The ownership exit of Russian oil assets from South-East Europe has sharpened attention on vulnerabilities that were long considered peripheral to the region’s energy debate. Among them, nuclear fuel stands out as the least visible and yet most structurally entrenched dependency. While oil and gas flows dominate political discourse, the nuclear fuel cycle continues to transmit geopolitical risk into European electricity markets through channels that are technical, opaque and slow to unwind. For South-East Europe, the exposure is largely indirect, but its price and security consequences are real and growing.
At the heart of the issue is the distinction between reactors and fuel. Even where countries do not operate nuclear power plants, they are exposed through regional power markets, cross-border trade and price formation. Nuclear generation shapes wholesale electricity prices across Central and Eastern Europe, and any disruption or repricing of nuclear fuel feeds directly into the marginal cost of power imported into the Balkans. The Russian position in uranium conversion, enrichment and fuel fabrication therefore matters far beyond the boundaries of nuclear-operating states.
The nuclear fuel chain and where power really lies
Uranium mining is only the first step in a long and capital-intensive chain. After extraction, uranium must be converted, enriched and fabricated into fuel assemblies compatible with specific reactor designs. Each stage is highly specialised, regulated and concentrated. Control over enrichment and fabrication, rather than raw uranium, is where strategic leverage resides.
Russian entities dominate critical segments of this chain. Through a combination of historical investment, scale and state backing, Russia retains a commanding position in enrichment and fuel services for reactors of Soviet and Russian design, which still account for a substantial share of Europe’s nuclear fleet. Across the European Union, Russian-linked providers account for roughly 35–45% of uranium enrichment services and an even higher share of fuel fabrication for VVER-type reactors.
This dominance has proven remarkably resilient to sanctions. Unlike oil, nuclear fuel has been treated as a sensitive and safety-critical input, exempted from rapid disruption. The result is a dependency that persists even as other Russian energy links are severed.
Exposure pathways into South-East Europe
South-East Europe itself operates limited nuclear capacity, but it is embedded in a regional power system shaped by nuclear generation in neighbouring countries. Electricity imports from Central Europe, Hungary and beyond carry nuclear costs embedded in wholesale prices. Long-term power purchase agreements, balancing markets and emergency imports all reflect the marginal cost of generation elsewhere.
When nuclear fuel costs rise, the effect propagates quietly. Wholesale electricity prices increase by a few euros per megawatt-hour, capacity premiums widen, and hedging costs climb. For SEE utilities already under pressure from gas volatility and ageing coal fleets, this additional layer of cost compounds financial stress.
Quantitatively, analysts estimate that fuel-cycle repricing linked to reduced Russian participation could add €5–10/MWh to wholesale electricity prices across interconnected markets over the second half of the decade. For countries importing 20–30% of their electricity, this translates into annual system-level cost increases of €100–250 million, depending on market conditions.
The cost of diversification
Reducing Russian dominance in the nuclear fuel cycle is technically feasible but financially and temporally demanding. Alternative suppliers must be qualified for specific reactor types, new enrichment capacity must be built, and regulatory approvals must be secured. None of this happens quickly.
At the EU level, replacing Russian enrichment and fuel services is estimated to require cumulative CAPEX of €10–15 billion over the next decade. This includes new enrichment cascades, fuel fabrication lines and supporting infrastructure. Even under accelerated scenarios, meaningful diversification before 2030 is unlikely.
In the interim, utilities face higher procurement costs. Fuel contracts signed at market-reflective terms incorporate risk premiums that were absent under long-standing arrangements. For nuclear operators, fuel OPEX could rise by 20–30% relative to historical baselines, eroding the cost advantage of nuclear generation and pushing it closer to the marginal cost of gas-fired power under moderate gas price scenarios.
Financing, balance sheets and hidden transmission
For utilities, nuclear fuel risk is not only an operating cost issue but a financing one. Lenders increasingly price geopolitical exposure into credit conditions. Where fuel supply is concentrated, refinancing costs rise and hedging becomes more expensive. These effects are rarely visible in tariff debates but show up in higher weighted average cost of capital.
For South-East Europe, the transmission mechanism is indirect but persistent. Higher financing costs for nuclear generation elsewhere lift regional power prices and volatility. Capacity auctions clear at higher levels, and long-term contracts embed risk premiums that persist for years.
In aggregate, these effects could add €0.5–1.0 billion to cumulative electricity procurement costs across the SEE region between 2026 and 2030, even without any acute disruption of fuel supply.
Why nuclear dependency matters more after oil
The exit of Russian ownership from oil assets removed a major political channel of influence, but it also exposed how much of Europe’s energy system still rests on less visible dependencies. Nuclear fuel exemplifies this dynamic. Because it is technical, regulated and safety-critical, it moves slowly and attracts less public scrutiny. Yet its impact on prices and security is systemic.
As oil and gas become increasingly market-priced and diversified, nuclear stands out as the last major energy input where Russian leverage persists at scale. This creates an asymmetry: electricity systems are expected to provide stability and decarbonisation, yet they rest on a fuel cycle that is geopolitically concentrated.
Implications for South-East Europe energy strategy
For SEE policymakers, the lesson is not that nuclear fuel risk can be eliminated quickly, but that it must be priced honestly. Electricity strategies that assume stable, low-cost imports underestimate future volatility. Grid investment, storage development and demand-side flexibility become more valuable when upstream price anchors weaken.
From a fiscal perspective, ignoring nuclear fuel risk merely postpones its manifestation. Higher power prices eventually translate into tariff pressure, industrial competitiveness losses or direct state support. Incorporating realistic price bands of €5–10/MWh linked to nuclear fuel diversification into planning models would materially improve resilience.
Outlook to 2030
By the end of the decade, Europe will have begun to loosen Russian dominance in nuclear fuel, but it will not have eliminated it. Alternative suppliers will gain share, yet capacity constraints and qualification timelines will limit speed. Fuel costs will remain higher and more volatile than in the pre-2022 period.
For South-East Europe, this means that nuclear fuel will continue to influence electricity markets even without domestic reactors. The dependency is indirect but unavoidable. In a system already stressed by gas volatility and coal’s declining viability, nuclear fuel repricing adds another layer of complexity.
The quiet constraint
Nuclear fuel does not produce headline crises. It does not stop flows overnight or generate visible shortages. Its influence is quieter, embedded in contracts, financing terms and price curves. Yet in aggregate, it shapes the cost and stability of electricity systems across Europe.
The exit of Russian oil ownership has made one thing clear: dependencies that appear technical and distant can have macroeconomic consequences. Nuclear fuel is the clearest example. For South-East Europe, acknowledging this quiet constraint is a prerequisite for building an energy strategy that is resilient not only to visible shocks, but to the slow, cumulative pressures that define the next decade.