A full shutdown of nuclear power across South-East Europe would represent the most severe structural stress test the regional energy system has faced since market liberalisation. Unlike price shocks or fuel disruptions, nuclear exit would remove firm, low-marginal-cost baseload that currently anchors system stability, cross-border trade and seasonal balance. The consequences would not be linear. They would cascade through generation adequacy, grid stability, renewable monetisation, state utility balance sheets and regional geopolitics.
The region currently relies on roughly 9–11 GW of nuclear capacity, concentrated primarily in Romania, Bulgaria, Hungary and Slovenia, with indirect exposure for Western Balkan systems through imports and cross-border balancing. In normal years, nuclear supplies 18–25 % of SEE electricity demand, and far more during low-hydro or low-wind periods. Removing it overnight would create an immediate structural gap that renewables alone cannot fill without radical changes in system operation and capital deployment.
The first-order impact would be a firm capacity deficit. Nuclear plants operate at 85–95 % capacity factors, providing predictable output independent of weather. Replacing 10 GW of nuclear on an energy basis 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 is even larger. Wind and solar do not replace nuclear’s contribution to peak security or inertia. Without nuclear, the region would face recurring adequacy shortfalls during winter evenings, summer heatwaves and prolonged low-wind periods.
State-owned utilities would become the immediate shock absorbers. Their thermal fleets, much of them lignite- or coal-based, would be forced to run harder and longer. Plants currently operating at 40–55 % utilisation would be pushed toward technical limits, accelerating wear, increasing unplanned outages and driving OPEX sharply higher. Fuel procurement costs would rise, carbon exposure would explode, and utilities would again face the political dilemma of either 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 landing on public balance sheets.
Gas would initially fill part of the gap, but only partially and at high risk. Combined-cycle gas capacity in SEE is limited and unevenly distributed. 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, not fall. Gas prices would reassert themselves as the dominant marginal price driver, pushing wholesale electricity prices structurally higher by €20–40/MWh in normal years and far more in stress periods.
Hydropower would provide some buffer, but it is already heavily utilised and increasingly climate-constrained. In wet years, hydro could temporarily compensate for 10–15 % of lost nuclear output, but in dry years it would offer little relief. More importantly, hydro reservoirs would be drained earlier and faster, reducing seasonal flexibility and increasing vulnerability later in the year. The system would become more brittle, not more resilient.
This is where renewables enter the picture, but not in the way policy narratives often suggest. Wind and solar would expand rapidly under a nuclear-exit scenario, but they would not automatically stabilise the system. On the contrary, without nuclear’s stabilising mass, high RES penetration would increase volatility, deepen price swings and magnify balancing requirements. Wholesale markets would see more frequent zero-price and negative-price hours during high RES output, followed by extreme scarcity pricing when weather conditions turn adverse.
In such a system, renewables without storage become economically fragile. Merchant wind and solar revenues would compress, not expand, because energy prices would collapse precisely when generation is highest. At the same time, imbalance penalties and curtailment risk would rise sharply. Developers would find that megawatts alone are no longer financeable. Lenders would reprice risk aggressively, shortening tenors and demanding higher equity buffers.
Balancing would become the dominant system function. Without nuclear inertia and frequency stability, SEE grids would require a step-change in fast-responding assets. Battery energy storage would move from optional optimisation tool to system-critical infrastructure. To stabilise frequency, manage ramps and cover short-duration adequacy gaps, the region would need at least 20–30 GWh of battery storage by the early 2030s, compared with only a few gigawatt-hours today. Even this would only address intraday and short-term balancing, not multi-day or seasonal deficits.
The economic role of batteries would expand dramatically. Storage would capture a growing share of system value, potentially generating 40–60 % of total renewable EBITDA in a nuclear-free scenario. Ownership power would shift further toward capital platforms capable of financing and operating large storage portfolios. At the same time, system dependence on storage would introduce new risks: degradation, software failure, cyber exposure and concentrated ownership of flexibility. Regulators would face difficult questions about market power and system resilience.
Cross-border trade would also change character. Today, nuclear-heavy systems export stability to neighbours. Without nuclear, all SEE markets would become simultaneous importers during stress periods, sharply reducing mutual support. Interconnectors would still matter, but they would no longer guarantee availability. During regional cold spells or heatwaves, prices would converge upward, and imports would dry up. This would further reinforce the need for domestic firm capacity and storage.
From a financing perspective, a nuclear exit would split the market in two. On one side, highly optimised RES + storage portfolios would attract capital, albeit at higher complexity and cost. On the other, state-owned utilities would be pushed deeper into residual risk, financing thermal life extensions, grid reinforcements and emergency reserves with limited revenue upside. Public debt and contingent liabilities would rise. Lenders would increasingly distinguish between ring-fenced private assets and system assets carrying political risk.
The long-term macro implication is clear. A nuclear-free SEE system would be more expensive, more volatile and more financially polarised. Renewables would still grow rapidly, but only those paired with flexibility would be bankable. Balancing would become the dominant value pool. State utilities would shoulder increasing liabilities to maintain adequacy, while private capital would focus on volatility monetisation rather than energy supply per se.
In this stress-test scenario, nuclear exit does not create a simple renewables boom. It creates a system where flexibility, not generation, determines survival. Renewables without storage would struggle. Storage without regulation would concentrate power. And the absence of nuclear would expose the underlying truth of the SEE energy transition: decarbonisation without firm low-carbon baseload shifts risk rather than eliminating it, moving it from reactors to batteries, from fuel supply to balance sheets, and ultimately from markets to the state.
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