For many years, hydropower has been a critical component of Southeastern Europe’s electricity landscape, underpinning energy stability and providing cost-effective generation. Countries such as Montenegro, Bosnia and Herzegovina, Serbia, Albania, and Romania have relied on their extensive reservoir systems not only for affordable electricity but also for balancing supply and demand, generating export revenues, and ensuring energy security. Traditionally, hydropower plants could predictably adjust to seasonal variations, with droughts leading to higher prices and strong hydrological conditions yielding low-cost exports to markets like Italy and Hungary.
However, recent developments indicate a significant shift in this dynamic. In May 2026, despite favorable hydrological conditions in parts of the Western Balkans, hydroelectric generation across the broader HU+SEE system saw a decline of approximately 357 MW compared to previous periods. This decline is particularly concerning as it coincides with a weakening in the market value of hydroelectric exports even when physical generation levels remained high.
This change is not solely attributable to weather patterns; rather, it reflects a broader structural transition within the market. Increased solar energy penetration, shifting cross-border flows, distortions from the Carbon Border Adjustment Mechanism (CBAM), and midday oversupply in Italy are reshaping the operational landscape for hydropower. For instance, Montenegro’s state utility EPCG reported that CBAM-related market effects resulted in a reduction of electricity export revenues by around €13 million during the first quarter of 2026.
The implications of these shifts are profound. Historically, robust hydrological conditions would translate into enhanced profitability for regional utilities. Reservoir-rich countries were able to leverage their surplus generation effectively during peak demand periods in neighboring markets. However, as solar energy becomes more prevalent during daytime hours—when hydropower traditionally maximized its output—the economic model supporting these utilities is becoming increasingly complex.
Recent data illustrates this trend starkly: net exports from the SEE region to Italy shifted from approximately +310 MW to -148 MW in early May 2026. This reversal is critical as Italy has been a key balancing market for SEE exporters. The region now faces challenges with weaker profit margins during solar-heavy hours when demand diminishes.
Consequently, hydropower is evolving from a straightforward baseload exporter into a more sophisticated flexibility asset within an increasingly volatile electricity system. Operators with storage reservoirs must now focus on optimizing their output based on market conditions rather than simply annual generation totals. The ability to store water during low-price periods and release it during peak demand times will be essential for maintaining competitive advantages.
This transformation necessitates new financial strategies for hydro portfolios as they adapt to changing market realities. Countries like Romania exemplify this shift; Hidroelectrica reported improved profitability amidst regional volatility by emphasizing strategic market positioning over mere hydrological abundance.
The operational complexity facing hydropower operators extends beyond just managing generation timing. They must also navigate factors such as evening balancing spreads, cross-border congestion issues, negative price avoidance strategies, intraday volatility management, ancillary service revenues, and competition from battery storage technologies.
The investment climate for future large-scale hydropower projects is becoming increasingly challenging due to rising construction costs driven by inflation and regulatory hurdles related to environmental compliance. Additionally, European electricity prices are exhibiting greater volatility influenced by renewable energy integration while future profitability hinges on flexibility rather than just output volume.
This evolving context presents significant risks for existing projects across Bosnia and Herzegovina’s hydropower sector. Initiatives like HPP Dabar and HPP Mrsovo highlight how financing disruptions and permitting complexities can jeopardize traditional infrastructure delivery models.
The competitive landscape is further complicated by rapidly decreasing battery storage costs that allow these systems to compete directly with hydroelectric facilities for balancing revenues and ancillary services. As solar capacity continues to expand without corresponding improvements in transmission infrastructure, batteries are positioned to capture value more effectively than traditional hydro systems.
Despite these challenges, hydropower remains a vital resource within the region’s energy mix due to its capacity for providing balancing flexibility at scale. However, governments face increasing pressure from local opposition regarding new projects due to environmental concerns while also contending with stricter ESG standards imposed by European financing institutions.
The future of Southeastern Europe’s electricity system will likely depend on hybrid models that integrate various sources of flexibility—including hydropower alongside battery storage and gas balancing—rather than relying solely on any single technology. This integrated approach will reshape asset valuation methods across the regional power sector as stakeholders adapt to an environment where hourly price capture and balancing participation take precedence over traditional metrics like annual generation projections.
The ongoing transformation within the SEE electricity markets underscores that while hydropower remains integral to the region’s energy framework, its role is no longer defined by stability alone but rather by its ability to adapt dynamically within an increasingly complex market structure.
