The summer of 2026 has turned hydrology from an operating variable into a regional energy-security concern. Serbia’s Đerdap 1, the country’s largest hydropower plant, was producing only around 5,000 MWh per day in late July—roughly one-third of its normal output—as prolonged heat and drought pushed the Danube toward historic lows.
May and June were reportedly the plant’s weakest production months since its opening in 1970. By early August, inflows were expected to approach 1,500 cubic metres per second, close to the biological minimum. At the same time, low water levels restricted barge loading to just 30–40% of capacity and complicated cooling operations at Serbia’s Kostolac coal complex. A single climatic event was therefore simultaneously reducing renewable generation, disrupting fuel transport and putting additional pressure on thermal power plants.
The episode highlights a growing weakness in how Southeast Europe has traditionally valued hydropower. Large plants have long been viewed as dependable domestic resources capable of reducing fuel imports and providing flexible generation. They remain important for both functions, but historical production is becoming a less reliable indicator of future output. Hotter summers, lower river flows and increasingly variable precipitation can reduce hydropower generation precisely when electricity demand for cooling is at its highest and solar production declines in the evening.
This does not make hydropower less valuable. Instead, it makes flexibility, reservoir management and climate adaptation more important. Reservoir-based plants can respond quickly to changes in demand, while run-of-river facilities remain directly exposed to available water volumes. Operators will increasingly need better seasonal forecasting, coordinated management across borders and operating rules that treat ecological flows as binding system constraints rather than optional environmental considerations.
The Danube is a shared energy artery for the region. Lower output at Đerdap increases Serbia’s need for electricity imports, with potential consequences for prices and power flows in Romania, Bulgaria, Hungary and the wider Western Balkans. At the same time, low river levels threatened cooling-water supplies at Romania’s Cernavodă nuclear plant and reduced output at Hungary’s Paks facility. The 2026 episode demonstrates that even a diversified generation mix can face correlated climate risks when multiple technologies depend on the same river basin.
Investment priorities should therefore adapt to the new reality. Turbine refurbishment can increase the amount of electricity generated from each unit of water, while digital controls can improve dispatch and operational efficiency. Batteries can help preserve hydro reservoirs during prolonged shortages by managing intra-day fluctuations in supply and demand. Additional cross-border interconnection can also spread local shocks across a wider electricity market. None of these measures can create water, but each can reduce the economic impact of water scarcity.
New hydropower projects should also be stress-tested against future hydrological conditions rather than relying primarily on twentieth-century averages. Expected generation, debt-service capacity and environmental impacts can all change if drought years become more frequent. A project that appears inexpensive on a cost-per-megawatt basis may ultimately prove expensive per delivered megawatt-hour if water availability has been overstated.
The key lesson from Southeast Europe’s 2026 experience is therefore not that hydropower has failed. It is that water can no longer be treated as a constant. The region’s hydropower fleet remains one of its most valuable sources of renewable flexibility, but its future contribution will increasingly depend on climate-resilient operation, modernised equipment and stronger integration with battery storage and cross-border electricity markets.
