Hydropower was the single most important stabilising and price-shaping asset class in South-East Europe during January, not because it delivered the largest absolute volume of energy, but because it controlled the timing of energy. In a month defined by evening ramp stress, constrained imports, and repeated scarcity pricing on power exchanges, hydro reservoirs and cascades functioned as the region’s primary flexibility buffer, absorbing volatility when conditions allowed and monetising it when the system tightened.
Across the Western Balkans and Romania, January hydrology was not extraordinary in aggregate volume terms, but it was decisive in operational terms. Systems with reservoir hydro entered the month with sufficient water to provide daily and intra-day balancing, even as wind output oscillated sharply and solar remained seasonally constrained. This meant that hydro plants were repeatedly dispatched not as baseload energy suppliers, but as shape assets, targeting the same evening hours that drove power prices on SEEPEX, CROPEX, and OPCOM into triple-digit territory.
Serbia’s hydro fleet, dominated by large reservoir and cascade plants operated by EPS, played a particularly visible role. With more than 3 GW of installed hydro capacity, Serbia’s system used hydro strategically during January to defend peak adequacy rather than maximise raw generation. This behaviour is visible indirectly in SEEPEX pricing: baseload averages of €118.13/MWh coexist with peak extremes approaching €294/MWh, indicating that hydro was not flattening the curve completely but was instead deployed selectively. When hydro withheld water during off-peak or energy-long hours, prices softened toward the €60–70/MWh band; when hydro released into evening ramps, it capped prices that might otherwise have cleared even higher under import constraint conditions.
In Croatia, hydropower’s influence was similar but structurally more exposed to regional coupling. Croatia’s system relies on a mix of reservoir and run-of-river hydro, but with higher dependence on imports during stress periods. January CROPEX averages of €143.16/MWh baseload and €165.66/MWh peak reflect a market where hydro mitigated volatility but could not fully neutralise it once interconnectors tightened. Hydro generation reduced the frequency of scarcity events, but when imports from neighbouring systems were constrained, Croatian hydro alone was insufficient to prevent peak repricing into the upper band.
Romania’s case demonstrates how hydro interacts with nuclear and cross-border flows rather than acting in isolation. Romania entered January with hydro availability that was operationally adequate but not abundant enough to dominate the stack. Hydro therefore functioned primarily as a balancing layer on top of nuclear baseload and gas-fired generation. Despite this, OPCOM cleared at the highest regional averages, €150.51/MWh baseload and €176.60/MWh peak, underscoring a critical point: hydro stabilises volatility, not necessarily price level. When a system is frequently tight on imports or flexibility, hydro smooths the spikes but cannot eliminate a structurally high marginal cost.
The most dramatic illustration of hydro’s dual role appeared in Montenegro. The Montenegrin system, centred on a small number of hydro assets and almost entirely dependent on imports for marginal balance, exhibited extreme price dispersion on MEPX. January produced baseload days as low as €18.79/MWh and as high as €156.24/MWh, with peak days ranging from €26.12/MWh to €186.38/MWh. These swings are best explained by hydro dispatch decisions interacting with import availability. When hydro and imports aligned, Montenegro cleared at implausibly low prices; when either element tightened, the absence of thermal or gas-fired backup forced rapid repricing. Hydro in this context was not just a stabiliser but a multiplier of outcomes, amplifying both the lows and the highs.
From a regional perspective, hydropower’s January impact was therefore asymmetric. It reduced the duration of scarcity but not its value. The fact that SEE markets still printed peak prices well above €200/MWh indicates that hydro reservoirs were preserved for system security rather than exhausted to suppress prices. This behaviour is economically rational in a winter context: water has option value, and hydro operators optimise across weeks, not hours.
In trading and portfolio terms, hydro owners were among the clearest winners of January. The spread between off-peak prices near €60–70/MWh and peak prices exceeding €170–290/MWh allowed hydro to monetise shape repeatedly. Conversely, systems with limited or no hydro flexibility paid a structural premium. This explains why markets with strong hydro participation showed lower volatility amplitude but still shared in the region-wide scarcity pricing regime.
January confirms that in South-East Europe, hydropower is no longer a simple “cheap energy” source. It is the region’s primary flexibility asset, and its strategic deployment determines how scarcity is priced, how long it lasts, and who captures its economic value.
