The great electrification: Nuclear energy in the changing power system

Europe’s great electrification is significantly reshaping the continent’s energy system. As outlined in our series’ opening article , the transition is no longer driven by climate goals alone, but by strategic needs to strengthen competitiveness and reduce dependence on fossilfuel imports. Electrifying demand, scaling renewable generation, and upgrading grids are now the pillars of building a cleaner, more affordable, and more autonomous energy system.

Within this changing landscape, nuclear energy occupies a distinctive and often debated position. Today it supplies nearly a quarter of EU electricity, acting as a source of stable, low‑carbon power. Yet Europe’s electricity system is evolving toward one dominated by variable renewables, flexible consumption, and decentralized infrastructure. This raises a fundamental question: How well does nuclear energy fit in such a system – and what contribution can it realistically make to Europe’s great electrification?

This chapter assesses the fundamentals and economics of nuclear energy, how Europe’s existing fleet is aging, and why long construction times and system‑integration constraints limit the scale of new nuclear capacity. It also draws on a diverse set of energy system scenarios and project‑based outlooks to explore where nuclear energy is most likely heading by 2040.

How nuclear power works in the current energy system

Nuclear power reactors produce energy by initiating and controlling sustained nuclear chain reaction, in which heat, generated from fission, creates steam and drives electricity‑producing turbines. Like other thermal plants, they convert heat to power, but the source is the atomic nucleus rather than fossil fuels. Because this process does not involve combustion, it has very low lifecycle carbon emissions.

What distinguishes nuclear energy in the power system is the physics and engineering of the reactor core. Reactors operate with very high power density, run for 12 to 18 months between refueling, and deliver consistently high capacity factors, typically above 85% to 90%. These features also mean that nuclear plants are engineered for long, continuous production rather than frequent starts, stops, or rapid adjustments. Historically, this has made nuclear energy well‑suited to a firm baseload operation, providing a stable supply across days and seasons.

Other firm technologies behave quite differently. Gas‑fired combined‑cycle units can adjust output rapidly and operate flexibly in mid‑merit or peaking roles, but their economics are shaped by fuel costs and price volatility. Hydropower can be highly dispatchable, but is constrained by reservoir levels, seasonal inflows, and ecological limits. Nuclear energy, by contrast, has low marginal costs but high technical and economic consequences for deviating from continuous output. Ramping up or down is possible only within a narrow band, at the expense of efficiency and equipment wear. This limited adjustability is increasingly relevant as renewable penetration grows, since systems dominated by variable wind and solar require assets that can modulate output rapidly in response to changing residual load.

Types of nuclear reactors currently in operation

The most common nuclear reactors in operation today are light water reactors (LWRs), which use ordinary water as both a coolant and a neutron moderator. The average LWR has about 1,100MW capacity to produce electricity. Within this category, there are two principal types: pressurized water reactors (PWRs) and boiling water reactors (BWRs). PWRs keep water under high pressure so it heats without boiling; the heated water then transfers its energy via a heat exchanger to produce steam in a separate loop. BWRs allow water to boil directly inside the reactor vessel, sending steam straight to the turbine. These designs make up almost the entirety of the current EU nuclear fleet.

SMRs: A promise at the edge of commercial reality

While today’s fleet relies exclusively on established technologies, a range of advanced reactor concepts is under development and could alter deployment options in the long term. Small modular reactors (SMRs) are one of those advanced concepts.

SMRs are nuclear reactors typically producing up to 300MWe per module and designed for modular, factory‑based construction, enabling more predictable and rapid delivery and potential cost reductions through series production. Their smaller size, enhanced inherent and passive safety features, and flexible deployment models distinguish them from traditional gigawatt‑scale reactors. They span a range of technologies, many of which draw on established reactor principles.

SMRs could potentially provide steady and low‑carbon energy while also supplying industrial heat, hydrogen, and district heating by leveraging their modularity. According to the European Industrial Alliance on SMRs, SMRs can repower retiring fossil‑fuel sites and improve geographic siting flexibility due to lower land and cooling water requirements. These uniquely attractive qualities have garnered widespread recognition of the potential role of SMRs in a decarbonized energy system.

However, SMR deployment currently faces significant barriers – not only in Europe, but globally. These include:

The early 2030s will be decisive for SMRs. Demonstration projects, progress on regulatory harmonization, and credible financing models will determine whether SMRs can scale meaningfully. A key open question is whether they can ultimately deliver faster and more cost‑effective deployment than large-scale reactors and meet new business models, such as supplying industrial clusters.

If those conditions are not met, SMRs may struggle to compete – both with refurbished large reactors and with non‑nuclear low‑carbon options. If the conditions are met, SMRs could become a valuable addition to Europe’s low‑carbon system but way beyond 2040, in our view.

[1] In February 2026, a Romanian project to build six NuScale SMRs with a total of 462MW capacity secured Final Investment Decision (FID). The project will be Europe’s first SMR to be deployed.

The nuclear industry in Europe has stagnated since the early days of the nuclear boom in the 1980s. The oldest nuclear reactor still in operation since 1973 is in the Netherlands, while the latest entered operation in 2023 in Finland. Currently, there is only one reactor under construction in the EU, in Slovakia, while France’s latest power plant in Flamanville is expected to start full commercial operation in 2026.

Since the early 2000s, only seven new nuclear plants have been deployed in the EU, while more than 70 have been shut down. A variety of reasons are behind this trend, but the most common ones are political decisions, technological constraints, and economics. This imbalance between additions and retirements is the most important structural driver of nuclear energy’s declining share in the EU power mix – and it is unlikely to reverse meaningfully before 2040, even though the European Commission (EC) has underlined the strategic importance of strengthening the role of nuclear energy.

Nuclear energy continues to play a central role in the electricity mix of several member states (see figure 2). In France, Slovakia, Hungary, and Belgium, nuclear power accounts for more than 40% of total power generation, underscoring the considerable reliance on existing reactors to ensure electricity supply and system stability.

In 2024, nuclear power provided nearly a quarter (23.4%) of the EU’s electricity with 101 active nuclear reactors across 12 MSs (see figure 2), equal to nearly 650TWh (gross) electricity production.

The EU’s nuclear sector is entering a period where financial, technical, and geopolitical pressures intersect to shape its future viability. High investment costs, persistent delivery challenges, and growing fuel‑cycle and supplychain constraints now raise essential questions about maintaining and modernizing the EU’s nuclear capacity.

Nuclear cost dynamics and competitiveness

Nuclear power was once seen as cheap because early plants had lower construction costs, shorter building times, and predictable and low operating costs. But rising capital expenses, longer and risky construction timelines, stricter safety requirements and changing, flexible electricity markets have since driven costs upward. These dynamics fundamentally influence the role of nuclear energy in a low-carbon, renewable-driven electricity system.

Today, the economic challenge is characterized by extremely high upfront capital and financing requirements – often in the billions or tens of billions of euros – combined with long and uncertain construction periods. Once operational, nuclear plants benefit from relatively low operating and fuel costs, creating a cost structure dominated by CAPEX rather than OPEX (see figure 4). This means that nuclear economics depend heavily on securing predictable, long-term revenue streams – an increasingly difficult task in electricity systems with high shares of variable, zero‑marginal‑cost renewables and more volatile wholesale prices.

Understanding the true cost of nuclear electricity requires an overview of its full lifetime cost structure. Levelized cost of electricity (LCOE) expresses the average cost of producing 1MWh of electricity over a plant’s lifetime, including capital, operations and management, fuel, financing, and decommissioning costs. Because LCOE is highly sensitive to upfront investment levels, construction time, and the number of operating years over which capital is amortized, nuclear energy tends to show relatively high LCOE values.

In Europe, newly built nuclear energy generally falls within EUR 110 to EUR 170/MWh, depending on assumptions such as discount rate, construction time, and financing conditions (see figure 5). In contrast, renewable sources such as onshore wind and solar PV typically achieve LCOEs below EUR 100/MWh, and in many cases significantly lower, making them highly competitive for new capacity additions. This cost gap has major implications: Even if nuclear provides firm output, its relative cost competitiveness shapes whether it is expanded, maintained, or replaced by combinations of renewables, storage, and flexible demand.

This cost structure also explains why lifetime extensions have become economically pivotal for Europe’s nuclear fleet. Because existing reactors have already recovered most of their initial capital investment, extending their operating life significantly reduces the cost per MWh simply by spreading historical CAPEX over more generation years. Lifetime extension projects also require lower investments than new builds – typically 25% to 50% less – while preserving large volumes of low‑carbon, firm capacity.

When these extensions are included in the LCOE, economics shift significantly. According to the NEA LCOE calculator, lifetime-extended nuclear generation in the EU could show LCOE values as low as EUR 29/MWh, placing them on par with or even below the cost of many renewable technologies and making lifetime extensions one of the most cost‑effective sources of firm, low‑carbon electricity.

Note: Based on the JRC METIS model simulation. * Combined Cycle Gas Turbine ** Open Cycle Gas Turbine Source: JRC 2023, EC 2025

Delivery delays and cost overruns

In the EU, reactor construction timelines have become particularly long, with several projects exceeding 15 years – more than double the time it typically takes to complete a project in China, where it takes 6 years. By comparison, the global average construction time has risen to around 9.4 years, up from roughly 7 years in the 1980s.

These increased lead times have led to visible cost increases and overruns (see figure 6). In the EU, the costs of Flamanville-3 (France) have almost quadrupled – from EUR 3,900/kW to EUR 12,000/kW, while the costs of Finland’s Olkiluoto-3 reactor have more than doubled – from EUR 4,100/kW to EUR 8,300/kW.

Every additional year adds substantial interest during construction, inflates total project costs, and exposes investors and financiers to large cost‑overrun risks that private capital typically prices unfavorably. In deregulated electricity markets, where revenues depend on short‑term price signals, it is increasingly challenging to finance nuclear projects without state-backed guarantees, long-term contracts such as Contracts for Difference (CfD), or direct public ownership.

Note: Cost estimates don’t include interest. Original values are converted using an exchange rate of EUR/USD 1,08 (2023 average). Hinkley Point C is under construction, its cost estimates represent the latest known value. Source: IEA 2025, RaboResearch 2026

Supply chain dependencies in times of geopolitical turmoil

Economics are not the only challenging factor within the nuclear sector. The EU faces growing supply chain vulnerabilities that stem from both external geopolitical pressures and internal structural weaknesses.

The bloc remains almost entirely dependent on imported uranium, with most supplies originating from Canada and Kazakhstan (see figure 7), while domestic production is negligible. Although Europe maintains its own conversion capabilities through Orano (FR) and enrichment through Urenco (UK, NL, DE), legacy reliance on Russian fuel‑cycle services – especially for Eastern European reactors – continues to expose member states to geopolitical risk. This challenge is amplified by the EU’s lack of HALEU[2] fuel production, which is essential for many next‑generation SMRs.

[2] High-Assay Low-Enriched Uranium is uranium enriched to greater than 5% and less than 20% of the U-235 isotope. It will be the primary fuel of many advanced reactors including SMRs.

Source: ESA 2025, RaboResearch 2026

Beyond fuel, the broader nuclear supply chain is constrained by a shrinking manufacturing base, geopolitical threats, bottlenecks in heavy‑forging capacity, and limited availability of nuclear‑grade components and specialized materials. These structural weaknesses have contributed to delays and cost overruns in recent European new‑build projects and are exacerbated by sanctions and disrupted access to parts for Russian‑designed reactors.

Compounding these issues is an aging workforce that functions as a supply chain constraint on its own. With nearly 40% of Europe’s nuclear workforce now over 50 years old, and shortages emerging across key engineering, manufacturing, and regulatory roles, the sector faces a tightening labor pipeline at precisely the moment when refurbishment, new build, and SMR deployment demand is rising.

Together, these overarching challenges – economics, deployment, and the supply chain – pose a strategic risk for the future of nuclear energy in the EU, threatening to slow reactor life‑extension, stall SMR deployment, and undermine Europe’s ability to even maintain its nuclear capacity in the decades ahead.

Europe’s nuclear sector is entering a period defined less by expansion and more by transition. While it continues to provide firm, low‑carbon electricity, the conditions under which it operates are shifting rapidly. Aging reactors, long construction timelines, rising project costs, and tightening supply chains are reshaping expectations for what Europe’s nuclear sector can realistically deliver by 2040.

Nuclear in 2040: What the scenarios reveal

Building on the scenarios introduced in the second article in our series, this analysis draws from a diverse set of energy-system scenarios to assess the role of nuclear energy toward 2040 (see table 1 and figure 8).

Despite different modeling approaches, most scenarios converge on a similar range for nuclear generation in 2040 between 605TWh and 666TWh, whereas the EC’s Impact Assessment projects a notably lower level of 495TWh. The difference is explained by the diverging modeling assumptions that reflect Europe’s aging reactor fleet, phase‑out decisions in several member states, and the slow pace at which new nuclear capacity could realistically be commissioned.

The same logic explains the downward trend in the EC pathways and in BloombergNEF’s Economic Transition Scenario (BNEF ETS) – though for different reasons. In the EC scenarios, the decline is largely structural. In the BNEF ETS, the decline stems mainly from pure cost‑competitiveness, where falling renewable and storage costs outperform nuclear.

By contrast, all other scenarios show nuclear generation rising slightly to moderately toward 2040. This is particularly visible in BNEF’s Net Zero Scenario (NZS), whereas Shell and the IEA show only marginal increases. Importantly, this growth does not reflect an expected large expansion of Europe’s nuclear fleet. Instead, it arises from these scenarios’ internal logic: Under high electrification, stronger climate ambition, or heightened energy‑security concerns, models tend to retain existing nuclear assets for longer, allow slower phase‑outs, or assume higher utilization of the remaining fleet.

The nuclear outlook through the lens of today’s fleet

To explore possible nuclear pathways from a different angle, we have developed four potential scenarios based on the currently operating fleet with lifetime extensions combined with the planned nuclear assets.[3]

Our scenarios assume that all of the planned reactors are commissioned by 2040, that a 90% capacity factor applies across all units, and that Spain either completes or cancels its national phase‑out by 2031 (see figure 9):

Across all scenarios, nuclear generation remains generally stable until the late 2030s. A visible increase appears around 2040, as planned new reactors would begin operation. After this point, the trajectories begin to differ.

In the 60-year extension scenarios, output starts to slightly decline in the early 2030s due to some reactors reaching decommissioning age. In the early 2040s, the decline becomes steeper as reactors retire in large numbers, mainly in France, with the steepest drop occurring when the Spanish fleet is phased out.

In the 80-year extension scenarios, production remains higher and more stable for longer, avoiding the abrupt decline observed in the 60‑year cases. In this scenario, nuclear plants would retire mainly in the 2060s.

In case of a full phase-out in Spain, 56TWh of nuclear generation disappears from the mix as of 2031, moderately decreasing nuclear generation in both scenarios (orange and yellow).

These fleet‑based scenarios are optimistic and represent the upper bound of what could be achieved with current technologies. They assume extensive lifetime extensions under regulatory conditions that are, in practice, stringent and may limit the feasibility of such extensions.

[3] We have included reactors that have reached an advanced planning phase. Therefore, our selection may differ from plans described in the National Energy and Climate Plans (NECP) of the member states.

How does nuclear power fit into a new, flexible energy system?

As Europe’s electricity system becomes increasingly renewable‑driven, decentralized and dynamic, the shifting operating environment is exposing the structural mismatch between nuclear energy’s current design and future system needs.

Nuclear reactors deliver constant output, but this very steadiness makes them poorly suited to the short‑term variability that defines a renewables‑heavy grid. They cannot shut down and restart daily, and although some down‑modulation is technically possible, it remains narrow, costly, and accelerates wear, making continuous operation the default mode. As renewable penetration grows, the minimum daily residual load declines, reducing the physical space for inflexible generation and limiting the amount of nuclear energy the system can integrate. This creates a structural integration limit: The lower the residual load, the smaller the role nuclear baseload units can (safely) play.

To accommodate nuclear generation in such a system, countries shall either increase system‑wide flexibility or align stable demand with nuclear energy’s continuous output. Options include storage, interconnection, flexible demand (e.g., electrolyzers, industrial clusters, data centers), and sector coupling where nuclear heat or power can serve non‑electric end uses. These strategies do not make nuclear flexible, but they can help to continue to integrate steady output into a renewables‑led system.

Because every EU member state is moving toward higher renewable shares, these dynamics translate into differing future system configurations that determine how nuclear generation can realistically operate. Table 2 summarizes three scenarios across the EU, considering nuclear energy’s role in the evolving energy system.

The role of nuclear energy is evolving in a context of an aging nuclear fleet, rapidly falling renewable costs, and the emergence of a far more flexible, dynamic electricity system. Across Europe, the future of nuclear energy up to 2040 is shaped less by technological promise, and more by policy choices, project timelines, system constraints, and the physical realities of how electricity is generated and balanced.

The scenario evidence is consistent. With long construction times, repeated delays, and cost overruns, no new large reactors are expected to enter operation before 2040. This means that Europe’s nuclear output over the next 15 years will be almost entirely determined by the existing fleet.

This implies that nuclear generation will most likely stagnate or decline slightly toward 2040. Upholding current output depends overwhelmingly on lifetime extensions, which remain the most economically attractive and technically feasible pathway for preserving firm, low‑carbon capacity. If lifetime extensions do not materialize, nuclear generation could decrease to 500TWh across the EU. Given the constraints we’ve highlighted, we do not expect SMRs to scale meaningfully within this timeframe either.

As a result, we expect nuclear generation to remain a strategic but system‑bound source of firm, low‑carbon power that will remain largely constant. Its value will lie in anchoring reliability during low renewable output periods and reducing reliance on fossil‑based backup. Nuclear generation will likely form a stable floor in the future power mix. It will be mostly sized to the lowest levels of daily residual demand as it is not designed to provide the daily flexibility required in a renewables‑led system.

Several developments could shift this outlook. Faster‑than‑expected commercialization of SMRs, more ambitious capacity‑market designs valuing clean firm power, or stronger geopolitical drivers for energy autonomy could elevate nuclear energy’s long‑term relevance. Some signs already indicate that countries with high nuclear shares may prioritize keeping their existing fleets online while advancing renewable expansion at a moderate pace.

Conversely, increasing renewable overbuild, tighter economic constraints on lifetime extensions, slow progress on fuel‑cycle diversification, or public resistance could further limit the role of nuclear power. These factors will not change the core system‑fit constraints, but they may shift the scale and strategic relevanceof nuclear energy within the great electrification.