A full shutdown of nuclear power across South-East Europe would be a structural stress test for the regional energy system since market liberalisation. The change would remove firm, low-marginal-cost baseload that currently supports system stability, cross-border trade and seasonal balance. The effects would propagate through generation adequacy, grid stability, renewable monetisation, state utility balance sheets and regional geopolitics.
Nuclear’s role in supply adequacy and seasonal balance
The region relies on roughly 9–11 GW of nuclear capacity, concentrated in Romania, Bulgaria, Hungary and Slovenia. Western Balkan systems would face indirect exposure through imports and cross-border balancing. In normal years, nuclear provides 18–25% of SEE electricity demand, with higher shares during low-hydro or low-wind periods.
An overnight removal would create an immediate structural gap that renewables alone cannot fill without changes in system operation and capital deployment. Nuclear plants typically run at 85–95% capacity factors, producing predictable output independent of weather. Without that output, the region would face recurring adequacy shortfalls during winter evenings, summer heatwaves and prolonged low-wind periods.
Replacing nuclear output with wind and solar capacity
The first-order impact would be a firm capacity deficit. On an energy basis, replacing 10 GW of nuclear output would require roughly 25–30 GW of new wind or 40–45 GW of solar, assuming average regional capacity factors. On a firmness basis, the gap would be larger than the energy replacement figures suggest.
Wind and solar do not replace nuclear’s contribution to peak security or inertia. As a result, the adequacy challenge would extend beyond annual energy volumes into peak and stability requirements. The timing of shortages during specific weather patterns would remain a key operational concern under a nuclear-free configuration.
Thermal generation response and cost pressures for state utilities
State-owned utilities would absorb part of the immediate shock by running thermal fleets harder and longer. Much of the fleet is lignite- or coal-based, and plants operating at 40–55% utilisation would be pushed toward technical limits. That shift would accelerate wear, increase unplanned outages and raise operating expenses.
Fuel procurement costs would increase while carbon exposure would rise. Utilities would face a political choice between passing costs through tariffs or absorbing losses. In a nuclear-free scenario, annual system costs across SEE would likely rise by €8–12 billion, depending on gas and carbon prices, with a significant share affecting public balance sheets.
Gas and hydropower constraints under stress conditions
Gas would initially cover part of the deficit but only partially and with high risk. Combined-cycle gas capacity in SEE is limited and unevenly distributed across countries. Even if fully utilised, existing gas plants could replace only 30–40% of lost nuclear energy.
Fuel import dependence would increase sharply, particularly for non-EU Western Balkan states. System exposure to geopolitical risk would rise rather than fall. Gas prices would become the dominant marginal price driver, pushing wholesale electricity prices structurally higher by €20–40/MWh in normal years and more during stress periods.
Hydropower could provide some buffer but is already heavily utilised and increasingly constrained by climate conditions. In wet years it could temporarily compensate for 10–15% of lost nuclear output, while dry years would offer little relief. Reservoir drawdown would occur earlier and faster, reducing seasonal flexibility later in the year.
Renewables expansion alongside higher volatility and curtailment risk
Wind and solar output would expand rapidly under a nuclear-exit scenario, but it would not automatically stabilise the system. Without nuclear’s stabilising mass, high RES penetration would increase volatility, deepen price swings and raise balancing requirements. Wholesale markets could see more frequent zero-price and negative-price hours during high RES output.
The same conditions could be followed by extreme scarcity pricing when weather turns adverse. In this setting, renewables without storage become economically fragile as merchant revenues compress when prices collapse during peak generation hours. Imbalance penalties and curtailment risk would rise sharply as well.
Batteries as a system-critical requirement for frequency and ramps
Developers could find that megawatts alone are no longer financeable under these market dynamics. Lenders would reprice risk aggressively by shortening tenors and demanding higher equity buffers. The role of balancing functions would increase as grids require faster response capabilities.
Battery energy storage would shift from an optimisation tool to system-critical infrastructure. To stabilise frequency, manage ramps and cover short-duration adequacy gaps, SEE would need at least 20–30 GWh of battery storage by the early 2030s compared with only a few gigawatt-hours today. Even that scale would address intraday and short-term balancing rather than multi-day or seasonal deficits.
Storage economics, regulatory questions and concentration risks
The economic role of batteries could expand significantly as storage captures a growing share of system value. In a nuclear-free scenario it could generate 40–60% of total renewable EBITDA. Ownership power could shift toward capital platforms able to finance and operate large storage portfolios.
The dependence on storage also introduces risks including degradation, software failure, cyber exposure and concentrated ownership of flexibility. Regulators would face questions about market power and system resilience as storage becomes central to operational security.
Cross-border trade changes when all markets seek imports simultaneously
Nuclear-heavy systems currently export stability to neighbours through cross-border flows during normal conditions. Without nuclear generation in the region, all SEE markets could become simultaneous importers during stress periods, reducing mutual support when it is most needed. Interconnectors would remain relevant but would no longer guarantee availability.
During regional cold spells or heatwaves prices could converge upward while imports dry up. This pattern reinforces reliance on domestic firm capacity alongside storage to manage local deficits under adverse weather conditions.
Financing split between RES-plus-storage portfolios and utility residual risk
A nuclear exit scenario could split financing into two tracks. Highly optimised RES plus storage portfolios may attract capital despite higher complexity and cost. State-owned utilities could be pushed deeper into residual risk by financing thermal life extensions, grid reinforcements and emergency reserves with limited revenue upside.
The shift could increase public debt levels and contingent liabilities across the region. Lenders are expected to differentiate between ring-fenced private assets and system assets carrying political risk as regulatory frameworks evolve around adequacy responsibilities.
A nuclear-free SEE system is expected to become more expensive, more volatile and more financially polarised according to the scenario parameters described for this stress test. Renewables growth could continue but bankability would depend on pairing projects with flexibility resources rather than generation alone. Balancing is described as becoming the dominant value pool while state utilities carry increasing liabilities to maintain adequacy.
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