In South-Eastern Europe (SEE), hydropower has historically been a cornerstone of electricity generation, contributing significantly to the stability and flexibility of regional power systems. Countries such as Serbia, Montenegro, Bosnia and Herzegovina, Romania, and Bulgaria have relied on hydropower for low-cost energy and essential balancing capabilities. However, the implications of climate change are reshaping this dynamic, introducing new challenges for electricity security across the region.
The installed hydropower capacity in SEE remains relatively stable, with some regions even witnessing modest growth through refurbishments and the addition of small hydro projects. Despite this stability, the reliability of hydropower generation is increasingly compromised. Output is becoming less predictable, with seasonal variations and a growing vulnerability to prolonged drought conditions that can last for multiple years.
Statistically, hydropower accounts for 20–35 percent of annual electricity generation in normal hydrological years within various SEE systems. In particularly wet years, this contribution can exceed 40 percent, leading to suppressed wholesale prices and reduced reliance on fossil fuels. Conversely, during dry spells, hydropower output may decline by 25–40 percent compared to long-term averages. These fluctuations contribute directly to price volatility and an increased dependency on fossil fuel imports.
Recent trends indicate that dry years are becoming more frequent rather than remaining anomalies. Climate modeling for the Balkan and Danube basins points to prolonged periods of low precipitation and heightened evaporation rates during summer months. This situation creates a dilemma for operators managing reservoir-based systems as they must balance energy optimization with water security needs for irrigation and flood control.
The economic repercussions of these challenges are evident. During dry years, SEE markets face a dual challenge: reduced hydro output removes a low-cost energy source from the market, thus elevating prices set by higher-cost fossil fuel units; simultaneously, decreased hydro flexibility necessitates greater reliance on gas imports for grid balancing. Recent data reveal that weeks with limited hydro availability have coincided with wholesale price increases ranging from €30 to €60 per megawatt-hour compared to normal conditions.
This evolving landscape necessitates a reevaluation of how hydropower is perceived within the energy framework. It should no longer be regarded solely as a generation asset but rather as a strategic reserve that provides flexibility during peak demand periods. Drought conditions that weaken this reserve can significantly undermine overall system resilience.
The integration of renewable energy sources such as wind and solar further complicates this scenario. The expansion of these technologies has increased the demand for fast-responding balancing resources. Historically, hydropower has served this function effectively; however, its availability is now often misaligned with renewable output patterns—solar peaks in summer when reservoirs face the most stress while wind generation fluctuates independently of precipitation patterns.
This misalignment presents a critical blind spot in system planning where many decarbonization strategies assume stable hydro output as a baseline condition. In SEE, such assumptions are increasingly precarious; underestimating hydropower variability could lead to inadequate system adequacy models that fail to account for necessary balancing resources and security margins.
The geopolitical aspects also introduce complexities into the hydropower equation. Shared river basins across national borders mean that upstream precipitation variability and reservoir management decisions can profoundly impact downstream power generation and grid stability. As climate pressures mount, coordination over water use becomes politically sensitive—highlighting an intersection between electricity security and water governance that has yet to be fully integrated into regional energy policies.
Despite these challenges, abandoning hydropower is not an option; it remains an essential component of the energy mix in SEE. However, its role must be redefined to emphasize flexibility over volume contribution. This shift requires new dispatch strategies and remuneration mechanisms while fostering closer integration with regional balancing markets.
Quantitatively speaking, losing even a modest percentage of effective hydro availability during peak periods could inflate regional balancing costs by hundreds of millions of euros annually due to higher fuel consumption and import premiums—costs that may not be immediately visible but manifest as elevated wholesale prices affecting state-owned utilities financially.
As climate variability continues to shape operational realities in SEE’s electricity markets, managing hydropower’s risk profile becomes paramount. Failure to do so risks exacerbating reliance on gas plants or coal during stress events—threatening both energy transition efforts and overall decarbonization goals. Addressing these challenges requires an integrated approach that incorporates hydrological risk into market design and cross-border coordination efforts.
The growing risks associated with hydropower are not merely speculative; they are currently influencing pricing dynamics and system stresses throughout South-Eastern Europe’s electricity landscape. As climate variability intensifies further adaptation will be crucial in navigating this evolving energy landscape.
