies enormously depending on whether the design is first-of-a-kind (FOAK) or has already been proven elsewhere. ⚙️

• Pre-application engagement: developers meet informally with regulators for years before filing anything, ironing out technical questions early to avoid surprises later

• Licensing review: the formal construction permit or combined license application, reviewed against a published (but frequently missed) timeline

• Site preparation and construction: excavation, foundations, module fabrication, and the actual assembly of the reactor building

• Testing and commissioning: cold functional testing, then hot functional testing, then fuel load, each requiring separate regulatory sign-off

• Commercial operation: the date a plant actually starts delivering power under contract, not just generating heat in a test

The phase everyone underestimates is the first one. Companies like TerraPower and X-energy spent years in pre-application meetings with the NRC before ever submitting a formal permit request, and that groundwork is a big part of why their reviews moved faster than the agency’s own generic schedules predicted.

Natrium: two years from NRC docket to broken ground

TerraPower’s timeline is the cleanest data point the industry has right now, because it’s the only commercial advanced reactor to complete the full licensing-to-construction sequence in the U.S. so far. The company submitted its construction permit application for Kemmerer Unit 1 in Wyoming in March 2024. The NRC formally docketed it in May 2024, setting an initial 27-month review schedule. The review actually finished ahead of that mark: the commission approved the permit on March 4, 2026, roughly 22 months after docketing, and 11 percent under budget according to the Department of Energy’s own account. 🏗️

What happened next is the part people miss. TerraPower didn’t wait around. Official construction on the 345 MW sodium-cooled fast reactor began April 23, 2026, less than seven weeks after the permit was issued. A few numbers that anchor this project’s clock:

• 22 months: NRC review time, from docketing to construction permit

• 7 weeks: gap between permit approval and construction start

• 2030: targeted completion for a facility that could cost up to $4 billion

• Total elapsed time from Wyoming site selection (November 2021) to targeted completion sits at roughly nine years

That nine-year figure, not the 22-month licensing window, is the number worth remembering if someone asks you how long an SMR “takes.” The permit review is the fast part.

BWRX-300: eight years from reactor selection to first power

GE Vernova Hitachi’s BWRX-300 project at Ontario Power Generation’s Darlington site tells a slower, steadier story, and it’s arguably the more useful comparison because this design is a 300 MWe boiling water reactor built on already-licensed technology, not a brand-new reactor chemistry. OPG selected the BWRX-300 in December 2021. It applied for a construction license in October 2022. The Canadian Nuclear Safety Commission didn’t grant that license until April 4, 2025, roughly 30 months later, following a two-part public hearing process. Construction actually began in May 2025. 🇨🇦

The current projection has the first unit’s construction wrapping up in late 2029, with commercial operation following in 2030, according to GE Vernova. That means:

• ~30 months: CNSC licensing review, application to license

• ~4.5 years: construction license to commercial operation

• ~9 years total: reactor technology selection (2021) to commercial operation (2030)

• 1.2 GW: total planned capacity once all four Darlington units are running, with units two through four expected online between 2034 and 2036

Notice that even a proven light-water design, backed by decades of BWR operating history, still lands in roughly the same nine-year range as TerraPower’s genuinely novel sodium-cooled reactor. That should tell you something about where the real time sink is in this industry, and it isn’t the reactor physics. It’s regulatory review plus first-of-a-kind construction learning curves.

Why timelines slip: Hermes 1’s 28-month extension

Not every project holds its schedule, and the honest version of this article has to include the one that didn’t. Kairos Power’s Hermes 1, a non-power demonstration reactor at Oak Ridge, Tennessee, received its NRC construction permit in December 2023, the first non-light-water reactor permitted in the U.S. in more than 50 years. The original permit specified a completion deadline of December 31, 2026. Construction broke ground in July 2024, with the company initially targeting operation sometime in 2027. ⏱️

In March 2026, Kairos went back to the NRC and asked for a 28-month extension, pushing the construction deadline to April 30, 2029. The company’s own filing attributed the delay to development challenges tied to the “first-of-a-kind nature of the Hermes Test Reactor facility design and construction,” as World Nuclear News reported. That’s a remarkably candid admission, and it’s worth sitting with:

• 28 months: the extension Kairos requested, more than doubling the original construction window

• 50+ years: how long it had been since the U.S. permitted a non-light-water reactor before Hermes, meaning there was no recent domestic playbook to follow

• Hermes 1 is a non-power demonstration reactor, meaning even the “easy” precursor to a commercial plant slipped

• Hermes 2, the commercial-scale 50 MWe follow-on, is still targeting 2030, a date that now depends on lessons Hermes 1 hasn’t finished teaching yet

This is the pattern anyone tracking SMR schedules needs to internalize: FOAK projects slip because there’s no supply chain memory to draw on yet, not because the underlying physics changed. If you’re trying to model out which projects are likely to hold their dates versus which ones are showing early slip signals, SMRbrief Pro members can search, filter, and export the full intelligence picture behind developments like this one across every active project, not just the three covered here.

Part 53 promises 18-month reviews, but no one’s tested it yet

On March 25, 2026, the NRC finalized 10 CFR Part 53, the first entirely new reactor licensing framework since 1956. It’s technology-neutral, meaning it doesn’t force every design through the same light-water-reactor-shaped review process, and regulators estimate it could cut design review timelines to as little as 18 months while halving application costs, per coverage of the rule. 📜

Nobody has actually run a project through Part 53 start to finish yet, so treat that 18-month figure as an aspiration rather than a track record. What’s true right now, based on the three real projects above:

• Licensing review, even on the fast end, runs 22 to 30 months under the current framework

• Construction itself, once permitted, adds another 4 to 5 years for FOAK projects

• Total site-selection-to-operation timelines cluster around 8 to 9 years for every serious project with a real date attached

• Nth-of-a-kind reactors, the second, third, and fourth units built once the supply chain and workforce exist, should run considerably faster, though nobody has one finished yet to prove it

So if you’re asking how long it takes to build an SMR today, the honest answer is somewhere between eight and nine years from a firm site decision to commercial power, with the licensing phase eating roughly two to three of those years and the rest going to construction, testing, and the inevitable FOAK surprises. Which of these three timelines do you think holds, and which one slips next?

Every SMR press release in 2026 leads with a megawatt figure or a dollar sign. What those releases don’t say is who actually pours the concrete, welds the piping, and signs off on the paperwork that lets a reactor operate legally. That’s the part of the story nobody puts in a headline, and it’s also where the jobs are. A recent University of Texas workforce study put it bluntly: skilled trades like welders, pipefitters, and electricians need 3 to 5 years of apprenticeship and certification, but funding for SMR projects tends to get approved after construction timelines are already locked in. That mismatch is why hiring managers at TerraPower, Kairos Power, and X-energy are all fighting over the same small pool of qualified people. 🔧

The U.S. nuclear workforce needs to roughly triple by 2050 to meet demand, and the Department of Energy’s own employment data shows more than 80% of employers across nuclear construction and manufacturing are already struggling to find qualified workers. If you’re weighing a move into this sector, or wondering whether your current trade or degree translates, here are five roles with real hiring activity behind them right now, not just projections.

Nuclear-certified welder, pipefitter, or electrician

Of the roughly 67,000 welders working in the United States today, fewer than 5,000 hold nuclear-grade certification. That gap alone tells you everything about why craft wages in this sector have climbed 20% since the end of the pandemic. 💰 Every SMR site under construction, from TerraPower’s Kemmerer build in Wyoming to Kairos Power’s Hermes campus in Oak Ridge, needs people who can weld, wire, and pipe a facility to NQA-1 nuclear quality standards, not general commercial code.

The entry path isn’t glamorous, but it’s real. Trade schools and union apprenticeship programs teach the base craft, and companies increasingly run what industry recruiters call “nuclear wrappers,” short coaching add-ons that layer nuclear documentation and procedural discipline on top of skills a welder or electrician already has from shipbuilding, oil and gas, or heavy civil work. A few numbers worth knowing before you commit:

• Skilled technicians typically earn $70,000 to $95,000 once certified

• Full nuclear-grade welding or pipefitting certification takes 3 to 5 years

• The main knowledge gap employers cite is NQA-1 documentation and NRC process familiarity, not the craft itself

• Workers from adjacent fields (shipbuilding, LNG, semiconductor fabs) transfer in faster than complete newcomers

This is arguably the fastest on-ramp into the SMR industry for anyone without a four-year degree, and it’s also the bottleneck the whole sector is racing to fix.

NRC-licensed reactor operator

Every operating SMR eventually needs someone physically qualified to run it, and that requires a license from the Nuclear Regulatory Commission itself, not a company certificate. Reactor Operator (RO) and Senior Reactor Operator (SRO) licenses are facility-specific, earned through a mix of classroom instruction, simulator time, and a brutal two-part exam that mixes written questions with a hands-on operating test. ⚛️

Pay reflects how narrow the qualified pool is. Federal wage data puts the national median for licensed reactor operators at $122,890, while total-compensation trackers that include overtime and shift differentials show averages closer to $157,000. Constellation Energy and Duke Energy consistently rank among the top-paying employers for this role, alongside the U.S. Navy’s own nuclear program, which trains a meaningful share of the civilian operator pipeline.

• Entry-level operator pay starts lower, often in the $65,000 to $80,000 range before full licensing

• Fully licensed RO and SRO roles routinely clear six figures

• Licenses don’t transfer between facilities without additional plant-specific training

• The Bureau of Labor Statistics projects overall power plant operator employment declining slightly through 2034, but SMR builds and reactor restarts are pushing openings the other direction for this specific credential

If Rolls-Royce SMR’s Wylfa project and the wave of U.S. Gen IV demonstration plants both hit their 2030 targets, the operator shortage gets worse before it gets better. That’s good news if you’re the one holding the license.

Nuclear licensing and regulatory affairs engineer

Somebody has to talk to the NRC, and that somebody is increasingly hard to hire. Licensing engineers write and manage the technical documentation, safety analyses, and docket submissions that let a reactor design move from paper to a construction permit, the exact process TerraPower and X-energy both navigated this year. It’s less glamorous than reactor physics, but it’s arguably more scarce. 📋

Federal data pegs the national median for nuclear engineers at $133,970, though that number understates what licensing specialists command in the hubs where the work concentrates. The Washington D.C. metro area, thick with NRC staff and federal contractors, sees senior licensing roles touch $163,000 to $175,000. Idaho and New Mexico, home to Idaho National Laboratory and Los Alamos, run a bit lower on salary but come with a correspondingly lower cost of living.

• Entry-level nuclear engineering roles start around $90,000

• Regulatory and licensing specialists are in particularly short supply relative to reactor design engineers

• Compliance officers, environmental safety officers, and legal advisors fluent in NRC rules round out this same hiring category

• Demand spans every company on the construction permit side of the industry right now, not just the ones already operating

Health physicist or radiation protection technician

Radiation safety is its own career track, and it scales up, not down, as more reactors move from licensing into construction and eventually operation. Health physicists design and enforce the protocols that keep workers and the public within regulatory dose limits, while radiation protection (RP) technicians handle the day-to-day monitoring on site. ☢️

• Health physicists average around $95,000, with top specialists clearing $175,000+

• RP technicians typically start between $60,000 and $80,000

• This role sits at the intersection of physics, industrial hygiene, and NRC compliance, so a physics or health sciences background transfers well

• Demand grows fastest during the construction-to-operation transition, exactly where TerraPower’s Kemmerer site and Kairos Power’s Hermes campus sit today

If you’re trying to figure out which companies are actually hiring for these roles versus which ones are still years from needing them, SMRbrief Pro members can search, filter, and export the full intelligence picture behind developments like this one, including which projects are hitting the construction phase where RP staffing ramps up fastest.

Nuclear construction project manager or QA/QC specialist

This is, by most measures, the highest-paying entry point into the SMR workforce that doesn’t require a nuclear-specific degree. Construction project managers on nuclear builds oversee budgets running $500 million to $3 billion or more, coordinating simultaneously with regulators, utilities, and specialist subcontractors. Senior EPC project directors on nuclear and LNG megaprojects are consistently reported as the highest-paid segment in the entire engineering, procurement, and construction sector. 📈

• Construction PM salaries range from $130,000 to $250,000+ annually in the U.S.

• Quality assurance and quality control (QA/QC) managers are described by industry recruiters as among the hardest roles to fill, right alongside schedulers and commissioning specialists

• A PMP certification plus 10+ years of major power-generation or industrial construction experience is the typical bar for senior roles

• SMR projects push more work into off-site modular fabrication and systems integration, which is shifting demand toward people who understand both factory assembly and field commissioning

The main skills gap employers cite here isn’t project management itself. It’s NQA-1 documentation and NRC process knowledge, the same paperwork fluency that shows up as the bottleneck for skilled trades. If you already manage large capital projects in power, heavy civil, or industrial construction, that documentation gap is closable faster than people expect.

None of these five paths require starting from zero. Purdue’s new stackable SMR credential program and the Department of Energy’s Nuclear Reactor Safety Training and Workforce Development Program, which just funded 10 university-led projects with $49 million, are both explicitly designed for people transitioning in from adjacent fields rather than starting a nuclear degree from scratch. Rolls-Royce SMR alone expects its UK build-out to support up to 40,000 jobs by 2050, according to industry workforce data compiled by Morson, and that’s one company in one country. Which of these five roles lines up closest with what you already do, and is the retraining gap smaller than you assumed?

2026 is the year small modular reactors stopped being a slide deck and started being a construction site. For a decade, the SMR pitch was always “five years out.” Now the U.S. Nuclear Regulatory Commission has issued its first construction permit for a commercial non-light-water reactor in more than 40 years, Ontario’s BWRX-300 has steel going into the ground, and the U.K. has picked a winner for its first fleet. Even China’s Linglong One is racing to become the world’s first land-based commercial SMR, a reminder that the West isn’t the only one pouring concrete. 🏗️

None of this happened by accident. AI data centers need firm, round-the-clock power that wind and solar alone can’t promise, and utilities are done waiting on transmission queues. That demand pulled billions of dollars of private and government capital into a handful of companies that actually have dockets, permits, and shovels in the ground, not just renderings. Here are the five that pulled ahead this year, and why.

X-energy is turning a chemical plant into a nuclear testbed

X-energy is building four Xe-100 reactors, an 80 MW high-temperature gas-cooled design, at Dow’s UCC Seadrift petrochemical site on the Texas Gulf Coast. Combined, the four-pack adds up to 320 MWe, enough to replace the fossil-fuel cogeration plant currently running the site. The NRC completed its Environmental Assessment in May 2026 with a Finding of No Significant Impact, and a construction permit is expected in the first quarter of 2027. ⚛️

What sets X-energy apart isn’t just Dow. It’s the pipeline: contracts with Dow, Amazon, and the U.K.’s Centrica add up to more than 11.5 gigawatts across 144 reactors. The company backed that pipeline with real money in 2026:

• An upsized IPO in April at $23 a share, now trading on Nasdaq as XE

• An additional $1 billion in DOE cost-shared funding for the Seadrift project, bringing the government’s total commitment there to roughly $2.15 billion

• The first-ever NRC Category II license for TRISO-X to manufacture advanced fuel, granted in February 2026

• A March MOU with Japan’s IHI to expand U.S.-Japan supply chain capacity for the Xe-100

Dow expects to receive its first commercial reactor delivery in the early 2030s, but the fuel fabrication and licensing groundwork happening right now is what X-energy says makes Seadrift the template for every industrial site that follows it.

TerraPower broke ground on America’s first advanced reactor

TerraPower, the Bill Gates-backed developer, hit the milestone the whole sector has been chasing: an actual NRC construction permit. On March 4, 2026, commissioners unanimously approved the permit for Kemmerer Unit 1 in Wyoming, home to TerraPower’s Natrium reactor, a 345 MW sodium-cooled fast reactor paired with a molten salt storage system that can push output to 500 MW on demand. Construction officially began April 23, 2026, according to the company, less than seven weeks after the permit came through. 🔧

The historical weight here is hard to overstate without sounding like a press release, so let’s just stick to facts: it’s the first construction permit the NRC has granted a commercial reactor in nearly a decade, and the first ever for a non-light-water design. A few numbers that matter:

• Project cost projected at up to $4 billion

• Sodium-cooled fast reactor rated at 345 MW, boostable to 500 MW

• Site sits next to a retiring coal plant, replacing jobs the closure would have cut

• Targeted completion in 2030

TerraPower’s sister project, the Hermes test reactor built with fellow ARDP recipient X-energy’s peer Kairos Power (more on them below), shows how tightly the DOE’s original 2020 bet on these two companies has paid off. Both were long-shots five years ago. Neither is anymore.

Kairos Power is racing a molten-salt reactor into Tennessee

Kairos Power builds a fluoride salt-cooled high-temperature reactor (KP-FHR) that runs on TRISO pebble fuel, technology with roots in 1960s Oak Ridge research reborn for a 2026 grid. The company’s Hermes 1 test unit is, right now, the only Gen IV reactor under active nuclear construction in the United States. Behind it comes Hermes 2, a 50 MWe commercial-scale demonstration plant that broke ground this year on the same Oak Ridge campus. 🧪

Hermes 2 exists because of a deal that turned heads in the industry: Kairos, the Tennessee Valley Authority, and Google agreed in 2025 to put the reactor’s output directly onto TVA’s grid, making it the first commercial deployment tied to Google’s advanced nuclear procurement push. A few specifics worth flagging for anyone tracking the fuel side of this story:

• Kairos finalized a DOE contract for HALEU in January 2026 to fuel the Hermes demonstration reactor

• A September 2025 agreement with BWXT targets commercial-scale TRISO manufacturing for Hermes 2 and future units

• Hermes 2 components are fabricated at Kairos’s Albuquerque manufacturing campus and shipped to Tennessee for assembly, a factory-build approach the company is betting will cut costs

• Commercial operation is targeted for 2030

If you’re wondering how this compares to the more established light-water designs below, SMRbrief Pro members can search, filter, and export the full intelligence picture behind developments like this one, including fuel supply timelines that don’t always make the press release.

GE Vernova Hitachi’s BWRX-300 is going global fast

Of everyone on this list, GE Vernova Hitachi Nuclear Energy has the least to prove technically. Its BWRX-300, a 300 MWe boiling water reactor built on the NRC-certified ESBWR design, is under construction right now at Ontario Power Generation’s Darlington site in Canada, the first SMR construction project in the Western world, with completion expected by decade’s end. 🌍

The bigger story this year is reach. GE Vernova and Poland’s Orlen Synthos Green Energy (OSGE) signed a Poland Generic Design Agreement in February 2026 to develop a detailed BWRX-300 reference design for the Polish market, backed by up to $4 billion in U.S. Export-Import Bank and International Development Finance Corporation support. That’s a lot of acronyms for one deal, so here’s the shape of it:

• Poland is targeting a first unit at Włocławek by 2032, with up to 24 reactors planned across six sites

• The NRC is separately reviewing the Tennessee Valley Authority’s application to build a BWRX-300 at Clinch River, Tennessee

• Darlington’s reactor pressure vessel is already in manufacturing, per GE Vernova

• Poland still generates roughly 70% of its electricity from coal, which is the real reason this deal matters

Which of these five reactors do you think reaches commercial operation first, Darlington’s BWRX-300 or TerraPower’s Natrium? Worth arguing about in the comments, because the smart money keeps splitting on that question. 💬

Rolls-Royce SMR won the UK, then went to Sweden

Rolls-Royce SMR spent years as the perpetual bridesmaid of the sector, and 2026 is when that changed. Great British Energy - Nuclear named Rolls-Royce SMR the preferred technology for the U.K.’s first SMR fleet after a two-year competition against GE Hitachi, Holtec, and Westinghouse, World Nuclear News reported. The reactor itself is a 470 MWe pressurized water reactor, derived from decades of Royal Navy submarine engineering, and it’s going up first at Wylfa on Anglesey in North Wales. ☢️

The contract, backed by £2.5 billion in government funding, was formally signed this year and lets Rolls-Royce SMR start ordering long-lead equipment. A few numbers to anchor the scale of this bet:

• Wylfa’s first three reactors are expected to support around 3,000 jobs at peak construction

• In June 2026, Sweden’s Videberg Kraft picked Rolls-Royce SMR to build three reactors on the Värö peninsula, up to 1,500 MWe total

• Rolls-Royce SMR is now the only developer with multiple firm commitments in Europe

• Backers include the Qatar Investment Authority, Constellation Energy, and a 20% equity stake held by the Czech utility CEZ

That combination, a domestic anchor customer plus an export order landed in the same year, is what separates a chosen technology from a company that’s merely hopeful. Rolls-Royce SMR’s own progress page reads less like a pitch deck now and more like a project schedule.

Five companies, five very different bets on reactor chemistry, and all five now have something in common they didn’t have two years ago: dirt moving, permits signed, or a customer with skin in the game. The next twelve months will separate the ones that stay on schedule from the ones that quietly slip into “early 2030s.” Which of these five would you put your money on to actually flip the switch first?

InvestmentsAsk most people what an SMR project brings to a town and they picture one thing: construction workers in hard hats. That’s real, but it’s also just the loudest part of a much bigger hiring wave. The current build-out touches forge shops in Illinois, community colleges in Wyoming, and federal offices in Rockville, Maryland, long before a single reactor generates a watt. U.S. nuclear workforce models point to growth from roughly 100,000 workers today to something closer to 375,000 by 2050, and SMR projects are the fastest-growing slice of that curve.

Here are five categories of jobs actually showing up on hiring boards and DOE award lists right now, ranked from the ones you can see from the road to the ones you’d never guess are nuclear at all.

Construction trades, the first and biggest wave

Every SMR project starts as a construction site, and that phase is where headcount peaks hardest. TerraPower’s Natrium plant in Kemmerer, Wyoming expects a peak construction workforce of 1,600, covering everything from civil engineers and heavy equipment operators to concrete batchers and electricians. Across the Atlantic, Rolls-Royce SMR’s Wylfa site in Wales is projected to support up to 8,000 jobs during its build phase, with roles like machine operators, groundworkers, and site engineers leading the earliest hiring rounds.

What makes SMR construction different from a typical industrial build is the paperwork layer stacked on top of the physical work. Nuclear-specific quality assurance standards mean even a standard electrician or welder role usually requires additional certification once nuclear-grade materials enter the picture. Roles filling up fastest right now include:

• Project engineers and schedulers, who translate the modular build sequence into a workable site plan

• QA/QC managers, tasked with documentation standards ordinary commercial construction doesn’t require

• NQA-1 certified welders and inspectors, a credential most general contractors don’t carry

• Commissioning specialists, who test systems before a reactor is cleared to operate

• Superintendents with prior nuclear or heavy industrial experience, consistently the hardest role to fill

That last gap is worth sitting with for a second. Nuclear pay is genuinely higher than comparable commercial construction work, largely because so few people currently hold the required nuclear documentation and quality-control experience. If you’re already working data centers, heavy civil, or industrial QA/QC, that’s the fastest lane into an SMR build.

Permanent plant operators, the jobs that outlast the construction crews

Once the cranes leave, a much smaller but far more durable set of jobs remains. A typical 300-megawatt SMR unit needs roughly 150 to 250 permanent employees across engineering, operations, maintenance, and skilled trades, according to industry workforce estimates. TerraPower expects more than 250 permanent Kemmerer positions once Natrium is operating, many at six-figure salaries. The Tennessee Valley Authority’s Clinch River project in Oak Ridge, Tennessee is projected to add more than 300 permanent jobs, while X-energy’s Xe-100 project at Dow’s Seadrift, Texas facility anticipates around 100 permanent positions once operational.

These roles skew toward long careers rather than project-based work, which is exactly what makes them the backbone of a host community’s economy:

• Reactor operators and control room staff, requiring NRC-licensed operator certification

• Instrumentation and controls (I&C) technicians, maintaining the sensors and safety systems

• Radiation protection technicians, monitoring exposure and site safety day to day

• Maintenance and mechanical trades, handling the ongoing upkeep a reactor needs over decades

Which of these roles matters most to your own town probably depends less on the reactor vendor and more on whether the site is a new build or a coal conversion, since coal-to-nuclear projects can often retrain existing plant staff into a meaningful share of these positions rather than hiring an entirely new workforce.

Manufacturing and supply chain jobs, hundreds of miles from any reactor

This is the category most people miss entirely, because it doesn’t show up near a construction site. It shows up in machine shops and forges that may be nowhere near a planned reactor. In May 2026, the Department of Energy awarded more than $94 million to eight American manufacturers specifically to close SMR component bottlenecks. American Forgemasters in New Castle, Pennsylvania received $2.9 million for a new furnace to produce large component forgings for Gen III+ SMRs. Scot Forge in Spring Grove, Illinois got $12.3 million for a vertical turning lathe and gantry milling machine to manufacture large reactor components domestically. Global Nuclear Fuel Americas in Wilmington, North Carolina received $3 million to add a second fuel rod fabrication line.

None of those three towns hosts an SMR. All three now employ people building the parts that make one possible. That’s the pattern worth watching if you don’t live anywhere near a proposed reactor site:

• Nuclear-qualified forging and casting operators, a skillset the industry has been short on for 30 years

• Precision machinists trained on nuclear tolerance standards, tighter than most commercial manufacturing

• Fuel fabrication technicians, needed at facilities scattered across a handful of states regardless of where reactors get built

• Materials inspectors and NDE (non-destructive examination) technicians, verifying components before they ship

If you’re trying to track which manufacturers are actually hiring against these DOE-backed contracts versus which ones are still waiting on firm orders, that’s exactly the kind of company-by-company detail SMRbrief Pro keeps updated as new awards and supplier announcements land.

Teaching and training roles, the quiet growth category

Somebody has to train the 150 to 250 people who’ll eventually staff each new plant, and that’s created an entirely separate hiring wave inside community colleges and technical schools. Western Wyoming Community College was awarded $1.9 million to launch a Generation IV Nuclear Plant Technician program, the first of its kind in the state, built specifically around Natrium’s local hiring needs. TerraPower’s own 35,000-square-foot Kemmerer Training Center, built around a full-scale plant simulator, will train not just its Wyoming workforce but operators for future Natrium plants worldwide.

The U.S. Bureau of Labor Statistics projects roughly 500 nuclear technician job openings annually over the next decade nationally, a mix of new positions and retirements, which means the instructors, lab coordinators, and curriculum developers building these programs are themselves a growing job category:

• Nuclear technology instructors at community and technical colleges

• Simulator and lab coordinators running hands-on training facilities

• Apprenticeship program managers, coordinating between developers and local trade schools

• Workforce development grant administrators, managing the federal and state funding behind these programs

This is probably the least visible job category on this list, and also the one most likely to exist in a town that has no reactor plans whatsoever, since regional community colleges are positioning themselves as training hubs for an entire multi-state labor market.

Regulatory, safety, and specialized professional roles

The last category sits mostly in Rockville, Maryland, home to NRC headquarters, but its ripple effects reach state energy offices and utility legal teams everywhere. The 2024 ADVANCE Act pushed the NRC to expand hiring under its existing Atomic Energy Act authorities specifically to keep pace with advanced reactor applications, and the agency has been adding dedicated review teams to provide continuity across licensing reviews.

The jobs here look less like a hard hat and more like a law degree or an engineering PhD:

• Reactor safety and licensing engineers, reviewing applications like TVA’s Clinch River permit

• NRC attorneys and policy analysts, handling enforcement actions and rulemaking tied to the ADVANCE Act

• Field inspectors, visiting sites to verify compliance once construction begins

• State energy office staff, increasingly tasked with coordinating siting, permitting, and community benefit agreements as more states compete for SMR projects

Do you actually need to live near Rockville to land one of these roles? Not necessarily. States actively courting SMR developers, including Wyoming, Tennessee, Texas, and increasingly several in the Southeast, are building out their own energy office staff to manage exactly this kind of project pipeline, which means the regulatory job market is spreading well beyond the NRC’s own headcount.

Whether any of these five categories lands near you probably depends less on whether your state gets an actual reactor and more on whether it lands a forge contract, a training grant, or a state energy office expansion instead. Worth checking your own state’s economic development office for SMR-related grants before assuming the jobs are all happening somewhere else.

BasicsNuclear power has avoided roughly 1.5 gigatonnes of global CO2 emissions a year since it started running at scale, according to the IEA, and something close to 70 gigatonnes cumulatively since 1971. Those numbers come almost entirely from large conventional reactors built decades ago. The question hanging over small modular reactors is whether they can add a meaningful second act, not just as a cleaner way to keep AI data centers running, but as a tool that reaches parts of the emissions problem that big plants never could.

The honest answer is mixed. Some of the five pathways below are already under construction. Others depend on cost curves that haven’t bent yet. Here’s where SMRs are actually positioned to cut carbon, ranked by how close each one is to real deployment rather than by how good it sounds in a pitch deck.

Retiring coal plants without retiring the emissions math

The most immediate carbon case for SMRs isn’t glamorous. It’s plugging a small reactor into the exact grid interconnection a coal plant is about to vacate. A 2022 Department of Energy study, still the reference document everyone in this space cites, screened 394 coal sites and found 80% of them have the basic characteristics needed to host an advanced reactor. The case study result is the number worth remembering: swapping a large coal plant for a similarly sized nuclear plant on the same site cuts regional greenhouse gas emissions by 86%, the equivalent of pulling more than 500,000 gasoline cars off the road.

TerraPower’s Natrium project in Kemmerer, Wyoming is the clearest real-world test of this idea. The 345-MWe sodium-cooled fast reactor, sited next to a retiring coal unit, began construction this spring after the NRC issued its first commercial construction permit in nearly a decade. Coal-to-nuclear conversion also solves a problem carbon math alone doesn’t capture:

• Preserves the existing grid interconnection, cutting years off transmission permitting

• Retains a trained energy workforce, since DOE estimates roughly 80% of coal plant jobs transfer directly

• Reuses site infrastructure, which DOE says can cut construction costs by up to 35%

• Keeps the tax base intact for host counties that would otherwise lose it overnight

None of that guarantees the economics work everywhere. Plenty of the 394 screened sites will stay coal, gas, or nothing at all. But of the five pathways here, this is the one with an actual reactor pouring concrete right now.

Feeding AI’s power habit without adding more gas turbines

This is the pathway getting all the headlines, and for good reason: it’s where the money and the megawatts are moving fastest. On August 4, Florida’s Holtec International signed a non-binding agreement with Louisiana’s Entergy Services and South Korea’s Hyundai Engineering & Construction to evaluate a dual-unit SMR-300 project capable of delivering 680 MW of carbon-free power to Gulf South data centers. NuScale’s separate deal with the Tennessee Valley Authority targets 600 MWe of capacity that the company says would cut emissions by more than 1 million metric tons of CO2 annually compared with an equivalent coal plant.

The climate logic here is straightforward but easy to miss amid the AI hype: without firm, always-on nuclear capacity, most hyperscalers filling the demand gap are turning to natural gas turbines instead, not more solar and batteries. Every megawatt of SMR capacity that displaces a planned gas peaker, rather than simply adding to total generation, is a real emissions win. Every megawatt that just meets demand growth that would have gone unmet otherwise isn’t. Tracking which is which, deal by deal, is exactly the kind of granular work that separates a real climate contribution from a marketing claim, and it’s why SMRbrief Pro tags every announced data center offtake agreement by whether it’s displacing fossil capacity or simply adding new load.

Decarbonizing the heat that renewables can’t touch

Solar panels and wind turbines are good at making electrons. They’re much worse at making the high-temperature steam that refineries, chemical plants, and steel mills need around the clock, which is why industrial heat remains one of the hardest emissions sources to clean up. This is where SMRs have a genuine structural advantage over renewables, not just a cost one.

The clearest current example is X-energy’s planned deployment of four Xe-100 units at Dow Chemical’s Seadrift, Texas facility. Each unit is designed to deliver 80 MW of electricity and 200 MW of process heat, aimed at replacing fossil-fired steam generation and eventually supporting on-site hydrogen production. NuScale is running a parallel effort with Ebara Elliott Energy, using heat exchangers and steam compressors to boost reactor-generated steam to the 500°C range that chemical plants actually need, with field testing targeted for after 2027.

The emissions upside varies a lot by end use:

• Chemical sector cogeneration: up to 60% carbon reduction versus gas-fired steam, per recent industry analysis

• Steelmaking via nuclear-produced hydrogen: roughly 50% reduction versus a conventional blast furnace, per RMI research, though direct gas-based reduction can achieve similar cuts more cheaply today

• Petroleum refining: the single largest near-term opportunity, since refinery steam and hydrogen demand is almost entirely gas-fed right now

This pathway is real but slower than the coal or data center stories. High-temperature designs capable of the 700-900°C heat that primary steelmaking needs aren’t commercially mature yet, and most near-term industrial projects, including Dow’s, are targeting lower-temperature steam rather than the hardest-to-abate processes.

Making renewables’ worst days less carbon-intensive

Solar and wind are cheap when the sun shines and the wind blows. On the days they don’t, grids fall back on whatever’s fastest to ramp, which today usually means natural gas. SMRs don’t compete with renewables for the same hours; they compete with the fossil backup that renewables currently need.

Sweden’s Vattenfall and the industrial consortium Industrikraft, whose members include ABB, SSAB, and Volvo, moved their planned SMR project at the Ringhals site into joint development late last year, shortlisting either five GE Vernova-Hitachi BWRX-300 units or three Rolls-Royce SMR units for a combined 1,500 MW addition. The project exists specifically because Swedish heavy industry needs firm, fossil-free power to hit its own decarbonization targets, and intermittent renewables alone can’t guarantee it.

A few reasons this pathway matters for the emissions math specifically, not just the reliability story:

• Every hour a firm nuclear unit covers is an hour a gas peaker doesn’t fire up

• Grid operators need less battery overbuild to manage renewable variability when nuclear provides a steady floor

• Industrial offtakers with hard decarbonization deadlines, like the Ringhals consortium members, are willing to fund firm capacity that pure-play renewables developers won’t build alone

This is probably the least visible of the five pathways in day-to-day coverage, but it’s arguably the one that determines whether high-renewable grids actually hit net zero or just get most of the way there and stall on the last, hardest hours.

Replacing diesel where the grid doesn’t reach

The smallest pathway in total emissions terms, but the most literal fit for what “small” modular actually means, is replacing diesel generation in places a transmission line will never reach. Russia’s Akademik Lomonosov floating nuclear plant has been supplying power and heat to the remote Arctic port of Pevek since 2020, running on the same reactor technology used in Russia’s icebreaker fleet. Rosatom is now building at least four more floating plants, with one or more slated to power the Baimskaya copper mine in the Chukotka region, a site with no realistic grid connection and no alternative to diesel or heavy fuel oil.

This use case won’t move the needle on global emissions totals the way coal-to-nuclear conversion or AI data center displacement will. But per unit of capacity, it may be the cleanest substitution on this list, since diesel generation is both carbon-intensive and expensive to fuel in remote locations, meaning the economic case and the climate case point in the same direction without much subsidy required.

Which of these five pathways actually delivers the most avoided emissions by 2035 is still an open question, and it’s one worth revisiting project by project rather than taking any single company’s roadmap at face value. The coal conversions and data center deals are the ones with steel in the ground today. The industrial heat and remote diesel plays are the ones worth watching for the next reactor vendor that actually breaks ground rather than just signs another memorandum of understanding.