Hydropower has historically served as a crucial stabilizer for electricity systems across South-Eastern Europe (SEE), providing essential operational stability and price moderation. Countries including Serbia, Montenegro, Bosnia and Herzegovina, Romania, and Bulgaria have relied on hydropower for both low-cost energy and vital balancing capabilities. However, as climate variability becomes more pronounced, the reliability of hydropower is increasingly under threat, introducing significant risks to regional electricity security.
While installed hydropower capacity in SEE remains largely stable, with some growth through refurbishments and new small hydro projects, the central concern lies in the reliability of output. The predictability of hydropower generation is diminishing, becoming more seasonal and vulnerable to prolonged droughts. This shift undermines its traditional role as a dependable source of flexibility at a time when such flexibility is critically needed.
Statistically, hydropower contributes between 20% to 35% of annual electricity generation during normal hydrological years across several SEE markets. In particularly wet years, this contribution can exceed 40%, leading to lower wholesale prices and reduced reliance on fossil fuels. Conversely, during dry years, hydropower output can decline by 25% to 40% compared to long-term averages, resulting in increased price volatility and heightened dependence on fossil fuel imports.
Recent analyses indicate that dry years are becoming more frequent rather than remaining exceptional occurrences. Climate models for the Balkan and Danube regions project an increase in prolonged low-precipitation periods and erratic seasonal runoff patterns. For reservoir-based systems, this creates a conflict between optimizing energy production and ensuring water security. Operators face difficult decisions regarding water allocation for peak pricing periods versus essential non-energy uses such as irrigation and flood management.
The economic ramifications of these challenges are already apparent. During dry years, SEE markets experience dual pressures: diminished hydro output eliminates a low-cost energy source from the merit order while simultaneously increasing reliance on higher-cost fossil units for balancing needs. This situation has led to wholesale price spikes of €30 to €60/MWh during periods of constrained hydro availability compared to hydrologically normal conditions.
This evolving dynamic necessitates a re-evaluation of how hydropower is perceived within the energy system. It is increasingly recognized not merely as a generation asset but as a strategic reserve whose value lies in its timing rather than sheer volume. Reservoir-based hydropower plays a crucial role during scarcity periods; however, drought conditions can significantly weaken this option, thereby compromising overall system resilience.
The integration of renewable energy sources further complicates the landscape. The expansion of wind and solar power in SEE increases the demand for fast, dispatchable balancing resources. Historically, hydropower has fulfilled this role effectively; however, misalignment between hydro availability and renewable generation patterns has emerged. Solar production peaks during summer months when reservoirs are under significant stress from low water levels, while wind generation often correlates negatively with precipitation trends.
This misalignment creates a blind spot in system planning where many decarbonization strategies assume stable hydro output as a constant factor. In SEE, this assumption is increasingly unreliable; underestimating hydropower variability may lead to inadequate balancing models and inflated security margins, ultimately exposing the system to greater risks of price spikes and emergency interventions.
Geopolitical factors also play a critical role in the management of hydropower resources within SEE. Hydropower assets often span across international river basins, meaning that upstream precipitation variability and reservoir management decisions can significantly affect downstream grid stability. As climate-related stresses escalate, coordination over water resource management will become more politically sensitive, intertwining electricity security with water governance—an aspect not yet fully integrated into regional energy policies.
Despite these challenges, abandoning hydropower is not an option; it remains an indispensable component of the energy mix. However, its function must be redefined to prioritize flexibility and reserve value rather than solely focusing on energy volume contributions. This shift necessitates new dispatch strategies and remuneration mechanisms while enhancing integration with regional balancing markets.
Quantitatively speaking, even a modest decrease of 5% to 10% in effective hydro availability during peak demand periods could lead to hundreds of millions of euros in increased regional balancing costs annually due to higher fuel consumption and import needs. These costs may be diffuse and often hidden but manifest as elevated wholesale prices and increased financial strain on state-owned utilities.
Ultimately, managing hydropower’s climate-sensitive risk profile requires explicit integration of hydrological uncertainties into electricity market design and capacity planning processes. Failure to address these realities could lead to over-reliance on gas plants and increased coal usage during critical stress events, undermining efforts toward decarbonization.
The risks associated with hydropower are not merely future concerns; they are actively influencing price dynamics and system stability across South-Eastern Europe today. As climate variability continues to intensify, adapting electricity systems to navigate these emerging challenges will be crucial for the region’s energy transition.
