The American and European reactor construction booms of the 1970s and 1980s have run their course. Western utilities, saturated with capacity after decades of rapid industrial build-out, have stopped ordering reactors. Chernobyl has done its political damage.

The French Messmer programme has delivered 54 reactors in roughly 15 years, but Paris is now operating a mature fleet, and not expanding it. In the United States all reactor orders placed after 1973 have been canceled. The word most commonly attached to nuclear construction, on both continents, is “pause.”

Japan is an exception. It is the world’s second largest economy dependent on imports for 90% of its energy needs. Driven by energy security concerns it has developed a national target of 50% nuclear electricity by 2030. Japanese utilities have continued building at scale as the West has stood down.

TEPCO, the Tokyo Electric Power Company, operates large multi-unit sites at Fukushima Daiichi, Fukushima Daini, and the world’s largest nuclear generating site, Kashiwazaki-Kariwa. It has brought a systematic industrial discipline to the task that its Western counterparts have largely abandoned.

At Kashiwazaki-Kariwa, units 6 and 7 come online. They are ABWRs, 1350 MWs each and the world’s first Generation III reactors. The first of a kind (FOAK) unit is built in 38 months of nuclear construction and costs roughly a third less than unit 5, a seventh-of-its-kind standardized BWR5 Mark II, built at the same site by the same construction crews, essentially simultaneously.

This stellar result sets the benchmark for the EPR designers at Framatome and the AP1000 team at Westinghouse. Both programmes publicly aim for 36-month construction schedules. As Krellenstein observes, this prompts a reasonable inference: if the Japanese can build a FOAK Gen III reactor in 38 months with 1990s digital tools, why couldn’t the West?

The ABWR appeared to prove that the obstacles plaguing nuclear construction in the 1970s and 1980s were not intrinsic to the technology. They were interpreted primarily as problems of document management, design coordination and supply chain integration, precisely the problems that the information technology revolution of the 1990s was supposed to have solved.

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A Controlled Experiment

When Olkiluoto 3 began construction in 2005 as the first EPR, the Western nuclear industry had the same computers, the same CAD software, the same building information modelling tools, and the same AutoCAD and Primavera and Navisworks that Japan had used to build Kashiwazaki Kariwa 6 and 7.

Commodity laptops were faster than anything available when TEPCO planned its first ABWR. Adobe Acrobat was on every engineer’s desktop. Radio frequency identification (RFID) inventory management became standard practice in manufacturing supply chains across the developed world.

However, results in the West differed markedly from the Japanese experience. Finland’s Olkiluoto 3 took 18 years from construction start to grid connection. The Vogtle AP1000 units in Georgia, the only AP1000s completed in the United States, ran roughly 7 years late and billions over budget, bankrupting Westinghouse in the process.

The EPR at Flamanville in France, begun in 2007, achieved grid connection only in 2024. These projects were assembled after a long pause, dependent on teams, supply chains, and regulators lacking recent experience in delivering nuclear megaprojects.

Digitalization was necessary for Japan’s impressive achievement, but it was only one variable in the stack. Japanese nuclear construction continuity into the 1990s conserved a workforce with recent build experience, project managers who had closed out large units, and a supply chain still qualified and synchronized to nuclear specifications.

Kashiwazaki Kariwa 6 and 7 were successive iterations of an ongoing construction program. Japan demonstrated pre-construction discipline, an integrated supply chain, the utility as developer model, and above all spent more than a decade on pre-construction design and constructability work.

The 1978 Tokyo Meeting

The ABWR originated in a TEPCO feasibility study commissioned in 1978, 13 years before construction began at Kashiwazaki-Kariwa. TEPCO brought together every major boiling water reactor developer in the world: General Electric, Hitachi, Toshiba, the Italian firm Ansaldo, and the Swedish firm ASEA, which had independently developed BWR technology without a GE licence, deploying it at Forsmark, Ringhals, and Oskarshamn.

Such cooperation was deliberately radical for an industry organized around vendor competition. TEPCO was paying its vendors to make their existing designs obsolete in order to secure the next one.

The premise underlying their assignment was expressed in one question: if you could redesign the boiling water reactor from scratch, drawing on everything the global BWR fleet had learned about construction and operation, what would you change?

That meeting produced the conceptual design that eventually became the ABWR. Its underlying philosophy was simple: build what the utility could actually construct, validate, operate, and understand, using proven components and methodologies available at the time, and eliminate complexity wherever it did not buy proportionate safety or performance.

This is quite different from the philosophy that produced the AP1000, which emerged primarily from US government-funded research into advanced passive safety concepts. The AP1000 is revolutionary in its passive safety architecture. The evolutionary ABWR made design decisions driven primarily by the needs of a utility aiming to build at scale.

The Design Philosophy

The ABWR containment building is a squat cylinder of reinforced concrete, shorter than the turbine building on the same site. Height is both a key driver of cost and an enemy of seismic resilience. Japan’s geology demanded a short, stiff structure.

The free volume of the ABWR containment is roughly 1/5th that of an equivalently sized PWR, 450,000 cubic feet, compared to 2.5 to 3 million cubic feet in an equivalent pressurized water reactor. Most of this reduction in containment volume is intrinsic to boiling water reactor design: with the elimination of steam generators, pressurizer, hot legs, or cold legs. However, the elimination of external recirculation pumps reduced containment size further relative to other BWRs.

Perhaps the most revealing design choice of the ABWR is the reactor internal pump, or RIP. To understand why, it is worth recalling what came before.

Boiling water reactors benefit hugely from recirculation flow. In a BWR, water in the core is both coolant and neutron moderator. Steam bubbles, which are roughly 100 times less dense per unit volume than liquid water, weaken moderation and reduce reactor power. Controlling the void fraction in the core (reducing steam bubbles) is therefore a primary mechanism of power control.

The way to do this is to drive recirculation flow through the core: pushing water through the fuel at high velocity sweeps bubbles away and increases moderator density. An extraordinary illustration of the importance of recirculation flow is the fact that its flow rate dwarfs the feed water flow rate, that is the water returning to the reactor pressure vessel from the turbine condenser, by a factor of 5-7.

Early BWRs accomplished this with large external recirculation loops: pipes carrying reactor water out through the vessel wall, through pumps, and back in at the bottom. GE’s BWR3 through BWR6 product lines replaced those loops with jet pumps: 2 external recirculation pumps driving high-velocity jets into a Venturi throat, with surrounding water entrained by the Bernoulli effect, multiplying the flow without multiplying the large-diameter pipe penetrations. Most operating BWRs in the United States today possess this configuration.

The ABWR went further. Drawing on technology pioneered by ASEA on the Swedish fleet at Forsmark, designers eliminated external recirculation entirely, replacing it with 10 RIPs mounted on the bottom skirt of the reactor pressure vessel. The RIP motors sit outside the vessel; the impellers are on the inside, driven through the lower skirt. There are no recirculation loop pipe penetrations. The only fluid penetrations below the midpoint of the nuclear fuel are the RIP penetrations themselves, which are far smaller in diameter than the large recirculation piping they replaced.

The resultant safety gain is real: recirculation line breaks contributed significantly to large break loss-of-coolant accident probability in earlier BWR designs. The ABWR eliminates that category of event entirely. But more importantly, as far as construction is concerned, is the simplification of the reactor building layout.

Removing the recirculation loops removes a substantial volume of large-diameter, nuclear-quality piping from the containment building, along with all the associated weld inspections, seal packages, and QA documentation. Every weld eliminated is a weld that cannot introduce a defect, cannot require a repair, and cannot become an inspection item for the regulator.

Operational consequences are equally significant. Each of the 10 RIPs is individually controlled by a variable frequency drive. By increasing pump speed and raising moderator density uniformly across the core, the reactor can move from 60% to 100% power in roughly 2 minutes without moving a control rod.

Krellenstein notes that this ramp rate is comparable to a combined-cycle gas turbine. Because the power change spreads evenly across the core, it avoids the local “hot spots” in neutron activity that happen when control rods are pushed in from specific locations.

The late-cycle “xenon pit” problem, which normally limits a reactor’s ability to ramp power up and down near the end of its fuel cycle, is less restrictive in the Advanced Boiling Water Reactor. Its internal recirculation pumps increase moderation in a way that preserves enough reactivity margin to keep adjusting power smoothly right up until the final coast-down period.

Thus, in a single piece of hardware, RIPs constitute a safety improvement, a construction simplification, a maintenance reduction, and an operational flexibility gain. That combination is the physical manifestation of ABWR’s pragmatic design philosophy.

The Original Large Modular Reactor

The ABWR is a large modular reactor. That framing matters because modularity is currently marketed as a defining advantage of small modular reactor designs, as though off-site prefabrication become available only below a certain nameplate capacity. The ABWR demonstrated otherwise at 1,350 megawatts.

Every unit ever built, including the Lungmen plants in Taiwan, was constructed on a bargeable site, with a large crawler moving directly from the barge slip to place the entire bottom section of the containment as a single piece onto the foundation. The fabrication shops producing those modules were inside the same “Zaibatsu” vertically integrated conglomerates as the design organizations, so the integration between what was designed and what could actually be shipped and placed was well understood.

The modularization schema was deliberately flexible, which turned out to matter more than the degree of modularization on any given unit. The first ABWRs were more stick-built, with prefabrication increasing on the third and fourth plants as construction teams learned what the approach could and could not do. When the hydraulic control units, initially modularized as a single prefabricated room, proved harder to execute that way than anticipated, the teams pulled back and stick-built them instead.

In a Western programme governed by fixed contract milestones and adversarial relationships between the utility, the architect-engineer, and the vendors, that kind of adjustment generates claims and schedule impacts. At Kashiwazaki-Kariwa it generated a revised work package, because TEPCO owned the design and bore the consequences of getting it wrong, which meant it also had the authority to fix it without litigation.

Four Hours Sharpening, Two Hours Cutting

The ABWR’s extraordinary built time was largely due to pre-construction planning. 13 years of design development, regulatory engagement, supply chain preparation, and digital pre-construction work occurred prior to nuclear concrete being poured.

By the time Kashiwazaki-Kariwa 6 broke ground, the design was finalized. Every cable tray, every pipe penetration, every weld sequence, every construction work package had been resolved in the digital model. Worker congestion through the construction sequence had been reduced. Concrete pours had been scheduled to the seasons to meet weather requirements. The entire warehouse inventory was managed by RFID. QA travellers and field work packages were transmitted to Palm Pilots on site rather than managed through paper binders.

From rock inspection to commercial operation, every subsequent ABWR built in Japan was completed within roughly 40 to 50 months. The 4 Japanese ABWRs operational by 2006 were built at a staggering rate of approximately 28 megawatts per month of construction time, or roughly 1 MW per day. For sake of comparison Vogtle Unit 3 was only 9 MW/month and the Flamanville EPR 8 MW/month.

The standard aspiration of nuclear construction improvement is a learning curve story: the FOAK is hardest, and each subsequent unit gets cheaper and faster as the builder learns. The ABWR bucked that trend. Its FOAK was a third cheaper than the seventh of a kind predecessor it replaced. The learning happened in the context of an active build program and 13 years of construction-informed design work before ground was broken, not in the field afterward.

In contrast the AP1000 and EPR were not merely unfinished designs when they entered the field, they were attempting to compress the Japanese pre-construction process into the construction schedule itself. They paid for every unresolved interference and every incomplete work package in real time, with tradespeople standing idle and interest during construction sky rocketing.

The failure to export the ABWR

In 2003, Finland’s utility Fortum selected the EPR over the ABWR for Olkiluoto 3. The EPR slightly underbid the ABWR, and from the perspective of a utility making a 2003 decision, the choice was not obviously wrong.

Kashiwazaki-Kariwa 6 and 7 were already operating as reference plants, but the industry had not yet absorbed what its benefits were. The prevailing and seemingly reasonable assumption was that the industry could now expect Gen III construction performance in the 36-to-38-month range. Olkiluoto 3 was supposed to be the proof point for the EPR just as Kashiwazaki-Kariwa had been for the ABWR.

The Olkiluoto 3 result is now part of a sorry historical record: 14 years late and roughly 3 times the original budget.

Would these outcomes have been partially avoided if The ABWR had been built in Finland or the United States? The ABWR had genuine advantages that the EPR and AP1000 lacked at first pour. The Lungmen units, 2 ABWRs built in Taiwan, that although never allowed to operate for political reasons, were built to ASME codes and represented a direct analogue to a Western regulatory environment.

The ABWR was the first reactor ever certified under the NRC part 52 framework. As mentioned above, the modularization scheme was more flexible than the AP1000’s rigid modular architecture, which contributed significantly to field execution problems at Vogtle.

Toshiba’s withdrawal from the South Texas Project in 2018 represented a financial failure, not a technical one: unpromising market conditions and an inability to find investors after the shale gas revolution collapsed merchant power economics were the spoilers. Hitachi’s suspension of the Wylfa Newydd ABWR project in Wales in 2019, after it had completed the UK Generic Design Assessment in 2017 and spent roughly £2 billion on development, was due to a deficiency in the financing structure, and not the reactor design or its licensing record.

Does the US need competition in large reactor technologies?

As mentioned in the introduction to this essay the U.S. Department of Energy has begun exploring alternatives to the AP1000. To the DOE, Westinghouse and its majority owner, the private equity firm Brookfield Asset Management, are moving too slowly. Utilities, for their part, want cost-overrun insurance that the current federal financing framework does not provide, and Westinghouse’s 2017 bankruptcy from Vogtle cost overruns is not a distant memory for anyone being asked to sign a new contract. Reporting by Alex Kaufman in March 2026 describes active engagement with GE Vernova Hitachi Nuclear Energy on potential deployment of the Advanced Boiling Water Reactor, alongside separate outreach to South Korean counterparts regarding the APR-1400.

The case for competition has precedent within the US nuclear industry itself. In the 1990s and 2000s, steam generator replacement outages across the operating fleet initially required roughly 200 days. Over successive projects, that window was compressed to approximately less than 30 days.

The improvement came from repetition across a series of similar projects combined with direct competition between Bechtel and Steam Generator Technologies (SGT). Utilities could observe divergent performance in real time. Schedules could no longer be defended as fixed physical constraints. Each iteration forced contractors to explain delays in operational terms rather than attributing them to inherent complexity.

A similar dynamic is visible in current reactor construction programmes abroad. China maintains parallel large reactor supply chains, building Chinese AP1000 units alongside the Hualong One. This structure keeps cost and schedule performance legible across competing designs and organizations.

The technical basis for introducing competition in the United States already exists. The ABWR holds a completed design certification in the United States, with multiple reference units constructed and operated. The remaining constraint is institutional rather than technological.

Does GE Vernova have the capability to build both large and small modular reactors?

The most important constraint on an ABWR revival is organisational capacity. GE Vernova through GE Hitachi Nuclear Energy, which holds the ABWR certification, operates with roughly 1,400 to 1,500 employees globally and is already fully committed to first of a kind BWRX 300 deployments in Tennessee and Ontario.

Those programmes require sustained focus across licensing, supply chain formation, and site execution. A large reactor programme would introduce a parallel effort with distinct engineering, procurement, and regulatory demands.

This reflects a structural shift. The organization that developed the ABWR and built the BWR5 and BWR6 fleet operated at larger scale within an industry that was building continuously. Today’s entity is smaller, more focused, and aligned around small modular reactor deployment, with capital and strategy directed toward the BWRX 300 and a reduced physical footprint following the sale of Vallecitos, GE’s historic BWR development site in California.

Alex Kaufman reports that the company has limited interest in reactivating the ABWR. An organisation of this size is unlikely to be able to sustain two separate reactor programmes simultaneously. The case for competition in reactor procurement remains, but it depends on whether any developer has the scale and execution capacity to deliver it.

Focusing on the wrong problems

The Western nuclear debate is hyperfixated on novel reactor designs as the solution to its decades-long struggle to build nuclear on budget and on schedule. The hope seems to be that a technological breakthrough or a novel concept will create a demonstrably superior reactor that will reverse decline and restore competitiveness with China.

Modularity, passive safety, novel coolants, TRISO fuel: these grab the headlines and drive funding cycles. Reactor design is no doubt a part of the equation. Modularity done well reduces field labour. Passive safety systems can eliminate backup diesel generators, reduce concrete and steel use and simplify cabling.

The ABWR however, illustrates that in nuclear the most consequential design gains often come from seemingly mundane construction and operations informed improvements rather than novelty. Nuclear technology iterates slowly and mature light and heavy water designs have taken 40+ years to arrive.

History however is clear that design alone, however well-conceived, is a relatively small portion of the ingredients that determine whether a reactor programme succeeds. Light water reactors despite significant design differences between PWRs and BWRs for instance have all converged on similar ranges of capacity factors, economic performance and construction schedules. There has not been a clear winner.

As the ABWR experience illustrates, what seems to really matter to successful deployment is design completion prior to construction and delivery by a competent project development organization, operating inside an industrial ecosystem that is active and staffed with experienced people at every level from project managers to tradespeople.

The West is currently disadvantaged after decades of relative inactivity within a broader shift in political economy towards deindustrialization and financialization. Supply chains have atrophied and experienced professionals are mostly retired.

As a result the Western nuclear renaissance, when it comes, will likely be a crawl before it learns to run again. Early projects will disappoint when measured against Japan’s record from the 1990s or China’s contemporary construction timelines. The central challenge of revival will involve sustaining political and financial commitment in spite of those disappointments while maintaining a laser focus on the lessons the ABWR experience has taught us.

Listen to the full conversation with James Krellenstein on the Decouple podcast.

Ten RITM-200 reactors have been manufactured since 2012 for five Project 22220 icebreakers, with eight already operating on the Northern Sea Route aboard the icebreakers Arktika, Sibir, Ural, and Yakutia. The RITM-200S is the FNPP optimized variant

As previously discussed on Decouple, rather than emerging from a clean-sheet SMR program the RITM descends in an unbroken line from the first generation of Russian nuclear submarines through three further generations of icebreakers accumulating over 400 reactor years of operation.

The mine these reactors will serve is not a marginal resource play. The Peschanka field within the Baimskaya licence area contains Joint Ore Reserves Committee (JORC) standard resources of 9.9 million tonnes of copper and 16.6 million ounces of gold, with annual ore processing capacity projected at 70 million tonnes. There is no grid, gas pipeline, or hydroelectric resource within reach, and diesel at this scale and remoteness is not a serious economic option.

Why Not Gas Turbines?

The choice of nuclear over gas turbines was not purely a matter of Arctic physics. Russia is no stranger to building gas infrastructure north of sixty; however, its large-capacity gas turbine industrial base has never been genuinely domestic.

High-capacity units above 100 MW were sourced overwhelmingly from Siemens, GE, and Alstom through licensed technology, joint ventures, and direct imports. The vulnerability of that arrangement became visible well before 2022. Siemens halted deliveries to Russian state-controlled entities in 2017 after four of its turbines were illegally diverted to Crimea in breach of EU sanctions. Then, after February 2022, GE stopped all servicing of its Russian-installed base under expanded US sanctions prohibiting engineering services.

Russia’s first genuinely domestic high-capacity gas turbine, Rostec’s GTD-110M, reached its inaugural commercial installation only in October 2024; serial production capacity of four units per year is not expected until 2028. At the scale required by Baimskaya, no sanctions-proof gas turbine solution existed or was imminent when the power contracts were drawn up.

Nuclear offered complete vertical integration within the Russian state system, spanning reactor design, fuel fabrication, hull construction, and the refuelling logistics chain at Atomflot, with no real Western sanctions exposure. The higher upfront capital cost was the price of autarky, and given the trajectory of Western sanctions policy, it was the rational price to pay.

The FNPP hulls are Chinese, built by Wison Heavy Industries at its Nantong yard, selected through competitive tenders on cost and schedule grounds over Russian and South Korean alternatives. Domestic yards run simultaneously at capacity on the Project 22220 icebreaker program.

Unlike Wison’s Zhoushan entity, sanctioned by the US Treasury for its work on Novatek’s Arctic LNG 2 project, the nuclear hull contract was placed with Wison’s Nantong facility, a legally and operationally distinct yard within the same corporate family. The Nantong facility’s supply chain, financing, and labour pool sit outside the transactional surface which Western sanctions were designed to reach. Thus no dollar-clearing bank, Western component supplier, or counterparty with secondary sanctions exposure are required.

Western Maritime Nuclear Myopia

Rather than carefully studying the Russians, the undisputed leaders in maritime SMRs, Western commentators tend to track NuScale’s regulatory milestones, Core Power’s fundraising announcements, or the latest molten chloride fast reactor rendering.

NuScale and Canadian firm Prodigy Clean Energy have proposed housing up to 12 NuScale Power Modules on a single marine facility, a concept that scales to 924 MWe on paper. Yet as former Decouple guest Aleksey Resvoi has pointed out, this proposal must contend with NuScale’s 20-meter tall “sky scraper” integral power module and containment vessel, which presents obvious stability problems aboard any hull experiencing real sea conditions.

An analogy which illustrates the difference in integral steam generator design philosophy between NuScale and the RITM is the maintenance gap between the American M1 Abrams and the Russian T-72. The Abrams is a genuine engineering achievement but runs on a 1,500-horsepower gas turbine which cannot be meaningfully repaired outside a depot, and whose filters clog in mud.

The T-72 runs on a diesel engine that a regimental workshop can overhaul. Soviet designers drew the line between crew-level and specialist maintenance differently, and drew it much further forward.

NuScale’s helical coil steam generators are thermodynamically clever, achieving compact geometry and high heat transfer surface area inside the integral vessel. They are, however, challenging to access and maintain.

The RITM uses replaceable steam generator cassettes with an explicitly designed 20-year service life, shorter than the reactor pressure vessel’s 60-year rating by intent. This accepts a modest thermodynamic penalty in exchange for cassettes that can be more easily extracted and replaced during scheduled maintenance. Major overhauls are conducted at Atomflot, Rosatom’s purpose-built nuclear fleet-servicing base in Murmansk, the only non-naval facility in the world with the infrastructure to handle operating maritime reactors.

Core Power has gone further into novelty territory here, partnering with TerraPower and HD Hyundai to pursue TerraPower’s Molten Chloride Fast Reactor (MCFR) for marine application. The MCFR proposes to use liquid chloride salt as both fuel and coolant, to operate at fast neutron spectrum, and to run at higher temperatures than conventional reactors. It has progressed from a non-nuclear integrated-effects test, running pumped-salt operations in a laboratory in Everett, Washington, towards a non-power critical experiment at Idaho National Laboratory targeted for approximately 2030.

Molten salt chemistries are corrosive, require exotic materials, and have never been operated continuously at commercial scale in any environment, let alone one subject to rolling, pitching, and wave slamming.

Pragmatism Wins the Day

The engineers who built the RITM understood that every design decision had to survive contact with the Arctic. They were not optimizing for thermodynamic elegance, waste minimization, or fuel cycle closure.

Russia kept iterating on light water because light water is proven. They now have 400 battle tested reactor-years of maritime operating history having harnessed the same design bureaus, test loops, materials laboratories, and institutional memory within a state-directed vertically integrated industrial system.

The West, while nostalgically clinging to narratives of nuclear energy dominance, keeps betting that start up culture and conceptual novelty will leapfrog its competitors’ steady investment, continuous deployment and iteration of proven technologies.

The RITM embodies everything Western policymakers say they want from an SMR: modularity, serial production, flexible deployment across marine, barge, and land-based applications, and a demonstrated fuel cycle.

With eight reactors already operating in Arctic conditions and 8 more under construction or fitting out, Baimskaya is the proof-of-concept that makes Rosatom’s FNPP export pitch credible in a way unmatched by any current Western maritime nuclear proposal.

The Floating Nuclear Power Plant Revolution may not be televised, but it will be Russian.

Imagine a technology that could take the most feared byproduct of nuclear power and transform it into fuel: burning the long-lived actinides that make spent fuel a supposed million-year liability down to fission products that decay to background radiation within a few centuries.

All of this while extracting enough energy from the 95,000 metric tons of nuclear waste sitting in pools and dry casks across the United States to power the entire country for 150 years.

That technology has been demonstrated. At Idaho National Laboratory, the Experimental Breeder Reactor II (EBR-2) ran for 30 years on metallic fuel cycled through an attached electrochemical reprocessing facility, closing the loop in exactly the way the vision describes: spent fuel in, fresh fuel out, waste reduced to a centuries-scale rather than geological-scale problem. The physics and engineering has been proven at pilot research scale. It has however failed to scale.

What did scale commercially looks considerably different. La Hague, the world’s largest reprocessing facility, has operated for the better part of a century. France built it not out of a romantic attachment to the closed fuel cycle but out a perceived energy security necessity: Almost no domestic fossil fuels, and, in the postwar decades, uranium supply chains that looked dangerously thin.

French reprocessing works. It has extended the country’s uranium utilization, deferred the need to mine fresh uranium by putting depleted enrichment tails and recovered plutonium back to work as MOX fuel, and given Paris a degree of fuel cycle independence that looks increasingly valuable as the theme of energy security once more rises to prominence with the Iran war and the closure of the Strait of Hormuz.

What French reprocessing does not do is meaningfully reduce the volume of material destined for deep geological disposal. But the La Hague program is not EBR-2. It is a pragmatic industrial process operating within the constraints of thermal reactor physics, and those constraints are severe. The gap between what France actually achieves and what the closed cycle promises is the central story of nuclear reprocessing, and it begins with understanding what is actually sitting in those spent fuel pools.

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What Spent Fuel Actually Is

When uranium fuel completes its working life in a reactor, it leaves behind a material of remarkable complexity. A fresh fuel assembly loaded into a pressurized water reactor contains uranium enriched to roughly 5% U-235, the fissile isotope that sustains the chain reaction, with the remaining 95% being U-238, which does not fission under thermal neutron bombardment but plays its own important role. Over the course of 18-24 months in the reactor core, several things happen simultaneously.

The uranium-235 is progressively consumed, splitting into fission products: a zoo of mid-weight atoms, many of them intensely radioactive, which accumulate in the fuel and increasingly poison the neutron economy in the reactor. Separately, some of the uranium-238 absorbs neutrons and transmutes into heavier elements. The most significant of these is plutonium-239, which is fissile and begins contributing meaningfully to the reactor’s power output. By the time a fuel assembly is discharged, roughly half of the energy being generated comes from this in-situ produced plutonium rather than from the original uranium-235.

What emerges from the reactor is therefore not simply depleted uranium. It is approximately 95% uranium, mostly uranium-238 with perhaps 1% uranium-235 remaining, around 1% plutonium spread across several isotopes of varying usefulness, and 3 to 4% fission products.

The fission products are what make spent fuel so radiologically hostile: short-lived but intensely radioactive isotopes generating substantial decay heat and penetrating gamma radiation. The barrier to reloading the spent fuel is primarily that the fission products have made the neutronic environment unworkable and the physical handling of the fuel intolerable. Reprocessing is, at its core, the project of separating the still-useful heavy metals from this contaminating matrix.

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The Manhattan Project’s Civil Legacy

The motivation for developing that separation capability did not originate in civilian power generation. Plutonium-239’s properties as a weapons material, chiefly its relatively modest critical mass compared to highly enriched uranium and its producibility from abundant uranium-238, made its extraction a military priority from the earliest days of the American atomic program.

The Hanford site in Washington State was separating plutonium for the Fat Man bomb before a single civilian reactor had generated a watt of commercial power. PUREX, the plutonium-uranium redox extraction process that remains the dominant reprocessing technology today, was a product of that program.

The civilian rationale came later, and it was genuinely compelling given what was known at the time. Postwar estimates of global uranium reserves suggested severe scarcity. If nuclear power was to provide a substantial fraction of the world’s energy, a once-through fuel cycle would exhaust available uranium within decades.

Reprocessing and breeding, in which fast neutron reactors would produce more fissile material than they consumed, appeared not merely attractive but necessary. Scientists at the Chicago Metallurgical Laboratory, working through the physics with the tools available to them, were not wrong to conclude that closed fuel cycles were the only path to long-term nuclear viability.

What they could not know was that uranium would prove far more abundant than early surveys suggested. As exploration intensified, reserves expanded dramatically, and the economics of fresh fuel remained stubbornly favorable relative to the cost of recycling.

When Jimmy Carter banned commercial reprocessing in the United States in 1977, framing it as a nonproliferation measure, the ban was already pointing at a technology that market forces had largely sidelined.

The commercial record made this plain. West Valley in New York, the only U.S. reprocessing plant that ever operated, ran from 1966 to 1972 before shutting down; the estimated cost of upgrades needed to meet newer regulatory requirements rose above $600 million, making restart uneconomic.

Barnwell in South Carolina was partially constructed but never operated: the 1977 policy reversal interrupted construction, and a subsequent GAO review found little commercial interest in completing it given a weak nuclear outlook, unresolved federal policy, and high costs.

The GE Morris plant in Illinois never operated as a reprocessing facility at all; cold testing revealed the technology was more complex than anticipated, the plant would have required extensive modification, and it became a spent-fuel storage site instead. When Ronald Reagan reversed Carter's ban in 1981, the commercial response was revealing: nothing happened. No reprocessing industry emerged. The economics had already delivered the verdict that a rowdy policy debate had obscured.

Inside La Hague

France is the exception that proves the rule, and La Hague is where that exception takes physical form. The largest reprocessing facility in the world, handling around 1700 metric tons of spent fuel per year (equivalent to roughly 17-20 full core loads) at peak operation, La Hague has been running in various forms since the late 1950s. Understanding what it actually does, step by step, is the only way to understand what commercial reprocessing can and cannot accomplish.

Spent fuel arrives in massive shielded transport casks, each containing perhaps a dozen fuel assemblies and weighing enough to require specialized rail or road transport. The assemblies must sit in cooling pools for months before processing begins, allowing the most intensely radioactive short-lived fission products to decay and reducing the thermal load to manageable levels. This waiting period involves a tradeoff that will become important later: the longer the fuel cools, the more certain isotopes decay into daughter products that complicate downstream handling.

When processing begins, the fuel assemblies are fed into a guillotine chopper: a hydraulically powered blade that slices the entire assembly, zircaloy cladding, ceramic fuel pellets and all, into segments roughly three centimeters long. This is the moment when cladding that has maintained a hermetic seal through 4.5 years of neutron bombardment releases in a single instant the fission gases that have been accumulating inside under pressure. Krypton, xenon, iodine and other volatile species must be captured and filtered rather than vented to atmosphere, and they constitute the first gaseous waste stream the process generates.

The chopped fuel segments then drop into boiling nitric acid. The acid dissolves the uranium dioxide ceramic and releases the heavy metals into solution while leaving the zircaloy cladding hulls behind as a solid residue. Those hulls, too contaminated by neutron activation and fission product migration to recycle economically, are compacted and stored as an intermediate-level waste stream.

What remains after the acid dissolution is a solution containing uranium, plutonium, fission products, and minor actinides all dissolved together. This solution is then contacted with tributyl phosphate dissolved in a kerosene like hydrocarbon solvent. Here is where the chemistry gets elegant: uranium and plutonium, unlike the fission products, preferentially migrate into the organic phase. By manipulating the oxidation states of uranium and plutonium relative to each other, exploiting the fact that they behave differently under different redox conditions, the process separates them into distinct streams with around 99.5 percent recovery efficiency. The fission products, stripped of the heavy metals they were mixed with, remain in the aqueous phase with almost no cross contamination.

Those fission products are then concentrated, calcined, and incorporated into borosilicate glass, poured into steel cylinders and stored at La Hague. If the fuel came from a foreign utility, France is contractually and legally obligated to return these cylinders to the country of origin, which has created its own geopolitical complications over the years with Japan and Germany. The uranium stream and plutonium stream depart the process separately, each carrying their own challenges.

What the Process Actually Reduces

It is worth pausing on a claim the reprocessing narrative tends to treat as settled: that PUREX substantially reduces the volume of waste requiring deep geological disposal.

The standard figure, repeated by the World Nuclear Association and the IAEA alike, is an 80 to 85 percent reduction in high-level waste volume compared to a once-through cycle. That number is technically defensible in one narrow sense. It compares the volume of vitrified fission product glass canisters against the volume of intact spent fuel assemblies, and since uranium makes up roughly 94 percent of spent fuel by mass, removing it does dramatically shrink the pile of material formally classified as high-level waste. But the comparison omits something important.

In a once-through fuel cycle, the depleted uranium tails from enrichment are a low-level waste problem at most. They are mildly radioactive, carry no fission products, and do not require geological disposal.

When France takes that material, mixes it with separated plutonium to fabricate it into MOX fuel, and irradiates it in a reactor, the depleted uranium that would never have required a deep repository has been converted into spent MOX fuel that under current conventions does.

In addition spent MOX fuel is several times more radioactive than equivalent spent LEU fuel, and its decay heat declines more slowly, meaning it occupies more effective repository space per assembly than the fuel it replaced.

Reprocessing generates multiple additional waste streams that intact direct disposal does not: compacted zircaloy hulls and hardware from fuel disassembly, low- and intermediate-level liquid wastes from the PUREX chemistry, contaminated resins and solvents, and solidified residues from effluent treatment. Each of these streams requires its own handling, conditioning, and disposal pathway.

The total volume of material requiring regulated disposal across all these categories exceeds what would have resulted from simply burying the original spent fuel assemblies whole. Reprocessing does not reduce the waste problem so much as it disaggregates and redistributes it across a more complex and costly management chain.

Standard PUREX also leaves the minor actinides, americium, curium, and neptunium, in the fission product waste stream rather than recovering them. These are the isotopes with very long half lives responsible for most of the radioactivity in the hundred-thousand-year timeframe that regulators believe make deep geological repositories a civilizational-scale engineering necessity.

What reprocessing in a thermal reactor cycle does avoid is one fresh mining cycle and one batch of enrichment tails: a real but narrow benefit, achieved at significantly greater expense and effort.

The Isotopic Trap

The plutonium stream that emerges from PUREX is not weapons-grade material, and understanding why illuminates one of the central constraints on the entire reprocessing enterprise.

Plutonium-239, the isotope produced when uranium-238 absorbs a single neutron, is fissile and desirable both for weapons and for fuel. But uranium-238 does not stop absorbing neutrons after producing plutonium-239. Successive captures produce plutonium-240, which is not thermally fissile and constitutes a neutronic burden; plutonium-241, which is fissile; and plutonium-242, which is not. The longer fuel remains in a thermal reactor, accumulating burn-up, the more the plutonium inventory shifts toward these higher isotopes.

A reactor optimized for weapons-grade plutonium production would discharge fuel after only a few weeks, with burn-up measured in single-digit gigawatt-days per tonne. A commercial power reactor runs its fuel to fifty or sixty gigawatt-days per tonne, producing plutonium that is substantially degraded from a fissile quality standpoint.

This isotopic degradation compounds with each reprocessing cycle. In a thermal reactor, plutonium-239 and plutonium-241 are consumed preferentially during irradiation while plutonium-240 and plutonium-242 accumulate.

After one pass through a MOX fabrication and irradiation cycle, the recovered plutonium contains a significantly higher fraction of non-fissile even numbered non-fissile isotopes. After a second pass, the material is approaching the point of limited utility in a thermal neutron spectrum. The twice-through-then-out cycle that France actually operates is not a policy choice made for lack of ambition; it reflects the physics of what thermal reactors do to plutonium.

The uranium stream carries its own complications. Reprocessed uranium (RepU) is not natural uranium. It contains uranium-236, a neutron absorber that reduces reactivity and uranium-232 which relatively quickly decays through a chain that produces thallium-208, an energetic gamma emitter that makes the material progressively more difficult to handle as it ages. To put it coarsely, instead of aging into a fine wine, reprocessed uranium deteriorates into mouldy grapes. Fabricating it into fresh fuel requires higher enrichment levels and handling radioactive feedstock on production lines designed for essentially inert natural uranium powder, demanding remote or shielded operations where direct human contact was previously routine.

At La Hague, the recovered uranium stockpile has grown for decades. France stores it in the hope of eventual use but has not found an economically or practically compelling route to deploying it at scale. It is the program’s largest stranded asset.

MOX: What the Plutonium Actually Becomes

The separated plutonium does have a destination. Mixed oxide fuel, combining recovered plutonium with depleted uranium tails from the enrichment process, is loaded into 15-20 of France’s fifty-four operating reactors. This is the practical expression of the entire PUREX enterprise, and it functions but with constraints that reveal the limits of the technology in a thermal reactor context.

Fresh LEU fuel contains roughly five percent uranium-235 as its fissile component, with uranium-238 making up the remainder. MOX fuel substitutes plutonium for that fissile loading, with the fissile plutonium fraction typically running between 4 and 8% depending on the isotopic quality of the recovered material and the desired burnup target. The depleted uranium carrier, with its negligible uranium-235 content, is essentially inert from a fission standpoint. From an energy density perspective, the two fuels are broadly comparable in a reactor core

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The neutronic differences are real, however. Plutonium fission produces a shorter delayed neutron lifetime than uranium-235 fission. Delayed neutrons, the tiny fraction of neutrons emitted seconds after fission rather than instantaneously, are what make thermal reactors controllable on human timescales. A reactor core with a higher plutonium fraction responds more rapidly to reactivity perturbations, tightening the margins that operators and control systems manage.

France limits MOX loading to around 30% of any given core not because higher fractions are physically impossible, but because they would require operators trained and equipped for a reactor that behaves differently from every simulator they have used.

The AP1000 and EPR were designed with full MOX capability in mind, incorporating the additional control authority that a 100 percent MOX core demands, but that capability has not been commercially exercised.

A CANDU solution to the RepU problem? Natural Uranium Equivalent (NUE)

The accumulating stockpile of reprocessed uranium (RepU) at La Hague poses a difficult challenge. CANDU reactors, which run on natural uranium and use heavy water as both moderator and coolant, operate with such a thermally efficient neutron economy that they can sustain criticality on fuel enriched well below the threshold required for light water reactors. RepU, with its residual uranium-235 content of around one percent, sits above the natural uranium threshold and looks, at first glance, like a natural feedstock for a heavy water reactor. The advanced fuel CANDU reactor concept, pursued through a joint venture between Candu Energy Inc. and China National Nuclear Corporation attracted enough political weight to bring the Chinese Premier Li Keqiang and Justin Trudeau to the same signing table.

The concept has genuine logic. Canada possesses the reactor technology capable of using the material. China, which is expanding its commercial reprocessing capability will soon possess RepU in quantities that would otherwise sit indefinitely in storage. This RepU could be fashioned into Natural Uranium Equivalent fuel (NUE) by downblending it slightly with depleted uranium from enrichment tails to be used in CANDU reactors. Both parties saw the potential benefits. What the demonstration program revealed was how much difficulty lies between an appealing concept and a functioning fuel fabrication process.

The small-scale fabrication of the 24 NUE bundles manufactured for the demonstration irradiation was more difficult than foreseen. Specifically selected batches of depleted uranium were needed to match the batches of recycled uranium to achieve an equivalent weight percent uranium-235 to fabricate the pellets.

There were problems with dry blending the depleted uranium and recycled uranium for sintering the pellets, because the grain sizes of the uranium dioxide powder had very large variations. To overcome this issue, the material had to be dissolved in acid and put through a conversion process back to uranium dioxide powder, essentially reintroducing a wet chemistry step into a fuel fabrication process whose simplicity was part of the CANDU value proposition. The challenges with large-scale production were not resolved. NUE has not been used further in the Qinshan reactors.

The reasons reach beyond fabrication difficulty. A CANDU fueling machine loads individual bundles into pressure tubes that run horizontally through the reactor, with fresh and spent bundles moving through each channel during power operation.

A core loaded with RepU bundles of variable enrichment introduces neutronic asymmetries that the standard operating model was not designed to manage. The uranium-232 decay chain imposes a time pressure on using the material before it becomes too radioactive for conventional handling. Lastly the reprocessed uranium’s isotopic composition, variable across different source batches and different cooling histories, resists the kind of precise characterization that stable reactor operation demands.

Each obstacle individually might be surmountable; collectively, they have proven sufficient to stall the program.

The Fast Reactor Promise and Pyroprocessing

Everything described so far takes place in the thermal reactor world, where neutrons are moderated to low energies and the isotopic limitations of recycled plutonium become progressively more binding. The genuine closure of the nuclear fuel cycle, the version where ninety-five thousand metric tons of American spent fuel might theoretically power the country for a century and a half, requires a different neutron spectrum entirely.

Fast reactors, in which unmoderated neutrons sustain the chain reaction, can fission isotopes that thermal reactors cannot. Plutonium-240, the accumulating burden of every thermal reprocessing cycle, fissions readily under fast neutron bombardment. So do the minor actinides: americium, curium, neptunium, that constitute the long-lived hazard in spent fuel.

A fast reactor with a closed fuel cycle does not merely extend uranium utilization; it progressively burns down the transuranic inventory that makes geological disposal a deep-time engineering problem. The fission products that remain are genuinely short-lived on geological timescales, decaying to background levels within a few centuries rather than hundreds of thousands of years.

The reprocessing technology best suited to this vision is pyroprocessing rather than PUREX. Instead of dissolving spent fuel in nitric acid and manipulating liquid-liquid extraction chemistry, pyroprocessing dissolves metallic fuel in a molten chloride salt and applies an electrical potential across electrodes.

Heavy metals migrate electrochemically, leaving fission products behind. The process does not separate plutonium from uranium or other actinides for that matter. They all migrate together, which is simultaneously a proliferation advantage and an operational feature for fast reactor fuel cycles that want to keep them mixed. EBR-2 at Idaho National Laboratory ran for decades on metallic fuel with an attached pyroprocessing facility, demonstrating the integrated concept at a small research scale.

The gap between that demonstration and commercial deployment encompasses the entire history of fast reactor development. Despite heroic efforts by the USA, Japan, France, India, Russia and China, no fast reactor has achieved the reliability and economics of the mature light water reactor fleet. In fact the only fast reactors currently operating at all are two units in Russia, one in China and one in India, the PFBR, which achieved its 1st criticality on April 6th of this year after more than 20 years of construction.

The fuel required for pyroprocessing, metallic uranium-plutonium-zirconium alloy, is used in no commercial power plant anywhere in the world including those Russian, Chinese and Indian fast reactors all of which use MOX.

Pyroprocessing has been demonstrated in batches measured in kilograms, not the hundreds of tonnes per year that a meaningful contribution to spent fuel disposition would require. The economic structure of building new pyroprocessing capacity is significantly impacted by capital cost recovery. If built the early decades of operation will impose a heavy fixed-cost burden regardless of throughput. La Hague can offer relatively competitive reprocessing because its capital costs are long since written down; a new pyroprocessing facility would need to recover its full construction cost against a fuel market priced on the marginal economics of existing enrichment capacity. Oklo’s peak valuation of $21 billion reflects the market’s appetite for the narrative more than its assessment of the near-term industrial reality.

The Permanent Condition

America’s 95,000 metric tons of spent fuel await disposal. The physics and processes that make them potentially valuable is proven and has not changed. Uranium-238, transmuted to plutonium and cycled through fast reactors with pyroprocessing, could in principle extend the energy yield from existing fuel stocks by factors that dwarf what PUREX and MOX achieve in practice.

What the history of reprocessing demonstrates however, is that the distance between physical principle and economic reality is vast. As with many compelling solutions to vexatious problems the pilot program exists. Scaling and making a process commercially viable remain the core challenge determined in this case by isotopic decay chains, tight fabrication tolerances, material accounting protocols, and high capital costs amortized over small batches of fuel for reactors that have failed to become commercially viable.

France has run the world’s most ambitious civilian reprocessing program for the better part of a century and extended its uranium utilization by roughly 10% at the fleet level. This is a meaningful achievement but far from being transformative.

Nuclear energy lives permanently in this tension. It must bridge the gap between compelling narratives and the grinding cost and difficulty of the engineering.

Reprocessing has arrived at the destination the physics and economics permitted, which turned out to be considerably short of where the dream was pointing.

The complexity of conventional oil sits at the importer’s end in multi-billion dollar refineries which take years to build.

LNG is almost the opposite: its complexity sits at the exporter’s end, locked inside exquisitely engineered liquefaction infrastructure. On the importer’s side warming the liquid back to its gaseous state requires little more than running seawater over a heat exchanger.

The Germans demonstrated this at breakneck speed during the energy crisis of 2022. They built 5 floating storage and regasification units, essentially modified LNG tankers moored offshore. The fastest was stood up in under seven months.

Once regasified the pressure is managed, a pipeline is run to a combined cycle gas turbine, and voila you have electricity. Those power plants are assembled in 24 to 36 months from factory-built components with very low construction risk. They achieve close to 60 percent thermal efficiency, making them the most thermodynamically elegant large-scale power plants ever constructed.

The complexity on the production side is a different matter entirely. Each liquefaction train at Ras Laffan represents roughly $7 billion in capital investment. The process reduces its volume by roughly 600 times through cryogenic cooling, getting it down to the minus 162 Celsius threshold where it occupies a manageable volume for ocean transport.

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This is the asymmetry that explains why so many countries made what seemed like rational energy security bets on LNG. The capital burden on the importing side was manageable and the long term contracts relatively affordable. Supply during an era of open sea lanes and reliable contracts, looked stable.

Unlike crude oil, where pricing is anchored to deep, globally traded benchmarks and a highly liquid spot market, LNG remains structurally tied to long-term bilateral contracts necessary to cover the high capital cost of liquefaction facilities.

Today roughly 60% of global LNG volumes are committed under such contracts, leaving a relatively thin pool of uncontracted supply. Most cargoes are pre-allocated, so a country reliant on Qatari volumes cannot readily switch to Australian or U.S. supply at short notice. In a global supply crunch these buyers are pushed into the spot market, where competition for a relatively thin pool of uncommitted cargoes drives prices sharply higher.

Even as the U.S. brings new liquefaction capacity online, LNG supply remains slow to adjust. New trains are costly and can take close to a decade from initial planning to first cargo, leaving limited spare capacity to absorb sudden disruptions.

The 2022 European gas crisis offered a deceptive lesson. Germany solved it by building receiving infrastructure fast, which made LNG look resilient. That was however an importing problem, not a production problem. Global liquefaction capacity was intact and US production was surging. The receiving end of LNG bends to political will, tight timelines and emergency permitting. Destroyed liquefaction infrastructure does not.

In the year or so since it became clear that the second Trump administration and Republican Congress were intent on dismantling the Inflation Reduction Act (IRA), a particular intellectual formation has hardened among climate-focused commentators in the West.

The argument runs as follows: China has identified that the industrial commodities of the 21st century as solar panels, batteries, electric vehicles, and the rare earth magnets inside wind turbines and EV drivetrains. By pouring state capital into manufacturing all of these at an overwhelming scale, China has positioned itself as the dominant industrial power of the coming era.

The United States, by contrast, has chosen fossil fuels and is becoming a museum of obsolete technologies, to use Bill McKibben’s phrase. China, in this reading, is not just winning an industrial competition. It is saving the climate.

Historian Nils Gilman, writing in Foreign Policy, envisions an “eco-ideological Cold War” pitting a potential Sino-European green entente against a US-led petro-bloc. Noah Smith writes that China is “quietly saving the world.” James Meadway declares that China has “obliterated” the argument that nothing can be done on climate because of China.

The electrostate thesis, as it has become known, holds that China is reorganizing its entire economy around electricity, increasingly sourced from wind and solar, and that this transformation is both a play for industrial supremacy and an inadvertent path to global decarbonization.

There is enough truth in this picture to make it influential. China installed 315 GW of new solar capacity in 2025 bringing its cumulative installed PV capacity to 1.2 TW nearly the entire installed capacity of the US grid. China’s solar manufacturing dominance is extraordinary. Its battery supply chain is, by most measures, unassailable on any near-term horizon. Its electric vehicle industry has crossed an inflection point that now looks permanent. These facts are not in dispute, and the cost reductions China has driven in solar and batteries have been genuinely transformative.

The problem is that the thesis is constructed almost entirely from what is visible at the output layer, from the finished solar panel, the EV on the road, the battery pack. Follow the supply chain upstream, ask what industrial system produced those things and what powered that system, and a very different picture emerges.

There is a Ford Motor Company promotional film from the mid-twentieth century that traces the full manufacture of an automobile from the first blast of explosives in an iron ore mine, through smelting, rolling, stamping, and final assembly. Its purpose was to celebrate American industrial integration. It functions equally well today as a corrective to how Western observers think about Chinese manufactured goods. We see the finished product and construct a story about the civilization that made it. We do not however ask what was burned to produce it.

The Ballast Rock

China’s own government is clearer about its energy system than its Western admirers tend to be. Official policy statements and domestic media describe coal as the “ballast rock” of China’s energy supply, providing cheap electricity, industrial heat, and chemical feedstocks for the bulk of the industrial economy. Coal generated 59 percent of Chinese electricity in 2024. China consumes 56 percent of all coal used globally. Vanishingly little coal capacity has been fully retired, only 2.5 GW in 2024.

The construction pipeline makes the trajectory plain. The desert industrial parks in Xinjiang tell the same story: more than half a dozen coal generation units, several of them commissioned since 2022, supplying aluminum reduction cells, metal silicon furnaces, and the ultra-pure polysilicon plants that feed China’s solar manufacturing supply chain.

Shaanxi’s coal to chemicals industry, centered on the city of Yulin, continues to expand with government backing: the National Development and Reform Commission (NDRC) has classified coal-derived chemicals as a ‘new productive force’ in the same policy breath as solar panels and electric vehicles.

Here’s a fact for China’s climate cheerleaders to mull over. As Javier Blas has pointed out, if China’s coal to chemicals industry was a country it would rank as the world’s third largest consumer of coal, trumped only by the rest of the Chinese coal sector and India’s national consumption, but ahead of the major coal users like the US, Japan, Indonesia and Turkey.

The claim that China is becoming a green electrostate sits alongside an operational coal fleet of 1300 GW with 261 GW of coal capacity either under construction or already permitted. While some are ultra-supercritical coal plants which now serve as flexible backup and load-smoothing assets for variable renewables, this fleet is not a legacy sector approaching retirement. Many are fresh investments in the sectors the electrostate narrative holds up as proof of China’s clean industrial future.

China will not retreat from coal for ideological reasons, as the European bloc has done with both coal and nuclear. Chinese planners have reasons to retire older, less efficient plants and reduce coal combustion near urban centres, but there is no structural incentive to remove a working power source from a system still growing at roughly 7 percent per year in electricity consumption.

Aluminum as a Diagnostic

An insightful case study for what is actually happening in China’s industrial economy is aluminum, sometimes referred to as “congealed electricity.”

Making a ton of primary aluminum requires roughly 13,000 kilowatt-hours (kWh) of electricity. To put that in terms that register: producing one kilogram of aluminum consumes about as much electricity as running an average North American house for twelve hours, while recycling a kilogram of steel in an electric arc furnace (EAF) takes roughly half an hour of equivalent draw.

The aluminum industry has always chased the cheapest available power. It built smelters next to the Bonneville Power Administration and the Tennessee Valley Authority (TVA) in the United States, next to dedicated hydroelectric dams in Iceland and Norway, and in Quebec, where legacy hydro produces electricity at costs no thermal plant approaches. American aluminum, which has shrunk to one sixth of its peak production of 4.6 million tonnes/yr in 1980, used to receive half its power from federal or state-owned utilities.

China now produces roughly 60 percent of the world’s primary aluminum, about 45 million tons per year, against a domestic capacity cap set by the NDRC to prevent further oversupply.

The electrostate narrative around Chinese aluminum runs as follows: production is migrating from the coal heartlands of Shandong province toward Inner Mongolia and Xinjiang, where renewable energy development has accelerated, and toward the hydropower-rich southwestern provinces of Yunnan and Sichuan.

The implication is that one of the world’s most electricity-intensive industries is being progressively decarbonized by the same renewable buildout reshaping China’s broader grid.

The timeline punctures this immediately. The majority of new aluminum capacity in Inner Mongolia and Xinjiang was built before 2020, before large-scale wind and solar deployment in northern China, and before the central government introduced any renewable energy purchasing requirements for the sector.

These smelters relocated to the northwest because coal was cheap there, and local governments were offering captive coal power at rates that made the economics irresistible.

The renewable energy purchasing requirement, mandating that smelters source a portion of their electricity from clean generation, was introduced only in 2024, and currently sits at around 30 percent for Inner Mongolia and Xinjiang.

Even on paper, even counting purchased renewable energy certificates rather than electrons physically flowing from wind turbines to reduction cells, these smelters remain predominantly coal-powered.

And paper is doing considerable work in that sentence. Upward of 80 percent of aluminum smelters in Inner Mongolia, and practically all of those in Xinjiang, have on-site captive coal power plants. There is nothing transitional about that infrastructure. The renewable purchasing requirement’s 30% cap is itself an admission that the economics of running these smelters on wind and solar do not close.

The Yunnan story is more favourable to the green narrative. Southern China’s hydropower provinces have genuine surplus generation capacity, and the Hongqiao Group, operating its aluminum business under the Weiqiao brand, has been aggressively moving capacity to Yunnan to capture cheap hydro before the NDRC production cap forecloses further expansion.

About 15 percent of China’s aluminum capacity now sits there. This represents genuinely lower-carbon production, but it is opportunistic: companies racing to claim cheap electrons while they still can, not a planned industrial transition toward renewable power.

Taking the full picture, roughly 25 percent of China’s aluminum production is hydropower-sourced. The other 75% runs on coal.

The Un-Electrification of Magnesium

If aluminum complicates the electrostate thesis, magnesium inverts it entirely. Before the late 1990s, most of the world’s primary magnesium was produced electrolytically, through a process broadly similar to aluminum smelting, using seawater-derived magnesium salts reduced through electrolysis. Production was spread across the United States, Norway, France, and Canada. The process was electricity-intensive but coal-free.

China industrialized magnesium production through a completely different route. The Pidgeon process, a pyrometallurgical method using carbon-based reduction of magnesium-bearing ores in small batch-operated furnaces, requires almost no electricity.

The coal chemical heartland of Shaanxi province became the global capital of magnesium production not because it had clean power or innovative electrolysis technology, but because it had coal to burn and workers to tend furnaces, and the economics of attaching a small magnesium shop to an existing coal chemical complex made the product nearly free at the margin.

The result was the complete elimination of Western electrolytic magnesium production. Today, over 95 percent of the world’s primary magnesium, a market of roughly one million tons per year, is produced in China through the Pidgeon process, almost entirely as a byproduct of coal chemistry.

Magnesium matters beyond its own market. It is a critical input for aluminum alloys and lightweight automotive and aerospace structures, which means it sits directly in the supply chain of the very EV revolution the electrostate narrative celebrates.

However, the electrostate, in this corner of the periodic table, ran in reverse. Magnesium production was deliberately un-electrified by China to achieve cost dominance and the climate movement has nothing useful to say about it because it contradicts the entire narrative.

The Electrotech Stack and Its Foundation

Zoom out from aluminum and magnesium to the full set of supply chains the electrostate argument relies on, and a structural pattern becomes visible that the narrative consistently elides.

The five supply chains at the core of the electrostate thesis, solar cells, lithium-ion batteries, rare earth permanent magnets, semiconductor-grade silicon, and the metals that go into EV structures, all share characteristics that are more explanatory than their clean end uses.

In each, China accounts for 75-94% of global production. The consumer-facing product sits downstream of an upstream processing step that is not modular, not easily replicated, and not captured by the language of the tech economy.

The electricity intensity of each of these upstream steps is extraordinary: solar-grade polysilicon requires five times as much electricity per unit mass as aluminum. Battery graphite matches aluminum’s energy consumption. Synthetic graphite, which accounts for 97 percent of global graphite anode production and is produced almost entirely in China, was built up in coal-intensive provinces precisely because the energy-intensive reduction process was cheapest where coal was cheapest.

China’s dominance in these industries was built between roughly 2005 and 2020, during the last great wave of coal capacity construction, when cheap and reliable thermal power allowed Chinese firms to accumulate the process knowledge, engineering expertise, supply chain integration, and economies of scale that now make these industries effectively uninvestable for outside competitors.

A cohort of chemical engineers who graduated from Chinese universities between 1980 and 1995, and spent their careers building polysilicon reduction plants, battery cathode factories, and rare earth processing facilities, is the actual foundation of Chinese industrial dominance in the electrotech stack.

The solar panels and wind turbines are the visible surface of a structure whose load-bearing elements were built in coal smoke, and the timeline matters: the dominance preceded the renewables buildout, rather than resulting from it.

What Chinese Energy Policy Actually Is

The electrostate framing imposes an ideological coherence on Chinese energy policy that the evidence does not support. China’s strategy is better understood as systematic, unsentimental diversification across every available energy vector simultaneously, driven by the specific vulnerability of importing roughly 12 million barrels of oil per day, much of it transiting the Strait of Hormuz.

China electrifies not because it has identified electricity as the industrial commodity of a new era, but because liquid hydrocarbons represent its central strategic exposure and domestic electricity generation is the domain where it has resource options.

China doubled its domestic natural gas production between 2015 and 2025 and will likely surpass Iran this year to become the world’s third-largest gas producer.

It has 200 GW of gas-fired generation capacity, roughly four times its nuclear fleet by installed capacity. Renewables are one strand of a deliberately plural strategy, and the electrostate thesis mistakes that strand for the organizing principle of the whole.

The think tank Ember Energy has described China’s coal flexibility as evidence of innovation, praising the retooling of coal plants as ideal partners for solar and wind. Ember’s framing is a good example of how the green electrostate thesis works in practice: China’s clean energy activities are foregrounded, and everything that complicates the picture is reframed as further evidence of sophistication.

Forget Climate Change, Can America Catch up in Aluminium?

The United States finds itself in an uncomfortable position. With aluminum tariffs applied to treaty allies, a domestic smelter fleet whose newest facility entered service in 1980, and primary aluminum production of 680,000 tons per year against consumption many times that figure the situation is grim.

The tariff logic is not entirely without merit: rebuilding capacity in strategically important metals is a legitimate national security objective, and China’s practice of building new coal-fired aluminum capacity in Indonesia and Vietnam as joint ventures, once the NDRC domestic cap was reached, demonstrates that the competitive pressure will not relent.

But the mechanism is badly matched to the problem. The average US aluminum smelter consumes 12 to 18 % more electricity per ton than its newest Chinese or Canadian competitors, a penalty reflecting decades of deferred investment. Power costs for US smelters exceed $60 per megawatt-hour (MWh); Canadian smelters pay $20 to $30.

The Aluminum Association has calculated that even a retrofit of an existing US smelter requires a power supply contract below $40/MWh to be financially viable. Tariffs move the commodity price. They do not move the electricity price, and the electricity problem is about to intensify, because a new million-ton smelter requiring 1.5 gigawatts of grid interconnection now competes for queue position with electricity hungry data centers operated by Microsoft, Google, and Amazon.

The structurally honest answer to the question of how the West rebuilds aluminum competitiveness might involve Alaska hydropower development and coordinated allied industrial policy with Canada, Europe, and South America, rather than the transactional trade war currently being waged against precisely those partners. Quebec’s legacy hydro system, producing electricity at costs no thermal plant can match, is a strategic industrial asset on the US border. Tariffing the aluminum it produces is an unusual way to secure an essential commodity.

What the Argument Requires You to Ignore

China emitting 25 % of global greenhouse gases is not a detail that can be resolved by pointing to its solar manufacturing output. The industries driving those emissions achieved Chinese dominance through a coal-powered learning curve that has not been reversed. The rate of emissions reduction in China’s industrial sector is slowing, not accelerating, as the low-hanging fruit of textiles electrification and cement demand decline gets exhausted.

If the goal is Western industrial and military competitiveness, the relevant question is what it would actually take to replicate or contest the system built between 2005 and 2020 by engineers who are now the most experienced in the world at what they do, working in an industrial ecosystem that was capitalized by cheap coal.

The answer is not flattering to any currently available Western policy agenda, which may partly explain the appeal of narratives that avoid the actual industrial mechanics of the competition.

The tariff instinct draws on a genuine historical memory: nineteenth century American industrial policy, the infant industry protectionism of the Hamilton Report and the high tariff era that followed, did help build domestic manufacturing capacity, and did so at a moment when the United States was catching up to British industrial dominance. The analogy is not absurd on its face. But that era involved building the underlying industrial infrastructure from scratch in a country with abundant coal, cheap land, and a rapidly expanding domestic market.

The current situation involves trying to rebuild capacity that was deliberately offshored over four decades, in an energy market where the cheapest available electrons are in Canada and Norway, against a competitor that accumulated irreplaceable process knowledge during a specific historical window that has now closed.

Nineteenth century tariff logic assumed you could build the thing if you protected the market long enough. The aluminum problem is not primarily a market problem. It is a power price problem, a supply chain knowledge problem, and a capital commitment problem, none of which a tariff schedule resolves.

On the climate front believing that China will take the world through the looking glass to net zero by 2050 requires believing that a country whose government describes coal as its energy ballast rock and which hosts captive coal power plants physically attached by conveyor belt to its most advanced manufacturing facilities, will undergo a transformation so complete and so rapid that it overrides the physical and economic inertia of all of that invested infrastructure.

The fact that this prediction finds a receptive audience in the Western climate movement is telling. It is what happens when people confronting what they believe to be an existential threat exhaust the available policy options.

The desperate need for a solution that produces a powerful appetite for evidence that someone, somewhere, is solving the problem at scale. China’s solar deployment numbers are impressive enough to feed that appetite. Everything upstream of the solar panel is easy to ignore, especially if looking at it means that the narrative collapses.

China’s clean energy manufacturing is real, consequential, and has permanently changed the economics of solar and batteries for the rest of the world. The industrial system that produced it is still, predominantly, powered by coal, and the Chinese government has told us so, repeatedly, in its own policy documents.

This essay accompanies a Decouple conversation with Seaver Wang, Climate and Energy Director at the Breakthrough Institute and co-author of “Greenwashing with Chinese Characteristics,” published in the Breakthrough Journal. If you find this work valuable, consider supporting Decouple by pledging on Substack or making a tax-deductible donation through our fiscal sponsor at Givebutter.

The Puzzle the Market Is Posing

Doomberg is back on Decouple. As one of the sharpest numerically-grounded voices writing about energy markets, he opened our recent conversation with a puzzle: given everything that has happened, the numbers simply should not look like this.

Venezuela’s president was arrested and extradited to New York, the United States imposed an embargo on Cuba, and a hot war with Iran has left the Strait of Hormuz closed and tankers sunk. Iranian missiles destroyed two liquefied natural gas (LNG) trains at Qatar’s Ras Laffan industrial complex, taking roughly 17 percent of Qatari production capacity offline for an estimated five years, while Ukraine continued its campaign against Russian oil tankers and refineries.

Had you presented that full scenario to any energy analyst six months ago and asked them to price oil, almost nobody would have said $98 West Texas Intermediate (WTI) and $110 Brent. Most would have taken the over on $150 without a second thought.

The relative calm in price action requires explanation. Oil’s share of global primary energy has fallen from around 50 percent at the time of the 1973 Arab oil embargo to roughly 35 percent today, meaning a given volume disruption transmits less shock into the broader economy than it once did.

The actual supply disruption running through the Strait of Hormuz is currently around eight to ten million barrels per day rather than the theoretical maximum of twenty, and China alone holds 1.5 billion barrels of strategic reserve, enough to absorb five million barrels per day of that shortfall for 300 days if deployed at scale.

None of this means the crisis is trivial. The pain is real and unevenly distributed. The question it poses, especially for Europe, is whether the shock is finally severe enough to force a reckoning with thirty years of decisions that left the continent structurally exposed in ways that were at least partially avoidable.

What the 1970s Actually Built in Europe

The European response to the OPEC embargo was an impressive mobilization that moved decisively and pragmatically taking advantage of the unique conditions available throughout the bloc.

France

France moved decisively launching the The Messmer Plan in direct response to the oil shock. It remains the fastest large-scale nuclear buildout in history. France had little domestic oil, but it had everything else the program required: a large corps of state-trained engineers produced by the Grandes Écoles, heavy industrial capacity rebuilt under the postwar dirigiste economic model, and a nationalized utility in Électricité de France (EDF) already accustomed to executing at the direction of the state rather than waiting on market incentives.

Its political class drew the logical conclusion: electrify aggressively around a domestic nuclear base, using a standardized reactor designs that a purpose-built supply chain could replicate at pace. Space heating, water heating, rail and significant portions of industrial process heat were shifted onto the grid as the fleet came online, deliberately substituting domestic electrons for imported hydrocarbons across as much of the economy as the technology of the era allowed.

The result over roughly twenty years was 54 operating reactors, an electricity system generating around 75 percent of its output from nuclear, net electricity exports to neighbours who had made different choices, and as an unintentional side effect a per-capita carbon footprint in the power sector that remains among the lowest in the developed world.

Britain Norway and the North Sea

Britain and Norway answered through a different channel with the same underlying instinct. The North Sea had yielded promising geological discoveries before the embargo, but the post-shock period transformed offshore petroleum into a central national project on both sides of the median line.

The technical obstacles were formidable: deepwater fields in rough northern seas, novel platform engineering, supply chain development for equipment categories that had barely existed before.

Both governments pressed through, operating under a governing assumption that sounds almost exotic in Brussels today, namely that a country should develop strategically important resources under its own waters when those resources can materially improve national resilience.

Within roughly a decade Britain had moved from significant oil importer to net exporter. Combined British and Norwegian output contributed materially to the global oil supply glut that emerged through the 1980s. The glut that always follows a supply shock once investment finally responds to price signals was this time in part European.

German Gas Diplomacy

West Germany’s answer came through diplomacy and welded steel. The first Soviet gas began flowing west through the Brotherhood pipeline in 1968, predating Ostpolitik’s formal articulation but embodying its central intuition: that a Russia earning deutschmarks from gas exports had a material interest in stable relations, and that pipelines, unlike armies, are hard to redeploy.

The 1973 embargo deepened that conviction. If imported Middle Eastern oil was vulnerable to political interruption, the answer was to secure more pipeline gas from a supplier with whom West Germany had a structured commercial relationship and a shared interest in its continuation.

The Urengoy-Pomary-Uzhgorod pipeline, completed in 1984 and running from the vast Urengoy gas field in western Siberia to the West German border, was a direct product of that post-shock logic, and it was built over fierce American objection.

The Reagan administration attempted to block European firms from supplying equipment and technology for its construction, arguing that the pipeline would create dangerous dependency. Bonn, Paris, and London essentially told Washington to mind its own business, and the pipeline was completed anyway.

What the gas bought Germany was an industrial cost structure that its European competitors could not match. German chemical producers, steel mills, glassmakers, and ceramics manufacturers built their economics around feedstock and energy costs that were simply unavailable to producers in Britain, France, or the United States.

BASF’s Ludwigshafen complex, the largest integrated chemical site in the world, was in part a monument to cheap Russian gas. Germany became the economic engine of the European Union partly on the strength of that bargain, running large industrial surpluses while its neighbors ran deficits, with cheap energy as one of the structural advantages that made German manufacturing so difficult to compete against.

The results of this collective mobilization were visible by the mid-1990s in a set of numbers worth holding in mind. Europe consumed around 32 EJ of hydrocarbons annually and produced around 15 EJ domestically. Roughly 8 EJ of Russian oil and pipeline gas, operating under long-term contracts with a generally reliable delivery history, functioned as quasi-domestic supply despite transiting through the iron curtain. Effective external import dependence was around 30 percent of consumption.

The French nuclear fleet anchored cheap, firm electricity across much of the continent. North Sea output was near its peak. Groningen, the vast Dutch gas field, underpinned Northwest European supply. Europe had a healthy energetic basis. A continent that had been genuinely vulnerable to a Middle Eastern supply cartel in 1973 had, through two decades of serious state-directed and private sector investment, rebuilt the physical foundations of its own security.

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The Pyramid Inverted

That position was dismantled through choices made by a political class that had become unmoored from the physical foundations of its own prosperity.

Maslow’s hierarchy was designed as a model of individual motivation, but it maps onto collective political behaviour with uncomfortable precision. A society that has secured abundant energy, industrial production, and physical safety creates the conditions in which political attention can migrate upward into questions of identity, moral positioning, and self-actualization.

The pathology arrives when those governing from the upper floors lose the ability to perceive the importance of the foundations beneath them, and begin making decisions that erode that base in the service of ideological commitments the foundations had made affordable.

By the mid-1990s, Europe had secured its ground floor thoroughly enough that its political class could afford to stop thinking about it. The first Conference of the Parties (COP) climate meeting opened in Berlin in 1995, the same year that marked Europe’s high-water point of energy self-sufficiency. That coincidence is not the whole explanation for what followed, but it is too precise to ignore.

The Decadence of Nuclear Phaseouts

No decision illustrates this dynamic more clearly than the closure of operating nuclear plants. The reactors that came online between the mid-1970s and late 1980s were not marginal facilities at the end of their useful lives. They were industrial cathedrals: vast, complex, irreplaceable concentrations of engineered knowledge representing decades of accumulated operating experience, trained workforces, regulatory culture, and supply chain depth, with low fuel costs, zero carbon emissions, and capacity factors that no other thermal generator could match.

They were shut down because opposition to nuclear power had become a marker of political identity in societies wealthy and secure enough to prioritize symbolic concerns over material ones. The antinuclear movement was a signal of ecological conscience and distrust of technocratic state power that resonated precisely because the lights had stayed on for so long that nobody could imagine them going out.

Germany shut its last three reactors in April 2023, in the middle of an acute energy crisis triggered by the loss of Russian gas, having spent the preceding decade replacing firm nuclear output with a combination of intermittent wind, coal, and imported gas.

The decision was not revisited when the crisis arrived, because doing so would have required the governing coalition to admit that the Green politics it had elevated to the centre of its identity had materially harmed the people it governed. Political identity proved stickier than physical reality, even once the electricity bills surged.

The scale of what was lost cannot be recovered quickly, and that is the point that cuts deepest against any optimism about Europe’s near-term capacity to respond. France still has a nuclear fleet, but it is the aging inheritance of a state that no longer exists in the form that built it.

The engineering workforce that commissioned those 54 reactors has largely retired. The specialized welding trades, the project management systems, the regulatory culture oriented around construction rather than obstruction, all of it was allowed to thin during the decades when new nuclear construction seemed unnecessary and the people demanding it were dismissed as relics of an earlier, less enlightened politics.

When France finally attempted to demonstrate that it could still build, the result was Flamanville 3: a single EPR reactor whose construction began in 2007, encountered cascading quality control failures and design changes, and achieved grid connection only in late 2024 after costs escalated to roughly 13 billion euros against an original estimate of 3.3 billion, a measure of how much institutional knowledge had been lost, and how expensive it is to rediscover what your predecessors once knew how to do.

Europe’s Hydrocarbon Dysmorphia

Today the continent consumes roughly 38 EJ against only 6 EJ produced domestically, with Russian supply now largely severed and Russian LNG under a 2027 phase-out deadline. This represents an extraordinary inversion of insecure hydrocarbon import dependency form 30% in 1995 to 80% in 2026.

The gap between what Europe consumes and what it can produce has widened from something manageable to something genuinely precarious.

The political economy behind this is not simple ignorance. It reflects the triumph of a specific set of assumptions that dominated European governance from roughly the mid-1990s onward. Neoliberalism and Ricardian comparative advantage, applied as governing doctrine held that offshoring industry and supply chains to wherever production was cheapest was rational efficiency rather than strategic vulnerability.

If someone else could supply energy more cheaply than Europe could produce it domestically, the logic ran, then importing was the optimal outcome, and if that someone else also absorbed the climate sin of extraction, so much the better. Europe could signal ecological virtue by de-industrializing while guzzling hydrocarbons produced out of sight and out of mind, congratulating itself on declining domestic emissions that had not so much been eliminated as outsourced.

The post-Cold War liberal international order would constrain the behaviour of exporters through norms, contracts, and multilateral institutions. The physical substrate, the reactors and rigs and pipelines, could be allowed to thin because the market would supply what was needed, and the moral ledger would look clean in the process.

Europe’s oil and gas consumption peaked at roughly 45 EJ around 2005 and has declined to around 38 EJ today, a reduction of around 15%. The European Environment Agency attributes this to a combination of efficiency improvements, warmer winters, higher post-2022 energy prices, renewables deployment, and structural shifts toward less energy-intensive industries, which is a diplomatic formulation for a process that deserves a blunter name: de-industrialisation.

Steel mills, chemical plants, ceramics manufacturers, and glassmakers that once anchored regional economies across the Ruhr, the Po Valley, and the Midlands have contracted or closed, taking their energy demand with them. The continent did not so much reduce its energy consumption as export the industries that consumed it, along with the employment, the tax base, the engineering knowledge, and the supply chain depth they represented.

Each factory that relocated to cheaper jurisdictions removed another supporting beam from the base of Maslow’s pyramid, trading the material foundations of working-class prosperity for lower headline energy consumption figures that Brussels could present as evidence of a successful transition. It was, in the most literal sense, progress measured by what had been lost.

What this framework systematically failed to account for was the difference between efficiency in a stable trading environment and resilience under supply stress. A just-in-time supply chain optimized for cost is the opposite of what you want when the supply is interrupted.

A grid optimized for cheap intermittent renewables is not the same system as one built around firm dispatchable capacity. The assumptions encoded in comparative advantage theory describe a world of frictionless markets and cooperative suppliers, which is occasionally the world that exists and is frequently not.

What Europe Could Still Do, and Why It Has Not Done It

Doomberg made compelling counter-arguments to my EU doomerism. He pointed out that California has roughly as much oil and gas geology as Texas. It produces a fraction of what Texas does because the legal, fiscal, and regulatory environment makes development effectively impossible.

The same circular logic operates in Europe. If exploration is prohibited, companies do not invest to assess and prove reserves. When reserves remain unproven, policymakers point to the low reserve figures as evidence that the resource is not there. The prohibition creates the condition it claims to be responding to.

Groningen, the Netherlands’ giant gas field, could be restarted. The decision to close it was driven by induced seismicity causing structural damage to buildings in Groningen province, a genuine local problem that nonetheless removed a strategically important asset from the European supply picture at precisely the wrong historical moment.

The Norwegian portion of the North Sea is still producing more than three times as much oil as the British side, and while Norway holds a larger share of the basin's reserves, the gap in output reflects policy as much as geology: Norway offers tax incentives for new development and drilled 33 exploration wells in 2025 while the UK spudded none.

Shale-bearing geology exists in Poland, northern England, France, and Germany. A 78 percent marginal tax rate on exploration and production in Britain, combined with a legal prohibition on hydraulic fracturing, does not describe a country that has concluded its geology is inadequate but rather a country that has politically foreclosed on its options.

The honest assessment is that Europe has real options it has chosen not to exercise, and that the human capital and industrial ecosystem required to exercise them quickly has been allowed to thin. A European shale revolution is perhaps not implausible on geological grounds, but it faces a 20-year American head start in drilling technology, a near-complete absence of the service industry infrastructure that makes rapid field development possible, and a regulatory and social environment that has been actively hostile to hydraulic fracturing.

Groningen could be restarted but not without political cost and not without the engineering assessment of what sustainable production levels might look like after years of inactivity.

New nuclear construction could be authorized but the supply chains and workforce needed to execute it at the pace the 1970s demonstrated are not reconstituted by political commitment alone.

What remains to be seen is whether Europe will experience the current crisis as severe enough to unlock the political will to change the framework. The fiscal terms, the regulatory culture, the legal prohibitions, the institutional preferences that have governed European energy policy for three decades are after all choices rather than facts of nature.

The question the crisis poses is whether the pain has finally reached the threshold at which those choices get revisited, or whether the current political class will manage this disruption as they did the 2022 energy crisis, through emergency imports and demand destruction with a return to the same framework when the immediate pressure eases.

China’s Different Theory of the State

The contrast that makes European failure most legible is not another European country that made better choices. It is China, whose energy policy over the same period reflects a fundamentally different answer to the question of what a state is for.

China’s 2024 primary energy figures from the Statistical Review of World Energy are worth reading slowly. Coal supplied 58 percent of primary energy, almost entirely from domestic mines. Nuclear, hydro, and renewables together contributed roughly 12 percent. Oil and gas accounted for the remaining 30 percent, of which about a quarter of the oil and 57 percent of the gas came from domestic production.

The effective Chinese import dependence on total primary energy is around 15 percent. Europe’s equivalent exposure is 80 percent on hydrocarbons alone, against a backdrop of reduced firm electricity generation following nuclear closures.

Beyond the headline numbers, China accumulated roughly an additional million barrels per day of crude oil throughout 2025 and stored it in strategic reserves. It built coal stockpiles. It invested in coal-to-chemicals facilities that convert coal through gasification into synthesis gas, the carbon monoxide and hydrogen mixture from which Fischer-Tropsch catalysis can produce diesel, aviation fuel, ammonia, and essentially any hydrocarbon compound a modern economy requires.

Germany developed Fischer-Tropsch synthesis in the 1930s and 1940s under blockade conditions to fuel the Luftwaffe when oil imports were cut off. South Africa built a large coal-to-liquids industry during the apartheid sanctions era. No country builds capital-intensive, carbon-intensive, economically irrational coal-to-liquids capacity for fun.

Countries build it when they are explicitly planning for fuel denial or war. China’s coal-to-chemicals program makes national security sense and no other kind of sense, which is a direct statement of how Beijing’s planners assess their strategic environment.

China also moved to dominate the processing stages of commodity supply chains where it could not dominate the upstream resource. It produces roughly five million barrels of crude oil per day domestically and imports around eleven million, but it has built refining capacity of nearly nineteen million barrels per day, a nameplate figure that dwarfs its own consumption and positions it as a swing supplier of refined products to the rest of the world.

When China banned refined fuel exports within days of the conflict escalating, Australia found itself in difficulty almost immediately. Australia had allowed most of its domestic refining capacity to close over the preceding decade on the assumption that cheaper Asian-processed products would always be available, above all Chinese jet fuel, which had come to supply roughly a third of the country’s aviation needs.

The vulnerability ran from Australian dependence on Chinese refined products through Chinese dependence on Middle Eastern crude to Middle Eastern supply now disrupted: a chain of three links, each individually visible, none apparently prompting precautionary action.

The pattern is consistent across rare earth processing, battery manufacturing, solar panel production, and refining: identify the processing stage where dominance can be created rather than relying on geological endowment and use that position as a buffer against upstream interruption.

This is preparation for a world where the Strait of Malacca can be contested, the first island chain can be used as a coercive instrument and the assumptions of the liberal international trading order do not hold under pressure. Europe read the post-Cold War decades as evidence that those calculations had become obsolete. China saw them as an interval of relative quiet before patterns that have governed great power competition for centuries reasserted themselves.

Can Europe Rebuild its Energy Foundations?

Doomberg holds as axiom that supply shocks reliably produce the investment responses that eventually create gluts. The 1973 embargo produced the North Sea, the Messmer Plan, the IEA strategic reserve system, and eventually a global oil surplus by the mid-1980s. The 2008 financial crisis and $147 nominal crude produced the capital desperation that drove the U.S. shale revolution to commercial viability. Something analogous will emerge from the current crisis, though its precise shape is not yet clear and the degree to which Europe contributes is questionable.

The optimistic reading is that the current disruption finally forces decisions that the 2022 crisis did not. The options are real: Groningen could be restarted, North Sea acreage could attract development capital under different fiscal terms, and Europe’s commitment to new nuclear construction, if sustained, will in theory produce operating capacity, though the timeline will be measured in decades rather than years.

The political conditions that produced the Energiewende, that justified closing operating nuclear plants in the middle of an energy crisis, were themselves the product of Europe’s masterful response to the 1970s energy shock.

The question now is whether Europe can turn its focus to the material basis of its well-being and restore its energy foundation.

The SMR craze reflects a fundamental category error and combined cycle gas turbine envy. It tries to map the attributes of a CCGT plant onto nuclear, where the underlying cost structure and physical infrastructure is fundamentally different.

A CCGT plant is essentially a jet engine bolted to a heat recovery steam generator and a smaller steam turbine. The critical point is where the complexity sits. The gas turbine, which is the expensive and technically demanding component, is built in a factory, hot functionally tested and shipped to site as a finished machine.

Construction on site is largely installation, foundations, piping, electrical connection, using conventional materials and repeatable processes. That architecture shifts risk into manufacturing and compresses timelines. Rather than building the hardest part on site you are simply installing it in 24-36 months.

Nuclear does not behave this way. It can incorporate modular components, but the NSSS is only 25-40% of cost. The dominant cost drivers sit elsewhere. Civil works, excavation, basemat, containment, seismic qualification, remain site specific and labour intensive. Nuclear grade quality assurance, documentation, and inspection add another layer of fixed overhead. Safety systems with redundancy and independence are function driven, not size driven, so they do not shrink proportionally with output.

The nuclear steam supply system is not analogous to the gas turbine in a CCGT. It is not a fully integrated, factory proven machine that arrives ready to run. The plant comes together on site, under regulatory oversight, with integration, testing and certification happening during construction & commissioning.

This is why economies of scale are so strong in nuclear. Many of the costs do not scale linearly with power. When you reduce reactor size, you reduce output and revenue, while a large share of the cost base remains. Studies show that smaller reactors actually increase the relative share of on site construction because the civil works do not shrink in proportion to capacity.

The SMR thesis assumes nuclear can transition from a project to a product, capturing the modular, factory built economics of gas plants. The constraint is that the parts of nuclear that dominate cost remain stubbornly project based.

The envy is understandble. CCGTs are extraordinarily compelling. They are marvels of thermally efficiency, capital light, fast to deploy and supported by a global supply chain of standardized components. They are the most successful large scale power plants of the past decades.

It is only natural that nuclear developers would look at that model and attempt to emulate it but in so doing they are committing a grave category error, an error that is setting the western nuclear industry up for decade(s) of disappointment.

Some SMRs will get built but they will not replicate the CCGT promise. They will be mini versions of large reactors with mini revenues to pay off the significant inherent costs of nuclear power.

Joe St. Julian arrived at AtkinsRéalis four years ago as an outsider. He had spent two decades at Bechtel, most of it in the American federal nuclear sector, running cleanup operations at the K-25 gaseous diffusion facility in Oak Ridge, then serving as project manager on the Hanford Waste Treatment Plant, the $25 billion vitrification facility built to immobilize the liquid plutonium production waste accumulated between 1945 and 1987. Before that he had built large combined-cycle gas plants in Michigan for the Shaw Group. He is, in other words, a construction and project controls man who spent his career in the most complicated industrial environments the American government could devise. He did not grow up in CANDU.

That background turns out to matter for what he had to say about it. When St. Julian arrived in Canada and started doing what he calls “due diligence” on the reactor technology he had just been hired to sell, he was surprised. “I was actually shocked,” he told me. “I thought it was an incredibly innovative technology.”

American nuclear culture produced four original equipment manufacturers whose light water reactor designs account, directly or indirectly, for the vast majority of the world’s operating fleet. Canada went a different direction entirely. No enrichment dependency, no large forged pressure vessel, a reactor that runs on natural uranium and refuels online without shutdown. Thirty-five units built across six countries with a further 18 CANDU inspired pressurized heavy water reactors built by India. Almost nobody outside those countries can describe how it works.

St. Julian’s diagnosis of that invisibility is blunt: if the same technology had been developed in the United States, everyone in the world would know about it. He frames it as a cultural gap rather than a technical one. Canada built something genuinely differentiated and then, with characteristic understatement, did not particularly insist that anyone notice.

The last new CANDU to enter commercial service was Cernavodă Unit 2 in Romania, in 2007. Almost twenty years have elapsed since then, and the Canadian domestic fleet has been in a sustained refurbishment cycle rather than a new-build cycle. That refurbishment program, covering units at Darlington and Bruce Power in Ontario, has been ahead of schedule and under budget. St. Julian argues that the refurbishments are the most important thing that has happened to the CANDU program in the last two decades because they generated the operational knowledge, supply chain capacity, and cost data that a new-build program requires.

The Metamorphosis of the Monark

The product AtkinsRéalis is now offering domestically is somewhat confusingly called the “Monark.” When AtkinsRéalis unveiled the Monark at the World Nuclear Exhibition in Paris in November 2023, the company broke with CANDU’s naming conventions entirely. Where previous designs had carried alphanumeric designations tied to their fuel channel count or development lineage, the Monark was positioned as something categorically new: a 1,000 megawatt single-unit design drawing on civil infrastructure of two designed but never built CANDU designs, the ACR-1000, the EC6, as well as the reactor core of the Darlington station, with CANDU’s passive safety features and a 70-year design life. Its marketing emphasized a break from the past.

That concept has since been substantially reoriented. What St. Julian described in our conversation is a configuration being referred to as the Monark-D, for Domestic. It consists of a strict four-unit replication of the Darlington station as it stands today, refurbished and relicensed, with as few material design changes as possible. The driver has come from the utilities who are becoming increasingly gun shy about first of a kind (FOAK) risk. That risk is increasingly being seen as the primary killer of nuclear cost and schedule. The way to bound it is to build what has already been licensed.

The confidence for replicating Darlington comes from its excellent operating experience and the confidence of the regulator. Darlington Unit 1 holds the world record for the longest continuous run of any thermal generating plant in history, 1,106 consecutive days, a figure made possible by CANDU’s online refuelling capability, which allows fuel replacement without shutdown.

The CNSC granted Darlington a 20-year operating licence in September 2025, the longest nuclear operating licence ever issued in Canada, following the completion of a C$12.8 billion refurbishment that finished four months ahead of schedule and C$150 million under budget.

The four-pack configuration matters economically: shared containment, a single control room, shared utilities, all of which pull the capital cost per megawatt below what any single-unit arrangement can achieve, which is partly why Ontario’s utilities have built this way since Pickering.

The Domestic CANDU Market

The near-term domestic pipeline St. Julian described is large. Bruce C, a four-pack on the Bruce Power site. Wesleyville A and potentially Wesleyville B, totalling another eight units east of Toronto. That is twelve reactors in Ontario alone, all potentially Monarks. Getting there requires first validating that the Darlington design, as built, can be crosswalked to current codes, standards, and regulatory expectations without requiring changes expensive enough to undermine the economics.

AtkinsRéalis is currently working through approximately 400,000 design documents: calculations, drawings, specifications, studies and re-stamping each one against today’s engineering standards with a professional engineering seal. The CNSC has identified 7 licensing areas out of a total of 18 that require examination given the evolution of codes since Darlington was originally licensed roughly forty years ago.

The three that St. Julian flagged as most technically involved are seismic criteria, aircraft impact requirements introduced after the September 2001 attacks, and the instrumentation and control (I&C) architecture, which mixes analog and digital systems in ways that must be demonstrated adequate against current safety standards.

On each of these, St. Julian’s position is that there are no fundamental licensing barriers, a term he was careful to distinguish from “no issues.” Fundamental barriers, he explained, are a concept that applies to genuinely novel reactor designs, where some core aspect of the physics or safety case has never been reviewed by a regulator.

CANDU has thirty-five operating units and a safety record the CNSC knows in detail. The question is not whether it is licensable. The question is whether satisfying any evolved requirements will require material changes expensive enough to shift the levelized cost of electricity (LCOE) beyond what Ontario’s utilities and ratepayers can absorb. AtkinsRéalis expects to have answers by the third quarter of 2026.

What will it cost?

While refusing to offer an on the record estimate, St. Julian’s core point is that repetition drives the marginal cost down, and CANDU has more repetitions behind it than any of its Western competitors in the current market. The AP1000 has two operating units at Vogtle in Georgia, and four in China with twelve currently under construction there.

The EPR has Taishan 1 and 2 in China, Olkiluoto 3 in Finland, Flamanville in France and Hinkley Point C still under construction in the United Kingdom.

There have been 35 CANDUs built but the raw global count is not the most telling number for the Monark-D specifically. The four-pack configuration that Darlington replicates has been built five consecutive times in Ontario alone: Pickering A, Pickering B, Bruce A, Bruce B, and then Darlington itself, twenty large multi-unit reactors in sequence, each generation absorbing the lessons of the last.

The Darlington units are effectively the 17th through 20th iterations of that configuration. The wrinkles accumulated across Pickering and Bruce, the steam generator designs, the I&C architecture, the containment geometry, the shared utilities layout, were progressively reworked before shovels broke ground at Darlington.

St. Julian was pointed about what this means for comparative LCOE calculations against competitors like Westinghouse now attempting to ramp the AP1000 from its 35 billion dollar cost for unit 1 & 2 at Vogtle to serial three: “I can’t reduce the cost from serial two to serial three by 50%. It can’t be done. It’s never been done in the history of the world.”

The refurbishment data reinforces this. The first Darlington unit to go through its mid-life refurbishment took 44 months from October 2016 to June 2020. Unit 4, completed in March 2026, was done in 968 days, roughly 32 months, four months ahead of its own schedule. From the first refurbishment to the last, the outage duration compressed by roughly 30 percent. The overall C$12.8 billion program landed C$150 million under budget.

The new-build Monarks are being designed with a 35-year initial licensed life rather than 30, and St. Julian projected that the first life extension following that period will cost roughly half what the Darlington refurbishments did, because the institutional knowledge will already exist in the supply chain and the workforce. A hundred-plus year asset with two economic life extensions, not a 35-year asset followed by a decommissioning decision.

The CANDU Export Market

Romania

The two CANDUs with the most direct bearing on international sales prospects are not in Canada. They are at Cernavodă in Romania. Four stand alone CANDU 6 units began construction there in the 1980s but were interrupted by the fall of the Ceausescu regime. Units 1 and 2 have been in operation since 1996 and 2007 respectively. However AtkinsRéalis is now under contract to finish the partially built Units 3 and 4 at the same site. The C6 design, 380 fuel channels, 730MW output, already licensed in Romania and certified by the European Union, is the product AtkinsRéalis is leading with in Eastern Europe.

Poland

Poland is the most advanced conversation. St. Julian and AtkinsRéalis CEO Ian Edwards were in Warsaw recently for a supplier day intended to introduce the CANDU supply chain to Polish industrial partners. Export Development Canada (EDC), the federal export credit agency, has received a request for $15 billion in financing support on the basis that Polish units would generate at least that much in Canadian content.

For context, the EDC committed $850 million in loan guarantees to the Cernavodă Unit 1 life extension and $3 billion to finish the partially built Units 3 and 4; AtkinsRéalis is currently revising that latter application upward to $4.5 billion as the front-end engineering design matures and Canadian content projections improve.

The pattern in these deals is consistent: EDC provides a low-interest sovereign loan to the buyer country, the contractual requirement for Canadian content means the money flows back into Canadian engineering firms and manufacturers, and the loan is repaid from electricity revenues over the life of the plant.

Turkey and Asean

Turkey is the other active conversation in Eastern Europe, somewhat further behind Poland. The Association of Southeast Asian Nations (ASEAN) countries represent a cluster of longer-horizon opportunities: St. Julian said AtkinsRéalis is in discussions with six of the eight or nine ASEAN members, none of which currently have nuclear power and all of which have begun developing domestic regulatory capacity.

China

China is the most complicated file. Canada has had a continuous presence there since the two CANDU 6 units were built at Qinshan Phase III, commissioned in 2002 and 2003 by AECL on a turnkey basis, on schedule and under budget by a team led by legendary project manager Ken Petrunik. Those units are entering refurbishment planning and early-phase execution through TQNPC (Third Qinshan Nuclear Power Company). Qinshan’s CANDU units are consistently among the top-performing reactors in China by capacity factor and reliability, with periods where they rank at or near the very top of the national fleet.

There were preliminary discussions about building two additional C6 units in part to boost China’s endogenous medical isotope production, over 80% of which occurs at the existing Qinshan units, before the geopolitical deterioration of Canadian-Chinese relations in the late 2010s closed them down.

The Advanced Fuel CANDU Reactor

The more technically interesting conversation concerns the Advanced Fuel CANDU Reactor (AFCR), a concept developed jointly by Candu Energy, CNNC, TQNPC, the Nuclear Power Institute of China, and China North Nuclear Fuel Company through a series of agreements from 2005 to 2016.

When a PWR discharges spent fuel, that fuel still contains roughly 0.9 percent uranium-235, compared to the 0.7 percent in natural uranium that CANDU was designed to burn. A PWR cannot reuse that material directly because even at the higher enrichment levels that went in, the discharged concentration is too low to sustain a PWR chain reaction. The uranium must first be recovered through conventional reprocessing, which chemically separates it from the fission products and plutonium accumulated during irradiation. That recovered uranium is then blended down with depleted uranium from enrichment tails to produce what the program calls Natural Uranium Equivalent fuel. Because CANDU’s high neutron economy can sustain a chain reaction at concentrations that would extinguish a PWR, this blended fuel feeds into a CANDU core without any re-enrichment.

The ratio the joint development work confirmed is 4:1: the spent fuel from four 1,000 megawatt PWRs can fully supply one 700 megawatt AFCR, extracting a further 30 to 40 percent of the energy remaining in that material, while simultaneously drawing down the stockpile of depleted uranium enrichment tails used as the diluent, a stream that is itself an expensive long-term storage liability accumulating at enrichment facilities worldwide. The detailed conceptual design was completed and the fuel technology was partially demonstrated at Qinshan. Twenty four NUE bundles were successfully irradiated in the demonstration program, however NUE fabrication remains an open engineering problem, with pellet sintering challenges that have so far required a more involved powder conversion process. Ultimately the political rupture in Canada-China relations ended the program.

To grasp why this matters to China specifically, consider the trajectory. China currently operates around 58 reactors totalling roughly 60 GWe, with 33 more under construction and credible projections putting the fleet at 300 GWe or beyond by 2050. China already imports 80 to 85 percent of its uranium requirements; at 300 GWe of predominantly PWR capacity, annual uranium demand would approach 50,000 tonnes in a global market that produced around 60,000 tonnes in total in 2023.

China’s domestic resources are limited relative to that scale, and the geopolitics of uranium supply, concentrated in Kazakhstan, Canada, and Australia, are not straightforwardly friendly to a country whose relationships with Western suppliers have been under sustained pressure. Theoretically at that fleet size, the spent fuel from China’s PWRs could theoretically keep 70 to 75 AFCRs running with no additional natural uranium input, taking a meaningful bite out of both the waste management problem and the uranium import dependency simultaneously.

The AFCR does require reprocessing infrastructure: the recovered uranium must first be chemically separated from fission products through PUREX or equivalent processing before it can be blended with depleted uranium tails. However, China is already building two reprocessing plants at 200 tonnes per year each, so that piece of the puzzle is in motion regardless.

The cost of NUE fuel is higher than fresh natural uranium and fabrication challenges remain, which is a genuine limitation, but China has consistently demonstrated that it is willing to pay a premium for reactor technologies that extend its strategic capabilities like the HTR-PM high-temperature gas-cooled reactor at Shidao Bay and CFR-600 sodium fast reactor at Xiapu.

The AFCR sits in a similar space: it does not minimize near-term electricity cost, but it partially closes China’s fuel cycle using a commercially proven reactor platform. Prime Minister Carney’s recent state visit to China included AtkinsRéalis in the delegation. The AFCR conversations, St. Julian said, are restarting.

Reviving the 1980’s Golden Age of CANDU

The domestic supply chain question is where the gap between ambition and execution is most concrete. Today approximately 100,000 workers are sustained by the Canadian nuclear industry, primarily by the Bruce and Darlington and now Pickering refurbishment programs. The refurbishments have been running for about fifteen years, which means the supply chain has had a longer warm-up period than most observers credit. St. Julian describes this as a significant advantage over competitors: “Canada is well ahead of, I call it, the power curve.” The Americans attempting to ramp up an AP1000 supply chain essentially from a standing start, and the French working to reconstitute capacity for EPR2, are trying to do something that Canada has been doing continuously, if at reduced scale, for a decade and a half.

The most important gap St. Julian identified in the CANDU supply chain is heavy water supply. Existing Canadian inventory can cover the first one or two new units by drawing on surplus from Pickering and Gentilly, but a twelve-reactor build-out in Ontario would require production capacity that does not currently exist in Canada. AtkinsRéalis has signed a memorandum of understanding with Argentina, whose state nuclear technology company designed heavy water plant, Planta Industrial de Agua Pesada (PIAP) at Arroyito has been in operation for roughly forty years and was taken offline about seven years ago; AtkinsRéalis is helping restart it, intends to take off-take from it, and sees the process design as licensable for a Canadian facility. Bruce Power, Ontario Power Generation (OPG), and AECL are all participating in the working group addressing this.

The recent thaw in Canada-India relations opens a further pathway. Prime Minister Carney’s March 2026 visit to New Delhi produced a landmark $2.6 billion agreement for Saskatoon-based Cameco to supply nearly 22 million pounds of uranium to India for its civilian nuclear program, alongside a new Strategic Energy Partnership and explicit commitments to cooperate on reactor technology.

India operates the world’s largest heavy water production complex and has decades of experience with CANDU-derived reactors. There is a satisfying narrative symmetry in the emerging relationship: Saskatchewan uranium fueling Indian reactors, Indian heavy water filling Canadian CANDUs.

Team CANDU?

St. Julian was direct about where the heavier political economy question sits. The US federal government has committed to support the AP1000 program through an $80 billion investment in Westinghouse and committing to assist with financing, streamline permitting, and facilitate construction. In exchange, the government receives a profit participation of 20 percent of any cash distributions above $17.5 billion, and holds the option to require a Westinghouse IPO by 2029 and convert that interest into a 20 percent equity stake. Separately, the DOE has designated four federal reservations: Oak Ridge, Savannah River, Paducah, and Idaho National Laboratory, sites originally acquired through eminent domain for the weapons program, as co-location zones pairing nuclear power generation with hyperscaler data centers as anchor load customers

The U.S. government is not simply financing the program; it is taking a position in the upside. Despite this federal commitment, Westinghouse has no active supply chain and limited construction capacity for the program it has just been handed.

Canada’s situation is structurally the opposite with an active supply chain and workforce. What Canada lacks is the political architecture that converts that industrial inheritance into a coordinated program.

St. Julian said AtkinsRéalis is in early discussions with both the federal government and provincial governments about whether something structurally analogous to the US model makes sense for CANDU, not an American-style program, he was careful to say, but some form of direct investment that would allow the Crown to benefit not just from GDP and tax receipts but from a greater return on the technology it originally funded.

Canada already participates in the upside from CANDU deployment, but it does so through an upstream mechanism tied to intellectual property rather than through direct project ownership or visible revenue sharing at the plant level.

When the federal government sold the CANDU reactor division of Atomic Energy of Canada Limited to SNC-Lavalin in 2011, it retained ownership of the core CANDU intellectual property. The commercial entity, now operating as Candu Energy under AtkinsRéalis, was granted a long term license to deploy and monetize that technology globally. In return, AECL receives royalties tied to new builds, refurbishments, and related engineering services. These payments are structured as royalties tied to future reactor sales, life extensions, and certain products and services, with the government projecting potential recovery in 2011 of up to $285 million over roughly 15 years though the precise payment formula has not been publicly disclosed.

The practical effect is that Canada captures value from every CANDU project, but indirectly. The government does not take an equity stake in individual plants, does not receive a per megawatt hour production royalty, and does not participate explicitly in project level cash flows. The return is embedded in licensing revenue, supplemented by domestic supply chain activity and tax receipts. The actual royalty receipts have never been publicly disclosed.

The contrast with the U.S. government Westinghouse deal is therefore structural. Canada operates as an intellectual property landlord, collecting a slice of revenue through licensing while leaving project economics to private developers and utilities. The emerging U.S. model places the state closer to the asset itself, aligning public returns more directly with reactor deployment and performance.

Getting the Band Back Together

In 1982 there were approximately 100,000 people working simultaneously in the CANDU supply chain, thirteen reactors under construction domestically and internationally at a single point in time, federal and provincial governments aligned with Crown utilities like Ontario Hydro, AECL as the technical authority, and a constellation of engineering firms and manufacturers operating in coordinated roles in a Team Canada approach.

That synergy has subsequently fractured over thirty-five years of privatization, restructuring, and new-build drought. AtkinsRéalis is now one of several large engineering firms, alongside Kinectrics, WSP, Stantec, and Hatch, where once AECL and Ontario Hydro were the organizing center. The construction contractors, Aecon, Bird, PCL, are capable but were not built around a continuous CANDU new-build program. The supply chain of 250 manufacturers exists, has been spooling up through the refurbishments, and in St. Julian’s phrase, is “fully capable” if not yet at the capacity a fleet build requires.

“We are in the early stages of getting the band back together,” he said. That being said the Team Canada framing is coherent only if Canada actually decides to field a team and play ball.

Picking that team, and backing it with the kind of structural commitment the US has made to AP1000, would mean converting a latent industrial advantage into an actual program. The raw materials for that program are more intact than the twenty-year new-build gap suggests. The refurbishments are the crawl: fifteen years of continuous work that kept the supply chain active, drove the cost curve down unit over unit, and gave the CNSC enough confidence in the refurbished Darlington design to license it for another twenty years. The Cernavodă contract is the walk: the first partial new CANDU construction since 2007, generating real cost and schedule data where before there were only projections. The domestic fleet build, twelve reactors in Ontario if the program goes the distance, is the run. Canada is approaching the transition from refurbishment to sustained new-build.

When new CANDUs break ground, the workforce stepping onto those sites will not be starting from scratch. The tools remain in place, and the institutional memory has been sustained through decades of refurbishment and ongoing engineering work. The supply chain now sees a credible pipeline of projects for the first time since the 1980s, which changes the nature of the challenge. Reassembling large scale build capacity becomes a problem of coordination and scaling, rather than reconstruction. Whether Canada chooses to mobilize these capabilities toward sustained deployment is the billion dollar question.

This essay accompanies Decouple’s conversation with Joe St. Julian, president of nuclear at AtkinsRéalis. Watch on YouTube, or listen on Apple and Spotify. If you find our work valuable, consider supporting Decouple by pledging on Substack or making a tax-deductible donation through our fiscal sponsor at Givebutter.

The energy crisis resulting from the War in Iran is bringing the catastrophic energy blindness of Taiwan’s political leadership into unforgiving focus.

Taiwan imports roughly 35% of its LNG from Qatar. LNG fuels nearly half of Taiwan’s grid after its political phaseout of nuclear power. The island maintains only about 11 days of LNG storage.

Had Taiwan kept its full nuclear fleet operating and commissioned Lungmen, its completed but never fuelled fourth nuclear plant, the country would today have roughly 7,750 MW of nuclear capacity producing about 61 TWh per year, covering around 21 percent of the grid.

Replacing that nuclear output with gas requires far more primary energy because Taiwan’s combined cycle gas turbines operate at roughly 55 percent thermal efficiency. Producing 61 TWh of electricity from gas therefore requires roughly 110 TWh of fuel input, equivalent to about 10 to 11 billion cubic metres of natural gas or roughly 7 to 8 million tonnes of LNG per year.

That volume is almost exactly the amount of LNG Taiwan currently imports from Qatar.

In other words, the nuclear fleet Taiwan shut down would have displaced essentially the entire Qatari supply stream.

Instead that capacity was retired and mothballed on political grounds and the gap was filled with gas.

In a fit of common sense, Taiwan held a referendum in August of 2025 on whether to restart the Ma’anshan nuclear plant, the island’s last operating reactor station, which had shut down in May after its forty year operating licence expired.

A clear majority of participating voters supported restarting the plant subject to regulatory approval and safety confirmation.

Taiwan’s referendum law, however, requires affirmative votes from at least one quarter of all eligible voters, roughly five million people. The referendum received about 4.3 million yes votes, leaving it below the legal threshold and keeping the plant offline, effectively confirming the continuation of Taiwan’s nuclear phaseout and LNG over dependence.

Taiwan depends almost entirely on above ground insulated LNG tanks at their import terminals. They function as a buffer designed for a world of uninterrupted deliveries rather than a strategic reserve designed to ride out a supply shock.

When a major node in the LNG system fails, there is no large fleet of idle ships ready to reroute, no spare liquefaction capacity waiting to fill the gap, and in Taiwan no underground storage that can stabilize supply while the market adjusts.

Taiwan’s nuclear shutdown therefore produced a structural vulnerability that is in the context of our current energy shock now impossible to ignore. The reactors that were closed would today be offsetting almost the entire volume of LNG Taiwan buys from Qatar.

There's never been a better time to restart Taiwan's nuclear fleet. Will Taiwan’s political class abandon their luxury beliefs and come to their senses?

Only time will tell.

When Japan shut down its reactor fleet after Fukushima in 2011 and scrambled to replace the lost generation with gas, Qatar delivered. When spot and short-term suppliers, including an Italian energy major and at least one trading house, voided their flexible contracts with Pakistan during the 2022 price spike and rerouted those cargoes to European buyers willing to pay more, Qatar delivered those too.

Then a $50,000 Iranian drone struck Ras Laffan.

The attack came in the broader wave of Iranian retaliation for the US-Israeli bombing campaign against Iranian nuclear and military infrastructure. Qatar, which had maintained some of the warmest relations with Iran of any Gulf state and had served as broker for the first Israel-Hamas ceasefire, was hit anyway.

The strike forced an evacuation of the facility and the first force majeure declaration in Ras Laffan’s history. The complex produces 77 million tonnes per year (Mt/y), roughly 19 percent of the 411 Mt traded globally in 2024. The North Field East expansion, the first of three planned phases that would nearly double Qatari capacity to 142 Mt/y by 2030, was approaching its first commissioning when the drone hit.

That same week, in the Mediterranean, a Ukranian drone boat struck the Arctic Metagaz, a Russian LNG carrier transiting toward the Suez Canal. The ship was not difficult to find. It was on a known route, visible on commercial vessel-tracking platforms, its name painted on the hull.

LNG tankers had already been rerouting around the Cape of Good Hope since the Houthi attacks made the Red Sea dangerous in late 2023, absorbing the extra transit time and cost rather than risk the strait. But no LNG carrier had been successfully struck. The Arctic Metagaz was the first. For Russia, losing one vessel from a fleet of sixteen shadow tankers is not a rounding error.

The two attacks came within days of each other, from different actors hitting different kinds of targets with different customers, but they broke the same assumption. The cascade that followed is not limited to European gas futures. It includes fertilizer plants in Pakistan going dark, rice farmers in Thailand who cannot get diesel, and nine days of reserve supply sitting in South Korean LNG storage tanks.

The Champagne of Fuels

To understand why the disruption hit so asymmetrically, it helps to understand what LNG actually is and why its supply chain concentrates risk the way it does. Natural gas, cooled to roughly minus 162 degrees Celsius, compresses to about one six-hundredth of its original volume, dense enough to ship economically across oceans.

That compression is the whole business: the liquefaction trains at Ras Laffan are the refrigerators, enormous industrial machines that chill gas into liquid and run continuously, taking weeks to months to restart after a cold shutdown; purpose-built cryogenic tankers are the thermoses, keeping cargo at minus 162 degrees Celsius across thousands of miles of open ocean; and the regasification terminals in Japan, South Korea, and Pakistan are the toasters that warm it back into pipeline-ready gas.

In a previous episode with Stephen we called LNG the champagne of fuels, and the analogy holds: it is expensive to produce, requires extraordinary handling at every stage, and arrives at the table only because an elaborate and costly infrastructure exists to get it there without incident.

Those thermoses are extraordinary machines in their own right. A single LNG tanker carries roughly one terawatt-hour of energy, the equivalent of around one month’s output from a gigawatt-scale nuclear plant, and each ship costs around $250 million to build. There are only about 700 in the global fleet, compared to over 7,000 oil tankers. But the fleet size is a symptom rather than the cause of LNG’s brittleness.

Every stage of the supply chain, from the liquefaction trains at the export terminal to the regasification plants at the receiving end, requires billions of dollars of fixed, specialized infrastructure that takes years to build and cannot be quickly replicated or redeployed when something goes wrong.

Oil markets have strategic petroleum reserves, idle tanker capacity, and a deep spot market precisely because decades of embargoes and supply crises taught them they needed those buffers. LNG has spent most of its relatively short history as a point-to-point business, the same ships on the same routes under decade-long contracts, operating in conditions stable enough that nobody was forced to build in the same shock absorption.

The storage picture compounds this vulnerability, and it splits sharply along geographic lines. Europe has geology on its side: depleted gas fields and salt caverns that can hold months of supply, which is why European utilities spend the summer methodically refilling underground storage to carry them through winter.

When Russia invaded Ukraine in February 2022, European gas prices spiked but did not immediately collapse supply, partly because storage cushioned the initial shock. The catastrophic price levels came later, in August and September, when utilities were competing to refill those same caverns for the following winter and the spot market could not keep up.

Asia has no equivalent. Japan, South Korea, and Taiwan depend on above-ground insulated LNG tanks at their import terminals, the same thermos logic applied onshore. South Korea had roughly nine days of LNG supply in reserve when Ras Laffan went down. Taiwan had around eleven days. Japan was similarly exposed.

These are not strategic reserves in any meaningful sense; they are operational buffers sized for a world of reliable, continuous point-to-point delivery, not for a prolonged outage at the source. When something breaks in the LNG chain, there is no large pool of idle ships to redeploy, no spare liquefaction capacity sitting ready, and in Asia, no caverns to draw down while the market finds its footing.

Ras Laffan in Qatar sits at the center of this system as its single largest node, supplying roughly one cargo in five to a global market that particularly in Asia has little tolerance for missed deliveries.

The Gas Field Qatar and Iran Share

Qatar’s rise is inseparable from the geology beneath it. The North Field, which Qatar taps for all of its LNG production, is the largest single natural gas reservoir in the world, sharing a geological boundary with Iran’s South Pars field across an invisible maritime line in the Persian Gulf. Because the reservoir is highly interconnected, aggressive extraction on one side draws down pressure on both. There is no formal bilateral agreement governing development.

Qatar’s 2005 moratorium was as much to appease Tehran as it was to safeguard the reservoir, and when Qatar lifted it in 2017, its energy minister announced that new development would target the southernmost portion of the field, furthest from the Iranian border. Iran’s lagging compression and reservoir management may have caused gas to migrate toward the Qatari side. Qatar has been, in effect, slowly draining a reservoir it nominally shares.

Through most of the 1970s and 1980s, nobody particularly wanted gas. Saudi Arabia simply burned its associated gas at the wellhead while running power plants on crude oil, at peak consuming as much as 900,000 barrels per day through its generators in summer.

Qatar sat on the world’s largest reservoir with no obvious market. The Japanese made that ecosystem possible: Japanese utilities provided the long-term purchase contracts that made financing of multi-billion dollar liquefaction plants bankable, and Japanese firms brought the cryogenic engineering that made the refrigeration systems work at scale. Qatar’s first export cargo departed in 1997, late to a game Brunei and Indonesia had been playing since the 1970s, but what followed lifted Qatar to the top of the LNG export rankings within a decade and transformed a country of fewer than 400,000 citizens into the wealthiest nation per capita in the region.

Then Fukushima accelerated everything: LNG imports rose by roughly 25 percent in the year following the accident, adding demand equivalent to an extra cargo arriving every day and a half. Qatar delivered, cementing the reputation for reliability that would make force majeure, when it finally came, so difficult to believe.

Iran watched from the South Pars side, unable to attract the technology partners, project financing, or long-term offtake agreements that sanctions had placed simultaneously out of reach. No major buyer would commit to two decades of purchases from a counterparty whose bank accounts could be frozen by Washington on 60 days’ notice. Iran cycled through Total, Linde, and CNPC, each of whom walked away when sanctions tightened or waivers failed to materialize.

The facility it began building in 2007 sat roughly 60 percent complete for over a decade, and Iranian gas went instead into a subsidized domestic economy where much was wasted and South Pars pressure maintenance consistently lagged, accelerating the migration of molecules toward the Qatari side.

The North Field East expansion, now under construction, was premised on a stable regional environment in which Iran would not be a hostile actor. The first phase was scheduled to come online by the end of this year. It is now under force majeure.

Why the Emerging World Bleeds First

The countries that feel the pain immediately are not the ones that dominate financial coverage of the gas crisis. South Korea, Japan, and Taiwan have enough money to go into spot markets and buy whatever is available, even at doubled prices. South Korea is subsidizing power prices to shield consumers; Japan is passing costs through to households. It is expensive, but survivable in the short term. For all three of those economies, the deeper vulnerability is their storage position.

Pakistan sources the overwhelming majority, approximately 99%, of its LNG from Qatar, a concentration rooted less in planning failure than in structural disadvantage. Pakistan entered LNG markets in 2015 with depleted domestic reserves and a sovereign credit rating so weak that no Western major would commit to long-term supply agreements.

Qatar was the only seller willing to take the country on which left Islamabad with almost no negotiating leverage. The 2016 agreements locked Pakistan into pricing at 13.37% of Brent, worse than the 12.66% India later negotiated, and included a take-or-pay clause and a Net Proceed Differential provision that captured any upside from resales for Qatar while leaving Pakistan exposed to losses.

The 2022 crisis then stripped away what limited diversification Pakistan had managed to assemble. Its contracts with an Italian major and a trading house evaporated as those cargoes were redirected to European buyers willing to pay crisis-era premiums. Qatar, constrained by its own long-term contractual obligations and its reputation as the market’s most reliable supplier, delivered. The lesson Pakistan drew was not irrational given the evidence in front of it: when the gas markets are strained, only Qatar shows up.

As Stapczynski explained, Pakistan’s biggest gas distributor has already cut supply to fertilizer plants. The same pattern is now running through Bangladesh and India, where roughly half of LNG imports have historically arrived from Qatar. Gas is the primary feedstock for urea synthesis, and when it stops flowing, the fertilizer supply chain seizes within weeks. Food price inflation follows within months. These are the second and third-order effects that an energy lens makes legible in ways that the images of strikes and counterstrikes do not.

The cascade of energy related impacts resulting from Qatar’s force majeure and the closing of the Straits of Hormuz is already visible across the region in sometimes seemingly mundane detail. China has ordered its largest refineries to halt diesel and petrol exports to protect domestic stocks.

India’s restaurants are warning of possible shutdowns as the government prioritizes gas supplies for households. Singapore’s bunker fuel providers, who supply the ships that carry everything else, are rationing supply. Thailand, where farmers in the north are already queuing for diesel with the rice harvest due in the coming weeks, is asking the broader public to limit air conditioning to 26 degrees Celsius, just as the country enters its hottest season.

That last detail matters more than it might appear. This conflict has arrived at the worst possible moment on the regional energy calendar. March through May is peak heat season across South and Southeast Asia, the period when gas-fired peaker plants carry the load for air conditioning demand, the way July and August do in the global north.

Replacement supply cannot be sourced from a spot market that has already been drained. The result, if this persists into April, will not be discomfort but blackouts, and they will fall hardest on the industrial zones and residential blocks where backup generation does not exist.

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The Shadow Fleet and the LNG Exception

One thread of the conversation that deserves particular attention is the vulnerability of Russia’s shadow LNG fleet, and what the attack on the Arctic Metagaz in the Mediterranean means for how energy warfare is evolving.

The oil dark fleet is large enough and diffuse enough to be difficult to fully suppress; there are simply too many ships, too many registry jurisdictions, and too many willing buyers for enforcement to be comprehensive. LNG is categorically different. Journalists like Stapczynski have counted approximately 16 shadow fleet LNG vessels operating for Russia, transporting sanctioned output from the Arctic LNG 2 facility that the Biden administration targeted in 2024.

When one of those ships burns, it is not a rounding error. Russia loses a significant fraction of its shadow export capacity overnight, and because LNG vessels are individually trackable by satellite image, the location of every remaining ship is known to anyone with a laptop and a subscription to a vessel-tracking service.

To understand why the shadow LNG fleet exists in its current form, it helps to understand the architecture of the sanctions regime it is navigating. The United States, European Union, and United Kingdom have all imposed measures targeting Russian LNG, most significantly the Biden administration’s 2024 sanctions on Arctic LNG 2 and, later, on Portovaya. But these are Western sanctions, and a substantial portion of the world does not recognize them as legitimate. China’s official position is that unilateral Western sanctions lack legal standing under international law, and Beijing has made no secret of its willingness to continue purchasing Russian energy.

How China Sidesteps Western Sanctions

The practical reality is more nuanced than a simple refusal to comply. Chinese companies with global operations, access to the US financial system, and exposure to dollar-denominated transactions have very strong reasons to avoid being designated under secondary sanctions, which can effectively cut a firm off from the entire Western financial architecture. The result is a bifurcation: the Chinese state openly rejects the sanctions framework while Chinese companies privately manage their exposure to it.

The Beihai terminal in Guangxi province illustrates the logic precisely. China designated Beihai as the sole entry point for cargoes from Arctic LNG 2, and other Chinese importers stopped using the terminal entirely. The terminal was chosen for its low-risk profile: it is located in China’s smallest gas-consuming region, meaning any potential supply disruption or sanctions enforcement would have limited implications for the wider market.

By concentrating sanctioned imports at a single, deliberately quarantined facility, Beijing effectively shielded the rest of its gas sector from secondary sanctions exposure. The ships supplying Beihai, all of them subject to US or EU sanctions, have largely abandoned any pretence of concealment, operating with their Automatic Identification System (AIS) transponders switched on. As one energy consultancy analyst put it, they realized they would be found out on satellite imagery within days regardless, so there was no point in hiding.

This is also why a single LNG tanker cannot simply rotate between Russian and American supply streams. Unlike a flag registry or a corporate owner, both of which can be changed through shell company transfers and reflagging maneuvers that are standard practice in the shadow fleet, a vessel’s International Maritime Organization (IMO) number is permanent.

The Office of Foreign Assets Control (OFAC) designation attaches to that number, which means a ship that has called at a sanctioned Russian facility carries that designation for as long as it remains on the Specialty Designated Nationals (SDN) list, and delisting requires active engagement with OFAC that almost never happens in practice.

Once designated, a vessel is effectively locked out of Western ports, Western insurance, and Western-adjacent supply chains, with its remaining market confined to buyers in jurisdictions that do not enforce US secondary sanctions. The major portfolio players, Cheniere, Shell, the Japanese utilities holding long-term US LNG contracts, cannot allow their supply chains to touch a designated vessel without triggering the secondary sanctions exposure they have spent considerable legal effort to avoid.

The market is not merely bifurcated by politics; it is bifurcated by the physical and legal incompatibility of the two supply chains, written permanently into a ship’s identity the moment OFAC adds its IMO number to the list.

The Attack on the Arctic Metagaz

The Metagaz attack, which Russia attributes to Ukraine, is the first confirmed successful strike on an LNG carrier. That fact will reconfigure insurance pricing, routing decisions, and the calculus of every operator who has been transiting these vessels through the Mediterranean toward the Suez Canal.

Since the Houthi attacks on Red Sea shipping began at the end of 2023, legitimate LNG operators had already been routing around the Cape of Good Hope rather than through the Bab-el-Mandeb strait. The shadow fleet had been using the Mediterranean-Suez route precisely because it was still open. That is no longer the case.

The ships supplying Beihai have since avoided the Mediterranean entirely, which forces them onto one of two routes: around the Cape of Good Hope, adding weeks to each voyage and compressing the economics of each delivery, or through the Northern Sea Route, which is where the constraints become genuinely acute.

Why the Northern Sea Route is not yet the Solution

The NSR is not simply closed in winter in the way that a road closes. It is navigable by degree, depending on ice class, icebreaker availability, and the specific conditions of a given season. The shadow fleet LNG tankers servicing Arctic LNG 2 are predominantly Arc4-class vessels, meaning they can handle light ice independently but require nuclear icebreaker escort for anything heavier. The Arc7-class icebreaking tankers, capable of navigating winter ice conditions that would stop an Arc4 vessel entirely, are in desperately short supply. for Arctic LNG 2.

Russia has been trying to close this gap domestically. Three completed Arc7 carriers sit undeliverable at a South Korean shipyard because Western sanctions prohibit their transfer, and Russia’s own Zvezda yard is building replacements, but slowly and with Chinese assistance substituting for the European technology now denied to it.

In the meantime Russia has floated the concept of a nuclear-powered LNG submarine carrier, a vessel that would be immune to surface ice conditions entirely. It sounds like science fiction, and it probably is for now, but it is the kind of idea that only gets seriously discussed when every conventional option has a serious constraint attached to it.

The end result is a fleet that is operationally viable in summer, strained in autumn, and severely degraded in winter, dependent on routes that are now either militarily dangerous or seasonally impassable.

What the Shale Revolution Actually Bought

The United States’ willingness to sanction Russian LNG facilities, to allow Israel to attack Iran, and to absorb the geopolitical risk of a Strait of Hormuz closure is only possible because of the shale revolution.

Even before the conflict with Iran the Biden administration’s decision to sanction Arctic LNG 2 and remove Russian supply from global markets rested explicitly on the US being large enough a producer to stabilize the market in the aftermath. That logic carried forward into Trump’s second term, which has been willing to absorb disruption that would have been politically intolerable when the US was an energy importer.

A United States that was still a major LNG importer, which is what the early 2000s looked like before hydraulic fracturing unlocked the Marcellus, Haynesville, and Permian gas plays, would have faced the same supply shock every other importing country is facing right now. As a result of the shale revolution the receiving terminals being built along the Gulf Coast to handle anticipated LNG imports were quickly converted into export terminals, though the word converted flatters the difficulty.

Running the process in reverse requires entirely different industrial equipment: the storage tanks, marine berths, and some pipeline connections could be reused, but the liquefaction trains had to be built from scratch on the existing footprint. In ten short years the US became the world’s largest LNG exporter, producing around 21 percent of global supply, neck-and-neck with Qatar before this crisis and positioned to capture significant market share during a prolonged outage.

That positioning insulates American households and industrial users from the acute price pain now hitting Europe and Asia. US LNG export contracts are indexed to Henry Hub rather than global spot benchmarks, which means the thirty-five to fifty percent surges recorded on European TTF do not transmit directly into domestic gas bills. The insulation is real however, it is not complete, and it narrows the longer the Strait stays closed.

Interestingly the pricing structure of US LNG contracts means that it is not the export terminal operators but rather the US’s trading counterparties, including China, who are positioned to profit most from the current tightness in the LNG market.

The Chinese Paradox

China’s position in all of this is the most structurally interesting, and it reflects decades of deliberate state planning around exactly this kind of scenario. On the oil side, China holds the largest onshore crude stockpiles in the world, estimated at 1.2 billion barrels as of January 2026, providing roughly 108 days of import cover at current refinery run rates.

Beyond reserves, China has spent years building supply routes specifically designed to bypass maritime chokepoints, deepening pipeline connections to Russia and Central Asia that are entirely immune to anything happening in the Strait of Hormuz. On the gas side, the insulation runs deeper still. China’s domestic natural gas production hit 246 billion cubic meters in 2024, sustaining roughly six percent annual growth for most of the past decade, with unconventional sources including shale, tight gas, and coalbed methane now accounting for 43 percent of that output.

China is the world’s largest LNG importer and is genuinely exposed to the supply shock, but less so than its regional neighbors because it holds assets they do not: the ability to pivot toward Russian pipeline gas and sanctioned Arctic LNG without the legal and reputational costs that would destroy a Japanese or Korean utility’s access to Western financial markets, and a coal fleet large enough to absorb demand that gas cannot serve.

There is also a contract dimension, where China’s position shades from paradox into something closer to structural advantage. Between 2021 and 2023 China signed over 20 million tonnes per year of new long-term contracts with US LNG projects, a volume Washington had hoped would bind Beijing into durable commercial dependency on American energy. Then in February 2025, as the tariff escalation accelerated, Beijing slapped a 15 percent retaliatory duty on US LNG imports and stopped taking physical delivery entirely.

Sinopec, CNOOC, Sinochem, and PetroChina began redirecting contracted US cargoes to Europe and other Asian markets, a move made legally straightforward by the destination flexibility written into most US LNG contracts. The other major portfolio holders, Japanese trading houses, Shell, Trafigura, Gunvor, and Vitol, were doing the same thing, but without the geopolitical irony.

By the time the Ras Laffan strike landed, China held large contractual claims on American gas production that it was actively routing away from its own shores and selling at a premium into the same European and Asian spot markets now scrambling for replacement supply.

Rather than being bound into energy dependency China has instead converted that dependency into a trading position, pocketing the arbitrage while keeping its own import portfolio oriented toward suppliers the United States has minimal ability to sanction.

The Refill Problem and the Summer Ahead

Gas markets have seasonality that does not always map onto the political timing of crises, which is why the timing of any resolution matters as much as the resolution itself. Stapczynski walked through the scenarios explicitly.

If the strait reopens and Qatar restarts tomorrow, the disruption is an expensive blip. These are not simple machines: bringing LNG trains back to operating temperature after a cold shutdown takes weeks to months even under ideal conditions, and Qatar has been sub-chartering out vessels it no longer needed during the outage, so reassembling the logistics of a dispersed fleet adds further delay. Qatar’s energy minister told the Financial Times as much in the first days of the crisis. The supply disruption will outlast any near-term diplomatic resolution, but the market absorbs it and moves on.

If the outage runs into June or July, the calculus changes entirely. The Northern Hemisphere refill season runs roughly from April through September, when European utilities pull large volumes from global spot markets to rebuild storage caverns for winter, precisely when Asian buyers are also increasing demand for peak cooling load. When Russia began reducing gas deliveries to Europe after its invasion of Ukraine in February 2022, prices spiked and then settled.

The catastrophic levels, Dutch TTF briefly above 300 euros per megawatt-hour, came in August and early September during the refill scramble. Morgan Stanley’s analysis, circulated in the first days of this crisis, suggested that an outage lasting more than a month would tip the LNG market into structural deficit for the year, meaning global demand would exceed available supply even with all other producers running at full capacity.

If the outage stretches into months, that scenario becomes the base case rather than a tail risk. The price discovery mechanism becomes brutal: the countries with the deepest pockets secure supply, and the countries without them go dark. Pakistan is still economically reeling from the 2022 energy crisis.

As Stapczynski put it, the way countries recover from energy shocks changes their trajectory permanently. Pakistan’s solar boom, its IMF bailout, its shift away from gas as an industrial input, all of it traces back to 2022. A repeat, at greater magnitude, with less warning, and arriving during peak heat season across South and Southeast Asia, is what the analysts are trying not to think about too carefully.

LNG after Ras Laffan and the Arctic Metagaz

The threshold for disrupting the global LNG market is no longer a functioning state with an air force or navy. Ras Laffan declared force majeure because of a thirty thousand dollar propeller driven drone. The Arctic Metagaz was destroyed by what was likely an unmanned surface drone small enough to be launched without conventional naval support.

LNG moves through an unusually concentrated system of liquefaction plants, storage tanks, and specialized carriers that cost billions of dollars and exist in only a handful of locations worldwide, so a small group with a grievance, a coastline, and access to technology that costs less than a used car can interrupt flows that underpin a large share of global gas trade.

The Israeli vision, insofar as it can be read from the targeting choices and the public statements of its strategic thinkers, is of an Iran so internally fragmented that it cannot project conventional military power outward. A state, perhaps resembling post-Assad Syria, broken along ethnic and regional lines, with Kurdish, Baloch, Azeri, and other peripheral groups empowered enough to prevent Tehran from reconsolidating control.

That vision may be coherent on its own terms. A fragmented Iran is less capable of supplying Hezbollah, less able to coordinate proxy networks across the region, and less able to place a ballistic missile on Tel Aviv. The global economy, however, now faces the prospect of a failed state alongside the world’s most critical energy chokepoint, and that may be a considerably harder problem to manage than a hostile pre war Iran ever was.

Before this war, Iran was a unified and largely legible actor. The Supreme Leader held final authority over the IRGC, the regular army, and the proxy networks simultaneously. That centralization was the thing that made diplomacy, however difficult, at least theoretically functional: there was a clear chain of command to negotiate with, a leadership whose equities could be threatened, and a foreign ministry capable of receiving and transmitting agreements. That engagement was attempted twice in recent memory through the nuclear deal framework and interrupted both times by US and Israeli surprise attacks before it could potentially produce durable arrangements.

What the bombing campaign has produced in its place is different. Iran has activated what it calls the Mosaic Defense doctrine, reorganizing the IRGC into 31 largely autonomous provincial units whose commanders no longer require approval from Tehran to launch missiles, drones, or maritime operations. Iranian Foreign Minister Araghchi acknowledged as much publicly, saying that certain units had become independent and were functioning according to previously issued operational guidance rather than continuous central direction.

The IRGC’s decentralization was designed as a military resilience strategy, developed after watching the collapse of centralized Iraqi forces in 2003. As an energy security problem it is something else entirely. Provincial coastal commanders with autonomous strike authority and staging points along the Persian Gulf present a categorically different threat to the Strait of Hormuz than a unified state does. A unified state can be deterred, negotiated with, and held to agreements. Thirty-one semi-autonomous military nodes distributed across Iranian territory present a more complex challenge.

A fragmented Iran that cannot threaten Tel Aviv may still be entirely capable of making the Strait of Hormuz ungovernable for commercial shipping, and unlike a state, it offers no foreign ministry to call, no supreme leader and no clear chain of command through which a ceasefire can be transmitted.

The affordable, reliable LNG that was supposed to serve as the bridge fuel for the developing world was always premised on freedom of navigation holding. The logic connecting these events is straightforward: the global energy system is built on infrastructure that is individually reachable, geographically concentrated, and defended by assumptions about acceptable behavior that have been visibly eroding for two years. Pakistan’s farmers, Thailand’s rice harvesters, and India’s industrial users are now on the front line of an energy war and caught paying the carrying cost of those assumptions now.

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For the “swiss watch” fuel of a technology often described as uniquely complex, that is a remarkable number. It reflects seven decades of industrial refinement, automated production lines running continuously to supply around 400 reactors worldwide, rejection rates under 1%, and a quality control regime so well understood that a single leaking fuel pin now constitutes a reportable anomaly rather than routine background noise.

Advanced reactor vendors selling their designs on narratives of lower construction cost, simpler containment, and inherent safety almost uniformly propose to achieve those outcomes through fuel that is more complex, more expensive, and manufactured by supply chains that do not yet exist at commercial scale. That observation alone does not invalidate their business cases, but it demands that the cost and supply chain assumptions behind their fuel be examined with the same rigour applied to their reactor construction schedules.

Uranium Dioxide: Good enough at everything without being very good at anything

Part one of this series based on my discussion with Michael Seely of the Atomic Blender channel covered how uranium dioxide (UO2) became the dominant commercial fuel. The short version is that it occupies an unusually comfortable middle position among candidate fuel materials: high melting point, reasonable fission product retention, chemical compatibility with zirconium cladding and pressurized water, and fabrication simple enough to automate at industrial scale. The process is direct: press the powder into pellets, fire them in a kiln, load them into rods, backfill with helium, and weld the ends shut. UO2 is not excellent at any individual property, but it is adequate at all of them simultaneously, and seven decades of production refinement have made that adequacy extraordinarily reliable.

Adequacy has limits. UO2 as a ceramic transfers heat poorly. The relatively poor thermal conductivity gap between the pellet’s outer surface and its center creates a temperature gradient of close to 1,000 degrees Celsius across a pellet roughly a centimeter in diameter. The centerline of a UO2 pellet operating in a pressurized water reactor (PWR) can reach 1,200 degrees Celsius while the coolant immediately outside the cladding sits at around 300. That margin sounds generous given UO2’s melting point near 2,800 degrees, but it shrinks rapidly as operating conditions change. In a high temperature gas reactor where coolant temperatures already approach 800 degrees, and where gas transfers heat to the cladding less effectively than pressurized water, the centerline temperature easily climbs toward 1,800 degrees. The 2,800 degree limit, which looked reassuring in a PWR, looks considerably less reassuring with 1,000 degrees already consumed by the operating conditions of the reactor itself.

UO2 also fractures under thermal stress. Fresh pellets loaded into a reactor are smooth and nearly geometrically perfect. After a few power transients, microscopically they resemble cracked clay: jagged sections separated by fracture planes that open release paths for fission gases into the gap between pellet and cladding. X-ray images of irradiated pellets show something unrecognizable as the original cylinder. The practical consequence is that the gap fills with fission gas under pressure driven by high temperatures, and that pressure constrains how aggressively the reactor can be maneuvered. This is manageable in a baseload PWR; it becomes a harder constraint in a reactor expected to follow grid demand through rapid power swings.

These are the problems that TRISO (tristructural isotropic) fuel and metallic fuel both attempt to address, through quite different approaches and with quite different implications for cost.

TRISO: A Brilliant Idea With an Expensive Manufacturing Problem

TRISO fuel is, at its core, still UO2. Understanding this matters because the technology is often described as a completely different paradigm, when it is more precisely a geometric rearrangement of the same fundamental material, surrounded by protective layers designed to solve the problems that scale and geometry create.

A TRISO particle consists of a UO2 kernel roughly the size of a poppy seed, surrounded by a porous carbon buffer layer, an inner pyrolytic carbon layer, a silicon carbide (SiC) layer, and an outer pyrolytic carbon layer. The carbon buffer exists to absorb the volumetric expansion and fission gas accumulation that would otherwise stress the surrounding layers; it functions essentially as a compressible void, a deliberate accommodation of the physics rather than a resistance to it. The SiC layer provides the actual structural containment. Silicon carbide at relevant temperatures has a melting point so high that even if the UO2 kernel inside were to melt, the SiC shell would remain intact. These particles are then embedded in a graphite matrix that provides moderation.

The thermal problem largely disappears at this scale. A poppy-seed-sized sphere of UO2 has a centerline-to-surface distance measured in fractions of a millimeter rather than half a centimeter; the temperature gradient across it is correspondingly small. The fission gas fracturing problem does not disappear entirely, but the particle’s geometry and the buffer layer substantially reduce its severity.

The performance case is real. TRISO fuel ran in the German AVR and THTR-300 reactors, in the American Peach Bottom and Fort St. Vrain plants, and their fuel behavior was generally good. Where those reactors encountered significant difficulties, the problems were usually in supporting systems rather than in the fuel itself. That historical record is the legitimate foundation of the enthusiasm around TRISO.

The manufacturing problem is where the gap between the technology’s physical elegance and its economic viability currently sits.

Producing TRISO starts with dissolving UO2 in acid to form a uranium nitrate solution, precipitating that solution into tiny droplets, and then drying and calcining those droplets into UO2 kernels. The kernels are supposed to be spheres. Many of them are not. The output resembles kicked balls, slightly dented, not perfectly round. Imperfect kernels are rejected, recovered, ground up, and run through the process again. The recovery of the high-assay low-enriched uranium (HALEU) feedstock from rejected material requires its own chemical deprocessing, because you cannot simply regrind an imperfect TRISO particle the way you can regrind a chipped UO2 pellet and put the powder back in the next batch.

The coating layers are applied by suspending the kernels in a gas flow and powder-coating them from the outside, layer by layer. Each layer must achieve uniform thickness across the entire surface of each kernel, across a production run of billions of kernels. Each layer has its own reject rate. Rejected coated kernels require additional chemical separation to recover the underlying HALEU before they can reenter the production stream.

The cumulative reject rates compound. A process that rejects 10% of kernels at the UO2 stage, another 10% at first coating, and another 10% at subsequent coatings does not produce a 10% overall rejection rate; the losses multiply through each step. The practical result is that current TRISO production, being conducted at laboratory and demonstration scale by BWXT, X-energy’s XTRISO facility, and Standard Nuclear (formerly associated with Ultra Safe Nuclear), involves small batches with considerable manual intervention, high reject rates, and expensive HALEU recovery operations at each failed step.

The cost consequence is predictable. HALEU feedstock at around 20% enrichment costs approximately $15,000 per kilogram, compared to about $3,000 per kilogram for conventional 5% enriched uranium. TRISO fabrication on top of that currently runs somewhere between $5,000 and $15,000 per kilogram, though these estimates carry wide uncertainty and the upper end reflects current small-batch production conditions rather than any plausible industrial future. Total fuel cost approaching $30,000 per kilogram is therefore not an unreasonable current and foreseeable future estimate, against the roughly $3,300 per kilogram for a conventional UO2 assembly.

However, it is reasonable to believe that cost will fall if TRISO demand grows. A transistor analogy is apt: microprocessors in the 1970s were expensive precisely because the manufacturing processes for very small, tightly toleranced structures had not yet been optimized through repetition at scale. The cost of computing fell by orders of magnitude as demand drove automation and process refinement. The analogy has a limit, though. Semiconductor demand exploded because chips unlocked entirely new categories of human activity that had no prior substitute. A TRISO-fueled reactor produces electricity and medium grade process heat, which the world already generates through dozens of competing technologies at lower cost and with more mature supply chains. The demand curve for a premium-fuel reactor selling into a commodity electricity market is not going to resemble the demand curve for the personal computer. The question for TRISO is therefore not just whether demand will materialize, but whether it will materialize in sufficient volume, and concentrated enough in a small number of fuel specifications, to drive the automation that would make the economics work.

At the moment, there is no operating TRISO-fueled reactor in the Western world. The only commercial TRISO reactors anywhere are the two units of the HTR-PM (High Temperature Reactor Pebble-bed Module) at Shidaowan in China, which achieved a capacity factor of around 20% in their second year of operation. Nine years of construction followed by a multi-year commissioning period, then a 20% capacity factor, in a country willing to absorb those costs as part of a broader national nuclear learning program. As a commercial proposition for private Western investors, that starting point requires considerable explanation.

Metallic Fuel: Better Physics, Harder Problems

Metallic fuel addresses different limitations than TRISO and has a different historical pedigree. Where TRISO is essentially a miniaturized containment vessel wrapped around familiar ceramic material, metallic fuel replaces the ceramic entirely with uranium in its metallic form, typically alloyed with zirconium.

The physical advantages are substantial. Metal conducts heat orders of magnitude better than ceramic. The centerline temperature problem that plagues UO2 effectively disappears; heat moves out of a metallic fuel pin quickly enough that the temperature gradient across the fuel is small, allowing operation at higher power densities without approaching melting limits. The metallic crystal structure also retains fission products more effectively than the ceramic grain structure of UO2, because displaced metal atoms tend to settle back into the crystal matrix rather than remaining in interstitial positions that open fission gas release paths.

The central disadvantage is that the melting point of uranium metal, and of uranium-zirconium alloys, is substantially lower than UO2. Less margin exists before the fuel melts if cooling is lost. The distinction between losing coolant flow and losing coolant entirely matters here. The Experimental Breeder Reactor II (EBR-2) at Argonne National Laboratory demonstrated in April 1986 that cutting the primary sodium pumps at full power, a loss of flow event, produced no fuel damage; the expanding fuel geometry triggered the reactor’s inherent negative reactivity feedback, reducing reactivity and dropping power to near zero within about five minutes, without any control rod insertion or operator action. The physics worked as designed, and it was a genuinely remarkable demonstration. What was not tested was a loss of coolant, a different and considerably more severe scenario for metallic fuel, where the lower melting temperature leaves less time between coolant loss and fuel damage than the large margin of UO2 ceramic would provide. The passive safety case for metallic fast reactors is real; it is also narrower than its most enthusiastic proponents sometimes suggest.

EBR-2 was also the site of a more ambitious vision, one that explains why the reactor exerts such a strong pull on the imagination of companies like Oklo today. The reactor itself sat beneath a silver dome at the Argonne National Laboratory site in Idaho, generating around 62 megawatts of thermal power. Physically attached to the side of this dome was the Fuel Cycle Facility, a reprocessing plant arranged in a U-shape around its processing equipment. The design intent was explicit: spent metallic fuel would leave the reactor, travel into the Fuel Cycle Facility, work its way through a sequence of electrochemical processing stations along the U, and return to the reactor as fresh fuel, all without leaving the site. The first irradiated fuel was reprocessed in the facility in September 1964, and recycled fuel returned to the reactor by April 1965. During the years the cycle operated, the turnaround time from fuel removal to reloading ran between 30 and 50 days.

The process itself operated nothing like the remote, automated image the word “reprocessing” might suggest. Spent fuel arriving from the reactor was intensely radioactive, requiring all handling to be done through thick leaded glass windows using remote manipulators, in rooms filled with inert argon gas rather than air, because both sodium bonding on the fuel and the highly reactive materials involved in the electrochemical steps would respond badly to oxygen or moisture. The electrorefining step dissolved the spent fuel into a molten salt bath of lithium chloride and potassium chloride at around 500 degrees Celsius, then applied an electrical current to selectively deposit uranium onto a steel cathode while fission products remained in the salt. The plutonium and higher actinides came out as a separate product mixed with rare earth fission products, deliberately left impure as a proliferation-resistance measure, since the mixture is unsuitable for weapons use without additional separation steps that would be detectable. The recovered uranium was then cast back into metallic fuel pins and returned to the reactor.

This is a compelling system in concept. It is also, in execution, one of the most demanding industrial processes ever attempted in a nuclear context.

Oklo, the company currently pursuing a commercial version of this concept, draws heavily on the EBR-2 legacy. Their proposed Aurora reactor, at 1.5MW in its original design and now discussed at larger scales, would use HALEU metallic fuel and eventually close its fuel cycle through on-site reprocessing of what they describe as legacy spent nuclear fuel from the existing light water fleet. It is a genuinely compelling narrative. It is also, for reasons outlined above, an ambitious one.

Oklo’s 2023 investor guidance described an initial core requiring approximately 10 metric tons of HALEU for a 50 megawatt reactor, lasting around 10 years before a reload of roughly half that quantity. The Centrus Energy HALEU demonstration cascade at Piketon, Ohio, currently the only Western HALEU enrichment operation, produces approximately 900 kilograms per year. A single Oklo reactor would therefore require roughly eleven years of Centrus’s entire output just for its initial fuel load. That ratio will improve if Centrus expands or other enrichment capacity comes online, but the scale of the gap between current Western HALEU production and even a modest fleet of advanced reactors is not a detail to be resolved by noting that it will eventually be addressed.

The fuel cost figure of $7,000 per kilogram cited in Oklo’s investor materials does not survive scrutiny. HALEU at market prices already costs roughly $15,000 per kilogram before a gram of it enters a fabrication facility. Achieving $7,000 per kilogram as an all-in fuel cost would require either a negotiated subsidy from the Department of Energy, uranium prices significantly lower than current market rates, or an assumption about reprocessing economics that the existing evidence does not support.

Reprocessing is not a simple recovery operation. French LWR reprocessing at La Hague has consistently failed to compete economically with fresh uranium at current market prices. The gap is wide enough that EDF, the state utility operating France’s nuclear fleet, has carried its stockpiles of recovered plutonium and reprocessed uranium at zero book value since 1995, a formal accounting admission that these materials cannot be sold at any price that covers the cost of turning them into usable fuel. France sustains La Hague through deliberate energy policy, not because the economics compel it.

CERMET: Combining the Best of Both Worlds

The ceramic metallic (CERMET) fuel concept exists because both UO2 pellets and pure metallic fuel involve real tradeoffs that neither alone fully resolves. The basic architecture embeds ceramic fuel particles, typically uranium dioxide, in a metal matrix rather than pressing them into solid pellets and stacking them in a rod. The metal matrix conducts heat far better than a solid ceramic pellet, which reduces the centerline temperature problem; the ceramic particles retain fission products better than a homogeneous metallic pin, because the particle boundaries impede fission gas migration. Neither property is fully optimized, but both are meaningfully improved over either pure form, and the combination opens a design space that conventional pellet fuel cannot access.

Russia has been operating CERMET fuel in its nuclear icebreaker fleet continuously since the 1950s, accumulating more than 400 reactor-years of operational experience across successive reactor generations. The current RITM-200, developed by Afrikantov OKBM and now installed on four icebreakers with more under construction, uses a cassette-type core of 199 fuel assemblies containing UO2 particles dispersed in a silumin matrix, an aluminum-silicon alloy, enriched to just under 20% uranium-235. The silumin matrix conducts heat substantially better than the zirconium-based structures of conventional light water reactor fuel, reduces centerline temperatures, and tolerates the swelling that accumulates during a long fuel residence without the cracking behavior that plagues UO2 pellets under power cycling. The fuel rods are clad in a nickel-chromium corrosion-resistant alloy rather than zirconium, chosen specifically for its performance over the long refueling cycles the icebreaker mission demands. The RITM-200 core operates for 5-7 years between refuelings, in reactors that must handle continuous, aggressive power transients as the icebreakers throttle up against pack ice and back off in open water. That duty cycle would be punishing for conventional UO2 fuel. The CERMET matrix handles it routinely.

The operational significance of this is worth considering. The RITM-200 is not a laboratory demonstration or a national prestige project running at artificially low capacity to generate data. It is working propulsion equipment on vessels breaking ice in the Arctic, operated by crews who cannot easily return to port if a fuel problem develops. The icebreaker experience proved the fuel concept under conditions more demanding than any grid-connected power reactor will ever face.

The reasons this experience receives relatively little attention in Western advanced nuclear discussions are not entirely mysterious. Russian reactor data is difficult to access and published under terms that make independent verification hard. The RITM-200 fuel is manufactured by Russian industrial infrastructure with no Western equivalent, making it a poor reference point for companies trying to establish domestic supply chains. And the enrichment level, just under 20%, sits at the boundary of what Western nonproliferation policy treats as acceptable for civilian use, which adds a layer of political complexity to direct comparisons. None of these factors diminish the technical significance of what Russia has demonstrated, but they explain why it tends to appear as a footnote in discussions dominated by American and European vendor narratives.

Lightbridge Corporation is pursuing a different application of the metallic fuel concept, one aimed at the existing light water reactor fleet rather than at next-generation designs. Their cruciform-shaped metallic fuel rod, developed over more than a decade and now at the test rod stage at Idaho National Laboratory, is designed to replace conventional UO2 assemblies in operating pressurized water reactors without requiring HALEU. The helical cruciform geometry increases the surface area available for heat transfer and improves coolant mixing around the rod, which are the same principles that underlie the Russian icebreaker fuel geometry. At conventional enrichment levels, Lightbridge argues that the metallic matrix’s better thermal conductivity and fission product retention could enable higher power density, higher burnup, and longer operating cycles than current UO2 assemblies allow, improving economics for existing reactors without requiring new reactor construction.

The proposition is commercially clever because it targets an installed base of around 400 operating reactors rather than a fleet that does not yet exist. The question that irradiation testing at commercial scale will eventually have to answer is whether the performance improvements are large enough to justify the cost and regulatory burden of qualifying a new fuel form for reactors licensed around the behavior of pellet fuel, and whether those improvements can be maintained against the continuing refinement of conventional UO2 fuel through accident-tolerant fuel programs and LEU Plus enrichment developments. A fuel that is better than today’s UO2 may still lose the economic competition if the target is moving.

The Variable That Actually Drives Outcomes

Advanced reactor companies routinely project capacity factors in the low to mid 90s. This is however the performance level of a mature, well-operated light water reactor fleet after five decades of systematic improvement, not the performance level of light water reactors in their first decades of operation.

The 93% capacity factor that currently anchors American light water reactor economics accumulated through a specific institutional process: hundreds of reactors generating comparable operating data, an industry-wide information sharing structure through the Electric Power Research Institute (EPRI) and the Institute of Nuclear Power Operations (INPO), sustained regulatory attention to failure modes, and multiple fuel vendors competing on reliability as much as price. That process took decades and required a fleet large enough to generate statistically meaningful data across failure modes that individual plants encounter only rarely.

An advanced reactor running on TRISO or metallic fuel will not arrive at 93% capacity on its first cycle, just as the Shidaowan HTR-PM did not arrive there in its second year. It will encounter failure modes that simulations and laboratory testing cannot fully predict, because the interaction between fuel behavior, reactor conditions, and supporting systems only becomes fully legible under real operating conditions. The cost of learning those lessons is real, and it falls on whoever finances the early units.

The fuel cost question and the operational performance question are not independent. A reactor running at 20% capacity factor with expensive HALEU fuel is extracting a small fraction of the potential revenue from a very expensive input material. The economics of advanced nuclear do not become compelling simply because the reactor construction cost comes down, if the fuel cost goes up and the capacity factor starts low and climbs slowly through costly operating experience.

None of this means TRISO or metallic fuel are dead ends. The historical performance of TRISO in its operating demonstrations was generally good. Metallic fuel’s physical properties are genuinely superior to UO2 in several respects that matter. CERMET fuel’s performance in Russian icebreakers is operationally proven in a demanding environment. The question is the sequencing: how long does the learning process take, how much does it cost, and who pays for it?

China can absorb the cost of the Shidaowan experience because it represents a small fraction of a state-directed nuclear program whose ambitions extend far beyond any single technology. A Western venture-backed company, or even a consortium of industrial partners with hyperscaler power purchase agreements behind them, will face a more compressed timeline between first operation and the need to demonstrate commercial competitiveness. The fuel economics are a central part of that demonstration, and the current numbers, on both cost and supply chain availability, are demanding.

This is the structural question that runs underneath all of it: what allowed water cooled reactors to become self-sustaining as a commercial proposition, and why has no other reactor type crossed the same line? The answer is not that water cooled reactors were superior on every technical dimension. They were not. Sodium-cooled fast reactors breed fuel. Gas-cooled reactors achieve better thermodynamic efficiency at high temperatures. The relevant distinction is not which technology had the most attractive properties on paper, but which technology cleared the hurdle of organic private investment, and why.

Light water reactors cleared that hurdle because the hurdle itself was not that high. The technology built on two centuries of industrial experience managing pressure vessels and steam as a working fluid. Enrichment services, zirconium cladding supply, UO2 pellet fabrication, vendor warranties, insurance pricing, regulatory precedent: all of this infrastructure consolidated around light water requirements during the 1960s and 1970s, under conditions where government bore much of the early risk. By the time utilities were making investment decisions on their own balance sheets, they were buying into an existing system rather than funding the creation of one. The industry could sustain the technology organically, without a state apparatus continuously absorbing the burn-in costs of first-of-kind systems running well below their projected capacity factors.

No alternative reactor technology has yet crossed that line. Non-LWR concepts still require some combination of a novel fuel supply chain, reprocessing infrastructure, specialized materials expertise, or regulatory precedent that does not exist at commercial scale. An advanced reactor vendor is not simply selling a reactor; it is implicitly asking early customers to co-finance the creation of the industrial ecosystem the reactor depends on. X-energy cannot deploy its Xe-100 without first building out the TRISO-X fabrication facility in Oak Ridge, a dedicated HALEU TRISO production line that has no customers until the reactor fleet exists and no economic rationale without the customers. Oklo cannot close its fuel cycle without a commercial-scale pyrochemical reprocessing capability that the Western world has never operated outside a national laboratory. Kairos Power’s fluoride salt-cooled reactor depends on TRISO pebbles produced to its own geometry and specification. Terrestrial Energy’s molten salt design requires a fuel form that no commercial fabricator currently produces.

Each of these supply chains has to be invented, licensed, capitalized, and staffed before the reactor it serves can operate at anything approaching commercial scale, and each is essentially useless to any other concept in the current landscape. That last point compounds the problem considerably. Where the light water fuel cycle achieved its economics partly through consolidation around a small number of converging fuel specifications, the current generation of advanced reactor developers has produced a proliferation of bespoke fuel types so different from one another that shared infrastructure is nearly impossible to justify. The result is that the fixed costs of building each supply chain get amortized over whatever modest fleet a single vendor can assemble, rather than across an industry, which is precisely the condition that keeps unit costs high and prevents the kind of learning-by-doing that made LEU Uranium dioxide fuel fabrication affordable.

The conventional fuel cycle became boring through decades of unglamorous industrial learning. Advanced fuel cycles will have to earn their own version of boring.

That process is starting now, at small scale, in demonstration facilities and national laboratory test reactors, and the timeline for it to reach industrial maturity is measured in decades rather than years. Acknowledging that clearly, rather than projecting mature performance onto first-of-kind systems, is the honest foundation for evaluating where advanced nuclear actually goes from here.

This essay accompanies part two of Decouple’s deep dive on the nuclear fuel cycle with Michael Seely. Part one, on conventional UO2 fuel, fabrication, burnup limits, and accident-tolerant fuel, is available now on the Decouple Substack. Watch on YouTube, or listen on Apple and Spotify.

If you find our work valuable, consider supporting Decouple by pledging on Substack or making a tax-deductible donation through our fiscal sponsor at Givebutter.

Nuclear fuel does almost none of that. The fuel elements that go into a reactor and the fuel elements that come out are, to a first approximation, the same material in the same geometry, sitting in the same place. A spent fuel assembly pulled from a reactor after six years of operation looks nearly identical to the fresh one that went in. The mass has changed by a tiny fraction of a percent, nuclear alchemy has occurred in which half the periodic table has been generated in the form of fission products within the ceramic pellets but the volume and geometry is essentially identical.

This one fact, that nuclear fuel must be preserved rather than destroyed, that the job of every layer of every system surrounding the core is to maintain the integrity of a material through years of radiation bombardment and extreme temperature gradients, shapes much of nuclear engineering. It explains the cladding materials, the obsessive quality control in fabrication facilities, and the decades of slow, painstaking improvement that have transformed a fleet that routinely operated with failed fuel elements into one where a single leaker triggers a formal investigation.

I spent a long conversation with Michael Seely, a nuclear enginner with a focus on fuel and the mind behind the Atomic Blender channel, going through what nuclear fuel actually is, how it is made, why it fails, and how the industry learned to prevent those failures. What follows is my attempt to synthesize that conversation into something useful for anyone who wants to understand nuclear from the inside out.

What the Fuel Actually Is

The commercial nuclear fuel cycle, in its conventional form, converges on a single material: uranium dioxide, or UO2. Regardless of reactor type, whether you are talking about a pressurized water reactor in France, a boiling water reactor in Japan, or a CANDU in Ontario, the fuel pellet sitting at the centre of the fuel rod is almost certainly a dense ceramic cylinder of uranium dioxide roughly the size of a fingertip.

UO2 ended up in this position for reasons that are easier to appreciate once you understand what you are asking a fuel material to do. You need something that can withstand centerline temperatures of 1,200-1,600 degrees Celsius under normal operating conditions, while the coolant immediately outside the cladding sits at around 300 degrees, a gradient of nearly a thousand degrees across a pellet roughly a centimetre in diameter.

You need something that will not chemically react with zirconium cladding or the pressurized water flowing over it. You need something that will trap the fission products, the gases and solids generated as uranium atoms split, inside its crystalline matrix rather than releasing them into the coolant. And you need something that can be manufactured reliably, in quantity, at a cost that keeps nuclear electricity commercially competitive. In fact the key differentiator between nuclear and fossil power generation is that despite its complexity nuclear fuel remains a relatively very small contributor to operating expenses.

Uranium dioxide satisfies all of these requirements tolerably well, which is distinct from satisfying any of them perfectly. It is a ceramic, which means it has an extremely high melting point, around 2,800 degrees Celsius, providing enormous safety margin even under severe accident conditions. Its crystalline grain structure traps fission products reasonably effectively: the krypton, xenon, and iodine gasses generated by fission mostly stay embedded in the UO2 matrix rather than migrating into the gap between pellet and cladding. And the manufacturing process, while technically demanding, has been refined over seven decades into something industrial routine.

The fabrication sequence is instructive precisely because of how unglamorous it is. Enriched uranium hexafluoride arrives at the fabrication facility as a gas. It is converted to UO2 powder through either a wet or dry chemical deconversion process, both involving steam or water stripping the fluorine atoms away and producing hydrofluoric acid as a byproduct, which is why fuel fabrication facilities will let you tour almost everything except the conversion and deconversion sections. The resulting powder is pressed into pellet shapes roughly double the final size, then sintered at high temperature in a controlled atmosphere, where the individual powder grains fuse together and the pellet densifies and shrinks to its final dimensions. It gets inspected, polished, and loaded into zirconium-alloy tubes that are backfilled with helium and welded shut. Those rods are then assembled into fuel assemblies and shipped to a reactor.

That is how you make nuclear fuel. The process has no truly exotic steps. Given adequate equipment and trained staff, it is not categorically harder than pharmaceutical tablet manufacturing or precision ceramics production for industrial applications. The difficulty is not in any single step but in the aggregate quality requirements, and in the fact that the finished product has to perform flawlessly inside a reactor for six years before it is seen again.

The Bespoke Problem

One of the things I had naively assumed before talking to Michael was that light water reactor fuel had converged on something close to a standard. If you are making a Westinghouse pressurized water reactor, you use Westinghouse fuel, and presumably that fuel works in any other Westinghouse plant. The reality is considerably messier.

At a high level, yes, the fuel concept is consistent: enriched UO2 in a zirconium-clad rod assembled into a square grid. But the geometry, enrichment, dimensions, grid structure, and pin layout vary substantially across reactor families and, within those families, often across individual plants depending on their vintage, their operating history, and the specific optimization choices made by the utility and fuel vendor over decades of operation. Westinghouse plants run different fuel from Framatome plants. BWRs, which have gone through generations of lattice designs from 6x6 grids to 10x10, use different fuel from PWRs. Even within a single family, the axial enrichment profile, the radial enrichment distribution across the assembly, and the height of the active fuel zone will vary between plants.

The reason for this complexity is worth understanding, because it is not bureaucratic perversity. Core designers are trying to solve an optimization problem of extraordinary dimensionality. A typical PWR core has 150 to 200 fuel assemblies, each containing more than 200 individual fuel pins, each pin containing hundreds of pellets, and each of those pellets will spend up to six years inside the reactor core before being removed. Over that period, neutron flux, fission product buildup, cladding corrosion, and mechanical stress all interact in ways that depend on where in the core the assembly sits, how many cycles it has already completed, and what the surrounding assemblies are doing. The enrichment of each pellet is therefore not a single number decided once and applied uniformly; it is a three-dimensional distribution optimized to extract maximum energy while staying within safety limits and protecting the structural components of the reactor vessel from excess neutron bombardment at its ends.

Michael’s description of axial enrichment zones, where pellets at the top and bottom of a fuel rod are enriched to lower levels to reduce neutron fluence on the reactor pressure vessel, was one of those small details that makes the whole enterprise feel astonishingly sophisticated once you register it. The pellets in the center of the rod might be enriched to 4.5 or 5 percent uranium-235. The pellets near the ends might be at 2 percent, or even natural uranium, deliberately and precisely placing less fissile material where you want less activity. In a BWR, where steam voiding changes the neutron moderation environment as you move up the core, the axial enrichment zoning becomes even more granular, potentially spanning seven or eight distinct levels.

The practical consequence of all this customization is that fuel is not a commodity. You cannot easily substitute one vendor’s assembly for another’s in an existing core, and a fuel design qualified for one plant is not automatically qualified for another even if they share a vendor and a general reactor family. Qualification is expensive and slow, which is one reason why GE Hitachi’s sales pitch for the BWRX-300 being constructed at Darlington explicitly highlights the use of existing GNF2 boiling water reactor fuel. Bringing in qualified, proven, extensively documented fuel avoids years of regulatory work and removes one of the largest uncertainties in the licensing process. It is also, as Michael pointed out, one of the more underappreciated arguments for fleet standardization: if you are building ten AP1000s rather than ten bespoke reactor designs, you eventually reduce to something approaching a standard fuel specification, and the fabrication, qualification, and supply chain costs all follow accordingly.

Leakers, Zero by 2010, and the Patience of Industrial Learning

The history of fuel failures in the American light water fleet is a useful corrective to the assumption that nuclear technology arrived mature and simply had to be deployed. Through the 1970s, 80s, and well into the 90s, it was routine for a majority of the US fleet to operate with fuel pins that had developed small holes, what the industry calls leakers. Fission gases would escape through these holes into the reactor coolant system, radiation monitors would detect the activity, and operators would respond with compensatory measures ranging from reducing power in specific assemblies to adjusting coolant chemistry. The reactor kept running. The leakers were noted, managed, and tolerated as a fact of life.

The causes were mostly prosaic. Debris ingress was the dominant mechanism: metal filings, wire bristles from cleaning brushes, small hardware left behind during maintenance, any of which could get lodged between fuel rods and vibrate its way through the soft zirconium cladding over months of operation. Weld defects at the end plugs of fuel pins could allow water ingress, triggering a hydrating reaction that embrittled the cladding. Grid-to-rod fretting, where the structural grids holding the assembly together wore against the fuel pins under flow-induced vibration, produced a class of failures that took years of systematic investigation to understand and address.

The economic consequences were real. In boiling water reactors, where steam goes directly to the turbine rather than through an intermediate steam generator, fission product contamination of the turbine island created radiation exposures that complicated every subsequent maintenance outage, requiring additional shielding, extra radiation surveys, and prolonged cleanup. In both BWR and PWR plants, a fuel failure meant elevated coolant activity for the remainder of the cycle, which meant higher worker dose during the outage, stricter controls on component removal and handling, and sometimes early cycle termination if activity climbed high enough. These costs accumulated in outage labor hours and replacement power purchases, which is why the industry eventually decided to treat them as urgent problems worth solving rather than conditions to be managed.

The Zero by 2010 initiative, organized through the Electric Power Research Institute and involving coordinated action across the US fleet and its fuel vendors, targeted exactly this. Foreign material exclusion programs were tightened at every stage of the fuel fabrication and reactor maintenance process. Grid and fuel rod designs were modified to reduce fretting susceptibility. Welding and inspection procedures were revised. And, critically, operators started sharing failure data systematically across the industry rather than treating each incident as a local problem to be quietly resolved.

By 2010, the initiative had largely succeeded. The US fleet today operates with fuel failure rates that would have been unimaginable in 1985. When a leak does occur now, it is investigated as an anomaly, not absorbed as background noise. The Taishan EPR incident that drew international attention a few years ago, where elevated primary circuit activity pointed to a small number of failed fuel rods, was notable precisely because fuel failures are no longer routine; the detection thresholds are sensitive enough and the expectations high enough that a handful of leakers in a fleet of hundreds of reactors generates headlines.

This history is worth holding in mind every time someone talks about the 93 percent capacity factors that today’s light water fleet achieves and then projects that number directly onto whatever new reactor concept and fuel they are discussing. The 93 percent is the product of decades of systematic learning, investment in understanding failure modes, and industry-wide coordination of the kind that only becomes possible once you have hundreds of units in operation generating comparable data. It was not the starting point. It was the destination of a very long journey.

Burnup, Cladding, and Why Things Changed After Fukushima

Burnup is the nuclear engineering metric for how hard you have used your fuel: how much energy you extracted per metric ton of uranium loaded. CANDU reactors running on natural uranium, where the tiny fraction of fissile uranium-235 is exhausted relatively quickly and the buildup of neutron-absorbing fission products forces fuel changes after a short irradiation period, achieve around 7 to 8 gigawatt-days per tonne. Light water reactors, starting with enriched fuel and benefiting from the in-situ generation of fissile plutonium from the abundant uranium-238, run to 50 or 60 gigawatt-days per tonne today, with higher burnup fuels pushing toward 70 or 80.

The limiting factor at high burnup is not purely enrichment level or the fuel pellet itself. The UO2 can in principle sustain continued fissioning as long as fissile material remains and the neutron environment supports it. What gives out is the zirconium cladding surrounding the pellet. Two degradation mechanisms are the main concerns. Oxidation of the cladding’s outer surface by the hot pressurized water, carrying dissolved boric acid in PWRs, progressively converts zirconium metal to zirconium oxide and depletes the cladding wall thickness. Hydrogen pickup, where hydrogen liberated by the oxidation reaction diffuses into the cladding metal, forms zirconium hydride precipitates that reduce the material’s ductility, making it brittle and prone to cracking under mechanical stress. Under normal operating conditions these processes are gradual and manageable. Under accident conditions, particularly rapid temperature transients, the embrittled cladding can fracture catastrophically.

Fukushima refocused the industry’s attention on this second concern. The hydrogen generated by rapid oxidation of zirconium cladding under loss-of-coolant conditions was directly responsible for the building explosions at Fukushima Daiichi. The response was accident-tolerant fuel, or ATF, an umbrella term for fuel designs intended to reduce the rate of cladding oxidation and hydrogen generation under severe accident conditions, buying more time for operators and emergency systems to respond before the situation becomes irretrievable.

The most commercially advanced ATF approach involves chromium-coated cladding, where a thin chromium layer on the outside of the zirconium tube dramatically slows oxidation at high temperatures. Doped fuel pellets, where small additions of chromia or alumina to the UO2 matrix improve grain structure and reduce fission gas release, complement the improved cladding. The combination, being developed commercially by both Framatome and Westinghouse, does not eliminate hydrogen generation under the most severe scenarios, but extends the coping time meaningfully.

What emerged from the development work, somewhat unexpectedly, was that the same improvements enabling better accident performance also enable higher burnup under normal operating conditions. A more oxidation-resistant cladding that retains ductility at higher burnup, combined with a fuel pellet that holds its geometry and retains fission gases more effectively, opens the door to fuel enriched to 6, 7, or 8 percent uranium-235, well above the conventional 5 percent ceiling. This is LEU Plus, and its commercial appeal is not primarily about accident safety, it is about outage economics.

A reactor that can run 24 months between refueling outages instead of 18 eliminates one scheduled outage every three cycles. At a plant like Vogtle, where four units now share a site and maintenance staff, being able to stagger outages cleanly on a 24-month cycle instead of overlapping 18-month cycles reduces the requirement for contractor surge staffing and simplifies the planning horizon considerably. Fuel that costs two to three times more per kilogram but that you reload less often and from which you extract more energy can be economically rational, especially given that fuel represents only 15 to 20 percent of a nuclear plant’s operating cost. Whether LEU Plus becomes standard across the fleet or remains a premium option for specific operating configurations will depend on plant-by-plant economics, but the direction of travel will be intriguing to watch.

The Chicken and the Egg of the HALEU Supply Chain

All of this background on conventional fuel provides essential context for understanding why high-assay low-enriched uranium (HALEU), the feedstock required by most advanced reactor designs, represents such a significant challenge.

HALEU is enriched to between 5 and 20 percent uranium-235. That range might sound modest relative to the 90 percent enrichment of weapons-grade material, but the difference in manufacturing infrastructure between 5 percent and 19.75 percent is enormous. At 5 percent, the entire global enrichment and fuel fabrication industry has been optimized for decades, with equipment geometries, material accounting procedures, criticality safety protocols, and facility designs all calibrated to that enrichment level. Moving to 19.75 percent changes essentially all of these parameters. Batches must be smaller to stay subcritical. Water must be kept further away. Accounting must be tighter. The facilities look different, operate differently, and require different trained staff.

The economics compound the infrastructure challenge. Making one kilogram of 5 percent enriched uranium requires about 9 kilograms of natural uranium as feedstock depending on tails, plus a well-understood amount of centrifuge separative work. Making one kilogram of HALEU at 20 percent requires roughly 40 kilograms of natural uranium and about six times the separative work per kilogram of product. HALEU is therefore expensive before a gram of it enters a fabrication facility, and the fabrication of HALEU into finished fuel is a separate challenge with its own cost premium.

The demand side compounds things further. The entire current world annual HALEU consumption of the non-Russian world amounts to perhaps five or six metric tons, some in research reactors and the majority in the Russian icebreaker fleet. Centrus Energy, currently the only Western HALEU enrichment operation, runs a small demonstration cascade in Piketon, Ohio, producing around 900 kilograms per year under a contract with the Department of Energy as its offtaker. One advanced reactor, even a microreactor, can easily require a metric ton or more for its initial fuel loading. The DOE has been effectively subsidizing HALEU supply to backstop the first few advanced reactor demonstrations, but a commercial HALEU fuel cycle requires commercial HALEU demand, and commercial HALEU demand requires a fleet of operating reactors, and building that fleet requires fuel.

This circularity is not peculiar to nuclear. It shows up wherever a new industrial process requires scale to become economical but requires demonstrated economics to justify scale. What makes it particularly acute for advanced nuclear is that the investment required to establish a Western HALEU supply chain is very large, the timeline is very long, and the alternative, light water reactors running on fuel that is already produced in industrial quantity at well-understood cost, is extremely competitive. The startup founders and venture investors now flooding into advanced nuclear may be surprised to learn that the supply chain for their reactor’s fuel essentially does not yet exist in a commercial form. Building it will require sustained demand that no single company can create alone. That challenge is compounded by the sheer number of bespoke reactor vendors in the current landscape, each with their own fuel specification, and in many cases dramatically different fuel types, making any shared infrastructure difficult to justify and harder still to finance robbing them of the economies of scale which help control fuel costs.

The Thread Running Through All of It

What connects the fuel pellet sintering process to the Zero by 2010 initiative to the burnup limits imposed by cladding corrosion to the HALEU supply problem is a single underlying dynamic: nuclear fuel technology improves slowly, through systematic learning from operating experience, and the improvements compound over decades into capabilities that were genuinely not achievable at the start of the program.

The 93 percent capacity factor of the American light water fleet, the near-elimination of fuel failures, the push toward 80 gigawatt-day burnup with LEU Plus, the highly optimized three-dimensional enrichment distributions that extract maximum energy from every kilogram of uranium, none of this was present in the early plants. It accumulated through fifty years of operation, incident investigation, information sharing across the industry, and reinvestment in understanding failure mechanisms. This operationally informed refinement is in itself a technology as important as the nuts and bolts of the reactor itself. The CANDU fuel bundle, which Michael noted has barely changed in its basic geometry across all the reactors in Argentina, Romania, and Canada, represents a different kind of achievement: simplicity so well-matched to its application that it has not required improvement for decades.

The question this history poses for the next generation of reactors is not whether their fuel concepts are interesting, TRISO and metallic fuel both have genuinely attractive properties that I am looking forward to digging into in our next episode. The question is what the equivalent of fifty years of operational learning looks like for technologies that have never operated at commercial scale, and how long it takes before the 93 percent projection that appears in every advanced reactor presentation reflects something other than aspiration.

*This essay accompanies part one of Decouple’s deep dive on the nuclear fuel cycle with Michael Seely. Part two, on TRISO, metallic fuel, and the economics of advanced reactor fuel, will be available soon. Watch on YouTube, or listen on Apple and Spotify.*

*If you find our work valuable, consider supporting Decouple by pledging on Substack or making a tax-deductible donation through our fiscal sponsor at Givebutter.*

Recent conversations about the budding nuclear renaissance often begin with the same list. Microsoft restarting Three Mile Island, tech companies partnering with advanced nuclear reactor vendors or the proposed Japanese funded US AP1000 fleet build. These announcements generate headlines, volatile valuations and investor decks.

Meanwhile, forty Westinghouse pressurized water reactors (PWR) sit at roughly the same thermal power output they were commissioned at decades ago, operating within design margins calculated on transistorized computers before integrated circuits existed. Together, these plants hold between 6-10GW of additional capacity, the equivalent of eighteen to thirty 300MW SMRs, that could be unlocked faster and cheaper than any other nuclear source and perhaps even faster than new gas.

My conversation with returning guests Robb Stewart and James Krellenstein, CTO and CEO of Alva Energy, made the case that power uprates at existing PWR plants represent the lowest-hanging fruit in the sector, bypassing the megaproject risks and nuclear supply chain rebuilding that make new nuclear construction so daunting for utilities.

The components turn out to be far more manageable and anticlimactic than new build nuclear: non-safety-related secondary side equipment such as feedwater heaters and condenser tube bundles, alongside nuclear-grade steam generators that the fleet has already learned to replace during their month long scheduled outages using well-rehearsed industrial choreography.

Alva’s approach avoids the traditional uprate bottleneck by building a separate standardized 250MW Second Turbine Generator Plant (2TGP) building diverting incremental steam from an uprated core without touching the existing turbine centerline. Most of the construction happens on a conventional, non nuclear island using mature supply chains and firm fixed price engineering, procurement, and construction contracts, leaving the outage window limited to a short tie in during a normal refueling cycle.

Compared to a cohort of first of a kind nuclear steam supply system startups that accessed public markets through SPAC mergers and achieved substantial valuations in the hundreds of millions on compelling nuclear narratives this approach sounds deliberately boring. But perhaps boring is what our current moment demands. The question is whether the American nuclear zeitgeist can resist the allure of novelty long enough to pluck the low hanging gigawatts hiding in plain sight.

The uprate asymmetry: BWRs juiced, PWRs stayed natural

The United States nuclear fleet has already added roughly 7GW of capacity through uprates. More than two thirds of that came from boiling water reactors (BWR), which represent only about a third of the operating fleet by unit count. The average BWR in the United States now operates at 160MW above its original licensed thermal power. Some units, particularly in Sweden, have pushed uprates past thirty percent.

Pressurized water reactors, by contrast, have barely moved. A handful of plants have completed small stretch uprates in the 2-4% range. A few larger projects happened in the 1970s and around 2010. The Westinghouse four-loop PWR, which is the single most common nuclear steam supply system in the United States by installed gigawatts, has never completed what the NRC classifies as an extended power uprate above 7%.

This asymmetry is not because PWRs are harder to uprate. The explanation is historical and institutional. General Electric (GE) spent decades refining its understanding of multiphase flow in BWR cores, codifying that knowledge and then systematically carrying those analytical approaches through the regulatory process. By the time they were approved, utilities had a clear, repeatable path to extract more power from the same core geometry.

PWR vendors and utilities, for reasons that had more to do with regulatory caution and shifting business priorities than with physics, never invested in the same systematic effort. The result is a technical arbitrage where core thermal margins and fuel performance allow higher power operation within existing licensing limits, but the industry has lacked a standardized engineering package and industrial execution model to make uprates routine rather than bespoke.

If the opportunity has been sitting there for decades, why did nobody pursue it systematically before? The answer has less to do with engineering than with political economy. For much of the 2000s and 2010s, there was no price signal to reward incremental nuclear output. Load growth was flat or declining in many markets, including deregulated ones where nuclear plants delivered reliability and fuel security but were compensated as low value baseload. Natural gas was cheap, and utilities that maintained nuclear fleets optimized for operations and maintenance cost reduction rather than capital investment to expand output.

Lastly, the project delivery organizations that once executed complex plant modifications had been hollowed out or disbanded, and capital markets placed little value on incremental nuclear megawatts when combined cycle gas plants were faster and cheaper to build and were positioned to capture the highest value tiers in deregulated markets by offering dispatchable capacity and ancillary services.

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Why the margin exists: computers, steam generators, conservative assumptions

When Westinghouse and Combustion Engineering designed large PWRs in the late 1960s, computational tools for reactor thermohydraulics were primitive. Safety analyses stacked conservative assumptions because uncertainties could not be resolved with higher fidelity models.

In the interim two things have changed. Operating experience accumulated over thousands of reactor years and modern neutronics codes and thermal hydraulic simulations model core behavior with precision impossible in the slide rule era. A reactor designed in 1968 to very conservative margins can now demonstrate it has been operating well within actual physical limits.

The other major variable is steam generator technology. Early designs were prone to tube fouling, corrosion, and plugging. By the 2000s, the industry mastered steam generator replacement during scheduled outages, often upgrading to designs with better materials and more heat transfer area. A new steam generator with greater thermal capacity pulls more heat from the reactor coolant system without changing anything nuclear.

These dynamics mean many PWRs are constrained not by reactor physics, but by secondary side equipment that was never optimized for higher output and is replaceable during maintenance windows.

Feed water heaters, condensers, and solving the outage bottleneck

The irony of nuclear power uprates is that most of the limiting components are not nuclear grade. Feed water heaters, condenser tube bundles, and main turbine capacity are all balance of plant equipment subject to conventional power generation standards, not 10 CFR 50 Appendix B quality assurance.

This matters because it changes the cost structure and the supply chain. A nuclear grade reactor pressure vessel head replacement is a multi-year procurement involving specialized forging, ASME Section III N-stamp fabrication, and a narrow vendor base. A feed water heater replacement is a large industrial heat exchanger that power plants replace routinely, procured from a much broader supplier ecosystem, installed during a refueling outage with craft labor that does not require nuclear-specific training for most of the work.

However, traditional uprates face a brutal execution problem. Accommodating additional steam from an uprated core often requires upgrading or replacing the main turbine centerline, which can take a plant offline for many months, and in some cases more than a year, while large rotating components are removed, replaced, and recommissioned.

Gigawatt-scale turbine replacements are supply chain nightmares, with seven-year lead times for forgings and machining across global vendors. Refueling outages are already tightly choreographed events with narrow critical paths, and adding major turbine work creates cascading dependencies where a late component delivery or installation complexity can spiral into months of lost generation with average losses of ~1 million dollars per day offline.

The approach being pursued by Alva attempts to sidestep this by standardizing the secondary side uprate package and decoupling it from the outage critical path. Instead of upgrading the existing turbine centerline, the additional steam from the uprated core gets diverted to a new standardized 250MW steam turbine plant, the Second Turbine Generator Plant (2TGP), built outside the protected area while the reactor stays online. During a normal refueling outage, the new plant gets tied into the steam and feedwater headers. To the existing balance of plant equipment, it appears as if the uprate never happened, since the original systems continue operating at their pre-uprate design basis.

Where does the second turbine island actually go? The answer is that many United States sites were originally planned for additional units that were later canceled. Those cancellations left brownfield or greenfield space already served by transmission infrastructure, cooling water systems, and heat rejection capacity.

This configuration changes the economics substantially. The bulk of the work happens on a greenfield site using non-nuclear construction standards, which allows firm fixed-price EPC contracts of the kind that companies routinely execute for combined cycle gas applications. The outage duration drops from months to the time needed for steam generator replacement work that many plants already do in under 30 days. The 200 to 300MW steam turbine supply chain, which has been building these units globally for over a century, is far broader than the narrow vendor base for gigawatt-scale reactor centerline components.

The goal is to build off of examples like Bechtel and SGTe who turned multi-year replacement projects into highly choreographed outages that could swap out a 400-ton steam generator in under thirty days. The learning curve was steep, but once the process was standardized, costs and schedules dropped by an order of magnitude. The first steam generator replacement at Surry in the 1970s took longer than 14 months. By the 2000s, the industry was completing them in 26 days.

The same learning curve logic applies to uprates. The first few projects will be slower and more expensive as engineering margins get validated and installation procedures get refined. By the fifth or sixth unit, the process could become routine, and the economics start to look very different from traditional megaproject math.

Are Uprates Parasitic?

The entire uprate model rests on an assumption about asset longevity. Many of the three-loop and four-loop PWRs being discussed are 1960s and 1970s vintage. Some are well into their second license renewal period. How long can these plants realistically run, and does pushing them to higher thermal power shorten that operating life?

Alva assumes conservatively that uprate economics must clear over a twenty year window, even though many units are likely to operate longer based on subsequent license renewals and ongoing reactor pressure vessel embrittlement monitoring. To date, neither the Nuclear Regulatory Commission nor the utility industry has identified hard material limits that would preclude further extensions, and surveillance reactor vessel capsule data continues to support long term operation.

The asset life question also has a portfolio dimension. The U.S. PWR fleet is not uniform in age. Watts Bar Unit 2 entered service in 2016, Seabrook in 1990, and Vogtle Units 1 and 2 in the early 1990s. These are all Westinghouse four loop reactors, some younger than the engineers now designing uprates for them, spanning an opportunity set that includes plants with decades of remaining life alongside those closer to the end of their initial operating horizon.

Second, and more interesting, is the claim that the uprate configuration can actually improve reliability rather than degrade it. The stress on rotating machinery in a traditional uprate comes from forcing the existing turbines, pumps, and heat exchangers to handle more flow and higher thermal loads. That is where you see unexpected consequences, unplanned trips, thrown turbine blades, and accelerated wear.

By diverting the additional steam to a separate turbine island, the existing balance of plant equipment continues operating at its original design conditions. The reactor coolant pumps run at the same speed. The main turbine sees the same steam flow it always has. In some cases, plants that had been pushing their legacy equipment by a few percent to squeeze out marginal gains can now dial that back, sending the extra steam to the new turbine and recovering reliability margin on the old equipment.

The nuclear steam supply system itself, according to this argument, is not being stressed in the conventional sense. The new steam generators are designed for the higher thermal duty. The reactor core operates at a higher power level, but modern fuel can handle it, and neutron flux increases are accounted for in embrittlement calculations. In some configurations, the primary system actually runs slightly cooler than before because the improved heat transfer pulls more energy out at lower temperatures.

Steam generator replacement has historically been life-extending rather than life-consuming. If the uprate layers additional revenue on top of that investment without imposing new mechanical stress on the equipment that actually fails, the model works.

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What actually drives the schedule?

A claimed five-year timeline from engineering to commercial operation does not immediately sound transformational. Combined cycle gas plants can go from greenfield to energization faster than that in many jurisdictions, and the pitch is that uprates could potentially beat gas on speed. What takes so long?

The answer is procurement, specifically steam generator fabrication. There has not been a robust market for new steam generators in recent years, and the vendor base needs time to scale back up. Unlike balance of plant components, steam generators are nuclear-grade pressure vessels subject to ASME Section III requirements, and the forging and tube bundle fabrication cannot be rushed. That procurement dominates the critical path for the first project.

The critical difference from traditional uprates is what is *not* on the critical path. All of the balance of plant construction, the turbine island fabrication, the installation of condensers and feedwater heaters, happens in parallel in the Second Turbine Generator Plant while the reactor stays online. By the time the new steam generators are ready and the plant goes into a refueling outage, the 2TGP is already built and tested. The outage itself only needs to accommodate the steam generator swap and the tie-in to the new headers, work that fits within a normal refueling window that the plant would be taking anyway.

This architecture allows parallelization. Once the first project validates the design and establishes the supply chain, subsequent projects at other sites can proceed simultaneously. The developer is not waiting for one plant to finish before starting the next. Multiple steam generator sets can be in fabrication for different sites. Multiple turbine islands can be under construction. The bottleneck shifts from sequential field construction to fabrication capacity, and fabrication scales faster than field work.

There is also an option value embedded in the model. If a hyperscaler wants power faster and is willing to pay for acceleration, the plant can take an earlier outage, compressing the overall schedule at the cost of higher near-term spending. That flexibility does not exist in new build projects, where the critical path is locked in by the construction sequence.

Whether five years is realistic for the first project is testable. Whether the timeline compresses for subsequent units depends on how well the standardization actually works and whether the steam generator supply chain can ramp without hitting quality or delivery problems. The schedule claim is aggressive but not obviously implausible, and it is far more credible than any of the timelines being quoted for first-of-a-kind reactor designs.

The Microsoft arbitrage: $116/MWh for 800 megawatts

The demand signal for additional nuclear capacity is no longer theoretical. Microsoft signed a power purchase agreement with Constellation to restart Three Mile Island Unit 1 at a reported price of $116/MWh. That is multiples of the current PJM wholesale clearing price, and it is for 835MW of capacity that was already built, already licensed, and sitting idle.

This price point changes the economics of everything. A nuclear uprate that adds 200-300MW to an existing unit, if it can secure even a fraction of that premium through a long-term PPA with a hyperscaler or large industrial customer, suddenly has a revenue stream that supports very aggressive capital investment.

The reason those prices exist is simple. Data centers need firm, 24/7 power with very high reliability, and although climate policy is on the back burner some still value low-carbon generation to satisfy their corporate commitments and comply with their AI customers’ environmental procurement requirements which is why Constellation can command that kind of premium.

This dynamic is not limited to restarts. An uprate that brings 200-300MW of additional capacity online at an existing site, with an existing transmission interconnection and an operating license already in hand, competes not against wholesale power markets but against the all-in cost of new generation that can meet the same reliability and carbon requirements. In that comparison, uprates start to look very attractive indeed.

The time advantage is also real. A well-executed uprate can go from engineering to commercial operation in 3-5 years, depending on the licensing path and the outage schedule. That is faster than any new nuclear build and faster than most large combined cycle gas plants in contested permitting environments.

If the hyperscalers are serious about expanding their AI infrastructure over the next decade, and if they are willing to pay nuclear premiums to secure that expansion, then there are billions of dollars of potential offtake value sitting in the existing PWR fleet waiting to be unlocked.

A typical 20 percent uprate on a 1,200MW unit adds 240MW, almost the equivalent of a BWRX-300 or roughly three NuScale power modules, at one-fifth to one-seventh the cost and without the construction risk or regulatory complexity of first-of-a-kind designs. Multi-unit stations could add several Alva Second Turbine Generator Plants (2TGPs) the equivalent of multiple SMRs. The entire uprate potential across the PWR fleet represents 20 to 30 small modular reactors worth of capacity, available in three to five years rather than fifteen.

The hidden crux: Competent project delivery organizations

One of the most common objections to nuclear uprates is regulatory risk. The reality is that the NRC has a well-established framework for reviewing power uprates, and utilities have successfully completed dozens of them under both the standardized review process for power uprates and through the license amendment process.

The real question is whether the American nuclear industry can rebuild the kind of project delivery organizations that used to exist at utilities like Florida Power & Light (FPL). The difference between a good nuclear project and a disaster often comes down to the strength of the owner or developer organization, not the reactor vendor. This is the lesson from comparing the construction of nuclear power plants St. Lucie Unit 2 in Florida with Washington Nuclear Project 3 in Washington State. Both were Combustion Engineering reactors with Ebasco as architect engineer, both under the NRC, both starting construction in 1977.

St. Lucie 2 came in under budget in about five years in the post-Three Mile Island context. It was built by FPL working with a couple hundred person internal projects organization whose only job was to deliver new nuclear for the utility.

In sharp contrast, Washington Nuclear Project 3 helped trigger the largest municipal bond default in American history at the time, built by the Washington Public Power Supply System, a loose consortium of dozens of small public utilities that had never built large thermal plants before.

The timing, hardware, vendor, and regulator were identical, yet outcomes diverged because the owner side organization differed in its ability to integrate the work, supervise execution, and enforce discipline.

A project delivery organization is not a contractor. It is an entity that takes responsibility for integrating design, procurement, construction, commissioning, and handover, and that has the authority and accountability to enforce schedule and cost discipline across all of those phases. It sits between the utility that will own and operate the asset and the vendors that supply the hardware. It knows how to read a Primavera P6 project schedule, manage a critical path, run value engineering sessions, and make the hard calls about when to push and when to stop.

This kind of organization does not get built by raising venture capital or hiring consultants. It gets built by doing hard projects, making mistakes, learning from them, and keeping the team together long enough to apply those lessons to the next project.

In contemporary terms Canadian utilities, Ontario Power Generation (OPG) and Bruce Power, did not suddenly know how to run billion-dollar refurbishments. They learned by doing them, repeatedly, under enormous public scrutiny, and they kept the institutional memory alive by maintaining continuity in leadership and core staff. Ultimately both OPG and Bruce Power have delivered under budget and ahead of schedule.

The strategy of starting with uprates rather than jumping straight to new builds offers a sequencing that allows organizations to build capability progressively. If a developer can repeatedly bring 200-300MW increments online at multiple sites over the next five years, they will have demonstrated something that almost no one else in the American nuclear sector can claim right now.

Boring is the new radical

The nuclear industry has spent the last two decades chasing innovation in advanced reactors, modular designs and factory fabrication with very little to show for it.

Power uprates at existing PWRs represent industrial execution and process discipline rather than the kind of work that generates TED talks or 500 million dollar SPAC combinations, but they actually put gigawatts on the grid. At this point if the nuclear renaissance is going to be real, it will not be because someone invented a better reactor. It will be because someone figured out how to repeatedly deliver projects on time and on budget, and then scaled that capability across a fleet.

The hardware already exists, the regulatory path is clear, and the demand is there, but what has been missing is the organizational capacity to turn all of that into megawatts. Time will tell whether developers like Alva can execute on the first few projects, prove the model works across different sites and vintages, and build the kind of repeatable project delivery organization that can scale beyond uprates. If they can, the nuclear sector gains something it has lacked for decades: a credible path from concept to commissioning that does not depend on heroic assumptions or government guarantees.

The most boring path to ten new gigawatts might also be the best path, for now.

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For a country anxious about losing ground to China across multiple domains (manufacturing capacity, infrastructure buildout, renewable energy deployment, shipbuilding, high-speed rail), AI and semiconductor dominance represented one of the few remaining areas of clear American advantage. The DeepSeek moment revealed that the gap was narrower than assumed and that export controls weren’t creating the bottleneck Washington expected. The response was calls to tighten restrictions further, accelerate domestic chip production, and win the race to AGI before China closes the distance completely.

That moment also exposed a fundamental divergence in what each side fears and what each side is racing toward.

The United States treats AI as a moonshot toward artificial general intelligence (AGI), a digital deity that will either save or destroy humanity depending on which thought leader you ask. The fear? if we fall behind, China reaches AGI first and the geopolitical order flips permanently.

China treats AI as industrial policy, another layer in a decades-long infrastructure buildout designed to raise state capacity, manufacturing efficiency, and quality of life in roughly that order. The anxiety there runs differently: if they fall behind, they fail to escape the middle income trap and their productivity doesn’t outpace their stalling demography.

Regime stability through AI enhanced State Capacity

Western conceptions of Chinese AI tends to fixate on surveillance and social control. Facial recognition at subway stations, digital tracking during COVID lockdowns, and the social credit system all get heavy play. However, there is a more interesting side to this story.

China is deploying AI to increase state capacity right across the board. That includes making high-speed rail schedules more efficient, optimizing power grid load balancing, the banal streamlining of bureaucratic processes like driver’s license renewals, and integrating AI assistants into government service portals. The goal is to make the machinery of the state run smoother, faster, and more responsive.

This connects to a Confucian-inflected model of governance where legitimacy flows from competence. The Communist Party’s hold on power depends partly on delivering rising living standards and partly on demonstrating that the state apparatus functions well. When the subway is clean and runs on time, when permitting a restaurant doesn’t require six months of Kafkaesque runarounds, when energy blackouts don’t cripple coastal manufacturing hubs, the system earns trust.

Compare that to the American deployment pattern. AI in US government services tends to concentrate in immigration enforcement, predictive policing, and bail risk assessment. The neoliberal state has hollowed out administrative capacity in most other domains, so AI gets bolted onto the parts that still have funding and political will: security, borders, and carceral systems.

The Chinese model is no lightweight on surveillance but the broader strategy is to embed AI in logistics, manufacturing, grid management, and public services in ways that make daily life more convenient and the economy more productive. WeChat handles mobile payments, government IDs, train tickets, and restaurant reservations in one app. That creates a granular economic telemetry the state can access, but it also creates a service layer that millions of people use because it works.

The Soviet Computing Paradox and Why China Avoided It

In the 1950s, Soviet mathematicians and engineers were at the frontier of cybernetics. They had elite talent, advanced theory, and a compelling use case: scientific central planning. If you could network computers across the economy, maybe you could coordinate production without the price signals of a market economy.

It failed because the Soviet system was built on chronic information distortion at every level. Factories routinely falsified output data to meet unrealistic production quotas, while ministries jealously hoarded resources to protect their own bureaucratic turf. As a result, the data flowing up the hierarchy was often meaningless, rendering the decisions flowing back down even more disconnected from reality. Introducing computers into this structure did not resolve the dysfunction, it merely exposed it more clearly.

China faced a similar risk. Before Deng Xiaoping’s reforms, it ran a command economy with central ministries managing entire industrial sectors. But China decentralized. It introduced competition within the state sector, tied official promotions to measurable performance indicators, and let local governments experiment with different policies. The center still sets high-level goals, but mid-level actors figure out how to hit them and get rewarded or punished based on efficiency and results.

This is why AI integration works differently in China than perhaps it would have in the USSR. The system isn’t trying to centrally plan every transaction. It’s using AI to optimize specific functions (train scheduling, power dispatch, logistics routing) within a framework where local officials and state-owned enterprises have strong incentives to actually improve performance.

How Chinese AI is Regulated

Regulation in China operates through centralized authority and explicit enforcement, whereas the United States still lacks a coherent framework for governing advanced AI systems. Despite years of congressional hearings and public concern, there is no federal licensing regime for large models, no binding technical standards for deployment, and no single regulator with clear jurisdiction over model training.

The Biden administration’s 2023 executive order on AI relied primarily on reporting requirements and interagency coordination and was revoked by Trump in early 2025, while successive efforts in Washington have focused more on limiting state level AI regulation than on constructing a national one. The practical effect has been to leave governance largely in the hands of private companies and courts, creating a diffuse and reactive system that contrasts sharply with the direct state control exercised in China.

China on the other hand requires foundation models above a certain parameter threshold to be registered with the Cyberspace Administration, and compliance operates at several layers. Companies are expected to curate training data in ways that align with state guidance, to conduct internal content reviews during development, and to implement post-training alignment mechanisms that filter sensitive outputs.

The result is not simply an external censorship switch applied at the end, but a structured pipeline in which data selection, fine-tuning, and reinforcement processes are shaped by regulatory expectations. When a model begins to respond to politically sensitive prompts, such as detailed questions about Tiananmen Square, a filtering layer can interrupt the response in real time, reflecting both technical safeguards and anticipatory compliance by firms that understand the political boundaries within which they operate.

Unlike the USA, China has not been afraid to discipline big tech. When Beijing cracked down on high-frequency trading, banned cryptocurrency mining, and shut down the after-school tutoring industry, the logic was consistent. If an economic activity consumes energy and capital without contributing to long-term productivity or social stability, it gets pruned. AI is judged by the same standard. If it makes factories more efficient, trains faster, or government services less frustrating it gets state support. If it just churns through electricity for speculative gains or social media engagement metrics it faces restrictions.

Chinese AI companies know what the government wants and align accordingly, sometimes because they believe in the goals and sometimes because the alternative is getting shut down like Jack Ma’s Ant Financial.

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Energy Abundance and the Western Data, Eastern Compute Strategy

While the United States currently benefits from dominance in advanced semiconductor design, China holds a structural advantage in electricity supply. Decades of sustained annual grid expansion, combined with streamlined permitting and centralized siting authority, have produced an energy system capable of adding capacity quickly to expeditiously absorb large new loads. The American grid, by contrast, has stagnated since the 1980s, and new generation or transmission projects frequently encounter regulatory delays, local resistance, and litigation.

China added more than 500 gigawatts of new power capacity in 2025, roughly 80 percent of it wind and solar with the remainder largely coal. That increment alone approaches 40 percent of total installed US capacity. Bloomberg New Energy Finance projects that China could double its already vast grid capacity within five years. This expansion is not driven solely by artificial intelligence. It supports manufacturing, and a deeper electrification project aimed at reducing dependence on oil imports. Data centers, however, fit naturally within that larger trajectory of energy buildout.

The United States faces tighter constraints. Data center proposals often trigger local opposition because they consume significant electricity while creating relatively few long term jobs after construction. Utilities struggle to expand transmission infrastructure at comparable speed. Nuclear additions remain slow and capital intensive. Natural gas projects encounter supply chain and permitting friction. Each of these factors slows the pace at which compute intensive infrastructure can scale.

China operates within a coordination structure that allows energy planning and compute deployment to move together. Provincial authorities can designate large data center clusters in interior regions where land, coal, wind, and solar resources are abundant, while national planners align generation and transmission expansion with projected artificial intelligence demand. This approach, commonly described as the Western Data, Eastern Compute strategy, reflects the technical reality that training runs are energy intensive and well suited to bulk coal and renewables power generation in western provinces such as Gansu, Qinghai, and Inner Mongolia, whereas inference workloads are more latency sensitive and therefore remain closer to coastal population centers such as Shanghai, Shenzhen, and Beijing.

Racing in Diverging Directions

The framing of an artificial intelligence race between the United States and China assumes a single finish line and a shared definition of victory. That framing obscures the reality that each country is optimizing for different institutional priorities and deploying artificial intelligence toward different economic and political ends.

The so-called race therefore obscures the real question, which concerns how well each system will translate artificial intelligence into sustained power, legitimacy, and productivity within its own constraints.

Artificial intelligence is molded by the incentives, institutions, and bottlenecks that surround it. The divergence we are witnessing is less about who reaches a singular milestone first and more about how two distinct political economies absorb and direct a general-purpose technology. The outcome will be written not only in benchmark scores or valuation multiples, but in factories, grids, bureaucracies, and the lived experience of economic growth and state power.

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In this special episode, I sat down with someone whose name should be far better known in Canada and beyond. Ken Petrunik belongs to a small cohort of leaders who carried real responsibility for some of the most complex construction projects Canada ever undertook, and who helped establish Canada as a serious nuclear nation during the period when it actually built reactors at scale.

Petrunik was formed during the peak decades of Canada’s nuclear build program, when thirty five large CANDU reactors were constructed domestically and internationally over roughly thirty years, including periods when as many as ten units were under simultaneous construction.

The system that trained him was demanding and often unforgiving and operationally decisive. Responsibility attached to individuals rather than processes, and decisions were made by people who would later have to live with their consequences, sometimes for decades. That environment shaped a generation of project managers capable of integrating engineering reality, political pressure, labor dynamics, and schedule risk into a single operational picture.

That trajectory culminated in Petrunik leading the last CANDU reactors completed as true greenfield new builds, the Qinshan Phase III units in China, which were delivered ahead of schedule and under budget under a high risk fixed price engineering, procurement, and construction contract. Outcomes of that kind remain rare in nuclear construction because they require accumulated delivery capability and they depend on decisions taken early by people who understand how construction failures propagate before they become visible.

Standing on the shoulders of giants. Time to look down

As Canada once again contemplates an ambitious domestic buildout of large nuclear power, and as relations with China cautiously re warm alongside renewed export ambitions, there is urgency in studying the people who led a world class industry while that knowledge still exists. Contemporary nuclear debates devote enormous attention to reactor concepts, licensing philosophies, and steam supply system variants, while paying far less attention to the human factors constraints that determine whether any of those designs ever become operating plants. Nuclear success has always depended on a small number of project managers capable of holding technical complexity, institutional friction, and political pressure in balance while moving a project forward in real time.

Ken Petrunik’s career helps explain why some reactors arrived early and others never did. It functions as a case study in the flourishing, and eventual erosion, of nuclear build capability across time, geography, and political change.

Formed in the Only Environment That Could Produce Him

Petrunik’s development cannot be separated from the institutional environment in which it occurred. He joined Atomic Energy of Canada Limited when AECL functioned as a national design authority embedded in an active construction program, rather than as an advisory body removed from execution, and when Ontario Hydro was adding large baseload capacity at a pace that sustained continuous learning across design, construction, commissioning, and operations. Canadian suppliers were not acquiring nuclear grade capability through demonstration projects or paper qualification, but by manufacturing components repeatedly under real delivery schedules.

This environment produced professionals who accumulated full cycle exposure. Engineers and project managers moved between design offices, construction sites, commissioning teams, and operating stations, developing an intuitive understanding of how drawings translated into pours, how procurement delays constrained labor productivity, and how regulatory sequencing interacted with construction reality. Petrunik’s own background reflects this integration, combining technical grounding in reactor thermal hydraulics with extended periods living on site, where the relationship between planning and execution could not be abstracted away.

That exposure shaped how he approached project control, keeping attention on the small set of actions that genuinely governed progress rather than on accumulating layers of process. Living with the downstream consequences of procurement delays, interface mismatches, and sequencing errors produced a concrete sense of timing and priority. The system that formed Petrunik reinforced this discipline through repeated engagement with live projects, embedding judgment through experience long before later governance frameworks attempted to substitute procedural complexity for firsthand knowledge of how builds actually fail.

Exporting CANDU as an Execution System

Canada’s success exporting CANDU reactors is often attributed to the technical attributes of the design, including fuel flexibility, heavy water moderation, and natural uranium economics, all of which contributed to competitiveness in specific markets. Those features alone, however, do not explain why Canadian projects survived political instability, institutional disruption, and financing uncertainty that would normally undermine nuclear construction.

What accompanied the reactor hardware was an execution system that treated the owner and vendor as a single delivery organism rather than as counterparties attempting to shift contractural risk.

Qinshan and the Logic of Early Decisions

The Qinshan Phase III project provides the clearest window into Petrunik’s approach to nuclear construction. The contract imposed a compressed schedule with minimal tolerance for learning during execution, while labor quality uncertainty and political visibility amplified the cost of delay without expanding tolerance for failure. Under these conditions, recovery depended on decisions taken before their necessity was obvious.

One of the most consequential choices involved adopting open top construction, leaving the reactor building open longer than conventional practice to permit installation of large components by crane. Although the approach had been discussed on earlier CANDU projects, it had not previously been implemented, in part because it introduced civil engineering unknowns and required confidence that benefits would materialize later rather than immediately. The decision imposed near term difficulty in exchange for latent resilience.

Years afterward, when steam generator fabrication problems emerged, that earlier choice prevented what would otherwise have become a schedule failure, because installation flexibility had been preserved before the constraint was visible. The benefit existed only because the decision had been made early, by someone who understood the entire build sequence and could visualize how downstream failure modes would interact with structural choices made at the outset.

At Qinshan, one of the most high stakes moments came during a critical concrete pour on the reactor building compound containment when the 24 day continuous slip-forming operation began to fail in the middle of the night. The concrete was already moving, the formwork was under stress, and stopping the pour would have introduced cold joints that could have compromised structural integrity and schedule.

Rather than escalating the issue up a distant management chain or pausing for procedural clarity, the response was immediate. The team shifted to manual bucket placement, kept the concrete workable, maintained continuity through the night, and stabilized the pour until the formwork system could be restored by morning. The episode captures a defining feature of the project’s success, namely that authority, technical judgment, and accountability were present on site at the moment of failure, allowing a potentially schedule-breaking event to be absorbed through decisive action rather than converted into a prolonged disruption.

Throughout the project, Petrunik insisted that the owner see the real schedule drivers rather than a sea of minor tasks. The focus stayed on the few activities that could actually delay the plant, which made it easier to make decisions quickly when problems appeared. Because both sides were looking at the same risks, effort went into getting the project back on track instead of arguing about who was at fault. The project stayed manageable because despite surprises occurring, they were identified early and handled by people with the authority to act decisively.

Why Software Was Not a Magic Bullet

Across his career, Petrunik watched successive waves of project management software arrive with the promise that greater control could be achieved by breaking work into finer and finer pieces. Schedules expanded from a few thousand activities to hundreds of thousands, driven by the belief that more detail and more data would translate into better predictability. In practice, the growing volume of information often made it harder to see the small number of constraints that actually determined whether the project would finish on time.

As schedules and reporting systems became denser, senior leadership found it increasingly difficult to separate what truly mattered from what merely existed on paper. Construction, meanwhile, continued to advance according to physical realities that no amount of planning sophistication could override, including crane access, concrete cure times, labor coordination, sequencing conflicts, and tight spatial tolerances. Tools designed to demonstrate completeness and progress gradually redirected attention away from decision critical risks and toward the maintenance of elaborate representations of the project.

Petrunik deliberately resisted this drift by keeping the control schedule at a level that supported real decisions. Detail was added only when a specific problem demanded it, allowing the critical path to remain understandable and actionable. The underlying judgment was simple and hard won, namely that distance from the work, even when mediated through highly detailed tools, weakens decision making rather than strengthening it, and that execution improves only when tools reinforce direct understanding of how the job is actually being built.

The Loss of the Builder Environment

By the later stages of Petrunik’s career, the Canadian environment that had produced him no longer existed. A prolonged plateau in electricity demand removed the system level justification for continued baseload expansion, and once the need to keep building disappeared, the institutions that sustained delivery began to decay. Construction cadence slowed, feedback loops lengthened, and experiential knowledge stopped accumulating across generations.

Atomic Energy of Canada Limited was dismantled as export prospects receded, while Ontario Hydro was restructured around asset management rather than expansion. Greenfield construction gave way to refurbishment programs that preserved isolated technical skills without reproducing the integrated builder ecosystem that had once linked design, construction, commissioning, and operations under continuous schedule pressure. New entrants encountered a sector increasingly oriented toward analysis, licensing, and risk management, with limited opportunity to experience full project delivery.

Western nuclear programs now attempt to restart construction without a generation that has built at scale, compensating by importing governance frameworks, expanding oversight, and placing hope in novel reactor concepts or digital systems. These responses address symptoms rather than the underlying loss of experiential capacity. Petrunik’s later work in the Middle East underscores the contrast, as countries establishing nuclear programs prioritize recruiting individuals with demonstrated delivery experience and organizing institutions around their authority.

What Canada Is Deciding Now

The significance of Petrunik’s career lies in what it reveals about how nuclear capability is formed and lost. Builder competence is the result of sustained exposure to projects that require decisions to be made under pressure. Continuity matters because it creates repeated opportunities to exercise judgment, observe failure modes, and internalize how recovery actually occurs.

Canada’s re-entry into nuclear construction through small modular reactor projects at Darlington is occurring within a project management culture shaped by contemporary Western governance norms, where authority is diffuse, oversight is layered, and risk is carefully distributed away from individual decision makers.

The question Canada now faces is whether it is prepared to recreate the conditions under which that capability emerged previously, including concentrated authority, accountable decision making, and continuous exposure to delivery under real schedule pressure. Nuclear plants that arrive on time reflect choices about how people are trained, how authority is exercised, and how consequence is assigned. Canada once created these opportunities. The current build cycle will reveal whether it is able to do so again.

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Resources:

Ken Petrunik: Practical Project Management. https://books.google.ca/books?id=D40ZCwAAQBAJ&printsec=frontcover&redir_esc=y#v=onepage&q&f=false

CANTeach Construction of CANDU in China: A success story. https://canteach.candu.org/Content%20Library/20031901.pdf

By the late 1980s, Europe appeared well positioned to do so. France had completed a rapid and disciplined national pressurised water reactor buildout. Germany had demonstrated its ability to execute conservative, highly redundant plants through the Konvoi series. Political conditions were shifting as the Cold War wound down, cross border industrial cooperation was gaining momentum, and there was confidence that Europe could converge on a single flagship design that would move smoothly through national licensing regimes from Finland to the United Kingdom.

The EPR was conceived as that design. It sought to combine the scale, fuel efficiency, and digital instrumentation and control heritage of the French N4 lineage with the German emphasis on redundancy, physical separation, and operability and threw in a core catcher to boot. The ambition was to deliver a reactor that reassured regulators through conservatism, silenced critics through margin, and achieved compelling economics through sheer size.

What ultimately emerged was, at 1650MW, the world’s highest output commercial power reactor, and with it a revealing case study in the limits of engineering driven convergence.

Design by Accumulation

At a high level, the EPR remains a familiar large light water reactor. Its core geometry, fuel, and reliance on active safety systems place it squarely within the classical pressurized water reactor tradition. The distinction lies less in conceptual novelty than in the cumulative effect of design decisions layered atop one another.

From the French side, the inheritance is clear. The EPR descends directly from the N4 series, a four loop reactor optimized for economies of scale and built around an early, fully digital instrumentation and control architecture. Its core is physically large, with lower average power density, allowing thermal margins and improved fuel utilization to be achieved primarily through geometry and neutron economy rather than by elevating operating limits.

From the German side comes a different emphasis. The Konvoi plants were designed under intense public scrutiny, and the response was to prioritize robustness, separation, and operability. Four independent safety trains, conservative assumptions for external hazards, and generous spatial allowances inside a double containment supported both maintainability and operational flexibility. Space was treated as a safety feature rather than a cost to be minimized.

A safety train, in this context, is not a single system but a complete, independent pathway capable of performing required safety functions on its own. Each train includes its own mechanical systems such as emergency core cooling pumps, piping, valves, and heat exchangers, its own safety classified electrical supply beginning with an emergency diesel generator and dedicated buses, and its own instrumentation and control channel with separate sensors, logic, and actuation paths. All of this equipment is physically separated, seismically qualified, environmentally hardened, and supported by dedicated rooms, cabling routes, penetrations, ventilation, and fire protection so that a failure, fire, or flood affecting one train cannot disable another.

The EPR incorporated both traditions and then extended them. The safety architecture evolved from the partially sized trains of the Konvoi into a configuration where each train was independently 100% capable of meeting the full safety requirements of the reactor. Each train was paired with its own safety related diesel generator, and additional generators were added to support extended station blackout coping. The result was a single unit equipped with six on site safety diesel generators. For reference most PWRs have two.

Each of these decisions was defensible in isolation. Taken together, they produced a plant in which redundancy propagated through every layer of the physical layout. Additional trains required additional compartments, penetrations, supports, barriers, inspections, and procedures.

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When drawings meet concrete

The EPR passed its safety case on paper. Its difficulties emerged at the interface between design maturity and construction sequencing, the point at which large nuclear projects typically succeed or unravel.

Nuclear plants rarely reach full construction level design completeness before site work begins. Licensing review, vendor final data, and site specific engineering typically proceed in parallel with early civil execution. In first of a kind projects, this sequencing pushes many detailed routing, penetration, and interface decisions late into the build, once physical constraints are already fixed.

The Finnish experience illustrated this dynamic clearly. Regulatory concerns regarding the independence and clarity of the instrumentation and control architecture were resolved only after major structural elements had already been finalized. Addressing those concerns required changes to cabling and system routing that interacted directly with completed safety classified civil works. Each new or modified cable demanded a defined route, typically requiring additional penetrations through structures intended to preserve separation between redundant safety trains. Those penetrations then had to be requalified for fire, flooding, seismic loads, and environmental conditions, triggering repeated inspections, documentation updates, and intrusive modification of concrete that had already been poured, reinforced, and accepted.

The EPR magnified this problem because its redundancy architecture imposed physical separation and seismic qualification across nearly all safety related systems. As a result, civil works, cable routing, fire separation, and seismic supports moved from background engineering considerations into the center of the critical path.

Why similar ideas succeeded elsewhere

The EPR experience does not indict redundancy of active safety trains as a principle. German Konvoi plants embodied many of the same instincts regarding separation, space, and conservatism, and they were delivered successfully. The difference lay in context. Konvoi emerged in an ecosystem with an active supply chain, experienced contractors, and intact institutional memory.

The Korean APR1400 offers a complementary example. It remains an active safety design, but one shaped by selective simplification. Design choices such as direct vessel injection and modified accumulator behavior reduced system count without abandoning the underlying architecture. These were incremental refinements layered onto a familiar and repeatedly executed design.

At Barakah, success followed from continuity in execution. Korea transferred an integrated delivery capability that included engineers, construction managers, suppliers, and established routines. In parallel, the United Arab Emirates invested deliberately in importing expertise from around the world and developing its own cadre of engineers, operators, and regulators.

Redundancy carries a construction sequencing burden, a quality assurance load, and long term maintenance overhead. Organizations that retain the capability to manage those burdens can deliver highly resilient plants. Where that capability has eroded, the cumulative cost compounds across schedule, rework, and reliability.

Simplification as an alternative path

The divergence between the AP1000 and the EPR reflects different institutional pressures rather than different safety ambitions. In the United States, the late Gen 2 buildout left utilities with durable memories of cost escalation, construction disruption, and regulatory churn. By the 1990s, the central concern was no longer extracting additional theoretical safety margin, but restoring economic viability under deregulated markets and constrained utility balance sheets. That experience pushed designers and owners toward simplification and passive safety as a tool to lower OPEX.

This instinct was reinforced by Three Mile Island, which demonstrated that extensive active redundancy did not prevent a serious accident driven by system interaction, operator confusion, and loss of situational clarity. The lesson absorbed by utilities and regulators was that adding systems did not automatically translate into safer outcomes, and that complexity itself could become a risk factor.

The AP1000’s passive safety philosophy emerged from this environment. Westinghouse and its utility customers pursued designs that reduced reliance on active systems and operator action, while the Nuclear Regulatory Commission proved willing to analyze, license, and defend safety cases based on natural circulation, gravity driven injection, and extended grace periods. The regulatory system adapted to accommodate a different expression of safety, one grounded in system elimination rather than system multiplication.

In Europe, institutional pressure moved in the opposite direction. Political reaction to Chernobyl and sustained public anxiety around nuclear risk shaped regulatory expectations toward visible conservatism. Designers responded by layering additional redundancy, separation, and engineered protection onto already conservative pressurised water reactor architectures. The EPR expresses safety through accumulation, aiming to demonstrate exhaustive control over accident scenarios, while transferring much of the resulting burden onto construction sequencing, system density, and physical separation.

Early AP1000 projects showed that simplification does not eliminate first of a kind risk, but it does alter where that risk concentrates. Subsequent nth of a kind builds in China demonstrated that, once design and execution stabilized, the reduced system count supported repeatable construction and predictable delivery. By limiting redundancy and congestion, simplification constrained the surface area over which late design resolution could propagate. The EPR followed a different trajectory, extending active redundancy until the cumulative burden of construction, integration, and qualification became a defining constraint on delivery.

The Retreat from Export Ambition to Domestic Retrenchment and the EPR2

Seen in the order they entered construction, the EPR record ultimately retreated from the ambition that created it.

In Finland, the Olkiluoto plant began construction in 2005 and did not connect to the grid until 2022, a failure of schedule control under a fixed price turnkey contract that transferred design maturity and integration risk onto the vendor and became financially ruinous for Areva, whose reactor business was later restructured and absorbed into Framatome.

In France, Flamanville started in 2007, repeated many of the same execution problems even in the home regulatory environment, reaching full power only in December 2025.

In the UK, Hinkley Point C, launched in 2016 and now expected to enter service only in the early 2030s, reinforces the European pattern. Beyond construction complexity, the UK regulatory process imposed late, highly specific requirements that carried substantial civil and systems penalties, including mandated cooling water intake and fish protection systems that drove additional structures, interfaces, and bespoke engineering into an already congested plant.

The outlier remains Taishan, where construction began in 2009 and the first unit reached the grid in 2018. Even there, delivery was slow relative to the median build times of contemporary Chinese nuclear projects. That gap suggests that execution capability alone was insufficient to fully offset the inherent construction burden of the EPR itself. The fact that China has since moved on to other reactor designs, abandoning the EPR reinforces the conclusion that the architecture proved harder to construct and integrate than alternatives even with high cadence construction programs.

EPR2 is the institutional response to that history. Relative to the original EPR’s four fully capable safety trains, EPR2 reduces the architecture to three safety trains, with simplified separation and a smaller safety classified footprint. The double containment concept is abandoned in favor of a simplified single containment arrangement, reducing concrete volume, penetrations, seismic interfaces, and internal congestion. System layouts and digital instrumentation and control are rationalized around repeatable construction sequences rather than maximal separation.

In the end the export ambitions based on regulatory universality through redundant active safety systems have been explicitly abandoned with the EPR having been effectively withdrawn from international bids. The program is now framed almost entirely around repeat domestic builds in France. The hope is that a single regulatory regime, stable supply chains, and workforce continuity can create lift off for the EPR-2.

We wish them bonne chance!

And yet, after seventy years of experiments, prototypes, and near misses, nuclear propulsion remains confined to narrow use cases: submarines, aircraft carriers, icebreakers, and a single cargo ship on the Russian Northern Sea Route operating at the margins of the commercial world.

This recurring pattern is not accidental. It reflects a stable equilibrium between what nuclear propulsion offers at sea and what it costs, institutionally and logistically as much as financially, to deploy it. Climate pressure raises the value of zero emission propulsion and keeps nuclear shipping returning to the agenda, but it does not alter the underlying physics or economics. Where nuclear propulsion removes a binding physical constraint, it transforms operations. Where its advantages are incremental rather than decisive, it struggles to justify its burdens.

Where Nuclear Propulsion Wins Decisively

Submarines are the cleanest case. Nuclear propulsion did not merely improve submarines, it redefined them. Diesel electric submarines were essentially surface ships with the ability to submerge. They were constrained by snorkeling, refueling, low speed, and limited endurance. Nuclear propulsion erased those constraints simultaneously. Speed, stealth, endurance, and global reach all shifted by orders of magnitude, not by margins. The constraint on submersion time became calories for the crew, not fuel for the vessel.

Aircraft carriers follow a similar logic, though for different reasons. Carrier aviation imposes extreme power demands. Launching aircraft from a short deck requires sustained high speed into the wind, and fuel consumption rises sharply with speed. For large displacement ships, propulsion power scales roughly with the cube of speed, meaning that doubling speed can require on the order of eight times more fuel. For a carrier that must repeatedly generate high wind over deck to support flight operations, nuclear propulsion removes a severe fuel and endurance constraint.

Another underappreciated reason nuclear propulsion makes sense for carriers is fuel volume. The conventionally powered John F. Kennedy 1968-2007, for example, required about 3.2 million gallons of diesel for the ship itself, in addition to roughly 3 million gallons of JP-5 aviation fuel for its air wing. Together that is almost ten Olympic swimming pools of fuel.

Nuclear propulsion therefore frees vast internal volume for aviation fuel, weapons, and operational flexibility, which becomes a decisive advantage for sustained air operations.

Nuclear icebreakers represent a third category where propulsion is mission enabling rather than incrementally beneficial. Icebreaking imposes continuous, high power demands over long durations, often in remote regions where refueling is impractical or impossible and failure carries severe operational risk. Nuclear propulsion allows icebreakers to operate for extended seasons with sustained power output independent of fuel supply. In this context, nuclear propulsion solves a hard physical constraint rather than optimizing around cost.

In all three cases, nuclear propulsion enables missions that otherwise become impractical or impossible. Where it merely improves efficiency or endurance at the margin, its advantages fade.

Surface combatants such as cruisers illustrate the limits clearly. Unlike submarines, they already operate within a dense replenishment ecosystem. Aircraft carriers must be resupplied with aviation fuel every few days during high tempo operations, and that same logistics train routinely delivers fuel to the escorting cruisers and destroyers.

Refueling surface combatants at sea is therefore not a binding constraint. Nuclear powered cruisers gained endurance and speed, but they did not gain a fundamentally new mission or operating concept. They still required large crews, complex maintenance, and expensive mid-life refueling overhauls that imposed long periods out of service.

Once the decisive logistical advantage disappears, nuclear propulsion becomes difficult to justify. Around ten percent of US cruisers were nuclear powered during the Cold War. Ultimately, they were all decommissioned not because they performed poorly, but because their incremental benefits no longer outweighed their incremental costs as budgets tightened.

Civilian Shipping and the Limits of the Nuclear Advantage

Civilian shipping pushes this logic even further. Cargo ships exist to move mass at the lowest possible cost per tonne mile. Fuel is important, but it is only one component of a broader cost structure that includes capital cost, crew size, insurance, port access, regulatory compliance, maintenance regimes, and schedule reliability. Unlike submarines or aircraft carriers, civilian cargo ships do not exist to deliver unique capabilities. They exist to minimize cost within an intensely competitive global system.

Nuclear propulsion dramatically reduces fuel logistics, but it increases almost everything else. That tradeoff sits at the core of why civilian nuclear shipping repeatedly proved technically viable yet economically fragile.

During the Cold War, only four civilian nuclear powered cargo ships ever entered service. Each was launched for a different reason. Each functioned technically. Each was ultimately withdrawn for economic or political reasons rather than technical failure.

The NS Savannah

The first was the Savannah, launched in 1959 and brought critical in 1961 as part of the Eisenhower administration’s Atoms for Peace program. It was conceived less as a competitive cargo vessel than as a floating demonstration of peaceful nuclear technology. The ship carried passengers and cargo, operated a pressurized water reactor designed by Babcock and Wilcox, and entered service in 1962. Over the 1960s it visited dozens of domestic and foreign ports and transited the Panama Canal, forcing regulators to invent procedures for nuclear ship entry, low power maneuvering, tug escort, and liability coverage. From an engineering standpoint the ship operated as intended, and as a diplomatic project it achieved its purpose, but it was never designed to compete economically with conventional cargo vessels. Built before containerization and operated with higher crew requirements and bespoke regulatory treatment, Savannah was decommissioned in 1970 once its demonstration value was exhausted.

The Otto Hahn

West Germany’s Otto Hahn, launched in 1968, represented a more serious attempt to integrate nuclear propulsion into a working cargo vessel. Unlike Savannah, it was designed from the outset as an ore carrier rather than a political exhibit. Its reactor, also designed by Babcock and Wilcox, was an integral pressurized water reactor that compressed the primary system into a single pressure vessel, reducing volume, mass, and piping complexity. Otto Hahn operated successfully for years and demonstrated that nuclear propulsion could function reliably in commercial service. Yet its economics remained marginal. Nuclear trained crew commanded wage premiums, regulatory oversight remained exceptional rather than routine, and access to key maritime chokepoints remained restricted, with Otto Hahn denied transit through both the Panama and Suez Canals while nuclear powered. When fuel prices fell and conventional propulsion improved, the narrow economic window closed. The reactor was removed and the ship continued service under diesel propulsion.

The Mutsu

Japan’s Mutsu, launched in 1970 and completed in 1974, exposed a different vulnerability. During initial low power testing at sea, a shielding design flaw allowed fast neutrons to stream into unintended areas of the ship. There was no fission product release, but radiation was detected where it should not have been. Correcting the problem required substantial additional shielding, structural modifications, and reconfiguration of internal spaces. The technical issue was fixable. The political damage was not. Fishermen protested, ports refused entry, and national headlines declared radioactive leakage. After years of redesign and delay, Mutsu operated only briefly before being shut down, illustrating how unforgiving civilian nuclear shipping could be.

The Sevmorput

The most durable example was the Soviet Union’s Sevmorput, launched in 1986. Unlike its Western counterparts, it occupied a niche, the Northern Sea Route, where nuclear propulsion addressed a genuine physical constraint rather than offering a marginal economic improvement. Designed as a Lighter Aboard Ship (LASH) vessel, it carried cargo in self contained barges that could be offloaded to shallow, undeveloped, or icebound ports inaccessible to conventional deep draft ships. While not a true icebreaker, it was built with a reinforced ice class hull that allowed it to operate in heavy ice conditions and transit icebreaker opened channels along the Northern Sea Route. In Arctic waters, refueling is difficult, weather is unforgiving, port infrastructure is sparse, and sustained propulsion power is operationally essential. Nuclear propulsion offered a functional advantage that conventional alternatives struggled to match.

Even here, the equilibrium remained fragile. Sevmorput spent long periods laid up, and its utilization depended heavily on state support, Arctic traffic levels, and geopolitical priorities. It did not establish a template for global nuclear cargo shipping. It carved out a narrow role where alternatives failed physically, not merely economically. That pattern aligns with Russia’s broader nuclear icebreaker fleet, where nuclear propulsion succeeds by removing binding physical constraints rather than marginally improving fuel economics.

Taken together, these cases reveal a consistent pattern. Civilian nuclear propulsion worked technically. It failed economically except where it solved problems that conventional propulsion could not.

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Decarbonization Pressure Changes the Debate, But Not the Physics

The renewed interest in nuclear shipping today has been driven primarily by emissions constraints rather than fuel logistics. The International Maritime Organization has advanced decarbonization targets that push commercial shipping toward net zero emissions by mid century. Alternative fuels such as ammonia, methanol, and synthetic hydrocarbons impose penalties in energy density, handling risk, infrastructure requirements, or cost.

Against this backdrop, nuclear propulsion reemerges as one of the few options capable of eliminating operational emissions without reducing range, speed, or payload. That shift matters, but it does not dissolve the underlying cost and complexity problem. Decarbonization increases the value of zero emission propulsion, yet it does not remove the institutional overhead associated with nuclear systems.

Political resistance further complicates the picture. Efforts by Donald Trump to pressure the International Maritime Organization to retreat from its decarbonization agenda underscore a key difference between nuclear safety regulation and climate policy. Nuclear safety enjoys broad international consensus. Maritime decarbonization does not. If climate policy fragments along geopolitical lines, the main incentive structure favoring nuclear propulsion weakens significantly.

The central question remains whether climate pressure becomes strong enough to outweigh cost sensitivity in a sector defined by thin margins and relentless competition.

Advanced Reactor Concepts Reappear, but the Old Tradeoffs Remain

Renewed interest in nuclear shipping has revived familiar reactor concepts. Molten salt reactors, high temperature gas reactors, and other advanced designs are often presented as better suited for maritime use, promising lower pressure operation, inherent safety, or improved flexibility. These arguments are not new. Similar concepts were explored extensively during the early decades of naval nuclear development.

That experience produced a clear outcome. After testing a wide range of unconventional reactors, pressurized water reactors emerged as the near universal solution not by convention, but by elimination. Liquid metal cooled reactors were operated at sea in both US and Soviet submarines, while organic cooled and other exotic concepts were tested in prototype form. None delivered a decisive improvement once size, power density, reliability, maintainability, and crew requirements were fully considered.

Water’s role as both coolant and moderator enables compact, high power density cores that integrate efficiently into ship hulls. At sea, compactness directly affects stability, shielding mass, and usable volume. Designs with lower power density impose cascading penalties that grow rapidly in space and weight constrained environments.

Water cooled systems also align naturally with the marine environment. The ocean is an effectively infinite heat sink, and water cooled reactors tolerate water ingress. By contrast, gas cooled reactors suffer from low power density, while molten salt reactors embed fission products within circulating fuel. In such systems, the entire primary circuit becomes highly radioactive, turning pumps, valves, and heat exchangers into persistent radiation sources and complicating routine maintenance.

Technology readiness carries disproportionate weight at sea. Maritime reactors must endure constant motion, vibration, and long operating intervals with limited maintenance access. Pressurized water reactors have accumulated decades of operational experience under these conditions. Advanced reactor concepts have not.

Advanced reactors may eventually find a role in nuclear shipping, but history suggests that success will depend on demonstrated performance rather than assumed superiority. The persistence of pressurized water reactors reflects a fit between physics, engineering, and operational reality that remains largely unchanged.

A Narrow Commercial Niche, and an Aviation Analogy

If civilian nuclear shipping has a future beyond state owned icebreakers and military auxiliaries, it is likely to resemble a narrow corridor rather than a broad transition.

One plausible configuration involves very large vessels powered by tried and tested marine PWRs operating between a small number of dedicated ports, with specialized crews, standardized regulatory frameworks, and predictable routes. In that sense, nuclear shipping begins to resemble a hub and spoke model, not unlike the Airbus A380 concept in aviation.

The A380 was optimized for high volume routes between major hubs, trading flexibility for efficiency at scale. Its failure in passenger aviation reflected the rise of point to point travel and the premium placed on operational flexibility rather than pure capacity. Shipping differs in important ways. Cargo is less sensitive to frequency, and ports already function as aggregation nodes. But the structural lesson remains. Platforms optimized for extreme scale succeed only where traffic density, infrastructure, and demand stability align.

This leaves open the possibility that ultra large crude carriers or container ships operating on fixed routes between energy or resource hubs could justify nuclear propulsion under extreme decarbonization pressure. Even then, success would depend on unusually stable demand, supportive regulation, and some degree of state backed risk absorption.

That is a narrow niche, not a general solution.

Cost, Complexity, and the Persistent Constraint

Nuclear propulsion at sea has always been constrained by the same forces. It adds complexity to vessels designed to minimize it. It introduces regulatory and political risk into industries that operate on thin margins. It solves problems that become decisive only in extreme operational environments.

Decarbonization pressure increases its appeal, but it does not transform its economics. The history of nuclear shipping suggests not impossibility, but selectivity. Nuclear propulsion thrives where its advantages overwhelm its burdens. Everywhere else, it remains a solution in search of a problem large enough to justify it.

That reality has not changed, even as the climate imperative has waxed and waned.

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The program produced real machines and real experience, including functioning reactors buried under a glacier in Greenland, a research base in Antarctica, as well as remote continental sites in Wyoming and Alaska. Ultimately the program was cancelled not because the Army lacked engineering talent but rather because the total system never beat the alternative, even in some of the most austere, high cost environments imaginable.

The unique challenges posed by radiation and decay heat management meant that diesel won on logistics and simplicity. Outside of submarines, aircraft carriers and icebreakers, all applications where nuclear offers a step change in military capabilities over alternative fuels, small land based reactors never earned their keep.

Project Pele, an ongoing US Army effort to produce a mobile high temperature gas reactor, is the bridge between eras. It is not a commercial product but rather a prototype and a forcing function, designed to drive learning into hardware, licensing, fuel qualification, transport and all of the other unglamorous interfaces that never appear in investor decks.

The Janus program, named after the Roman God of transitions, is the next step, and it is qualitatively different.

It is a United States Army procurement program intended to act as industrial policy to transition a nascent microreactor industry from isolated demonstrations into commercial services. It does this by selecting multiple private reactor vendors, providing them with milestone based federal funding to design, build, license, deploy, and operate first of a kind microreactors, and then requires those reactors to sell electricity to continental US (CONUS) Army installations under market rate power purchase agreements.

The Army acts as an anchor customer, not by guaranteeing long term overpayment for power, but by subsidizing early technical and regulatory risk while enforcing price discipline once reactors enter operation.

This is the wager and it all hinges on the question of whether microreactors can ever compete in remote environments with diesel generators let alone with the cost of grid electricity in the continental USA. It is a very high bar indeed.

Janus as COTS for Nuclear

The Army is not pretending that a 1-10MW reactor can be brought to commercial operations on a normal power purchase agreement. CONUS Military installations are typically constrained to pay near local market rates for electricity. In much of the continental United States, including most of the bases identified by Janus, that means something on the order of 12 cents/kWh.

At 1MW, that translates into roughly $120 per hour of gross revenue. That is clearly not enough to pay for licensed operators, security, maintenance, capital recovery, decommissioning reserves, and backend fuel handling, let alone repay the enormous fixed costs of first of a kind nuclear hardware.

Combine this with the fact that FOAK microreactors, most of them non light water reactors, are unlikely to hit the 93% capacity factors we now take for granted in the experienced PWR/BWR fleet which will result in significant loss of revenue.

Janus attempts to give microreactors their best chance by shifting the subsidy to the front end. To accomplish this it is modelling itself on Commercial Orbital Transportation Services (COTS), the NASA initiative in the early 2000s that restructured how the United States procured launch capability. This was the program that enabled SpaceX which now accounts for more than half of all global orbital launches. Instead of building rockets in house or reimbursing contractors under cost plus contracts, COTS relied on fixed milestone payments, hard down selects, and vendor replaceability to force convergence through execution rather than promise.

COTS subsidized learning rather than launches. Firms were paid only when they demonstrated specific capabilities such as engine tests, integrated systems, orbital insertion, and cargo delivery. Cash was released when milestones were met, not when money was spent. The government absorbed early technical risk while refusing to guarantee long term revenue, ensuring that companies unable to close the gap between demonstration and service pricing failed quickly.

Janus is attempting to apply that same logic to microreactors. The Army is not trying to pick a winner in advance, nor is it pretending that electricity sales can fund first of a kind nuclear systems. Instead, it is using milestone based funding to buy down early uncertainty while deliberately constraining back end power prices to market rates in order to preserve commercial discipline.

Why Janus Starts on the Easiest Battlefield

Janus is about moving from demonstration to service, with commercial vendors selling electricity to CONUS Army installations.

This approach seems to implicitly rebut the most common microreactor narrative, that the killer application is the remote outpost and the fuel convoy where cost of diesel and lives at risk from fuel convoys justify the cost and complexity of nuclear. However the stated reason to deploy at CONUS bases is that this is a safer training ground. If you were to drop a FOAK microreactor into the most logistically hostile environment possible, you guarantee that every weak interface will be stressed simultaneously.

While Pele exists to reveal those weak interfaces, Janus exists to manage them.

Continental installations are grid connected and close to industrial services. They allow normal American logistics and normal maintenance ecosystems. The sequence is to learn to design and build and operate domestically and then earn deployment overseas in places like Guam or remote forward operating bases.

Technology Choice Based on Logistics

One of the clearest signals from the program is that Janus is not a closed club. With over fifty companies expressing interest, the selection process will be strict. Either the Army builds a funnel that rapidly converges on a small number of credible teams, or it splinters the already scarce nuclear engineering talent of the country across dozens of parallel reinventions of the same materials, the same components, and the same regulatory arguments.

Janus plans to address this with a deliberate, multi stage downselect process. The first round will quickly narrow the field. The next deepens technical scrutiny. Pitch sessions may become Rickover-esque interrogations, not the VC marketing exercises we are so familiar with.

Janus is not truly technology agnostic, even if it avoids picking a single winner at the outset. Light water reactors are not excluded by ideology but deprioritized due to their need for abundant onsite water and the Army’s desire for technology that comes without any major siting limitations.

There is also a quieter constraint, rail dependency. Large commercial and naval reactors rely on rail spurs for heavy components. Janus wants truck transport. That imposes hard dimensional and weight limits, bridge ratings, tunnel clearances, and radiation constraints at specified distances.

This creates a standardization pressure that mirrors early rocketry with a handful of viable envelopes. Designs that cannot fit them will not scale.

Pele’s Real Legacy, Logistics and Fuel

By the time Project Pele and its supporting infrastructure are fully counted, the total cost will be on the order of one billion dollars. That figure is sometimes cited as evidence of the near unsurmountable economic challenges of microreactor development, but the money has not been used to buy a single microreactor. In much the same way that decades of extraordinarily expensive NASA’s spaceflight programs created the technical, regulatory, and industrial substrate that later made SpaceX’s success possible, Project PELE hopes to play a similar role for microreactors involved in the Janus program.

One of the clearest examples is fuel logistics. Pele exposed a problem that is easily missed, how to move an entire core, not a handful of TRISO fuel elements, across the country without introducing breakage, criticality risk, or regulatory surprises. Earlier Department of Energy shipments were effectively artisanal, designed around small quantities and bespoke handling.

Once scale enters the picture and tens of thousands of TRISO fuel elements must be transported together, packaging itself becomes a nuclear design problem. Because the moderator is embedded in the fuel, container geometry, packing density, water ingress scenarios, and inspection tolerances all directly affect criticality assumptions and safety cases.

Decisions long since made for conventional fuel suddenly shape licensing, shipping approvals, and acceptance criteria at destination, forcing engineering discipline into what had previously been treated as logistics.

Why the SpaceX Analogy Only Goes So Far

If Janus is an attempt to apply the COTS model to nuclear, then its limits matter as much as its promise. The analogy holds at the level of procurement and incentives, but it faces challenges on economics and time constants.

As Ethan Chaleff has pointed out, orbital launch is a scarce, high value service where each technical success directly expands the addressable market and unlocks higher value missions. Baseload electricity, by contrast, is a commodity whose price is largely set externally, and at the 1-10 megawatt scale even flawless technical execution produces limited revenue relative to nuclear’s inherent costs. While improved reliability and risk reduction can open additional niche markets such as remote sites or specialized users, there is no single technical milestone analogous to a successful launch that causes a step change in pricing power or fundamentally transforms the economics of the service.

The difference in iteration speed compounds this mismatch. Rockets fail in seconds and teach quickly, allowing redesign on short cycles. Nuclear systems often fail late and teach slowly. In pressurized water reactors of the 1960s, nickel chromium iron Alloy 600 was widely used in steam generator tubing. Its susceptibility to primary water stress corrosion cracking only became apparent after decades of operation, long after it had been widely deployed at fleet scale. Correcting that mistake required an additional decade of inspections, replacements, and ultimately wholesale substitution with higher chromium Alloy 690 components at enormous cost, illustrating the slow, amortized learning cycle of nuclear engineering.

SpaceX experienced an analogous materials lesson on a radically compressed timescale. Early Falcon 9 vehicles used composite overwrapped pressure vessels (COPV) for helium storage inside cryogenic oxygen tanks. The AMOS-6 pad explosion in 2016 caused by oxygen freezing and igniting within the composite overwrap, forced a fundamental redesign of the COPV architecture, materials, and loading procedures. Within months, SpaceX introduced a new pressure vessel design and operational envelope, eliminating the failure mode before it could propagate across a large operational fleet.

One sector learned in months because failure was fast, observable, and relatively cheap. The other learned over decades because degradation was slow, distributed, and only visible after long service exposure. Microreactors inherit that slow pace of nuclear iteration regardless of their small size.

Janus therefore applies the SpaceX playbook under unusually tight constraints. It can impose discipline, force early confrontation with logistics and materials reality, and test whether a narrow set of designs can survive without permanent subsidy. What it will struggle to do is compress nuclear physics, regulatory time, or the economics of baseload power.

Seen this way, Janus is not a moonshot modeled on SpaceX’s outcome. It is a stress test modeled on SpaceX’s method, designed to determine whether microreactors can survive the most forgiving version of the market before anyone asks them to survive in a warzone.

There is a line I have been using for years: it is easier for a camel to pass through the eye of a needle than to build a nuclear plant on time and on budget. Does that mean rich people are barred from heaven or that nuclear plants are incapable of meeting their construction schedule? None of us knows the answer about the former just yet but history tells us the latter is well within the bounds of possibility.

However, with the new United States plan to stand up a fleet of eight AP1000s in partnership with Westinghouse and Brookfield, backed by an eighty billion dollar framework, that metaphor suddenly feels a lot less rhetorical and a lot more like a live policy problem.

We have a rare convergence in Washington. Biden framed nuclear as central to tripling clean electricity. The Trump administration has not only kept that direction, it has put much more political skin in the game, from explicit AP1000 fleet signals to hard cash for small modular reactors at TVA and Holtec.

For the first time since the early 2000s, there is real money, real political attention, and real load growth that actually needs firm power, from data centers and AI to electrification.

We have also been here before.

The last time the United States tried a nuclear renaissance, utilities created combined operating licenses, signed contracts with architect engineers, pushed AP1000 and ESBWR through design certification, and took on real nuclear construction risk. Then shale arrived, Vogtle and Summer spiraled, and the whole effort collapsed into a cautionary tale.

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In a recent conversation with James Krellenstein, CEO of Alva Energy and one of the sharpest forensic minds in nuclear project history, we tried to answer a simple question:

What, concretely, has to be different this time so that eight AP1000s become the backbone of a real fleet, not the prologue to another lost decade?

What follows is my attempt to synthesize that discussion and tie it back to the broader Decouple project of understanding how large energy systems can get built in the messy contemporary reality of the Western World.

The World That Built Gen 2 Reactors

To understand why the classic American nuclear build worked when it did, you have to start with a utility structure that hardly exists any more.

For most of the twentieth century, United States power companies were vertically integrated, regulated monopolies. They owned generation, wires, and retail. They had defined geographic service territories, and they recovered both operating and capital costs directly from ratepayers, subject to prudence review by state public utility commissions.

Two features of that world matter for our story.

First, utilities were drowning in real work. In the 50’s and 60’s, electric demand in the United States doubled roughly every 8 years. That means, over a 24 year career, a utility engineer could see the system they inherited multiplied by a factor of eight. New coal plants, oil plants, hydro, transmission, everything.

Second, the regulatory compact paid them to build. Once a project was judged prudent, the capital went into rate base and earned an allowed rate of return, often on the order of ten to twelve percent. Utilities were being paid, in a regulated way, to mobilize capital and concrete.

Put those together and you get organizations that were absolutely saturated in project experience.

In that world, the way we structured nuclear looked strange, but it mostly worked. Westinghouse, GE, Babcock and Wilcox, and Combustion Engineering sold what they explicitly called nuclear steam supply systems, essentially nuclear boilers. Architect engineering firms like Bechtel, Stone and Webster, or Ebasco designed the balance of plant around that boiler.

The balance of plant, which is about half of the capital cost, was not standardized by the reactor vendor. There was no one integrated product called “a Westinghouse plant.” Sharon Harris, Beaver Valley, North Anna, and dozens of other Westinghouse units all married the same NSSS to different turbine islands, feedwater layouts, auxiliaries, and even containment designs, depending on which architect engineer the utility hired.

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On paper, this sounds like a recipe for chaos. In practice, it worked because the owner organizations were so competent. Some utilities did not even bother with outside architects. Duke, for instance, engineered and managed most of its plants itself. Ontario Hydro did the same with CANDUs, at one point employing ten thousand people in its construction division alone, in what was jokingly described as a construction company that also happened to make electricity.

The key point is simple.

In the USA, nuclear was never a finished product sold out of a catalog. It was, and still is, a complex integration project, and the hardest part of that integration was done by the customer.

That model depended on utilities that were building plants constantly and could keep very large, very experienced project organizations together for decades. Which brings us to the first real rupture in the story.

Part 50, Part 52, And The Trauma Of The First Wave

The end of the Gen 2 build scarred the American utility industry in ways that are easy to forget from today’s vantage point.

Under the old Part 50 two step licensing regime, utilities first received a construction permit, then, after billions of dollars had been spent, came back for an operating license. In between those two steps, the regulator changed the rules.

Plants that had been designed and partially built under one set of requirements suddenly had to comply with a new set of post Three Mile Island rules. Entire systems were ripped out and rebuilt. Sunk costs multiplied.

On top of that, there was a fatal political design flaw. Local governments could veto emergency plans that the NRC required for operation. Shoreham on Long Island was fully built, reached low power operation, then died because Mario Cuomo and Suffolk County refused to approve an evacuation plan. The cost was shoved onto Long Island ratepayers for decades. Seabrook came very close to the same fate.

You can see why utility executives swore never again.

Part 52, created in the late eighties, was the institutional response to that trauma. It introduced combined construction and operating licenses and design certifications. The idea was simple, get your design certified once, get a COL that incorporates that design and a specific site, build in accordance with that license, demonstrate via inspections, tests, analyses, and acceptance criteria that you did what you promised, and you are entitled to an operating letter without another round of regulatory re-litigation.

The NRC has never revoked a COL or refused a 103 g letter for a plant built as licensed. By that narrow metric, Part 52 works.

Part 52, however, was only one half of the attempt to de risk nuclear in the early two thousands. The other half was political and financial.

The Noughties Nuclear Renaissance Was A “Need To Have” Moment

If you zoom back to the early two thousands, the conditions that produced the last nuclear revival were very different from the ones we talk about today.

Natural gas was scarce and expensive. Henry Hub prices spiked above thirteen dollars per million BTU in the mid two thousands. The United States was a net energy importer, pursuing LNG import terminals and looking nervously at Middle Eastern supply.

You could not, politically or environmentally, build new coal without a fight. Air quality and respiratory disease were front page issues even before carbon entered the policy mainstream.

Then came 9 11 and the hard realization that the country had bound its economic security to a very unstable hydrocarbon nexus.

In June 2005, George W Bush flew to Calvert Cliffs in Maryland, the first presidential visit to a nuclear power plant since Jimmy Carter’s emergency trip to Three Mile Island in 1979. From the turbine hall he called for a new round of nuclear construction and urged Congress to pass a comprehensive energy bill that would later become the Energy Policy Act of 2005, which he ultimately signed that August at Sandia National Laboratories in New Mexico.

Nuclear in that world was not a green nice to have, it was a strategic need to have.

The Energy Policy Act of 2005 encoded that logic. It created the DOE Loan Programs Office and gave it authority to provide loan guarantees that effectively let nuclear projects borrow at close to Treasury rates. It also provided production tax credits for the first movers, and it co funded the Nuclear Power 2010 and NuStart consortia that pushed AP1000 and ESBWR through design certification and early COL work.

Southern and its partners did not just talk about building reactors, they spent on the order of hundreds of millions to billions to secure COLs, begin site work, and place orders. Constellation and EDF pursued EPRs at Calvert Cliffs and Nine Mile Point. Toshiba arrived with ABWRs and the APWR. EPR applications showed up at Bell Bend and in Pennsylvania. This was not a vendor side marketing exercise. It was utility led and utility financed, often in regulated states that could put licensing costs into rate base and earn a return.

And yet it failed.

What killed it was not a lack of subsidies or a lack of designs. It was the combination of shale, institutional memory loss, and an owner side capacity problem that Part 52 simply did not touch.

Shale, Vogtle, And The Collapse Of Confidence

The shale revolution flipped the economic table.

Horizontal drilling and hydraulic fracturing in shale formations produced a flood of domestic gas. Power markets that had assumed scarce and volatile gas suddenly saw abundant cheap fuel. Coal plants were retired en masse because combined cycle gas plants were simply cheaper to build and run, even before environmental rules pushed in the same direction.

In that environment, the question in many boardrooms became brutally simple. Do we spend ten years and billions of dollars building two gigawatts of nuclear with enormous construction risk and national scrutiny, or do we quietly build a couple of gas plants outside town and be done in three years?

Fukushima did not help. Public support dipped, and the optics were terrible. But as James points out, the technical analyses that followed Fukushima actually strengthened the case for the Gen-3+ designs in the U.S. pipeline. Both the AP1000 and ESBWR were shown to be specifically not vulnerable to the kind of prolonged station blackout that destroyed Fukushima Daiichi, because their passive safety systems could maintain core cooling and containment integrity for days without AC power or operator action. (see our earlier episode with James below for a deep dive of the AP1000 safety systems)

The NRC incorporated these findings, paused briefly, then issued every U.S. COL for Gen-3+ reactors after Fukushima. The regulatory process moved forward because the designs addressed the very failure mode under scrutiny.

The real killer was not regulatory, it was economic.

Then Vogtle and Summer made everything worse by demonstrating, in real time, that the American supply chain and project culture had lost the muscle memory needed to build a large light water reactor.

Modularization was supposed to be the solution. Instead, it magnified inexperience. Chicago Bridge and Iron, with oil and gas fabrication heritage, struggled to deliver nuclear quality modules. Quality assurance was weak. At one point, core makeup tanks had to be shipped back to Italy because they had been fabricated to the wrong volume. A developer with a strong owner side organization might have caught that in the shop. Instead, it was caught on site, with all the schedule consequences that implies.

SCANA executives ended up in jail over the Summer fiasco. Southern’s balance sheet was battered by Vogtle. Utilities executives took the lesson that nuclear risk was potentially career ending, even when underpinned by federal loan guarantees and state level cost recovery laws.

By the time shale was in full swing, the Noughties renaissance was finished.

Which brings us to today.

The 2025 Moment Looks Better On Paper

On paper, the policy environment for new nuclear in 2025 is stronger than anything we saw in 2005.

The Inflation Reduction Act created a technology neutral clean electricity ITC and PTC that nuclear can use. Existing plants get a production credit that keeps them competitive against cheap gas and subsidized renewables. New plants can access an investment tax credit of thirty percent, with ten percent adders for things like domestic content and energy communities.

The DOE Loan Programs Office has been scaled up and proven. It provided twelve billion dollars in loan guarantees to Vogtle that are being repaid, and it is now supplying up to 1.52 billion to support the restart of Palisades, with multiple disbursements already out the door.

On the small reactor front, the Department of Energy has just committed up to eight hundred million dollars in cost shared funding to TVA and Holtec to advance BWRX 300 at Clinch River and SMR 300 units at Palisades, on top of the Palisades restart loan. TerraPower’s Natrium demonstration has cleared the NRC’s final safety evaluation for its Kemmerer construction permit.

Load growth is no longer an abstract climate model. Data centers for artificial intelligence and cloud services, electrified vehicles, and heat pumps are all real and visibly straining grids. That demand is already showing up in integrated resource plans and capacity auctions.

Politically, this is one of the few areas of genuine continuity across administrations. Both parties now talk about tripling or quadrupling nuclear capacity in the same breath as they talk about semiconductors, critical minerals, and strategic rivalry.

For the AP1000 specifically, the new United States Japan alliance around large reactors, the Polish program, and the eight unit fleet concept in the United States are finally starting to look like the kind of standardized program that AP1000 needed all along.

So why does it still feel like we could absolutely blow it?

Because one core variable that the policy debate largely ignores is still missing, and that is the existence of robust developer organizations that sit between vendors and utilities and actually know how to deliver a fleet of plants.

The Case Control Study From Hell: St Lucie 2 Versus WooPPSS

James likes to use a simple question to test our theories of project success.

If the hardware, the vendor, the design, and the regulator are all the same, why do some plants come in more or less on time and budget while others become municipal bond disasters?

His favorite case control pair is St Lucie Unit 2 in Florida and Washington Nuclear Project 3 in Washington State, both combustion engineering reactors with Ebasco as architect engineer, both under the NRC, both starting in the same era.

St Lucie 2 is one of the quiet success stories of American nuclear. It went from nuclear construction to cold hydro in about five years, post Three Mile Island, with the NRC in full flight. It was built by Florida Power and Light working in a hybrid organization with Ebasco. FPL stood up a couple of hundred person internal projects org whose only job was to deliver new nuclear for FPL, and it rode herd on its contractors.

Washington Nuclear Project 3, by contrast, helped trigger the largest municipal bond default in American history at the time. The Washington Public Power Supply System (WPPSS) was a loose consortium of dozens of small public utilities that had never built large thermal plants before. The developer org simply did not exist.

The timing was the same. The hardware was the same. The vendor was the same. The regulator was the same. The difference was the owner side organization that integrated, supervised, and disciplined the work.

You see the same pattern elsewhere. Costs fell significantly between Palo Verde 1 and Palo Verde 3 as Arizona Public Service learned and improved across three standardized units. Then that projects organization never built another plant. This stands in sharp contrast to France, where EDF acted as a national developer that kept one projects organization together across dozens of standardized units.

In North America today, the closest thing we have to that EDF model is Bruce Power and Ontario Power Generation. The sequence of life extension refurbishments at Bruce A and B, with power uprates layered in, is training an integrated projects organization that can slide directly into building the four large reactors planned for Bruce C. The technology forces a heavy mid life rebuild, which in turn keeps a competent construction org warm.

The blunt lesson is this, nuclear build success is more tightly correlated with the quality of the owner or developer org than with the reactor vendor or even the regulator.

And that is exactly the variable that is weakest in the United States right now.

Our Owner Organizations Are Weaker Than They Were In 2005

It is uncomfortable to admit, but the institutional position of American nuclear is in some ways worse than it was at the start of the Noughties renaissance and dramatically worse compared to the heydays of the 1960’s.

The last new large plant to reach commercial operation before Vogtle was started in the seventies. In the decades since, many utilities simply shut down their nuclear fleets, sold their plants to specialist decommissioners, or cut their nuclear divisions to the bone to survive in competitive markets against cheap gas. That hollowed out project organizations and capital project departments.

The people who used to do major turbine replacements, uprates, and life extensions retired or moved on.

Even where pioneering work has been done, as with Bechtel and SGT driving steam generator replacement outages down from eighteen months to under a month by getting very good at procurement and outage choreography, that expertise is siloed into a handful of contractors and client teams, not spread across a big build program.

On top of that, the psychological trauma of Summer and the cost and schedule drama at Vogtle sit on every utility board’s mind. SCANA does not exist any more. Southern survived, but every executive in the industry knows what happened there.

When Jigar Shah at the Loan Programs Office asks, as he has, why utilities are not lining up to claim “candy bar” loan guarantees for new AP1000s, this is the answer. It is not that the candy is fake. It is that nobody wants to be the next CEO whose face is in every trial exhibit.

This is why the fashionable idea of “cost overrun insurance” is at best incomplete and at worst dangerous.

The Mirage Of Cost Overrun Insurance

You hear a simple story. Nuclear is scary because of cost risk. Therefore the government should create a pot of money that covers, say, the first twenty five or fifty percent of cost overruns, and suddenly cautious utilities will be willing to play.

The problem is that insurance is not magic, it is incentives.

If the people who can spend extra hours and extra materials know that part of the extra bill will be picked up by someone else, the incentive to control costs weakens. For EPC firms in particular, “overruns” are also additional billable work. For an owner side organization that is already underpowered, external insurance can quietly become a way of outsourcing cost discipline to Washington.

You can see how deeply this incentive rot ran in late Gen 2. James described at least one case where a project manager delivered an entire nuclear project on time and on budget, only to be reprimanded by his superiors. Because regulated utilities earned a return on “prudent” capital additions, delay, redesign, and rework actually increased earnings. Finishing efficiently reduced the rate base. In that environment, a manager who tried to run a disciplined project was punished for doing exactly what the public assumed a utility wanted to achieve.

And the way many utilities maintained that distorted incentive structure was by using the NRC itself as a shield. In the late Gen-2 prudence hearings, the cleanest way to ensure that overruns would be ruled prudent and therefore rate-base eligible was to demonstrate that the cost increase flowed from an NRC requirement, inspection finding, or licensing change. That dynamic created a subtle but powerful incentive for builders and owners to welcome regulatory churn, or at least not resist it too hard, because the more the NRC intervened, the easier it became to socialize overruns onto ratepayers rather than shareholders. The regulator, intended as a safety watchdog, became an unwitting guarantor of cost recovery.

Cost overrun insurance that is not paired with a very strong owner side project organization risks recreating this exact moral hazard, only with Washington paying the bill instead of ratepayers.

Which brings us back to what needs to change.

What It Would Take To Thread The Needle This Time

If we really want eight AP1000s to be the backbone of a real fleet program, three things have to happen in parallel.

1. Build Developer Organizations Before You Build New Reactors

The most important thing missing from the United States nuclear landscape is not another design, it is credible developer orgs that can demonstrate they know how to deliver nuclear megawatts.

There is a reason Alva Energy, the company James leads, is focused first on power upgrades and life extension projects, not jumping straight to a first of a kind new build. There is a reason Bruce Power is sequencing refurbishments before Bruce C. These projects are large enough to test and train an organization, but small enough that failure does not take down a utility.

The United States has gigawatts of latent nuclear capacity locked up in uprates, refurbishments, and restarts. Palisades is the first restart of a shuttered commercial reactor in American history, backed by a 1.52 billion dollar loan guarantee, and fuel has already returned to site. Getting that right is not just about one plant in Michigan. It is about demonstrating that our ecosystem can still do complex nuclear work, on schedule, under regulatory scrutiny.

A rational AP1000 program would consciously cultivate one or more developer orgs through a pipeline of such projects, then hand them the responsibility for delivering a four unit site in partnership with a host utility.

2. Create Offtake Structures That Can Carry The First Projects

The first few AP1000s in a new program are almost guaranteed to be more expensive than the eighth. There will be learning, there will be process improvements, there will be conservative contingencies.

The only way that is financeable is if there is a counterparty with rock solid credit that is prepared to sign up for a power price high enough to support those contingencies. That might be a state backed entity like NYSERDA, aggregating load on behalf of multiple buyers. It might be an anchor offtake from a cluster of data centers that need credible decarbonized power in a world where grid upgrades and new gas permitting are both hard.

What it cannot be is a merchant bet where the entire economics of a plant live and die on the PJM day ahead price.

One useful piece of continuity from the Biden era is the explicit recognition, in DOE’s 800 million dollar SMR awards, that cost shared grants for early projects are justified as a way to unlock later fleet deployments. (The Department of Energy’s Energy.gov) That logic should apply even more strongly to large standardized units.

3. Do Smart Advanced Procurement Without Repeating Vogtle

The instinct to place long lead orders early is right. Reactor pressure vessels, steam generators, and other heavy forgings have long manufacturing times. In theory, warehousing components for eight units should let you move quickly once sites and developers are ready.

There are two big caveats.

The first is quality assurance. Ordering eight sets of core makeup tanks from Europe or Asia does you no good if someone discovers years after warehousing these parts that the volume is wrong when they arrive on the construction site. Actual nuclear projects that go well, from steam generator replacements to major component swaps, do not trust paperwork alone. They put owner representatives in the forge and the shop, measuring, witnessing welds, and checking test records.

If advanced procurement is run as a remote federal program, decoupled from the owner orgs that will actually use the kit, we will be setting ourselves up to repeat Vogtle’s mistakes at scale.

The second is supply chain realism. The United States no longer has indigenous capability to forge and assemble large reactor pressure vessels and steam generator shells at nuclear quality. That work is currently done in allied countries, at places like Doosan in South Korea or Le Creusot in France.

We should not wait for a fully domestic forging industry before placing AP1000 orders. The United States originally seeded those capabilities through technology transfer. Westinghouse co founded Framatome, whose very name, French American Atomic Constructors, tells the story. Combustion Engineering provided the basis for the Korean System 80 lineage. Now the flow can run in reverse.

A sensible policy might explicitly waive tariffs for the first few sets of heavy components to get projects moving, then phase in domestic content requirements over time, paired with IRA domestic content tax credit adders. That is how you signal to industry that the demand is real enough to justify rebuilding forge capacity onshore without using domestic manufacturing as a pretext for yet more delay.

The SMR Sideshow, And Why Big Reactors Still Matter

None of this is to dismiss the genuine progress on the small side.

TVA’s BWRX 300 at Clinch River has federal cost share backing and a direct line to an operating utility that still knows how to run nuclear. Holtec’s SMR 300 will piggyback on Palisades restart work and, if it goes ahead, will effectively make that site a mixed fleet campus. TerraPower’s Natrium is pushing the regulatory envelope for advanced reactors at Kemmerer.

These are real projects now, not just glossy renderings.

The danger is that SMRs become a distraction or psychological excuse to avoid the hard questions about how to build large standardized plants, on which any serious reindustrialization agenda will depend. The grid needs big, cheap megawatts at scale, and once you get past first of a kind novelty, the economy of scale of large light water reactors still rules the day.

If we treat SMRs as a training ground for project organizations and as a diversification of the portfolio, they could be valuable. If we treat them as a way to avoid ever building another gigawatt class plant, we have learned the wrong lesson.

Learning From History Without Being Crushed By It

The most depressing way to read the history of the American nuclear industry is as a story of repetition, where every attempt at revival is swallowed by the same combination of cost overruns, regulatory churn, and cheap gas.

This is not inevitable.

Part 52 has fixed one of the worst structural problems of the Part 50 era. The Loan Programs Office has shown it can deploy low cost capital and get it paid back. The Inflation Reduction Act has quietly leveled the playing field for nuclear against subsidized wind and solar. Shale has done most of the retirement it is going to do.

The real question now is organizational.

Can we build and sustain developer organizations that are rewarded for delivering, not just for announcing? Can we structure early projects so that utilities are not betting the company, but are still sufficiently on the hook to care deeply about schedule and quality? Can we resist the temptation to imagine that choosing the right reactor design is the decisive variable, when every historical comparison shows that outcomes hinge on the strength of the developer organization rather than the product itself?

If we can do those things, eight AP1000s will not be a moonshot, it could even be a starting point.

If we cannot, all the loan guarantees, tax credits, and presidential speeches in the world will not stop us from pulling defeat from the jaws of victory, again.

The camel and the needle image can be read in two ways.

One reading says nuclear construction is impossible and we are fools to try. The other, more accurate reading is that the obstacle is not the needle, it is the size and shape of the institutions trying to pass through it. If we reshape those institutions, the passage becomes difficult but no longer impossible.

The second nuclear renaissance will only be real if we approach institutional design with the same seriousness that engineers applied to the AP1000’s passive safety systems.

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From the Quincy Pact to a Nuclear Negotiating Table

On 14 February 1945 Franklin Roosevelt met King Abdul Aziz ibn Saud aboard the USS Quincy in the Great Bitter Lake. That encounter created the strategic architecture that governed United States Saudi relations for most of the modern era. The Kingdom supplied stable oil flows and received an American security umbrella. Washington guaranteed the survival of a monarchy in a volatile region. Even after seismic shocks such as the 1973 embargo, the Iran Iraq war, 9-11 and the shifts caused by the United States shale boom, the structure persisted.

That long history framed the meetings held last week in Washington. Mohammed bin Salman travelled to the United States for discussions with Donald Trump which included nuclear power. Together they announced that negotiations on a United States-Saudi 123 nuclear cooperation agreement had been concluded. No text was released. There was no confirmation that the Kingdom had accepted any version of the so-called “gold standard model,” in which the importing country forswears enrichment and reprocessing.

The announcement gestured at a breakthrough without explaining what either side had conceded. Instead of a detailed text, Washington and Riyadh offered a carefully staged moment meant to show that the two governments were moving in step again. Saudi Arabia could present the trip as progress toward securing the nuclear cooperation it has sought for more than a decade. The United States could signal that it still held enough leverage to shape the Kingdom’s civil program at a time of shifting regional politics. For everyone watching from the outside the lack of clarity became part of the message.

This moment matters more when understood against the slow and often opaque evolution of the Saudi civil nuclear program.

A Civil Program That Has Never Really Started

For more than fifteen years Saudi Arabia has floated nuclear ambitions that appeared large on paper and modest in practice. Early statements promised 17.6 gigawatts of large reactor capacity by 2030, Korean small modular reactors, a domestic fuel cycle and partnerships with the United States, France, South Korea, China and Russia. Precious little of that architecture materialized. The only project nearing completion is a 30 kilowatt Argentine research reactor in the commissioning and safeguards approval phase. What survives today is a tender for two large reactors and a file that has drifted through multiple bureaucratic re-organisations.

The apparent drift has had strategic value. By not committing early, the Kingdom ensured that no vendor held a privileged position. There was time for nuclear engineers to train abroad. Legal and regulatory frameworks developed gradually. Fuel cycle rights under the Nonproliferation Treaty were not surrendered. The long delay allowed Riyadh to watch how each potential partner behaved and how the global nuclear market shifted. The result is a program with very little concrete progress and a great deal of accumulated leverage.

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Why Nuclear Makes Sense Mostly as a Strategic Option

Saudi Arabia still burns on the order of one million barrels of oil per day for electricity and desalination during peak months, roughly one percent of global oil output across its ninety five gigawatt nameplate capacity grid. Freeing that oil for export would bring significant fiscal benefits, but the Kingdom has far cheaper ways to accomplish that goal than by building reactors. Since the 1970s Saudi Arabia has captured most of its associated gas through the Master Gas System and routed it into the domestic grid rather than flaring it. Current gas strategy focuses on expanding supplies from fields such as Jafurah and converting remaining oil fired units to natural gas. This shift is occurring alongside an unofficial target of roughly 100 to 130 gigawatts of solar photovoltaic capacity by 2030. Taken together, expanding gas use, replacing liquid fuel units, and rapidly scaling low cost solar provide a far shorter and more certain pathway to reducing oil fired electricity than waiting for a large nuclear program to come online.

Nuclear energy enters the picture for different reasons. It carries prestige. It anchors a long term industrial program. It provides the foundational components of a full fuel cycle. Most of all it creates latent capacity for rapid escalation if the regional environment deteriorates. That logic has been declared openly. In a 2022 interview Mohammed bin Salman stated, “If Iran acquires a nuclear bomb, we will follow suit as soon as possible.” Civil nuclear technology in this context is not only about megawatt hours but also about latent nuclear weapons potential.

A reactor deal with the right partner therefore becomes an instrument of long term signalling. It shapes alliances, defines the technological architecture through which any future fuel cycle could operate, and establishes the political obligations that would govern a Saudi program for decades. It is equally a liability for whichever country supplies the technology because the proliferation risks in this region are real, and the political consequences of enabling a latent nuclear capability are profound.

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Enrichment and the Shape of a Future Bargain

The United States has developed a preference for “gold standard” 123 nuclear cooperation agreements that forbids all enrichment and reprocessing. The UAE accepted such terms in 2009. That acceptance helped smooth the politics of the Barakah project in Congress. Saudi Arabia has refused to take that step. Article IV of the the Nonproliferation Treaty protects the right to peaceful fuel cycle activity and Riyadh sees no reason to give up a capability that its rivals either possess or are pursuing.

Before the Gaza war there was a serious attempt to build a three part arrangement that combined Saudi Israeli normalisation, a security guarantee and a nuclear cooperation agreement. Once the war erupted that track collapsed. Last week’s claim that a 123 agreement has been concluded is the first sign of renewed movement, but the absence of a public text makes it impossible to judge what shape the arrangement will take. If Washington accepts a non-gold standard framework, Congress will still have to approve it and concerns from Israel could be significant given its sizable US based lobby.

Why the UAE Picked Korea and Why That Still Matters

When the UAE held its competition in 2009, it treated nuclear energy as a capacity building problem rather than a geopolitical one. Emirates Nuclear Energy Corporation ran a disciplined tender. South Korea won with a 20.4 billion United States dollar bid for four APR1400 reactors, well below the Areva and GE Hitachi offers. The contract was heavily fixed price. KEPCO and its partners assumed substantial construction and integration risk in order to establish the APR1400 as a credible export product.

The UAE’s choice of nuclear reflected structural conditions that do not map cleanly onto Saudi Arabia today. Many are surprised to learn that the UAE is a net gas importer. Rapid growth in electricity demand and desalination outpaced domestic supply and produced a strategic dependence on Qatari gas supplied through the Dolphin pipeline. At the same time, solar photovoltaic technology in the early to mid 2000s was far less mature and far more expensive than it is today. Utility-scale solar in the Gulf was only beginning to emerge, and its cost structure made it inadequate as the main response to surging demand.

Nuclear provided the UAE with a large scale, non carbon source that reduced dependence on Qatari gas, and offered long term energy security. These pressures made nuclear urgent for Abu Dhabi in a way that was never as acute for Saudi Arabia, which has extensive domestic gas resources and is not structurally dependent on imported supply.

The results are visible. All four units at Barakah are operating. The project delivered a trained Emirati operating workforce and a competent national regulator. It remains the strongest modern example of a newcomer state executing a first-time nuclear programme without significant overruns. For Saudi Arabia the Barakah experience is both encouraging and complicated. It demonstrates that Korea can deliver. It also reflects a commercial and intellectual property environment that no longer exists.

The Lessons of Poland and Bulgaria

The financial structures of recent AP1000 projects reveal how costs vary with partner selection, project maturity, and the breadth of what is counted in programme figures. In Poland, the planned first plant at Lubiatowo Kopalino, using three AP1000 units under a Westinghouse-Bechtel consortium, carries an estimated cost of roughly 50 billion United States dollars. This is an all-inclusive national programme figure for a newcomer country with a greenfield coastal site, encompassing owner costs, contingencies, interest during construction, grid upgrades, civil works, and the institutional build out needed under European regulatory scrutiny.

By contrast, Bulgaria has capped its two-unit AP1000 expansion at around 14 billion dollars with Hyundai Engineering and Construction as preferred partner. This reflects a construction cost ceiling at an existing site with established grid and cooling infrastructure. It excludes the breadth of owner costs included in the Polish estimate, and independent Bulgarian analysts place the likely all-in figure closer to 17.6 billion euro. The project is also at an earlier definition stage; Hyundai and Westinghouse have so far signed only an engineering services contract, not a full EPC.

These cases illustrate how different risk allocations drive different outcomes. When Bechtel anchors EPC, the structure is conservative and costs rise because price certainty requires thicker contingencies. When a Korean firm that is prepared to assume more construction risk leads EPC at an existing site with lower local construction costs, the burden can fall. Final prices, however, are known only once binding EPC contracts are signed.

For Saudi Arabia the implication is straightforward. Any AP1000-based programme would preferably resemble the Bulgarian structure rather than the Polish one and would be designed around heavy use of Korean construction capacity and supply chains.

The Westinghouse Monroe Doctrine

The intellectual property environment that enabled Barakah changed fundamentally after the project was completed. The APR1400 was developed from a long standing System 80 technology transfer from Combustion Engineering, later acquired by Westinghouse. During Barakah this lineage was acknowledged, Westinghouse was part of the consortium, and United States approvals were routine.

In the years that followed, Korea began presenting the APR1400 as an indigenous design. Westinghouse and Washington pushed back. From 2022 onward the United States asserted that APR1400 remained dependent on United States-owned IP and was therefore subject to United States export controls. Litigation followed, culminating in a global settlement in 2025.

Leaked figures reported in the Korean press suggest that Korean firms must assign Westinghouse about 650 million dollars of equipment and services scope and pay roughly 175 million dollars in licensing fees for each export reactor. In effect the settlement places a United States commercial and political gatekeeper between Korea and any autonomous export bid.

The resulting structure functions as a modern Nuclear Monroe Doctrine. The original doctrine signalled that outside powers could not establish independent spheres of influence in the Americas. The Westinghouse-Korean settlement does not create a formal geographic prohibition, but it defines where Korea can act independently. KHNP’s effective sidelining or withdrawal from programmes in Poland, the Netherlands, Sweden and Slovenia reflects this new environment. The mechanism became explicit in the Saudi tender when Washington asked Seoul not to bid APR1400 and instead to join an AP1000-based proposal. United States export controls provide a workable veto through the ability to withhold authorisation for intermingled technology. That possibility alone is sufficient to shape Korean decisions.

The Korean Predicament

The settlement eliminated legal risk but created political strain in Seoul. Korean reporting described the terms as a burden on the industry and criticised the previous administration for conceding too much. The financial details came to light only because internal factions leaked them. Korea remains free to participate in foreign projects, but primarily as an EPC partner on AP1000 designs rather than as an autonomous exporter of APR1400. This structure is acceptable to countries that want both United States technology and Korean delivery capacity, and it poses no obstacle where Korea is welcomed as a major builder. The constraint is domestic. The pathway for a semi-independent Korean nuclear export option has narrowed. Korea’s future participation abroad now sits within a framework defined by Westinghouse technology, United States authorisation and United States strategic priorities.

Saudi Strategic Logic and Narrowing The Field

From Riyadh’s perspective the other major players present challenges.

France retains a sophisticated nuclear industrial base and decades of construction experience but its export bandwidth has eroded. EDF is still trying to bring Flamanville to full power after eighteen years of construction, attempting to finish Hinkley Point C, getting started on two EPR units at Sizewell, and preparing between six and fourteen EPR2 units in France. The signs of exhaustion are evident. EDF has withdrawn from multiple international tenders and its capacity to shoulder a project of regional significance in Saudi Arabia is limited.

Rosatom is competent but burdened by sanctions and political risk. China has demonstrated capacity but has limited export bandwidth, and a Chinese Saudi reactor would signify a geopolitical pivot.

As illustrated above Korea can deliver, but only inside an export architecture that gives Washington approval authority.

The United States offers the AP1000, political cover and a pathway to a reactor deal that aligns with long term security objectives. A Korean built AP1000 under United States oversight might just be the the most viable model.

Conclusion: A High Stakes Game of Optionality

Saudi Arabia’s nuclear program has always been presented as a civil project. In practice it functions as a strategic instrument in a region defined by rivalry and shifting alliances. The Quincy pact still shapes expectations. The meetings in Washington hint at a new bargain. The choice of reactor will affect more than the power grid, it will determine how the Kingdom positions itself between Washington, Beijing and Moscow. It will influence whether Saudi Arabia preserves a latent weapons option. It will test how far the United States is willing to go in directing allied technology through export controls.

For a Kingdom that does not need nuclear power to generate electricity, the stakes are unusually high. The final decision will be remembered not for the megawatt hours it produces but for the alliances it cements.

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