Water availability has become a direct electricity-market variable across Europe during the summer of 2026. Record-low river levels are simultaneously reducing hydropower output, restricting nuclear cooling systems and widening the gap between low-priced solar hours and increasingly expensive evening electricity. The impact is particularly visible across Central and Southeast Europe, where the Danube supports hydropower generation, nuclear cooling, industrial activity and cross-border transport.
The European Commission’s Joint Research Centre has reported record-low August water levels on the Danube, Rhine, Loire and Po, while around 50% of the EU and the UK was experiencing some degree of drought and 9% had reached the most severe alert level. Forecasts continued to point towards warmer and drier conditions through August and into September.
This is no longer a conventional generation outage affecting a single plant or fuel. It is a correlated hydrological shock. Low water reduces hydroelectric generation while simultaneously limiting cooling-water availability for nuclear plants. Heatwaves then increase air-conditioning demand at precisely the time when hydro and nuclear availability is weakening. Stagnant high-pressure conditions can also reduce wind generation, leaving gas, coal, imports, batteries and demand response to cover the evening system.
Hydropower is directly dependent on river flows, hydraulic head and turbine efficiency. Run-of-river plants feel the impact almost immediately because lower discharge means less water passing through turbines and fewer megawatt-hours generated. Reservoir-based plants have greater flexibility, but operators must decide whether to use stored water during the summer or preserve it for evening peaks, emergency balancing and the winter season.
Nuclear plants face a different constraint. The reactor and nuclear fuel can remain fully operational, while the conventional part of the plant requires large volumes of cooling water to condense steam after it passes through the turbines. Low river levels can place water intakes and pump systems outside their normal operating range, while high river temperatures can restrict the amount of heated water that can be discharged back into the river.
The clearest example is Romania’s Cernavodă nuclear power plant. Unit 1 had already been shut down as Danube levels deteriorated, while Nuclearelectrica began the controlled shutdown of Unit 2 on the morning of 13 August because of the continuing decline in river levels. Each reactor has approximately 700 MW of installed capacity, meaning around 1.4 GW of Romanian baseload generation became unavailable. Both units remained in a safe shutdown condition, with no reported impact on personnel, the public or the environment.
Cernavodă normally provides approximately one-fifth of Romania’s electricity requirements, making the outage materially more significant than the loss of a small thermal unit. It increases import requirements, removes a major source of low-variable-cost generation and raises balancing exposure during evening demand peaks. Nuclearelectrica has also obtained force-majeure certificates covering electricity-delivery contracts because the severe Danube drought prevented the company from meeting all contracted supply obligations from its own generation.
The issue has therefore moved beyond plant operations into contractual, counterparty and earnings risk.
Hungary is experiencing a similar problem at the 2,000 MW Paks nuclear power plant, which normally supplies close to half of the country’s domestic electricity. Low Danube levels forced Units 1, 3 and 4 to shut down, while Unit 2 operated at half output for 11 days before gradually increasing production on 10 August. An official government update dated 13 August said Paks was operating at only around 500 MW, or 25% of installed capacity, while the Danube was again expected to decline.
The Paks situation demonstrates that the critical issue is not simply the total volume of water flowing through the river. Plant operator MVM has explained that sufficient water could theoretically remain available for cooling, but the river level had fallen below the effective suction elevation of existing pumps. Operating units require roughly 100 cubic metres of water per second, while the four shut units require only around 2.5 cubic metres per second for residual cooling.
The plant was operating with the river approximately 28 centimetres below the previous 2018 record and more than one metre below the century-minimum level assumed when Paks was designed more than four decades ago.
Hungary has responded with an emergency river-engineering programme. The government approved a bed sill requiring approximately 145,000 cubic metres of rock, with two 80-metre barges prepared as an additional temporary measure. The intervention is expected to cost around HUF6.1 billion, while the government estimates that a complete shutdown of Paks could impose a burden of at least HUF50 billion per month.
The comparison illustrates the growing economics of climate adaptation. Relatively modest investment in water-intake resilience can protect generation assets whose replacement-power costs can be many times higher.
Further downstream, the same Danube shortage is cutting Serbian hydropower production. Elektroprivreda Srbije reported that Đerdap 1 was producing only around 20% of its usual output, with inflows falling to approximately 1,400 cubic metres per second. Đerdap 2 was operating at around 30%. Đerdap 1 has 1,140 MW of installed capacity and historically received average Danube inflows of around 5,370 cubic metres per second.
EPS expected Serbian electricity demand to approach 100 GWh per day during the heatwave and said around 10% of requirements were being procured from the market to compensate for missing hydroelectric generation. Thermal plants were carrying a larger share of domestic demand, while EPS sought to preserve reservoir stocks and coal inventories ahead of winter.
Serbia is therefore exposed on two fronts: directly through lower Đerdap production and indirectly through reduced nuclear availability in neighbouring Hungary and Romania. The loss of inexpensive regional generation limits the amount of electricity available for import precisely when Serbian demand is elevated.
The situation also challenges the traditional assumption that cross-border imports will automatically compensate for domestic weather-related outages. Interconnectors can transfer electricity, but they cannot create additional generation when several interconnected markets experience the same weather shock. Romania, Hungary and Serbia can all require additional imports during the same evening hours, bringing Austria, Slovakia, Croatia and Bulgaria into the same price-formation chain.
Transmission congestion then determines where the scarcity premium appears.
The wider European power system remains broadly adequate. ENTSO-E’s pre-summer assessment identified no major systemic adequacy threat across most of Europe, supported by expanding renewable generation, stronger cross-border coordination and growing battery capacity. Battery capacity had reached approximately 29 GW, while expected European hydro storage at the beginning of the season was already 18% below June 2025 levels. Summer electricity demand was forecast to rise by around 2.5% year on year.
The subsequent deterioration in river conditions highlights the difference between having sufficient capacity at the European level and having available capacity in the right region and at the right hour.
France provides an important counterexample. Water constraints do not make nuclear generation structurally unreliable. French electricity production reached 284.3 TWh in the first half of 2026, up 4.6%, while nuclear output increased by 7.9 TWh and average nuclear availability reached 73.9%.
Nevertheless, RTE has acknowledged that heatwaves and prolonged drought can temporarily restrict individual river-cooled reactors because of water-flow and discharge-temperature limits. At fleet level, these losses remain relatively small, but their impact on prices can become significant when they coincide with heat-driven demand and weak wind generation.
The market impact is becoming most visible in hourly price structures rather than monthly averages. The International Energy Agency expects EU electricity consumption to increase by around 2% in 2026, supported by electrification and higher cooling demand. Average EU spot prices in the second quarter were already more than 30% above the previous year, partly because of higher gas-generation costs.
Water-related restrictions on nuclear and hydropower are adding another scarcity factor to a market that is already operating with elevated fuel costs.
Hungary’s HUPX market illustrates the changing price structure. The baseload price for delivery on 15 August was approximately €137.94/MWh, while the conventional peak-load block averaged only €101.59/MWh. Intraday prices for 16 August were around €40–60/MWh during solar-rich midday periods before rising towards approximately €200/MWh during the evening.
Serbia displayed an even sharper pattern on 15 August, with the SEEPEX day-ahead price falling to €0.01/MWh around noon before reaching €182.90/MWh later in the evening.
Romania showed the same structural inversion. The OPCOM baseload block for 16 August stood at around RON717.86/MWh, while the daytime peak block was lower at RON624.92/MWh. The late-night block exceeded RON1,046/MWh. In July, Romania’s day-ahead market had already averaged approximately €120/MWh.
These figures describe an electricity system with surplus solar generation in the middle of the day and increasingly scarce firm electricity after sunset. The traditional assumption that peak hours are automatically the most expensive is becoming increasingly outdated in solar-heavy markets.
The IEA reported that the spread between midday lows and evening highs reached as much as $600/MWh in several European markets during the June heatwaves. Spain recorded negative wholesale prices during 17% of hours in the first half of 2026, compared with 10% during the same period of 2025.
Europe can therefore experience excess electricity and acute scarcity within the same day. Average baseload prices conceal much of the commercial value now moving towards batteries, pumped-storage facilities, flexible hydropower, demand response and fast-starting thermal plants.
Additional solar capacity will help meet daytime cooling demand, but solar alone cannot replace nuclear and hydro generation during the 19:00–23:00 period. Without storage, more photovoltaic capacity can deepen midday price compression while doing relatively little to solve the evening ramp.
Wind offers a different production profile, with lower correlation to solar output and greater potential to generate after sunset. However, wind investment must also account for the possibility that major heatwaves coincide with weak wind conditions across several markets.
The investment response should therefore combine generation, flexibility and water resilience rather than focus on a single technology. EPS has identified a 1 GW solar project, the proposed Niš gas plant, the Bistrica pumped-storage project and the longer-term Đerdap 3 development as components of Serbia’s security-of-supply strategy.
Hungary is accelerating investment in wind, storage and transmission, while Romania’s nuclear programme will increasingly need to incorporate cooling-water resilience into plans for the refurbishment of Cernavodă Unit 1 and the development of additional nuclear capacity.
A potential Southeast European resilience programme for 2027–2032 could require approximately €4–7 billion, although these figures represent analytical ranges rather than announced project budgets. Around €300–800 million could be allocated to deeper nuclear and thermal intakes, pumping systems, cooling optimisation, dredging and river-control infrastructure.
Another €800 million–€1.5 billion could support hydroelectric rehabilitation, reservoir digitalisation and projects designed to increase generation efficiency per cubic metre of water. Approximately €1–2 billion could support 2–4 GWh of battery storage and industrial demand-response infrastructure, with the remainder directed towards pumped storage, transmission reinforcement and strategically important interconnectors.
Battery projects will increasingly depend on their ability to monetise volatility rather than simply provide backup capacity. For a two-hour battery located in a volatile Central or Southeast European market, an illustrative model based on investment costs of €250,000–€400,000 per MWh, 250–300 annual equivalent cycles, a captured spread of €90–130/MWh and additional balancing revenues could produce a nominal equity IRR of approximately 12–16%.
Returns could rise towards 15–20% if evening scarcity remains persistent or capacity payments are introduced. Conversely, a normalisation of spreads towards €50–70/MWh could push returns back towards high-single-digit levels. A 12–18-month grid-connection delay could reduce equity IRR by roughly 2–5 percentage points while increasing effective project costs through interest during construction, equipment escalation and delayed revenues.
Hydropower requires a different investment approach. A reservoir plant may generate fewer annual megawatt-hours during dry periods but can increase the value of each unit of electricity by concentrating production during high-price evening hours. Its value increasingly comes from flexibility, balancing services, black-start capability and avoided scarcity purchases, rather than baseload generation alone.
Run-of-river projects have considerably less flexibility and should therefore be valued using more conservative climate-adjusted production assumptions.
Nuclear projects also require a more explicit hydrological risk premium. Plant valuations, availability guarantees and long-term PPAs should consider intake depth, river-bed erosion, minimum-flow forecasts, water-temperature restrictions and alternative cooling arrangements. Historical capacity factors based on twentieth-century river conditions are no longer sufficient for robust debt sizing or contracted-output guarantees.
The immediate outlook remains dependent on rainfall across the Alps, Central Europe and the Danube basin. Significant precipitation could allow nuclear units to restart and increase hydropower generation, while lower temperatures would reduce cooling demand. However, depleted soils, low river flows and reduced reservoir levels do not recover immediately.
Even after the current operational emergency ends, utilities will enter the autumn with greater sensitivity to reservoir preservation, nuclear availability and replacement-power costs.
Europe’s electricity market is therefore assigning an increasingly visible premium to water that can be converted into a reliable megawatt-hour after sunset. The most valuable assets are no longer necessarily those capable of producing the greatest annual volume, but those that can remain available during the narrow evening window when heat, low river flows and declining solar generation converge.
