In January, hydropower emerged as a crucial stabilizing force in the energy markets of South-East Europe, particularly amid challenging conditions characterized by evening demand spikes, limited imports, and frequent scarcity pricing. While not necessarily the largest contributor in terms of total energy volume, hydropower played a vital role in managing the timing of energy delivery across the region.
The hydrological conditions in the Western Balkans and Romania during January were adequate for operational needs but did not present extraordinary volumes. Reservoir hydro systems entered the month with sufficient water reserves, enabling them to provide essential daily and intra-day balancing. This operational flexibility allowed hydro plants to be dispatched strategically, focusing on peak evening hours that significantly influenced power prices on exchanges such as SEEPEX, CROPEX, and OPCOM, leading to instances of triple-digit pricing.
Serbia’s hydroelectric capacity, primarily managed by EPS with over 3 GW of installed capacity, was particularly influential. The country utilized its hydro resources strategically to maintain peak adequacy rather than simply maximizing output. This selective deployment is reflected in the pricing dynamics on SEEPEX, where baseload averages reached €118.13/MWh while peak prices soared to nearly €294/MWh. During off-peak hours, when water was withheld, prices softened to around €60–70/MWh; conversely, strategic releases during high-demand periods helped cap prices that could have otherwise escalated further due to import constraints.
In Croatia, the impact of hydropower was similarly significant but faced greater exposure to regional interconnections. The Croatian electricity system relies on a combination of reservoir and run-of-river hydro sources but is more dependent on imports during periods of stress. The average prices on CROPEX for January were €143.16/MWh for baseload and €165.66/MWh for peak demand, indicating that while hydropower mitigated some volatility, it could not fully counteract the effects of tightened interconnections when imports from neighboring countries were limited.
Romania’s situation highlighted how hydropower interacts with other generation sources such as nuclear and gas. The country began January with sufficient hydro availability to support operations but not enough to dominate the energy stack entirely. Hydro resources primarily served as a balancing mechanism atop a foundation of nuclear baseload and gas-fired generation. Consequently, OPCOM recorded high regional averages of €150.51/MWh for baseload and €176.60/MWh for peak periods, illustrating that while hydropower can stabilize price volatility, it does not necessarily lower overall price levels in tight market conditions.
Montenegro presented an extreme case of hydropower’s dual role within its energy market dynamics. With a limited number of hydro assets and heavy reliance on imports for marginal balance, Montenegro experienced significant price fluctuations throughout January. Baseload prices varied from €18.79/MWh to €156.24/MWh, while peak prices ranged from €26.12/MWh to €186.38/MWh. These variations can be attributed to the interplay between hydro dispatch decisions and import availability; when both aligned favorably, prices dropped dramatically, whereas constraints led to rapid repricing due to the lack of thermal or gas-fired backup.
Regionally, hydropower’s influence in January was asymmetric—while it reduced the duration of scarcity events, it did not diminish their value significantly. The persistence of peak prices above €200/MWh indicates that hydro reservoirs were maintained for system security rather than fully utilized to suppress market prices. This approach reflects an economically rational strategy within a winter context where water resources are viewed as having option value; operators tend to optimize their usage over longer time frames rather than hourly demands.
From a trading perspective, hydro owners benefitted notably throughout January due to favorable price spreads between off-peak levels around €60–70/MWh and peak prices exceeding €170–290/MWh. This scenario enabled them to capitalize on their ability to shape supply effectively. In contrast, systems lacking hydro flexibility faced structural premiums in pricing dynamics. As a result, markets with robust hydro participation exhibited lower volatility yet remained integrated into the broader regional scarcity pricing framework.
The developments observed in January underscore that hydropower has evolved beyond being merely a cost-effective energy source in South-East Europe; it has become an essential flexibility asset whose strategic deployment influences how scarcity is priced and who benefits economically from these dynamics.
