The potential complete shutdown of nuclear power in Southeast Europe poses unprecedented challenges for the region’s energy landscape. This scenario represents a critical stress test, as it would eliminate a significant source of low-cost, reliable baseload power that underpins system stability and cross-border electricity trade. The ramifications would extend beyond immediate supply concerns, impacting generation adequacy, grid stability, and the financial health of state-owned utilities.
Currently, Southeast Europe relies on approximately 9 to 11 gigawatts (GW) of nuclear capacity, predominantly located in Romania, Bulgaria, Hungary, and Slovenia. This capacity typically meets 18 to 25 percent of the region’s electricity demand in normal conditions, with even higher contributions during periods of low hydro or wind generation. The abrupt removal of this capacity would create a substantial gap that renewable energy sources alone cannot fill without significant operational and investment changes.
The immediate consequence of losing nuclear capacity would be a firm capacity deficit. Nuclear plants operate at high capacity factors of 85 to 95 percent, providing stable output regardless of weather conditions. To replace the energy output from 10 GW of nuclear power, the region would need to install between 25 and 30 GW of new wind capacity or 40 to 45 GW of solar capacity. Moreover, these renewable sources do not provide the same peak security or inertia that nuclear does, leaving the region vulnerable to recurring shortages during peak demand periods.
State-owned utilities would face immediate pressure as they attempt to compensate for the loss of nuclear power. Their thermal generation fleets, primarily reliant on lignite and coal, would need to operate at higher capacities than currently feasible. Many plants that now run at 40 to 55 percent utilization would be pushed closer to their technical limits, leading to increased operational costs and unplanned outages. This shift could result in an estimated rise in annual system costs across Southeast Europe by €8 to €12 billion, depending on fuel prices and carbon market dynamics.
While natural gas could initially fill some of the energy gap left by nuclear plants, its contribution would be limited. Existing combined-cycle gas plants could only replace about 30 to 40 percent of lost nuclear output due to their uneven distribution across the region. Additionally, reliance on gas imports would increase significantly, particularly for non-EU Western Balkan countries. Consequently, this heightened dependence on gas could lead to elevated wholesale electricity prices by €20 to €40 per megawatt-hour (MWh) during normal conditions and even more during stress events.
Hydropower might offer some temporary relief but is already operating close to full capacity and is subject to climate variability. In favorable wet years, hydropower could replace about 10 to 15 percent of lost nuclear output; however, in dry years, its contribution would diminish significantly. This situation would drain hydro reservoirs more quickly, reducing seasonal flexibility and increasing vulnerability later in the year.
In this context, renewables are expected to expand rapidly following a nuclear exit; however, their integration into the grid may not stabilize it as anticipated. High penetration levels of renewable energy sources without nuclear support could lead to increased volatility in electricity prices and greater balancing requirements. This dynamic would result in more frequent instances of zero or negative pricing during peak renewable generation periods followed by extreme price spikes during adverse weather conditions.
The economic viability of renewables without storage solutions becomes increasingly precarious under these circumstances. As energy prices drop during high generation periods, revenues from merchant wind and solar projects may decline significantly. Simultaneously, risks associated with imbalance penalties and curtailment could deter investment in new projects as lenders reassess financial risks associated with renewables lacking integrated storage capabilities.
Balancing services will take center stage in this new energy paradigm. The absence of nuclear inertia necessitates a shift toward fast-responding assets such as battery storage systems. By the early 2030s, Southeast Europe may require at least 20 to 30 gigawatt-hours (GWh) of battery storage compared to only a few GWh currently available. This transition will be crucial for managing frequency stability and short-duration adequacy gaps.
The role of battery storage will expand significantly within this framework. It could potentially capture up to 40 to 60 percent of total renewable earnings before interest, taxes, depreciation, and amortization (EBITDA) in a scenario devoid of nuclear power. However, increased reliance on storage introduces new risks related to technology failures and concentrated ownership structures that could raise regulatory concerns regarding market power and system resilience.
Cross-border electricity trade dynamics will also shift dramatically without nuclear power contributing stability. All markets within Southeast Europe may become simultaneous importers during periods of stress rather than exporters as they currently are when supported by nuclear generation. This change will likely lead to upward price convergence during regional cold spells or heatwaves while diminishing mutual support among neighboring countries.
From a financing perspective, a transition away from nuclear energy may bifurcate the market into two distinct segments: one focused on highly optimized renewable energy plus storage portfolios that attract investment despite increased complexity; the other comprising state-owned utilities burdened with residual risks associated with thermal generation financing and emergency reserves amidst limited revenue prospects.
In summary, a nuclear-free Southeast European energy system would likely be characterized by higher costs, increased volatility, and greater financial polarization among market participants. While renewable energy deployment will continue apace, only those projects paired with flexible storage options are likely to secure financing under these new conditions. As balancing services become increasingly vital for system stability, state utilities will bear escalating liabilities while private capital seeks opportunities within this evolving landscape.
