The SMR sector has entered one of the most concentrated periods of capital-market activity in nuclear-energy history. Companies that were, until recently, dependent on government grants, strategic investors, and patient private capital are now accessing public equity markets at scale. The volume and pace of listings in 2025 and 2026 are without precedent in the sector’s modern history.

On balance, this is a significant positive for nuclear energy. Public markets provide depth, liquidity, and visibility that private capital cannot replicate at scale. Indeed, they force discipline on governance, disclosure, and the rigour of financial projections, and signal something the nuclear sector has struggled to demonstrate for two decades: that institutional investors believe in the long-term commercial case.

But a pattern is emerging within the IPO wave that deserves more careful scrutiny than it has received. When European SMR developers seek capital, they increasingly do so in the United States. The implication is precise: European nuclear champions, built to serve European energy security, are being owned and priced by American capital markets.

That is not inherently a problem. It is, however, a tension the industry and European policymakers should name clearly.

What the IPO wave actually looks like

The SMR capital markets story began in earnest with NuScale Power, which listed on the New York Stock Exchange (NYSE: SMR) via a SPAC business combination, becoming the first pure-play SMR company to trade publicly. NuScale holds a distinction that matters: the only SMR design currently certified by the US NRC. That regulatory milestone makes it the closest analogue, in Western markets, to a company with a deployable product.

NANO Nuclear Energy (NASDAQ: NNE) was among the earliest movers, completing a traditional IPO in May 2024, raising $10.25 million at $4 per share, and becoming the first micro-nuclear reactor company to list on Nasdaq. Its designs, ZEUS and ODIN, are sub-10 MWe microreactors targeting remote and off-grid applications. Modest in scale at listing, NANO established that public markets would accept pre-revenue nuclear at the smallest end of the reactor spectrum.

Oklo (NYSE: OKLO) followed, also via a business combination. It focuses on sodium fast microreactors, targeting industrial and data centre customers directly, a go-to-market model that has attracted significant attention amid AI’s surging energy demand. As of late 2025, Oklo reached a market capitalisation of approximately $18 billion.

In April 2026, X-Energy (NASDAQ: XE) priced its IPO at $23 per share, raising capital to commercialise its high-temperature gas reactor technology. Amazon is a cornerstone strategic backer, and the relationship has become a significant commercial validator in the market’s eyes. X-Energy’s HTGR design offers both power generation and high-temperature process heat, making it relevant beyond the electricity sector.

Then came Fermi America, co-founded by former US Energy Secretary Rick Perry, which raised $682 million in its IPO and launched with a market capitalisation of approximately $12.2 billion. Fermi is not, however, an SMR vendor in the mould of Oklo or X-Energy. It is a project developer and integrator; its primary plan is to build four Westinghouse AP1000 reactors on an 11-gigawatt campus near Amarillo, Texas, through its “Project Matador” programme. It has signed a FEED contract with South Korea’s Hyundai Engineering & Construction and a forging agreement with Doosan Enerbility for reactor pressure vessels and steam generators. Fermi also holds an MoU with Doosan covering future SMR technology, but the flagship commitment is conventional large-scale nuclear. The company’s stock market debut was fuelled by AI data centre power narratives; the underlying business plan is closer to that of a nuclear project developer than a technology licensing company.

These headline listings represent only part of the picture. A secondary tier of companies has also entered or is entering public markets, extending the wave well beyond the names that dominate financial press coverage.

Terrestrial Energy (NASDAQ: IMSR) followed via a SPAC merger with HCM II Acquisition Corp., completing its business combination in late October 2025 and raising approximately $292 million in gross proceeds. The Canadian company is developing the Integral Molten Salt Reactor, a Generation IV design targeting industrial heat and power generation. Its listing made it the world’s first publicly traded molten salt reactor developer.

Deep Fission (NASDAQ: FISN) filed its prospectus in June 2026, raising $40 million at $16 per share. Its Gravity Reactor takes a novel approach: a pressurised water reactor installed in a deep vertical borehole about one mile underground, using hydrostatic water pressure instead of conventional pressure containment. The company is pre-revenue and early-stage, with an initial pilot configuration targeting up to 8 MWe.

Hadron Energy got listed via a SPAC merger with GigCapital7 under the planned ticker HDRN. The company reset its valuation from $1.2 billion to $600 million in April 2026, deliberately adjusting to public market conditions after the broader repricing of advanced nuclear equity. Hadron is developing the Halo micro-modular reactor, a light-water design targeting 10 MWe and 35 MW of thermal output, with NRC design-certification applications planned for the fourth quarter of 2026.

Finally, and most significant from a European perspective: Newcleo recently got listed on Nasdaq via a merger with NewHold Investment Corp III, at a pre-money valuation of $2.4 billion. Newcleo, a Franco-British company founded in Turin, is developing a lead-cooled fast reactor and has technology and commercial ambitions spanning France, the UK, and wider European markets. It would be the first originally European advanced nuclear company to access US public equity markets at scale. Its auditor has raised going-concern questions, citing recurring losses of about €140 million in 2025, underscoring the financial pressure that makes US capital so attractive compared with European alternatives.

The listing that received the least attention, but may prove the most strategically significant, came on October 2, 2026. Steady Energy, a Finnish SMR developer focused on low-carbon district heating, debuted on Nasdaq Helsinki First North. Its IPO was small by the standards of the wave: €5 million. It was oversubscribed. Shares fell roughly 6% on their first day of trading. On its own, the numbers are modest. In context, they mark something new: a European SMR company tapping public equity markets on a European exchange. The Nasdaq Helsinki First North is usually seen as the first step before moving onto Nasdaq.

Then, on September 16, 2026, Holtec International, positioned as one of the year’s largest nuclear IPOs, targeting a valuation above $10 billion and seeking to raise $900 million, officially cancelled its public listing. Holtec’s CEO described the environment as “a perfect storm,” citing the market’s sharp turn against the AI data centre economy in the weeks before the planned debut. The registration remains on file. Holtec expects to attempt the listing again within three to six months.

The performance reality

The companies that have listed face a common challenge: public markets are pricing them as long-duration technology bets, and in 2026, patient capital has become expensive.

NuScale’s share price has declined approximately 48% Year-To-Date. Oklo has fallen around 51% from its highs. X-Energy, which priced at $23 per share in April, traded near $14 by mid-year, down roughly 40% from its IPO price within months of listing.

The explanation is quite simple. Every publicly traded SMR vendor operating today is pre-commercial. None has a commissioned reactor generating electricity at commercial scale – even Oklo with its Groves reactor that reached criticality within the DOE Reactor Pilot Program is still a long way from commercial operations. None has a signed, binding power purchase agreement that would commit a customer to long-term offtake and clear the path to construction financing. The deals in the backlog are, in the main, letters of intent, memoranda of understanding, and framework agreements – commitments in principle, not capital.

Public markets, which were willing to overlook this in 2024 and early 2025 when AI demand narratives were at their most expansive, have become more discriminating. The correction in SMR equity prices in 2026 reflects a repricing of timeline risk, not a change in the fundamentals. Bank of America’s assessment that nuclear energy represents a $10 trillion opportunity over the next 25 years remains unchanged. McKinsey’s projection that the world will deploy $7 trillion to build AI data centres by 2030 remains unchanged. What has changed is the market’s patience with companies that have yet to translate that demand into binding commercial commitments.

The single most consequential catalyst the sector is waiting for is a signed, bankable power purchase agreement from a creditworthy counterparty. NuScale is in active negotiations with the Tennessee Valley Authority on a potential PPA for a 6 GW facility, which would represent the largest SMR deployment in the world by a considerable margin. If that agreement is signed before the end of 2026, the market’s assessment of SMR equity will change materially.

The question that Europe has not answered

The US listings dominate both capital raised and media attention. But the most strategically interesting development in the SMR IPO landscape is not what is happening in New York or on the Nasdaq. It is what is happening, and what is not happening, in Europe.

Steady Energy’s Helsinki debut is significant precisely because it is an exception. Europe is home to a meaningful cluster of advanced nuclear developers with genuine technical depth. Several have ambitions that exceed what European public equity markets can currently finance, and the capital logic is pushing them toward New York. Newcleo’s decision to pursue a Nasdaq listing rather than a European exchange best illustrates this dynamic. A Franco-British company, founded in Turin, with regulatory ambitions in France and the UK, is going to Wall Street because that is where the equity is.

When European SMR developers require equity capital beyond what domestic investors can provide, the default path leads to US markets: NASDAQ, NYSE, or the SPAC structures that precede them. The rationale is straightforward. US markets are deeper, more liquid, and more experienced with high-growth, pre-revenue technology companies. US institutional investors have developed frameworks for valuing pre-commercial nuclear assets that European institutional capital, broadly speaking, has not yet built.

The practical consequence is this: a European SMR company that lists in the United States acquires ownership structured around US institutional priorities, US activist shareholder norms, US reporting cycles, and, ultimately, a valuation driven by US market sentiment. In a sector where political and regulatory decisions will be made in Brussels, Paris, Warsaw, and Helsinki, that misalignment between ownership and operating environment carries long-term implications.

This is not a new dynamic. European technology champions have been listed in the United States for decades, and the debate over European capital market depth is long-standing. But nuclear energy is not a standard technology sector. It is a sector where the intersection of energy security, defence considerations, and regulatory sovereignty makes ownership more contentious than in most industries.

The European Investment Bank’s €40 million loan to Steady Energy in September 2026 is one response to this challenge, and an encouraging one. EIB has indicated that further loans to SMR developers are expected. The European Innovation Fund, national development banks, and sovereign wealth vehicles are increasingly present as potential co-investors. But debt is not equity. And the equity gap that drives European SMR companies toward US markets remains.

What this means for the market

The IPO wave does not resolve the fundamental challenge facing every SMR developer: the valley between a certified design and a commissioned plant is wide, expensive, and full of execution risks. Capital markets provide the fuel, but they cannot build the reactors. The next 18 to 24 months will be defined not by IPO filings, but by whether the industry can produce its first bankable, binding customer commitments in Western markets.

Three things are clear from the current landscape.

First, the market is willing to fund pre-commercial nuclear at scale, but not indefinitely without evidence of commercial traction. The repricing of 2026 is a signal, not a sentence. The sector retains substantial institutional support. What it needs are milestones, PPAs, construction permits, first-of-a-kind project financial closes that transform the narrative from promise to proof.

Second, the US remains the dominant venue for SMR capital formation, and that dominance will likely persist as long as European equity markets lack the depth and risk appetite to compete. Holtec’s cancelled IPO demonstrates that even the US market has limits in adverse conditions, but it also demonstrates that the intention to list is undiminished. The pipeline of planned nuclear public listings remains substantial.

Third, and perhaps most importantly for European stakeholders: the question of where European SMR capital is raised is also a question about where European nuclear is governed. A Finnish heating company whose shareholder base is predominantly American is not the same strategic asset as a Finnish heating company financed by Finnish or European capital. That distinction will matter when technology licensing decisions are made, when manufacturing partnerships are structured, and when the geopolitics of the energy transition inevitably produce pressure.

The IPO wave is a genuinely good development for nuclear energy. It is bringing capital, discipline, and visibility to a sector that needs all three. But for Europe specifically, the question of how to build the capital infrastructure that keeps European nuclear champions in European hands remains open, and is becoming more urgent as the first wave of SMR listings reshapes the industry’s ownership map.

Capital is flowing into the SMR sector at a pace not seen in a generation. The conversation now needs to be about whose capital, on whose terms, and the long-term implications for the countries that have decided nuclear energy is part of their future.

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These are necessary questions. But they overlook an earlier and equally consequential indicator of execution: fuel.

India currently operates approximately 8.8 GW of nuclear capacity across 24 reactors. Expanding that fleet to 100 GW would require more than an eleven-fold increase in installed capacity. Long before those reactors enter operation, India must establish the supply relationships, contracting structures and fuel-cycle capabilities needed to support them reliably over several decades.

Viewed through this lens, India’s uranium diplomacy in 2026 is more than a series of bilateral agreements. It reflects a broader transition: from securing uranium opportunistically to building a diversified, long-duration fuel supply portfolio.

That distinction matters. While reactor announcements demonstrate ambition, fuel commitments reveal how seriously a country is preparing to execute it.

Four developments, one emerging architecture

Between March and September 2026, India advanced uranium relationships with Canada, Kazakhstan, Australia and Uzbekistan. The four developments are not identical: two involve major supply contracts, one operationalises access to a new source, and one remains under negotiation.

Together, however, they point towards a deliberate portfolio strategy.

In March, Cameco signed a nine-year agreement with India’s Department of Atomic Energy to supply nearly 22 million pounds of uranium concentrate between 2027 and 2035. Valued at approximately C$2.6 billion, the agreement gives India long-term volume visibility from one of the world’s largest uranium producers. Its announcement in Delhi, in the presence of Prime Minister Narendra Modi, Mark Carney, and Saskatchewan Premier Scott Moe, also showed the strategic importance of the relationship. Cameco and the Canadian government both described the agreement as a major element of the renewed bilateral partnership.

In parallel, India finalised a major long-term contract, valued at over $4 billion, with Kazatomprom, which supplies roughly 23% of global uranium. If the Cameco deal provides volume certainty from a Western hemisphere supplier, the Kazatomprom deal secures India’s access to the world’s most productive uranium basin.

Australia represents a different form of progress. At the India–Australia summit on 9 July, the two governments finalised the administrative arrangement required to operationalise their civil nuclear cooperation framework. The decision does not itself constitute a uranium supply contract. It removes the procedural barrier that had prevented Australian uranium from being supplied to India under peaceful-use commitments and IAEA safeguards. A source of supply that had existed largely in principle since the bilateral agreement was signed can now become commercially relevant. 

Uzbekistan adds a further layer of continuity. In September, Prime Minister Modi visited Tashkent. India’s Ministry of External Affairs confirmed that Modi “appreciated the progress made in the long-term arrangement for supply of uranium from Uzbekistan to India.” Siby George, Secretary at the Ministry, said that an agreement was imminent: “We are closing in on the signing of an agreement very shortly.” An existing Uzbek supply contract, valid through 2026, is being replaced with a new long-term arrangement, maintaining continuity with a supplier that India has relied on for years, while formalising the relationship at a larger scale.

The distinction between these developments is important. India has not signed four equivalent uranium contracts. It has done something more strategically revealing: it has simultaneously secured contracted volume, deepened access to an established producing region, opened a previously unavailable supply channel and moved to preserve continuity with an existing supplier.

This is portfolio construction, not transactional procurement.

From geopolitical access to industrial execution

The significance of this portfolio becomes clearer when viewed against India’s history of exclusion from international nuclear trade.

India’s 1974 nuclear test sharply curtailed its access to international nuclear materials and technology. Canada suspended cooperation, Australia declined to supply uranium and the Nuclear Suppliers Group established rules that effectively excluded India because it was not a signatory to the Nuclear Non-Proliferation Treaty.

The 2008 Nuclear Suppliers Group waiver changed India’s position. It reopened access to international civil nuclear commerce while placing imported nuclear material and designated facilities under safeguards. Canada subsequently renewed cooperation, Australia revised its policy and India began rebuilding a network of international fuel relationships.

The agreements reached in 2026 should therefore not be interpreted as the sudden creation of a fuel strategy. They represent the maturation of a process that began nearly two decades ago.

The evolution can be understood in three stages:

• Re-entry: securing the legal and diplomatic ability to participate in international nuclear trade.
• Access: establishing bilateral cooperation agreements and initial supplier relationships.
• Portfolio development: locking in long-duration supply across multiple jurisdictions while preserving future procurement options.

India now appears to be entering the third stage.

That is a meaningful shift. It suggests that fuel procurement is increasingly being managed as a strategic component of nuclear deployment rather than as a downstream operational requirement.

Diversification is the strategic signal

The immediate purpose of these agreements is straightforward: India needs sufficient uranium to operate an expanding reactor fleet.

The more important insight lies in how it is assembling that supply.

Canada, Kazakhstan, Australia and Uzbekistan represent different production regions, trading relationships and geopolitical alignments. Building access across them reduces exposure to disruption in any single jurisdiction or bilateral relationship. It also gives India greater optionality as uranium demand rises and contracting conditions tighten.

This diversification is particularly important for India’s domestic pressurised heavy-water reactor fleet, which uses natural uranium. Although India has indigenous uranium resources and continues to develop its domestic fuel cycle, imported uranium can improve fuel availability and allow domestic reactors to operate at higher and more consistent load factors.

At the same time, uranium imports are only one component of India’s long-term fuel strategy. The country’s fleet also includes Russian-designed VVER reactors using enriched uranium fuel, while its broader three-stage nuclear programme envisages using plutonium in fast breeder reactors and, ultimately, India’s substantial thorium resources.

The recent achievement of first criticality at the Prototype Fast Breeder Reactor at Kalpakkam is a significant milestone in that journey, a tangible step toward the fuel independence the programme is designed to deliver. But that transition will take decades. Until fast breeder and thorium-based capacity reaches meaningful scale, India’s reactor fleet will remain dependent on imported natural uranium.

India’s challenge is therefore larger than procuring uranium concentrate. It must coordinate raw-material supply with conversion, enrichment where required, fuel fabrication, safeguarded reactor allocation, spent-fuel management and the progressive development of its closed fuel cycle.

The 2026 agreements do not resolve that full equation. They do show that one of its foundational layers is being addressed earlier and more systematically.

An execution signal but not yet proof of delivery

Fuel contracting can provide an important indicator of programme confidence.

A nine-year sovereign-backed uranium agreement is not typically concluded in isolation from anticipated reactor demand. Long-term commitments require demand forecasts, inventory planning, safeguards arrangements, transport coordination and alignment with the expected operating profile of the fleet.

India’s recent activity therefore strengthens the case that its nuclear programme is moving beyond target-setting. It suggests greater coordination between diplomatic engagement, resource security and long-term capacity planning.

However, fuel security should not be mistaken for proof that the full 100 GW programme is financed or executable.

Reaching the target will still require India to address several interdependent constraints:

• mobilisation of capital at unprecedented scale
• faster project development and construction
• expansion of domestic manufacturing capacity
• access to reactor technologies and critical components
• development of a substantially larger skilled workforce
• regulatory capacity capable of overseeing a much larger and more diverse fleet
• integration of private-sector participation without fragmenting accountability.

Fuel is therefore not the final proof point. It is an enabling condition, and one being put in place earlier than many market observers may have recognised.

What the market should watch next

India’s transition from a relatively small uranium buyer to a structural source of long-term demand could have implications across the nuclear value chain.

For uranium producers, India offers the prospect of sovereign-backed demand extending over multiple contracting cycles. Suppliers that can combine resource depth, delivery reliability, and geopolitical durability may be particularly well positioned.

For fuel-cycle companies, growth will not be limited to uranium extraction. An expanding and increasingly diverse Indian fleet could create demand across conversion, enrichment, fabrication, logistics, inventory management and associated technical services.

For reactor vendors and investors, the agreements provide evidence of upstream preparation. They reduce one category of programme risk, but the more decisive signals will come from project awards, financing structures, regulatory reforms, construction progress and the development of domestic industrial capacity.

For policymakers, India offers a broader lesson. Nuclear expansion cannot be planned as a sequence that begins with reactor procurement and ends with fuel. Fuel security, industrial capacity, financing, workforce development and regulation must be designed as an integrated system.

India’s SHANTI Bill directly addresses the regulatory dimension of that system. By ending the state monopoly on nuclear power generation, opening plant ownership and operation to qualified private and foreign companies, removing the supplier liability clauses that had long deterred international investment, and granting formal statutory independence to the Atomic Energy Regulatory Board, it creates the legal architecture that a programme of this scale requires. Removing the CLNDA’s contentious supplier liability provisions alone eliminates one of the most significant structural barriers that kept foreign reactor developers and equipment suppliers at arm’s length from the Indian market.

India’s 2026 uranium diplomacy should be understood alongside that legislative shift, not in isolation. Fuel security and regulatory reform are two dimensions of the same undertaking.

The country has not yet proved that it can deliver 100 GW of nuclear capacity by 2047. But it is beginning to build the portfolio of long-term commitments required to make that ambition credible, and it is building them in parallel, not in sequence.

The reactors will remain the most visible part of India’s nuclear expansion. The less visible signal may be the more consequential one: India is starting to secure the fuel before the fleet arrives.

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Nuclear energy is attracting capital at a scale not seen in decades. Thirty-one countries have committed to tripling their nuclear capacity by 2050, with new countries pledging since governments across Europe, North America, and Asia are extending plant lifetimes, restarting mothballed reactors, and funding new builds. Hyperscalers are signing long-term power purchase agreements that give nuclear operators revenue certainty for the first time in a generation.

All of this requires uranium in far greater quantities than the world currently produces. And the industry’s planning, for the most part, has not kept pace with the ambition.

The fuel supply conversation has until recently concentrated on conversion: the step that transforms uranium oxide into uranium hexafluoride, ready for enrichment. Conversion capacity is tight, concentrated in a small number of facilities, and was structurally dependent on Russian supply chain that can no longer be treated as available. That concern is legitimate and pressing.

But conversion is a constraint with known solutions, and investment flows already addressing it. Uranium mining is a constraint of a different character: longer lead times, larger capital requirements, and decisions being made today, or not being made, that will determine what is available in the late 2030s and 2040s. The question worth asking now is not which step in the fuel chain is tight at this moment, but which constraint will prove harder to solve and on what timeline.

Where uranium supply stands today

As of today, 440 commercial reactors are operating globally with a combined net generating capacity of approximately 397 gigawatts electric, requiring around 68,000 tonnes of uranium per year. Global primary mine production does not cover that requirement and has not, for most of the past two decades. The gap between what mines produce and what reactors require is filled by secondary supplies: drawn-down inventories, recycled material, and the progressive downblending of highly enriched uranium from weapons programmes, available since the end of the Cold War. That buffer is finite, and the assumption that it will remain available at scale is increasingly strained.

Kazakhstan produces approximately 40 percent of global uranium output and remains in a category of its own. Kazatomprom’s production rose ten percent in 2024 to 23,270 tU, with further increases planned as the company returns to 100 percent of its subsoil use agreements for the first time since 2018. Canada, through Cameco’s Cigar Lake and McArthur River operations, and Namibia are the next largest producers by volume. However, a large share of uranium from Namibia is being offtaken by Chinese utilities. Australia holds the world’s largest identified resource base, at 28 percent of the global total, but has not recently translated that resource position into top-tier production. Russia and Uzbekistan round out the significant producer group. Additional players, understanding the strategic aspect of covering uranium mining, are coming in such as the U.S. Between 2024 and 2025, the amount of U3O8 produced has more than tripled.

At current and near-term production rates, primary supply cannot scale at the speed implied by the nuclear capacity commitments now on the table. What primary production misses, secondary supply has historically covered. The question is whether that assumption still holds as demand scenarios expand.

What growth scenarios require

The OECD Nuclear Energy Agency and IAEA’s 2024 Red Book projects world nuclear capacity reaching 574 GWe by 2050 in the low-demand case and 900 GWe in the high-demand case, translating to annual uranium requirements of approximately 90,000 tU and 142,000 tU respectively. Against the 59,000 tU required today, the range implies a 50 to 140 percent increase in annual demand over 25 years.

The 31-country commitment made at COP28 to triple global nuclear capacity by 2050 would, if realised, push capacity toward approximately 1,200 GWe, beyond the Red Book’s high case, with uranium requirements scaling proportionally. Even the low scenario requires a significant expansion of primary production beyond current levels. The high case requires one of the most substantial expansions in the sector’s history.

The resource base is not the immediate concern. Identified recoverable resources stand at approximately 7.93 million tU, sufficient to supply all scenarios through 2050 and well beyond. But resources in the ground and production capacity are different things. The mines that will supply the global fleet in 2038 need to begin their development cycle now. Whether that cycle has started in earnest is the more pertinent question.

The conversion constraint  

Uranium conversion, the process that converts U3O8 into UF6 ready for enrichment, is the fuel cycle step that has attracted the most concern in recent years, and with good reason. Current global conversion capacity stands at approximately 65,000 tU per year against projected demand reaching roughly 85,000 tU per year by 2030, a gap of around 31 percent at a moment when Western buyers are actively seeking alternatives to Russian-controlled capacity.

The response is underway. 

In the United States, Solstice Advanced Materials’ Metropolis Works facility, formerly known as Converdyn, is projected to produce more than 10,000 tU of UF6 in 2026, approximately 20 percent above its planned 2024 output, following its 2023 restart and accumulation of over $2 billion in customer orders. New entrants are emerging: Uranium Refining and Conversion Corp received an NRC docket number in 2026, and FluxPoint Energy announced plans for the first wholly new US conversion facility in more than 70 years. Others, focussing more on alternative conversion processes such as Raven-Flint – fluorine-free process – are also positioning themselves, by being allowed into the DOE/NRIC LaunchPad program. European capacity is being expanded and reoriented. The conversion bottleneck is real, but it is an industrial infrastructure problem with a known solution set and an investment community now actively engaged with it.
The lead time for a conversion facility is measured in years, not decades.

High-assay low-enriched uranium, or HALEU, introduces a complication specific to advanced reactor designs. HALEU, enriched to between 10 and 20 percent U-235, compared with the 3 to 5 percent standard for conventional reactors and 5 to 10 percent for LEU+, is required by several small modular reactor designs now in development. As of mid-2025, Centrus Energy had produced just over 920 kilograms of HALEU from a demonstration cascade in Ohio, and no commercial-scale HALEU production exists outside Russia and China. A $900 million DOE contract with Centrus, finalised in 2026, is intended to establish the first meaningful domestic capacity. If SMR deployment scales as projected, HALEU supply will need to scale with it, adding pressure to both the conversion and enrichment steps for a subset of the fleet. To support this demand, URENCO has been working on deploying HALEU enrichment cascades, supported by the UK government. However, the challenge will be to deconvert HALEU at an industrial scale.

Mining has a different timeline

A major uranium mine takes ten to fifteen years from initial discovery, exploration and resource definition through permitting, environmental review, engineering, construction, and commissioning to reach sustained commercial production. This is not a policy choice or a bureaucratic delay. It reflects the physical reality of bringing a large, complex extraction project into operation in a regulated environment. It means that the mines needed to supply the global fleet in the mid-2030s must begin their development cycle no later than today.

The sector’s investment history does not inspire straightforward confidence on this point. Annual uranium exploration and mine development expenditures peaked at more than $1.5 billion before the post-Fukushima market downturn, fell to approximately $380 million in 2020, and had recovered only to an estimated $840 million in 2023. The investment cycle is now responding to the price signal, uranium spot prices have remained well above $80 per pound through much of 2025 and 2026, but the pipeline of projects advanced enough to enter production before 2035 is thinner than the demand scenarios require. Projects that were not in active development during the low-price years have lost between five and ten years of progress that cannot be recovered quickly.

The geographic concentration of production creates a further dimension of risk that market pricing does not fully capture. Kazakhstan alone accounts for over 40 percent of global supply, and Kazatomprom, state-controlled and subject to sulphuric acid logistics that constrained production through 2022 and 2023, is the single most consequential actor in global uranium supply. Canada and Namibia are the other significant production anchors. Australia, which holds the largest identified resource base, has been a relatively modest producer by volume. The implication is that geopolitical or operational disruption in one or two jurisdictions can materially affect global supply in a way that demand-side planning must account for.

The closed fuel cycle question

The theoretical case for reducing primary uranium demand through fuel recycling is compelling. In a fully closed fuel cycle, spent fuel from light-water reactors is reprocessed to separate residual uranium and plutonium, which are then fabricated into mixed-oxide fuel and returned to reactors. Sodium-cooled fast reactors can take this further, breeding additional fissile material from otherwise non-fissile U-238 and, in principle, extracting 60 to 100 times more energy from a given quantity of uranium ore than conventional reactors.

France is the only country that operates closed-cycle reprocessing at commercial scale. Orano’s La Hague plant processed approximately 1,130 tonnes of spent fuel in 2025. The plutonium recovered is fabricated into MOX fuel at the Melox plant, generating approximately 10 percent of French nuclear electricity and delivering raw material savings estimated at up to 25 percent compared with an open cycle. Russia operates reprocessing commercially at the RT-1 plant at Mayak. Japan’s Rokkasho reprocessing plant, after decades of delays, is moving toward commercial operation.

The global scale of reprocessing remains small. La Hague processes just over 1,000 tonnes per year in a world that produces approximately 10,500 tonnes of spent fuel annually across all operating reactors. Even a significant expansion of reprocessing capacity would not, within the 2030s, materially change the demand picture for primary uranium. The Red Book acknowledges the potential of advanced reactor and closed-cycle technologies but does not treat them as significant demand-reduction factors within its 2050 projection horizon.

The closed fuel cycle is a real long-term shift in nuclear fuel economics. It is not a near-term answer to the supply question being posed by the growth commitments of the 2020s. The organisations and governments treating recycling as a reason to delay investment in primary uranium supply are conflating a structural long-term trend with a near-term operational requirement.

The constraint that should concern the industry now

Conversion capacity will be expanded. The price signals are clear, the investment is moving, and the lead times are manageable. That step in the fuel chain will ease, unevenly, and with some difficult years in the interim, but it will ease. The same can be said for HALEU capacity, which is receiving focused government and private sector attention.

Uranium mining is a different problem. The mines that will supply the global fleet in 2038 need to be in active development now. Some of that investment is starting, exploration expenditure is recovering, and the price environment supports new project development. But the projects abandoned or deferred during the low-price years from 2014 to 2021 are not recoverable on the timelines that nuclear growth scenarios require. The pipeline of projects capable of reaching sustained production before 2035 is thinner than most demand projections assume.

Advanced reactor and closed-fuel-cycle technologies offer a genuine long-term restructuring of uranium economics. Fast reactors operating on recycled fuel would, at scale, dramatically reduce dependence on primary mine production. That transformation is worth pursuing and investing in. But it cannot materially alter the supply picture for the decade that matters most immediately, the 2030s, when the bulk of announced nuclear growth is scheduled to come online.

For the operators, investors, and governments driving the current wave of nuclear development, the practical implication is clear. The resource base is large enough. The identified geology is there. What is not yet there, in sufficient scale, is the sustained investment in mine development and the supply chain behind it. Conversion has the industry’s attention. Mining needs it more.

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Between September 2024 and January 2026, the four largest technology companies by data centre scale, Alphabet, Amazon, Meta, and Microsoft, each signed agreements to access nuclear power. In aggregate, those commitments represent up to 10 gigawatts of potential capacity and have been widely described as the moment when the nuclear-hyperscaler relationship moved from aspiration to contract.

The description is broadly accurate. But looking at what has actually been agreed, a more complex picture emerges. The transactions use similar language (power purchase agreement, clean energy contract, long-term deal) to describe arrangements that are structurally very different from one another. One company is buying electricity. Another is buying carbon credits from electricity it will never receive. A third is signing options on capacity from reactors that have not yet been licensed. Each carries different risks, requires different regulatory treatment, and provides a different level of revenue certainty for the nuclear asset.

Understanding the commercial architecture of these deals, what each structure actually is, what it does and does not guarantee, and where the risks sit, is not just a legal question. It is a strategic one. For utilities seeking to monetise existing or restarted nuclear capacity, for technology companies under pressure to demonstrate energy security and sustainability, and for the financing structures that must underpin any new nuclear investment, the commercial model is where ambition either converts into bankable certainty or stalls.

Three structures, not one

The transactions that have defined the nuclear-hyperscaler relationship since 2024 fall into three categories, each of which allocates risk differently.

The first is a conventional power purchase agreement, in which a technology company agrees to buy electricity from a specific nuclear plant over a defined term. Microsoft’s 20-year agreement with Constellation Energy for 835 megawatts from the restarted Three Mile Island Unit 1, signed in September 2024, is the clearest example. Amazon’s 17-year, 1.92 gigawatt agreement with Talen Energy for power from the Susquehanna nuclear plant, announced in June 2025, is another. Under these arrangements, the nuclear operator generates and delivers power, the technology company receives and pays for it, and the PPA price provides the revenue certainty needed to support the capital investment required to restart or extend the plant’s operating life.

The second model is structurally different. Meta’s 20-year agreement with Constellation Energy for 1,121 megawatts from the Clinton Clean Energy Center in Illinois is not a power purchase in the conventional sense. Meta is not buying electricity for its data centres. The plant continues to sell its output to the regional wholesale market. What Meta has purchased is the plant’s clean energy credits or the right to count Clinton’s zero-carbon generation toward Meta’s own renewable energy targets. The commercial logic is coherent: Meta’s long-term commitment provided sufficient economic certainty for Constellation to reverse plans to close the plant and renew its operating licence. But the mechanism is different from a conventional electricity PPA, and its treatment under future clean energy accounting standards is not guaranteed to remain unchanged.

The third model is still earlier-stage. Alphabet’s agreement with Kairos Power, targeting 500 megawatts of advanced reactor capacity by 2035, and Amazon’s $700 million investment in X-energy to support the Xe-100 small modular reactor are structures better understood as options on future capacity than as power purchase agreements. They signal demand and provide commercial validation for reactor developers, but the power they represent depends on technologies that have not yet been deployed at commercial scale. Project finance lenders treat them accordingly.

The distinction has practical consequences. A conventional electricity PPA for an operating plant can be used directly to support project financing; it provides the revenue certainty that lenders require to assess debt serviceability. A clean energy credit purchase provides softer commercial support. A development partnership with an unproven technology provider provides little that a lender can underwrite. Organisations designing nuclear supply arrangements need to understand which of these structures they are entering, and what it does and does not enable.

The grid question

Of the transactions completed to date, the Amazon-Talen Energy sequence is the most instructive. Not because of its size, but because of what happened when the proposed commercial structure was tested against regulatory reality.

The original deal proposed a behind-the-meter arrangement: Amazon’s data centre campus, located adjacent to the Susquehanna nuclear plant in Pennsylvania, would receive power directly from the plant without routing it through the regional transmission grid. From an operational perspective, this model has clear appeal. It eliminates transmission losses, avoids grid congestion, and provides dedicated, uninterrupted supply to a facility whose energy requirements are continuous and predictable.

In November 2024, the Federal Energy Regulatory Commission rejected the interconnection service agreement required to implement the arrangement, voting 2-1. The commission’s concern was not technical. It was commercial: the proposed structure would allow Amazon’s data centres to draw on the Susquehanna plant’s output while avoiding the transmission charges that other grid users pay, potentially shifting up to $140 million in annual costs onto other ratepayers.

The deal was restructured. In June 2025, Amazon and Talen announced a revised arrangement: a 17-year, $18 billion front-of-meter PPA in which Talen sells power to the regional wholesale market and serves Amazon as a licensed retail electricity provider, delivering nuclear-sourced power across the standard grid. Amazon receives the same carbon-free nuclear power. But it receives it as a grid customer, not as a co-located facility.

The FERC decision has become a reference point for any organisation considering behind-the-meter nuclear supply to a data centre. It establishes that dedicated nuclear supply, even where that supply is physically adjacent to the generator, is not treated as a purely private commercial arrangement. Transmission cost allocation is a regulated question, and the answer affects how the economics of the deal are distributed across the wider grid. Organisations designing nuclear supply arrangements for data centres need to engage with the regulatory structure early, and certainly before commercial terms have been agreed.

A mismatch in time horizons

The most significant structural challenge in the nuclear-hyperscaler relationship is one that the headline numbers obscure. The PPAs being signed run for 17 to 20 years. Nuclear power plants, following life extension approvals, are licensed and operated for 60 to 80 years. The gap between those two figures represents a commercial problem that has not been seriously addressed in most of the transactions announced to date.

For a nuclear operator, a 20-year PPA provides revenue certainty for a fraction of the plant’s economic life. The Microsoft-Constellation agreement for Three Mile Island runs from approximately 2027 to 2047. The Susquehanna plant, under its current licence, could operate well into the 2050s. The revenue model for the years after the PPA expires depends on market conditions, regulatory renewal, and the availability of a new offtaker in a market that does not yet exist.

For a technology company, the duration concern runs in the other direction. A 20-year commitment to pay approximately $110 to $115 per megawatt-hour, the estimated fixed price in the Microsoft-Constellation deal, is a substantial long-term financial obligation. In 2027, when the Crane Clean Energy Center returns to service, that price may be highly competitive relative to wholesale market rates for firm, low-carbon power. A decade later, as the energy landscape continues to evolve, the comparison may look different. Fixed-price long-term contracts provide certainty, but that certainty is not symmetric: it protects against price increases, but does not protect against the possibility that better or cheaper alternatives emerge.

The deeper issue is what happens if a data centre’s energy requirements change significantly before the PPA expires. Facilities designed for one generation of AI infrastructure may be partially repurposed, consolidated, or closed before a 20-year nuclear offtake agreement reaches its natural expiry. Unlike most renewable energy contracts, nuclear PPAs cannot simply be reassigned or cancelled without substantial financial consequences. Rigorous deal design addresses this by clarifying termination provisions, force majeure definitions, and the conditions under which the offtake obligation transfers or is released. Most of the deals announced to date have not disclosed this level of contractual detail publicly. The risk exists regardless of whether it has been disclosed.

The financing layer

Behind every nuclear-hyperscaler deal is a financing question that the headline announcement does not address. Nuclear plant restarts, life extensions, and uprates require significant capital investment. That investment needs to be financed. And the terms on which it can be financed depend substantially on the creditworthiness and enforceability of the offtake arrangements underpinning it.

The Three Mile Island restart illustrates the dynamic clearly. Constellation’s investment of approximately $1.6 billion in bringing Unit 1 back to service was supported by a $1 billion loan from the Department of Energy’s Loan Programs Office. The federal facility provided both the financing and a signal to private lenders and equity investors that the project met government bankability criteria. The Microsoft PPA provided the commercial revenue certainty. Both were necessary; neither alone would have been sufficient to move the project forward.

This financing structure (corporate PPA supported by government-backed debt) is likely to remain the template for nuclear restart and life extension projects for the foreseeable future. It reflects the credit reality that, even with an investment-grade corporate offtaker, lenders to nuclear projects require additional risk mitigation that private capital alone does not currently provide. The DOE Loan Programs Office has indicated that nuclear will be its largest single use of funds going forward, with a 2026 budget request including $30 billion in new loan authority oriented primarily toward nuclear and firm generation capacity.

For technology companies negotiating nuclear offtake arrangements, the financing structure is not a background consideration. The terms of a PPA, from its duration and price to termination provisions and step-in rights for lenders, directly affect whether the project can attract the project finance it requires to proceed. A PPA that provides insufficient revenue certainty, or that includes termination provisions that lenders regard as credit risk, may leave the nuclear asset unable to raise the capital it needs. In that scenario, the deal is signed, but the project does not advance. Organisations that understand this dynamic negotiate PPA terms with the financing structure explicitly in view, rather than treating the commercial agreement and the project finance as separate conversations.

A market that is not yet scaling

The headline figures from the nuclear-hyperscaler deals of 2024 to 2026 suggest a transformation in the sector’s commercial dynamics. The underlying numbers suggest something more measured.

The total nuclear capacity represented by hyperscaler agreements amounts to approximately 13 gigawatts. If all of those commitments were fulfilled on the timelines announced, they would generate approximately 102 terawatt-hours of electricity per year. Against the mid-range projections for US data centre electricity demand through 2035, that figure represents less than 20 percent of projected need.

The gap reflects a structural tension. The hyperscalers are spending at extraordinary scale on data centre infrastructure, $443 billion in 2025 and a projected $700 billion or more in 2026. Nuclear commitments, by contrast, represent a fraction of that capital deployment. The reason is partly timing: new nuclear capacity requires years of development, and the AI infrastructure buildout is moving on a quarterly schedule, not a decadal one. But it is also structural: the commercial models for nuclear-hyperscaler supply are not yet standardised or replicable enough to scale at the pace the gap implies.

Closing the gap will require deal structures that are more consistent and replicable, regulatory frameworks that are more clearly established following the Federal Energy Regulatory Commission precedent, and financing structures that depend less on bespoke government support for each individual transaction. None of those conditions yet exist at the scale the opportunity implies. The organisations that contribute to building clearer frameworks for grid interconnection treatment, for PPA bankability criteria, for the contractual provisions that lenders require, will shape the commercial environment in which subsequent deals are negotiated.

Getting the structure right

The nuclear-hyperscaler deals of the past two years have demonstrated that a commercial market for dedicated nuclear supply to data centres is forming. They have also demonstrated that the contractual, regulatory, and financing complexity of these arrangements is not always fully understood by all parties entering them.

For nuclear operators, the priority is revenue clarity across the full plant life, not just the PPA term. A 20-year offtake agreement that covers a plant’s operating costs provides near-term certainty, but a plant that cannot demonstrate a credible commercial model for years 21 and beyond will face increasingly difficult conversations as PPA expiry approaches. Agreements that include extension options, price reset mechanisms, or structured transition provisions for market-based offtake after the initial term strengthen the long-term commercial position and make licence renewal arguments easier to sustain.

For technology companies, the priority is understanding what the commitment actually involves. An energy credit purchase and a conventional power purchase agreement both involve long-term contracts with a nuclear utility, but they represent different obligations, different regulatory exposures, and different accounting treatments. A behind-the-meter arrangement and a front-of-meter retail supply deal carry very different grid interaction requirements. The organisations that engage with these distinctions early, with regulatory counsel, project finance advisors, and energy procurement specialists involved from the outset, are less likely to face the structural renegotiations that the Amazon-Talen sequence required.

For both sides, the lesson from the transactions completed to date is that the commercial model for nuclear-hyperscaler supply is not yet standardised. Each transaction has required significant bespoke structuring. The immediate challenge is not a shortage of intent, but the absence of a commercial and regulatory framework mature enough to scale. Building that framework is as important as signing the next deal.

The post Nuclear and data centres: beyond the PPA appeared first on Damona | Strategy consulting | Nuclear industry.

That gap, between the number of reactors that have stopped generating power and the number whose sites have been fully remediated, tells the central story of nuclear decommissioning. It is a decades-long, technically demanding, heavily regulated, and expensive process. The estimated global cost over the next four decades is approximately $500 billion.

Most organisations in the nuclear industry treat that figure as a liability. It sits on balance sheets, absorbs regulatory attention, and occupies the back pages of annual reports. The planning horizon for decommissioning is measured in generations, not business cycles. It does not attract the same commercial energy as new build.

That framing is understandable. It is also incomplete. Decommissioning is not only a liability. It is a market, large, complex, multi-decade, and structurally undersupplied with the advisory and commercial capability it needs to be executed well. The organisations that recognise this distinction early are positioning themselves ahead of a significant structural opportunity.

The scale of what is coming

The global nuclear decommissioning services market was valued at approximately $9.5 billion in 2025 and is projected to grow at a compound annual rate of between four and six per cent through 2034, reaching $19 billion then. These figures reflect only the near-term services market, the contracting, engineering, waste management, and project management work currently under procurement. They do not capture the full long-term value of the decommissioning pipeline, nor the advisory, commercial structuring, and workforce planning work that enables it.

The market’s geographic distribution is concentrated but shifting. Europe currently accounts for approximately 35 to 40 percent of global decommissioning revenues, driven by the UK’s legacy fleet managed by the Nuclear Decommissioning Authority and Germany’s post-Fukushima phase-out programme. The United States, with 41 permanently shut-down reactors the single largest national market. Asia, particularly Japan following Fukushima and South Korea’s ageing fleet, is an emerging decommissioning market of significant scale.

The UK provides the clearest illustration of both the magnitude and the complexity. The estimated cost of cleaning up the UK’s 17 civil nuclear sites managed by the NDA is £132 billion. The work is not expected to be completed for approximately 120 years. Sellafield alone, the largest nuclear site in Europe, has generated two major contracting packages in the last twelve months: a 15-year, £4.6 billion framework contract for high-hazard risk reduction work awarded in November 2025, and a further £2.9 billion in infrastructure support contracts awarded in October 2025.

A 15-year, £4.6 billion contract at a single site. That is not a liability management exercise. That is a market.

Why decommissioning has been treated as a problem, not an opportunity

The historical treatment of decommissioning as a cost to be managed rather than a market to be served reflects several structural features of how the nuclear industry developed.

Decommissioning funding was designed to be a regulatory obligation, not a commercial activity. In most jurisdictions, operators are required to set aside funds during the operating life of a reactor to cover future decommissioning costs. In the United States, combined nuclear decommissioning trust funds hold approximately $100 billion, with per-reactor cost estimates ranging from $280 million to $612 million. These funds are ring-fenced, regulated, and governed by strict rules about how they can be deployed. Regulatory framing and financial assurance, rather than commercial investment, have shaped how the industry thinks about the activity.

The timescales involved also work against commercial clarity. A reactor that shuts down today may not complete full site remediation for 40 to 80 years, depending on the strategy chosen. Operators must choose between immediate dismantling, a period of safe storage before dismantling, or long-term entombment, each with different cost, workforce, and regulatory profiles. The long duration compresses the incentive to plan strategically. Decisions taken today about site strategy, contracting approach, and workforce transition will define outcomes that no one currently in the room will see.

And the liability is real. In a transaction context, decommissioning obligations can represent a material, and frequently underestimated, component of asset value. In the UK, the Nuclear Liabilities Fund has seen estimated decommissioning costs nearly double since 2004. Across the global industry, the gap between pre-funded decommissioning reserves and total estimated obligations remains substantial. These are not theoretical risks. They are balance sheet exposures that affect credit ratings, transaction structures, and investor appetite.

Five components of the market

When decommissioning is approached as a market rather than a liability, five distinct commercial domains become visible. Each has its own supply chain, its own procurement logic, and its own set of organisations positioned to serve it.

• Strategy and programme planning. Before any physical work begins, an operator must make consequential decisions: which decommissioning strategy to adopt, how to sequence activities across a site or a fleet, how to structure the contracting model, and how to engage with regulators on the pathway to licence termination. These decisions have material cost consequences. An operator that optimises its decommissioning programme at the strategic level, rather than managing activities on a project-by-project basis, can significantly reduce total costs. Yet this is precisely the capability that is least well-served by the existing supply chain, which is predominantly oriented toward execution rather than planning.

• Engineering and dismantling contracting. The physical decommissioning work, reactor dismantling, contamination surveys, structural demolition, and site clearance, is delivered through large, long-duration contracts of the kind recently awarded at Sellafield. The market for these contracts is structurally oligopolistic: a small number of tier-one contractors have the nuclear-grade credentials, bonding capacity, and regulatory relationships to compete for major awards. The barriers to entry are high. The market opportunity for those inside the tier-one group is substantial.

• Radioactive waste management. Waste management is the most technically complex and commercially constrained element of decommissioning. The volume of radioactive material to be managed is large: at Sellafield alone, retrieving waste from legacy ponds and silos is a multi-decade programme requiring specialised robotics, remote handling systems, and processing capacity. Up to 90 percent of non-radioactive materials at a nuclear plant, metals, concrete, and process equipment, can be recycled and reused after clearance surveys, creating a secondary materials economy within the decommissioning process. The gap between waste arisings and available disposal routes remains a constraint in most jurisdictions, particularly for intermediate and high-level waste categories.

• Workforce planning and knowledge transfer. Decommissioning is a labour-intensive activity at a moment when the nuclear workforce is under structural pressure. Nearly 40 percent of the global nuclear workforce is expected to retire within the next decade. A March 2026 NSI report identified critical shortages in nuclear-qualified machinists, welders, inspectors, nondestructive examination specialists, and project managers, precisely the roles that decommissioning programmes require in volume. The workforce challenge in decommissioning is compounded by a knowledge transfer problem: the institutional memory of how a facility was built and operated, held by the people who built and operated it, must be captured before it is lost. This is not an HR function. It is a programme delivery risk.

• Site repurposing and community transition. What happens after a site is cleared is increasingly central to the planning and funding of decommissioning programmes. A decommissioned nuclear site is a piece of infrastructure, typically well-located, with existing grid connections, road access, and a history of managing complex industrial activities. The potential for reuse ranges from industrial parks to renewable energy installations to small modular reactor deployments. In Argentina, the Malargüe uranium processing complex, closed in 1986 and remediated over decades, was transformed into Parque El Mirador, a community green space co-designed with local residents. In the UK, Dounreay’s decommissioning programme has included comprehensive workforce retraining to stabilise the regional economy through the transition. The commercial question for site repurposing is not simply what the land is worth. It is who controls the planning process, how quickly regulatory oversight can be lifted, and whether the local authority and community have been engaged as partners rather than managed as stakeholders.

The five domains of decommissioning, strategy, contracting, waste, workforce, and site are each large enough to sustain a market. Together, they define a commercial ecosystem that the nuclear industry has only partially built.

What is structurally undersupplied

The physical execution capacity for nuclear decommissioning, from engineering contractors and specialist robotics companies to waste processing facilities, has developed significantly over the past two decades. Where the market remains thin is in the advisory and commercial structuring capability that enables programme owners to make better decisions about what to procure, how to sequence it, and how to structure the contracts through which they procure it.

Programme owners are often well-equipped to manage regulatory relationships and site operations. They are less consistently well-equipped to design and run sophisticated commercial procurement processes for multi-billion-pound, multi-decade programmes. The contracting models that best allocate risk between owner and contractor in a decommissioning context, where scope is uncertain, timescales are long, and cost estimation is inherently difficult, are not as well established as, say, contracts for new-build nuclear or offshore wind, which have become standardised through decades of transactional experience.

The workforce market also remains fragmented. The demand signal for decommissioning skills is growing, driven by the number of reactors entering the decommissioning process, the long duration of individual programmes, and competition for the same talent pool from new-build, life-extension, and advanced-reactor projects. But the planning and development of that workforce is rarely treated as a strategic function with its own investment logic. It is more often managed reactively, project by project, rather than as a sector-wide capability challenge requiring a coordinated response.

What the organisations doing it well are doing differently

The organisations capturing value in the decommissioning market share several characteristics that distinguish them from those that do not.

They plan at the programme level, not the project level. A utility managing a fleet of ageing reactors has more options available to it if it plans its decommissioning programme as a whole, sequencing sites, pooling procurement, standardising approaches, than if it treats each site as an independent problem. Fleet decommissioning programmes benefit from learning curve effects, shared contracting infrastructure, and the ability to develop and retain specialised workforce capability across multiple projects rather than building and dispersing it each time.

They invest in commercial structuring before contracting. The choice of contracting model whether to use target cost, fixed price, alliance, or framework arrangements has a larger impact on programme outcomes than most operators recognise at the point of procurement. The same physical scope, contracted differently, can produce radically different cost and schedule outcomes. Organisations that invest in commercial structuring expertise before they go to market are better positioned to design contracts that align contractor incentives with programme outcomes and that provide the flexibility needed to manage scope uncertainty over long delivery periods.

They treat site repurposing as a value driver, not an afterthought. Decommissioning costs can be substantially reduced when future site use is identified and planned early. A site being remediated to industrial brownfield standards rather than full greenfield has lower clean-up costs; a site with a credible reuse plan attracts stronger community engagement and reduced regulatory friction. The most effective decommissioning programmes embed site strategy from the outset, rather than treating it as something to be resolved after the technical work is done.

The window

The decommissioning market is in an early phase of maturation in some key countries. Even with Plant Life Extension, the volume of reactors entering the process will keep growing. The contract sizes are increasing. The regulatory frameworks governing decommissioning are, in most jurisdictions, evolving toward greater commercial sophistication in programme structuring and procurement. The workforce challenge is creating demand for new kinds of planning capability. And the question of what happens to nuclear sites after their operational lives is beginning to attract the attention of investors, local authorities, and energy planners who had not previously considered decommissioning their problem.

The organisations that will define the decommissioning market, as programme managers, commercial advisors, contracting specialists, and site developers, are making their moves now. The capital is beginning to follow. The supply chain is beginning to consolidate. The competitive positions that will matter in this market in 2035 are being established in 2025 and 2026.

$500 billion is a large number. What matters is who captures the value within it and how well they have prepared.

The post Decommissioning as a market appeared first on Damona | Strategy consulting | Nuclear industry.

The transactions driving this surge are structurally varied: technology acquisitions, operating asset purchases, life-extension deals, and strategic stakes in SMR developers. What they share is an accelerated pace that outruns the analytical capabilities most acquirers bring to the process.

Standard M&A due diligence is built around a set of assumptions that hold reasonably well for most industrial assets: that the financial statements capture the material liabilities, that auditing approach is too often procedural rather than substantive, that operational risk is bounded by the asset’s recent performance history, and that integration is primarily an organisational challenge. In nuclear, none of these assumptions is reliably true.

The question in any nuclear transaction is not just what an asset is worth. It is what obligations come with it, and whether the acquiring organisation has the capability to manage them. Most acquirers find out the answer to that second question after closing. This article sets out a framework for finding it before. 

Why the nuclear M&A moment creates analytical risk

The combination of factors driving nuclear M&A, rising electricity demand from data centres, energy security pressures, the return of policy support for nuclear in major OECD markets, and the entrance of new capital seeking exposure to the sector, is creating deal flow at a pace that the industry has not seen for decades.
Constellation Energy’s merger with Calpine created a combined entity of approximately $27 billion. BWX Technologies acquired Kinectrics for $525 million in January 2025. Across the advanced reactor sector, venture and private equity capital is transacting at record speed.

Deal velocity and analytical rigour are in tension. The due diligence processes that are becoming standard in other energy sectors (solar, wind, storage) have been refined by two decades of transaction experience and a relatively standardised set of risks. Nuclear due diligence does not have that foundation. The asset class is heterogeneous: operating reactors, decommissioning assets, technology companies, fuel cycle businesses, and service providers each presenting materially different risk profiles. The regulatory environment is jurisdiction-specific and non-transferable. And the liabilities, decommissioning obligations, spent fuel management costs, legacy workforce commitments, operate on timescales that sit outside the horizon of a standard investment thesis.

A 2025 analysis of global M&A due diligence trends found that due diligence exercises had become noticeably longer across all sectors, with record volumes of documents disclosed in data rooms and many potential transactions aborted as a result of matters uncovered during the process. In nuclear, the stakes of inadequate due diligence are higher than in most sectors, not only because the transactions are large, but because the liabilities that can be missed are not bounded by the size of the deal.

Three categories of risk that generic frameworks miss

The failure modes in nuclear due diligence cluster around three categories of risk that standard M&A analytical frameworks are structurally ill-equipped to assess.

Regulatory risk
Nuclear licence transfer is not a procedural step. In the United States, the NRC has reviewed more than 115 licence transfer applications since 1999, and its review focuses substantively on the financial qualifications of the acquirer and the adequacy of its decommissioning funding arrangements. The transfer process involves regulators assessing whether the incoming owner has the financial and operational capacity to meet the obligations that attach to the licence, not merely whether the transaction is commercially structured. This means that a technically sound deal can fail at the regulatory stage if the acquirer cannot demonstrate sufficient technical capability or financial depth. In jurisdictions outside the US, the regulatory transfer pathway varies significantly in scope, timeline, and outcome certainty, adding a layer of cross-border complexity that generic deal structures are not designed to absorb.

Liability risk
The liabilities attached to nuclear assets are large, long-duration, and frequently underestimated at the point of acquisition. The US Nuclear Regulatory Commission estimates that decommissioning a single reactor costs between $280 million and $612 million. Across the US fleet, decommissioning trust funds hold approximately $100 billion — but an estimated $9 billion of unfunded liability remains, to be collected over the remaining operating lives of approximately 100 reactors. In the UK, the estimated cleanup cost of legacy nuclear facilities ranges from £99 billion to £232 billion, with a best discounted estimate of £131 billion.

Spent fuel obligations are a separate and compounding variable. In the United States, the Department of Energy’s estimated liability for its failure to accept and dispose of commercial spent fuel reached $56.5 billion in 2025, growing as the national inventory increases by approximately 2,000 metric tons per year. For an acquirer of an operating nuclear asset, the spent fuel management obligation is a long-duration cost that does not appear on the asset’s income statement and is frequently underweighted in standard financial modelling.

Operational risk
The performance of a nuclear asset is inseparable from the capability of the organisation that operates it. Safety culture, workforce depth, maintenance regime, regulatory relationship, and the institutional knowledge embedded in the operating team are not visible in financial statements and do not transfer automatically with the asset. The operating licence is held by the licensee, not the asset, and the regulator’s assessment of licence holder capability is ongoing. An acquirer that does not assess operational capability as rigorously as financial performance is acquiring an asset it cannot reliably value.

Three lenses. One integrated view.

A rigorous nuclear due diligence framework requires three analytical lenses to be applied concurrently, not sequentially. The sequential model, financial analysis first, operational assessment second, strategic fit review third, is the standard approach in most M&A processes. In nuclear, it is inadequate, because the three dimensions are interdependent in ways that sequencing does not reveal.

Financial analysis through a nuclear-specific lens
Financial due diligence in nuclear must extend beyond the standard scope of revenue, cost, and balance sheet analysis to encompass: the funded status and actuarial assumptions of decommissioning trust funds; the cost basis and projected future costs of spent fuel management; the financial qualification requirements of the jurisdiction’s regulatory licence transfer process; and the relationship between asset performance history and the regulatory cost basis on which future revenue will be determined. Each of these elements requires specialist input that is not available in a standard financial due diligence team.

Operational assessment
The operational assessment must address questions that do not appear in standard technical due diligence:
What is the safety culture of the operating organisation, and how does the regulator assess it?
What is the depth and age profile of the workforce, and what loss of knowledge risk exists?
What is the maintenance backlog, and how does it compare to industry benchmarks?
What are the current and projected regulatory compliance costs?
How does the asset’s performance compare to peer facilities in the same jurisdiction?
These questions require nuclear operational expertise that most M&A advisory teams do not carry.

Strategic fit evaluation
The strategic rationale for a nuclear acquisition, whether it is clean electricity offtake, technology access, service market position, or geographic expansion, must be tested against the integration requirements that the acquisition imposes.
Can the acquiring organisation absorb the regulatory obligations? Does it have the operational capability to manage a nuclear licence? Is the integration timeline consistent with the regulatory process? Does the acquirer’s existing portfolio create any regulatory concentration risk? Strategic fit in nuclear is not only a question of commercial logic. It is a question of whether the acquiring organisation can become a responsible nuclear operator.

The integration question as a threshold condition

The most consequential due diligence question in any nuclear transaction is one that most acquirers ask too late: does our organisation have the capability to manage what we are about to own?

This is not a question about management bandwidth or integration resource. It is a question about whether the acquiring organisation can operate a nuclear facility in compliance with its licence, in a relationship with a regulator that will assess that compliance continuously, with a workforce whose institutional knowledge must be preserved through a change of ownership, and against a liability profile that will remain with the asset for decades after the transaction closes.

Regulators in most nuclear jurisdictions assess this question explicitly. The NRC’s licence transfer review considers whether the incoming owner has the financial qualifications and organisational capability to assume the responsibilities of a nuclear licensee. An acquirer that cannot answer this question credibly to the regulator will not complete the transaction regardless of how well-structured its commercial terms are.

The most successful nuclear acquirers in the current transaction wave share a characteristic that distinguishes them from unsuccessful bidders: they build their operational capability assessment in parallel with their financial due diligence, and they use that assessment both to inform their valuation and to design their post-closing integration plan before the transaction completes.

What rigorous nuclear due diligence looks like in practice

Translating the three-lens framework into a due diligence process requires structural choices that most M&A processes do not make by default.

Nuclear-specific expertise must be embedded in the core deal team, not retained as an external specialist function consulted only on discrete questions. The interdependence of the financial, operational, and regulatory dimensions means that insights from one lens must continuously inform the others. A finding in the operational assessment about workforce age profile changes the actuarial assumptions in the decommissioning liability model. A finding in the regulatory assessment about the jurisdiction’s spent fuel policy changes the financial provision calculation. These interactions cannot be captured by sequential review.

The due diligence scope must extend beyond the asset to include the regulatory relationship. Understanding how the regulator views the current licensee, its compliance history, its safety culture assessments, its outstanding regulatory commitments, is essential to assessing both the licence transfer risk and the post-closing operational challenge. This information is not in the data room. It requires direct engagement with public regulatory records, inspection reports, and enforcement histories that are available but require specialist interpretation.

The integration plan must be designed before closing, not after it. The period between signing and closing in a nuclear transaction is not a period of commercial continuity. It is a period when the regulatory transfer process is underway, the workforce is aware of the change in ownership, and the asset’s operational risk is at its highest. Acquirers that arrive at closing without a detailed operational integration plan, covering workforce retention, regulatory relationship management, and the first hundred days of new ownership, are taking a risk that the financial modelling has not priced.

The standard that nuclear transactions require

The surge in nuclear M&A activity is a rational response to a genuine market opportunity: assets that generate firm, dispatchable, low-carbon electricity at a time when that combination is increasingly scarce and valuable. The transactions are commercially sound. The due diligence frameworks being applied to them frequently are not.

Nuclear assets are not simply industrial assets with additional regulatory requirements. They are operating systems with long-duration liabilities, continuous regulatory oversight, and performance characteristics inseparable from the capabilities of the organisation that manages them. Generic M&A due diligence is not designed to assess these characteristics reliably.

The organisations that will create durable value in nuclear M&A are those that recognise this distinction early,  and build the analytical capability to close it before they close the deal.

The post What nuclear due diligence actually requires appeared first on Damona | Strategy consulting | Nuclear industry.

On June 11, 2025, the World Bank lifted its longstanding prohibition on nuclear project financing, which had been in place since 2013.  The same week, Microsoft’s 20-year power purchase agreement with Constellation Energy to restart Three Mile Island was progressing toward its 2028 completion target. Amazon’s data centres in Virginia were drawing on 1,920 megawatts of nuclear output from the Susquehanna plant. Google had signed the first corporate SMR fleet deal in history with Kairos Power.

And yet, in project development offices and government ministries across Europe, North America, and emerging nuclear markets, the approach to capital markets has not changed materially since the previous build cycle ended. The pitch decks tell a technology story. The risk allocation follows a model that has already destroyed two major developers. The financing structure assumes a type of capital that no longer dominates the market.

So what does the new nuclear capital stack actually look like? What has changed, which instruments are now available? Are developers, vendors, and governments taking the right approach when trying to attract it?

The scale of the shift

Nuclear investment has not merely recovered. It has been structurally repositioned. The IEA’s World Energy Investment 2026 report projected global nuclear capital flows to surpass $80 billion in 2025, roughly double the 2018 low, driven by new-build programmes, life-extension investments, and advanced-reactor development.

The composition of that capital has changed as much as its volume. A decade ago, nuclear financing was predominantly public: government balance sheets, state utilities, and bilateral development finance for export programmes. The private sector was largely absent. Today it is present in forms that would have seemed implausible in 2015.

Big technology companies have emerged as one of the most consequential new sources of capital in the sector. Over the twelve months to mid-2026, major technology companies signed contracts representing more than 10 gigawatts of possible new nuclear capacity in the United States. Microsoft committed to a 20-year PPA with Constellation Energy for the restart of Three Mile Island Unit 1. Amazon signed an agreement for 1,920 megawatts of output from the Susquehanna nuclear plant to power its AWS data centres and invested $500 million in X-Energy’s SMR programme. Google signed the first corporate SMR fleet deal, securing 500 megawatts from Kairos Power. Meta issued a request for proposals for one to four gigawatts of new nuclear generation and has awarded Oklo, TerraPower and Vistra – in addition to Constellation previously.

The development finance community has undergone a parallel recalibration. The World Bank’s June 2025 policy reversal was the most visible signal, but it is part of a broader pattern of multilateral institutions revisiting prohibitions that were adopted in a different energy policy environment. The Bank’s new framework explicitly supports SMR deployment, reactor life-extension programmes, and regulatory capacity building in emerging markets.

In the advanced reactor sector, private capital has accelerated sharply. Between 2020 and 2025, advanced reactor technologies secured $3.9 billion in funding. TerraPower, developing a sodium-cooled fast reactor in Wyoming, closed a $650 million Series C in June 2025, backed by Bill Gates and NVIDIA’s venture arm. In the final quarter of 2025 alone, nuclear startups raised more than $1 billion in a five-week period.

Three instruments that are reshaping the capital stack

The volume of capital moving toward nuclear is one part of the story. The more consequential change is structural: the instruments through which nuclear programmes are being financed have diversified significantly, and the logic of risk allocation underpinning them has shifted. Three instruments deserve particular attention.

The Regulated Asset Base (RAB) model. The most significant structural innovation in nuclear project finance over the past decade is the RAB model, first applied in the UK for large infrastructure projects and now being used for Sizewell C. Under the conventional Contracts for Difference (CfD) framework, the developer finances construction and begins receiving revenue only when the plant generates electricity, meaning all construction risk sits on the project company and its lenders. The cost of capital under this structure has been estimated at approximately two-thirds of the overall project cost.

The RAB model distributes risk differently: consumers contribute a regulated levy during construction, reducing the burden on the project’s debt stack and substantially lowering the cost of capital. The UK government estimates that the RAB approach for Sizewell C could save consumers £30 billion over the project’s life compared to a CfD structure, not because the plant is cheaper to build, but because it is cheaper to finance. Sizewell C reached financial close in November 2025 with a £38 billion financing package including £5 billion in export credit-backed debt from 13 banks, equity from the UK National Wealth Fund, and an investment-grade credit rating.

Export credit agency financing. Export credit agencies have become a defining feature of competitive nuclear deal structures in international markets. France’s Bpifrance provided the anchor export credit facility for Sizewell C. The US Export-Import Bank approved a $98 million loan to support a front-end engineering and design study for a US SMR export project in Romania, as part of a broader strategy to counter Russian and Chinese state-backed nuclear finance in emerging markets. South Korea’s KEXIM has been similarly active in supporting APR1400 exports, most notably through the Barakah project in the UAE. The competition among nuclear-exporting nations- the US, France, South Korea, Russia, China – is now as much a competition over financing terms as it is over technology or regulatory pathways.

Technology offtake as credit support. The most structurally novel development is the use of long-term power purchase agreements from creditworthy technology companies as the anchor offtake underpinning project finance debt. A 20-year PPA with an investment-grade counterparty provides the revenue certainty that project finance lenders require to underwrite construction risk. This mechanism, standard in renewable energy project finance for two decades, is now being applied to nuclear for the first time at scale. It is not a solution for all nuclear programmes, but it has materially changed the financing logic for both operating plant acquisitions and new-build in markets with data-centre demand.

What developers are still getting wrong

Against this backdrop of genuine structural change, the gap between what the capital market now offers and how most nuclear developers approach it remains wide. Three persistent failures stand out.

Telling a technology story instead of a commercial story. The dominant mode of presenting nuclear projects to investors and lenders remains technology-centric: reactor design, fuel cycle, safety case, regulatory status. These are necessary but not sufficient. What capital allocators need to assess is a commercial story: who is the offtaker, what is the revenue structure, how is construction risk allocated, what is the exit? Most nuclear pitch decks are engineering documents with financial appendices. The most successful recent capital raises, TerraPower’s Series C, the Amazon-Talen transaction, the Sizewell C financing, are defined by their commercial architecture, not their technology specification.

Misallocating risk across the capital stack. The failure of the fixed-price EPC model at Vogtle and V.C. Summer demonstrated the consequences of concentrating construction risk in a single contractor. The lesson has been partially absorbed: Sizewell C’s financing structure deliberately distributes risk across consumers, the state, export credit agencies, and commercial lenders. But many programmes in development, particularly in Europe and emerging markets, continue to propose structures that aggregate risk in ways that no private lender will absorb at a viable cost of capital. The result is a financing gap that cannot be bridged by optimism about future cost reductions.

Failing to differentiate in a crowded market. The expansion of the advanced reactor development pipeline has created a differentiation problem. Dozens of programmes are making broadly similar value propositions, clean, firm, dispatchable, to the same pool of institutional and venture capital. In the absence of operational data, capital has tended to consolidate around programmes with credible near-term deployment pathways, strong sponsor balance sheets, and anchor offtake. Programmes that cannot demonstrate at least two of these three characteristics are finding the capital market unreceptive, regardless of the quality of the underlying technology.

What the right approach looks like

The nuclear programmes that have successfully raised capital in the current environment share a set of structural characteristics that are instructive for developers at earlier stages.

They separate development risk, construction risk, and operational risk, and match each to the appropriate capital type. Development-stage risk, which is highest and most binary, attracts equity from sponsors, governments, and strategic investors. Construction risk, which is the primary source of cost overruns in nuclear history, is distributed across ECA facilities, regulated mechanisms, and consumer contributions where available. Operational risk, which is the most predictable phase of a nuclear project’s life, supports long-term project finance debt and institutional bond-market instruments.

They build the revenue story before they build the financing structure. The Constellation-Microsoft transaction worked because the commercial logic preceded the financing. The PPA created offtake certainty, allowing Constellation to finance the restart of Three Mile Island with a conventional debt-equity structure. Developers seeking to attract institutional debt without a credible offtake arrangement are, in the current market, asking lenders to take a risk that the technology sector has shown is transferable to creditworthy counterparties.

They engage export credit agencies as strategic partners, not as lenders of last resort. The ECA market is competitive. France, the US, South Korea, and others are actively seeking transactions that demonstrate the commercial viability of their respective nuclear export programmes. Developers with the right geographic and technological profile can use ECA engagement to anchor their financing structure, reduce their cost of capital, and signal to commercial lenders that the project’s sovereign risk dimension is managed.

Finally, they invest in owner capability alongside the capital story. A financing structure is only as credible as the organisation that will execute against it. Lenders and equity investors in the current environment are conducting rigorous assessments of owner capability, the technical teams, the programme management systems, the supply chain relationships that will determine whether the construction schedule on which the financial model depends is deliverable. The programmes that struggle to close their financing are often those in which the commercial architecture is sound, but the owner organisation cannot demonstrate it can build what it proposes to finance.

The window is open, but not indefinitely

The conditions that have brought institutional capital back to nuclear energy are a function of a specific moment: rising electricity demand from data centres and electrification, geopolitical pressure on energy security, a decade of renewable energy finance experience that has trained capital markets to underwrite infrastructure risk. These conditions may persist for a decade or more. They will not persist forever, and the competitive dynamics among nuclear-exporting nations mean that programmes that fail to close financing in the current cycle may find the next window has a different set of terms.

The capital is available. The instruments are more sophisticated than they have ever been. The remaining gap is not financial. It is the gap between how nuclear programmes have historically presented themselves to capital markets and what those markets now require.

Closing that gap is not a technical problem. It is a strategic one.

The post Nuclear financing in the new era appeared first on Damona | Strategy consulting | Nuclear industry.

The conventional explanation for nuclear power’s cost and schedule failures runs roughly as follows: nuclear is uniquely complex, burdened by regulation, politically contested in some regions, and too capital-intensive for private markets to bear. The implication is that the solution lies in regulatory simplification, public financing, and political will.

This explanation is not wrong. But it feels incomplete and obscures the more actionable diagnosis.

Aerospace and defence programmes operate under comparable technical complexity, comparable regulatory scrutiny, and, in the case of military systems, far greater political sensitivity. Yet the best-performing aerospace programmes consistently deliver at a level that the nuclear industry, at least in the West, has failed to match for decades. For instance, in France, Naval Group is expected to deliver the sixth and final Barracuda-class nuclear attack submarine to the Marine nationale in 2029, approximately one year ahead of its contracted 2030 schedule. A nuclear submarine programme, delivering early.

The difference is not primarily technical but structural. It lies in how contracts are written, how risks are allocated, how supply chains are designed, and how owner capability is built and maintained throughout the life of a programme. All to say, how project delivery is designed.

These are procurement architecture questions. And the nuclear industry might not have asked all the relevant ones.

The scale of a systemic problem

The data on Western nuclear construction performance is well-documented, but the pattern bears restating because it is so consistent.

The Flamanville EPR in France began construction in 2007 with an estimated cost of €3.3 billion and a four-year build timeline. By the time the reactor approached commercial operation, the cost had exceeded €13 billion, and the project was almost fifteen years late.

In Finland, the Olkiluoto 3 EPR was originally budgeted at €3.2 billion. The final cost exceeded €11 billion, a 3.7-fold increase, and the reactor came online thirteen years behind schedule. The project ended in multibillion-euro litigation between the Finnish utility TVO and contractor Areva over responsibility for the overruns.

In the United States, the Vogtle expansion in Georgia was contracted at an estimated $14 billion for two AP1000 reactors. The final cost exceeded $25 billion,  nearly double the estimate,  with the project running six years behind schedule. The overruns were so severe that Westinghouse Electric, the world’s leading nuclear technology vendor, filed for bankruptcy in 2017 after being unable to absorb losses from its fixed-price construction contract.

In the United Kingdom, Hinkley Point C was approved in 2016 with an estimated cost of £18 billion. By 2026, current price estimates had risen to approximately £48 billion, with the first unit not expected to generate power until 2030 at the earliest.

These are not isolated failures attributable to bad luck or unique local conditions.
They are the consistent output of a particular procurement architecture and constrained project delivery.

An inconvenient comparison

The instinctive objection to comparing nuclear with aerospace is that aerospace programmes also overrun. The F-35 Joint Strike Fighter, one of the most expensive weapons programme in history, saw its total acquisition cost rise from an initial estimate of $233 billion to over $485 billion by 2023, with the programme running more than a decade behind schedule.

The objection is valid as far as it goes. But it obscures the more illuminating comparison.

The F-35 is a cutting-edge fifth-generation combat aircraft developed over four decades in parallel with the operational doctrine it is meant to enable.
A nuclear power station, by contrast, is a large civil infrastructure project built around reactor designs that have been in commercial operation for decades. The physics has not changed. The regulatory framework, while demanding and being more stringent following the Fukushima accident, is not new. The argument that nuclear is simply “too complex to deliver reliably” collapses when one examines South Korea’s record.

South Korea has been building nuclear reactors sequentially since the 1970s. Its domestic APR1400 units have been constructed at an overnight cost of approximately $2,300 per kilowatt, roughly a quarter of the cost per kilowatt at Vogtle. The four-unit Barakah project in the UAE, built by a South Korean-led consortium, demonstrated learning rates that Western programmes cannot approach: Unit 4 reportedly cost around 40% of what Unit 1 cost, reflecting the compounding effect of building the same design with the same workforce in sequence.

The variable that separates South Korea from the West is not technical capability or regulatory environment. It is programme architecture: standardised design, a stable supply chain, a contractor with genuine serial construction experience, and an owner that maintains deep technical capability throughout.

The contract structure and project delivery problem

The most consequential design choice in any major nuclear programme is the contract structure and how project delivery is designed; and Western nuclear has persistently made the wrong one.

The lump-sum turnkey or fixed-price EPC model transfers virtually all construction risk from the project owner to the contractor in exchange for cost certainty. In theory, this protects the owner.
In practice, for projects as complex and first-of-a-kind as the EPR or AP1000, it has produced a sequence of contractor bankruptcies, protracted litigation, and projects stranded mid-construction.

The mechanism is straightforward. A contractor bidding a fixed price on a novel, highly complex project must either embed massive risk contingencies, making the bid uncompetitive, or underbid and absorb losses as complexity materialises.
The incentive structure is perverse: contractors have every reason to bid low to win work, and every reason to fight over variations rather than solve problems. Areva’s fixed-price contract at Olkiluoto ended in years of litigation with TVO. Westinghouse’s fixed-price contracts at Vogtle and V.C. Summer bankrupted the company.

The White & Case analysis of major energy procurement is unambiguous on this point: there is now “a growing reluctance among contractors to sign up to EPC contracts on a lump-sum turnkey basis”, given the complexity of modern energy projects. The legal and commercial framework that was supposed to provide certainty delivered the opposite.

Aerospace and defence procurement has, by necessity and hard experience, developed more sophisticated approaches. Development risk and production risk are typically separated. Incentive fee structures align contractor reward with delivery outcomes rather than variation claims.
The owner maintains sufficient technical capability to manage the scope and validate contractor performance.
Where fixed-price elements exist, they are applied to well-defined, lower-risk work, not to the totality of a novel, first-of-a-kind programme.

The UK’s emerging approach for future nuclear projects, including the Regulated Asset Base model for Sizewell C and alliance contracting models being explored for AMR programmes, represents a belated recognition that the LSTK model cannot work for novel, complex infrastructure. The transition is happening. It is happening more slowly than it should.

Supply chains designed for accountability

The aerospace industry organises its supply chain through a tiered structure in which accountability is explicit and traceable at every level. Tier 1 suppliers, like large integrators working directly with the OEM, are responsible for the performance and quality of their own supply base. Tier 2 suppliers are held to clear specifications by their Tier 1 customers. Traceability, quality management, and regulatory compliance flow up and down the chain.

Nuclear procurement has historically pursued a different objective: lowest cost.
The result is a supply chain in which nuclear quality assurance requirements are sparsely met, certified suppliers are few, and accountability for quality failures is diffuse.
Counterfeit or substandard components have entered reactor supply chains from manufacturers insufficiently subject to nuclear-grade inspection regimes.

The deeper problem is that lowest-cost procurement in a sector with sparse NQA-certified suppliers does not actually deliver lowest cost. It delivers deferred cost in the form of rework, inspection failures, and regulatory hold-ups. NQA requirements are associated with significant cost escalation when applied without sufficient clarity or experience, but the alternative, inadequately qualifying suppliers, results in a different, less controllable form of cost escalation.

Redesigning nuclear supply chains for accountability rather than lowest cost means developing a smaller number of deeply qualified suppliers with genuine programme relationships, applying tiered accountability logic, and maintaining owner visibility into supply chain performance rather than delegating it entirely to the prime contractor.

The owner’s capability problem

Perhaps the most underappreciated factor in Western nuclear construction failures is the erosion of owner capability.

In the decades between the last Western new build programmes and the current generation of projects, nuclear utilities lost, through retirement, restructuring, and institutional neglect, most of the in-house capability needed to manage the delivery of a major nuclear project. The IAEA has identified knowledge management and expertise retention as among the most critical challenges facing the sector, noting that new recruits can fill vacant seats but “cannot replace lost knowledge” accumulated over decades of operational experience.

The consequences materialised with particular clarity at Vogtle. When Westinghouse’s bankruptcy forced the project owners, Georgia Power and its co-owners, to take over direct management of the construction programme, they were responsible for managing a massively complex project for which they were, as observers noted at the time, fundamentally “ill-prepared”. The owner’s technical capability had atrophied during the years when nuclear construction had seemed like someone else’s problem.

The contrast with aerospace and defence procurement is instructive. The government customer maintains dedicated technical teams, integrated project teams, programme offices, and technical authorities throughout the life of a programme.
The UK established a dedicated Submarine Delivery Agency in 2018 precisely to create an enduring owner capability function for its submarine programme, with an explicit mandate to develop and retain the expertise needed to manage complex, long-duration delivery.

The principle is clear: the owner’s technical authority is not optional overhead. It is the mechanism by which the procurement can be managed at all. Nuclear new build programmes require this principle to be applied consistently, building and sustaining integrated owner teams with genuine technical depth from pre-FEED through construction and commissioning, not deploying a programme management office at contract signature and hoping for the best.

The serial build imperative

The final lesson from aerospace and from South Korea is the discipline of serial construction.

Aerospace’s most successful programmes achieve cost reduction and schedule reliability through the systematic application of learning rates: the same design, the same processes, the same supplier relationships, repeated and refined across successive production runs. Complex, technically demanding systems can be built reliably at scale when the programme architecture supports learning rather than constantly restarting from scratch.

Western nuclear has done the opposite. Every new build project in recent decades has been, in important respects, a first-of-a-kind effort: a new site, a modified design, a reconstituted supply chain, a fresh contractor team. Accumulated learning from one project is not systematically transferred to the next. MIT research on nuclear construction costs estimates that the overnight cost of the nth AP1000 unit, after ten to twenty builds, could converge to less than half the cost of the first unit.

South Korea’s reported cost per kilowatt for domestic units is the result of building the same design, with the same team, multiple times. Unit 4 at Barakah demonstrably benefited from three prior builds on the same site; the learning rate was real and measurable.

The implication for nuclear policy is uncomfortable: a fleet strategy is not merely a preference but an economic and operational necessity. Individual bespoke projects, each treated as unique, will continue to perform the way Western nuclear has performed. Programmes structured for serialisation, standardised designs, committed pipelines, and continuity of the contractor and supply chain will perform as South Korea has.

What needs to change

The nuclear industry’s cost and schedule failures are not a mystery.
They are the predictable output of a particular set of procurement choices: contracts that transfer risk to contractors who cannot bear it; supply chains organised for lowest cost rather than accountability; owner organisations that have allowed their technical capability to atrophy; and programmes structured as one-off events rather than the first unit in a series.

None of these problems is technical. All of them are tractable. The aerospace and defence sector has, through decades of expensive experience, developed approaches to each of them, not perfectly, but substantially better than current nuclear industry practice.

The current pipeline of Western nuclear projects, EPR2 in France, Sizewell C in the UK, the emerging SMR programmes across Europe and North America,  offers a genuine opportunity to apply these lessons before they are learned again at enormous cost.

The programme’s architecture determines its outcome. Getting the procurement right is not a detail. It is the work.

The post What nuclear procurement and project delivery can learn from aerospace appeared first on Damona | Strategy consulting | Nuclear industry.

The nuclear industry has spent the past decade focused on technology.

Reactor designs, safety systems, fuel types, modular construction methods, passive cooling architectures, the engineering conversation around Small Modular Reactors has become increasingly sophisticated and increasingly crowded. While over 80 SMR designs and concepts are currently under development worldwide, the commercial conversation has not kept pace.

How SMRs will actually be financed, contracted, deployed, and scaled remains one of the least resolved questions in the market today. That gap, between technological ambition and commercial architecture, is rapidly becoming the defining challenge of the sector.

The reality is straightforward: an SMR does not become economically transformative simply because it is smaller. It becomes transformative only if it can be deployed repeatedly, predictably, and at industrial scale.

And today, the market structure required to achieve that scale is still largely missing.

Why SMR economics work differently

The economic logic behind SMRs is frequently misunderstood.

Smaller reactors are not inherently cheaper on a per-megawatt basis. In many cases, first-of-a-kind SMRs are expected to be more expensive than large conventional reactors when measured against installed capacity.

What changes the equation is repetition.

The commercial promise of SMRs is built on the same industrial logic that transformed sectors such as commercial aviation and offshore wind: factory manufacturing, standardised designs, serial production, and learning curve effects generated across fleets rather than individual projects.

The OECD Nuclear Energy Agency has repeatedly highlighted this dynamic in its work on SMR deployment pathways. The competitiveness of SMRs depends fundamentally on volume. The difference between a first-of-a-kind unit and a fleet-deployed nth-of-a-kind reactor is not marginal but structural.

This has major implications for deployment strategy.

An SMR developed as a one-off infrastructure project, however technically credible, is unlikely to achieve the economics that justify the model in the first place. The commercial viability of SMRs depends on repeatability, manufacturing continuity, and deployment pipelines large enough to drive cost reductions over time.

The challenge is that current procurement and financing structures are still largely designed around traditional project-by-project nuclear development.

The NuScale lesson

The clearest illustration of this challenge remains the 2023 cancellation of NuScale’s Carbon Free Power Project in the United States.

The project was the most advanced SMR programme in the Western market and the first SMR design to receive approval from the US Nuclear Regulatory Commission. Technically, it represented a major milestone for the industry.

Commercially, it exposed the fragility of the current model.

The project had been structured around a subscriber framework in which a group of municipal utilities would collectively purchase electricity output under long-term agreements. As development costs increased, rising from initial estimates of approximately $5.3 billion to roughly $9.3 billion at the time of cancellation, participating utilities progressively withdrew from the project.

Ultimately, the issue was not reactor performance but cost absorption.

The commercial structure was unable to manage the uncertainty associated with the economics of first-of-a-kind deployment. By the time the project was cancelled, 23 of the original 35 subscriber utilities had exited.

The lesson was significant precisely because NuScale was one of the industry’s most mature programmes. It demonstrated that even a technically credible, regulatory-approved SMR can fail commercially if the deployment model does not adequately distribute FOAK risk.

The structural Catch-22

This reveals the central contradiction at the heart of the SMR market.

SMRs require scale to become economically competitive. But the conditions required to achieve that scale, lower costs, established supply chains, and proven operational performance, only emerge after scale already exists.

Every industrial technology faces some version of this problem. SMRs face it at nuclear scale.

The combination of high capital needs, long development timelines, and highly risk-sensitive customers creates a difficult commercial environment for early deployment. Utilities and governments generally prefer proven technologies with predictable cost structures. Yet the economics of SMRs improve only after repeated deployment has already taken place.

The result is a market where almost every stakeholder believes in the long-term potential, but relatively few are positioned to absorb the commercial premium associated with being first.

Without mechanisms capable of distributing that early-stage risk, deployment stalls precisely when commercial momentum is most important.

The commercial architecture is the real product

This is why the future of SMRs may depend less on reactor innovation alone and more on commercial architecture.

Fleet deployment models are central to this shift. Developers need deployment pipelines that span multiple units and sites, allowing manufacturing investment, supply chain development, and learning-curve efficiencies to compound over time. The economics of serial production cannot emerge from isolated procurement decisions.

At the same time, a new category of customer is beginning to reshape the market.

Large technology companies and hyperscalers are increasingly emerging as long-term nuclear counterparties, seeking stable, low-carbon electricity supply for data centres and digital infrastructure. Microsoft’s agreement linked to the restart of Three Mile Island and Amazon’s nuclear-related energy partnerships, and broader hyperscaler interest in advanced nuclear are important not only because of the electricity demand involved, but because they introduce highly creditworthy, long-duration customers capable of underwriting deployment risk in ways traditional utility procurement often cannot.

Government participation also remains essential.

The UK’s shift from the Contract for Difference model used for Hinkley Point C towards a RAB approach for Sizewell C reflects a broader recognition that financing structures matter as much as technology. By reducing financing costs and sharing construction risk more effectively, the RAB model seeks to address one of the fundamental barriers facing large-scale nuclear investment.

Similar mechanisms adapted to the realities of SMR deployment, including FOAK risk-sharing frameworks, revenue stabilisation mechanisms, and public-private financing partnerships, are likely to play a critical role in enabling early projects and building the foundations for future fleet deployment.

At the same time, supply chains themselves require forward visibility. Qualified manufacturers, specialised components, and skilled labour pools do not appear automatically once orders are signed. They require investment well in advance of demand. Without credible deployment pipelines, industrial capacity will remain constrained regardless of reactor readiness.

In other words, the challenge is no longer simply technological but also industrial and financial.

From engineering challenge to market design challenge

Political momentum around nuclear is clearly accelerating.

At COP28, 31 countries endorsed the goal of tripling nuclear capacity by 2050. SMR programmes are advancing across the United States, Canada, the United Kingdom, Central Europe, and the Gulf.

But political support alone does not create commercially viable deployment models.

The industry risks repeating a familiar pattern: developing technically credible reactors, attracting early-stage enthusiasm, and then struggling at the point where commercial deployment requires stable procurement frameworks, long-term financing structures, and coordinated industrial planning.

The next phase of the SMR market will not be defined solely by reactor performance.
It will be defined by whether the industry can build commercial structures capable of supporting serial deployment at scale.

Because the central challenge facing SMRs is no longer purely an engineering challenge.

It is increasingly a market design challenge.

The post The SMR commercial model problem appeared first on Damona | Strategy consulting | Nuclear industry.

Wind, solar, and storage dominate the public conversation around the energy transition. They attract the majority of political attention, investment flows, and infrastructure planning.

They are necessary. They are not sufficient. Because electricity is only part of the challenge.

Heat, the energy used to forge steel, fire cement kilns, refine chemicals, and process industrial feedstocks, accounts for nearly half of global final energy consumption, according to the International Energy Agency. In industry specifically, heat remains the dominant energy input, and the vast majority of it is still generated by burning fossil fuels directly.

This is one of the most structurally difficult problems in the energy transition. And it is one that nuclear may be uniquely positioned to help solve.

Industrial decarbonization has a heat problem

Industry remains the largest source of direct carbon emissions globally, accounting for approximately 37% of total CO₂ emissions when direct combustion and indirect electricity-related emissions are combined.

Within that total, a small number of sectors drive a disproportionate share of the challenge.

Steel production alone contributes roughly 7% of global CO₂ emissions, with blast furnace processes requiring temperatures above 1,000°C. Cement production typically requires kiln temperatures of 1,400–1,500°C and generates unavoidable process emissions from limestone calcination. Chemical manufacturing spans a wide range of heat-intensive applications, many of which require continuous, high-temperature energy across highly integrated process chains.

These are not peripheral sectors. They are foundational to the global economy — and among the hardest to decarbonize.

Why existing pathways leave a gap

Most industrial decarbonization strategies currently rely on three pathways: electrification, hydrogen, and carbon capture.

Each has a role to play. None fully solve the heat challenge on their own.

Direct electrification is effective for lower-temperature industrial applications and will remain an important part of the transition. But for many continuous, high-temperature processes, scaling electric heat economically remains challenging.

Green hydrogen holds significant long-term promise, particularly in steelmaking and chemicals. Yet cost, infrastructure requirements, electrolyser deployment, and renewable power availability continue to constrain large-scale deployment. For many industrial operators, hydrogen remains a medium- to long-term pathway rather than an immediate solution.

Carbon capture can reduce emissions from existing fossil-fired processes, but it does not eliminate dependence on combustible fuels. It reduces the carbon intensity of the system without fundamentally changing its underlying energy architecture.

The result is a persistent gap in the industrial decarbonization toolkit:
a shortage of scalable, clean, continuous high-temperature heat solutions.

Why nuclear deserves greater attention

Nuclear reactors produce heat first and electricity second. That matters.

Conventional light water reactors already generate steam at approximately 300°C, suitable for district heating and a range of lower-temperature industrial applications. But the more significant strategic opportunity lies in advanced reactor technologies designed specifically for higher-temperature output.

High-Temperature Gas-cooled Reactors and Very High Temperature Reactors are designed to deliver outlet temperatures in the 700–950°C range, making them relevant for a far broader range of industrial applications. At the upper end of that spectrum, they also enable more efficient hydrogen production pathways than conventional electrolysis.

This is not theoretical physics but an engineering and deployment challenge.

Nuclear process heat has already been demonstrated across multiple non-electric applications, and high-temperature industrial integration is increasingly moving from conceptual design toward commercial demonstration.

The market is beginning to move

Momentum is building.

China’s HTR-PM at Shidaowan became the world’s first commercial high-temperature gas-cooled reactor in 2023, establishing a critical proof point for advanced nuclear heat technologies. In the United States, the Department of Energy’s Industrial Decarbonization Roadmap identifies advanced nuclear as a strategic option for industrial heat supply, while national laboratories continue developing integration models for nuclear-industrial thermal systems.

At the same time, several advanced reactor developers such as Jimmy are explicitly designing their commercial offerings around industrial heat applications rather than grid-only electricity supply.

The emerging model is clear:
co-located nuclear and industrial assets, linked through long-term thermal offtake arrangements.

For industrial operators, this creates the possibility of securing stable, low-carbon heat directly at source while reducing exposure to grid congestion, transmission losses, and power market volatility.

Why this matters strategically

For many industrial operators, energy is not just an emissions issue. It is a competitiveness issue.

Steel, cement, and chemicals are globally traded commodities produced in margin-sensitive environments. Energy price volatility directly impacts operating margins and long-term investment decisions.

The European energy crisis of 2022–2023 exposed the vulnerability of industrial sectors reliant on gas-fired heat. Meanwhile, mechanisms such as the EU’s Carbon Border Adjustment Mechanism are turning carbon intensity into an increasingly explicit financial variable for exporters into European markets.

In this context, decarbonized industrial heat is no longer simply an ESG consideration.
It is becoming a strategic determinant of industrial competitiveness.

Nuclear process heat offers a pathway to address that challenge structurally: delivering continuous, carbon-free thermal energy with long-term pricing stability and limited fuel cost exposure.

The window for strategic positioning is open now

High-temperature nuclear heat is not yet available at broad commercial scale.

But industrial decarbonization decisions are not made on deployment timelines alone. They are shaped by long asset cycles, infrastructure planning horizons, and regulatory lead times.

Industrial assets commissioned today may operate for 30 to 50 years. Energy infrastructure decisions made in this decade will shape competitiveness and emissions trajectories well beyond 2050.

The companies that begin assessing nuclear heat pathways now, evaluating site compatibility, technology readiness, regulatory implications, and commercial structures, will be better positioned when deployment reaches maturity.

Those that wait for the technology to become fully commoditized may find that the strategic window has already narrowed.

A strategic reframing

The industrial heat challenge remains one of the least discussed, and most consequential, bottlenecks in the energy transition.

Nuclear may not be the answer for every industrial application.
But for many hard-to-abate sectors, it is one of the few scalable pathways to address the problem at its source.

The question is no longer whether industrial heat must decarbonize.

It is which technologies, and which operators, will move early enough to shape that transition rather than react to it.

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