Hydropower entered July 2026 as Southeast Europe’s most important flexible renewable resource, while also facing tighter constraints. Prolonged heat and drought reduced river flows and generation in several major markets as cooling demand increased and solar-heavy systems needed dispatchable power after sunset. In that setting, the impact extends beyond lower renewable electricity volumes. It also affects the ability to respond quickly during evening peaks and periods of system stress.
When hydro conditions deteriorate, gas, coal, imports and storage are required to replace both generation and operational flexibility. July’s water conditions became a variable for regional power markets, with the Danube providing a clear physical signal. Romanian water levels fell to their lowest since 1996, with river flow at the country’s entry point measured at approximately 1,700 cubic metres per second versus a July average of around 4,700 cubic metres per second. The low water affected irrigation, ferry services, grain shipping and tourism, while reservoirs were managed partly to safeguard nuclear cooling requirements.
Weekly and daily generation shifts during low-water conditions
The deterioration in the power sector was visible in weekly generation data. Regional hydropower output fell 4.7% to 3.57 TWh during Week 25, with reductions reported in Italy, Bulgaria and Romania. Over the same period, regional electricity demand rose 3.1%, thermal generation increased 19.4%, and gas-fired output rose 32.3%.
Hydro generation declined further week on week in Week 26. Regional hydropower output dropped 2.8% to 3.51 TWh, with Türkiye’s output falling 5.9%, removing 142 GWh from the regional total. Bulgarian hydropower generation fell 44.6%, while Serbia, Croatia and Greece recorded increases that reflected recovery from comparatively low prior levels in some cases.
A July 10 daily snapshot showed hydro output falling by approximately 520 MW to 4,871 MW. Regional demand reached 31,291 MW, while gas, coal and nuclear together supplied substantially more electricity than hydropower on that day. The figures illustrate how quickly reduced water availability can shift the generation mix toward thermal and other firm sources.
The regional averages do not imply uniform dryness across all river basins or a direct link between river flow and every plant’s output. Reservoir storage levels, local rainfall patterns, plant design choices, operator strategy and cross-border obligations can all affect results. The uneven national outcomes indicate that aggregated data can conceal differences between individual systems.
Dispatch value depends on timing as well as volume
The value of hydropower increasingly depends on timing rather than total energy alone. In solar-heavy electricity systems, reservoir hydropower’s key feature is not limited to how much it produces over a 24-hour period. It also includes the ability to retain water during low-price periods and generate when solar output declines and demand remains elevated. Neighboring markets seeking imports can further influence when hydro is dispatched.
This creates a trade-off between price capture and total production availability during dry conditions. Dry weather can increase the market value of each dispatchable hydro megawatt-hour while reducing the number of megawatt-hours available for sale. A generator may record higher peak prices while producing less overall electricity and facing greater uncertainty about future reservoir levels.
The distinction between plant types shapes how operators respond to changing water availability. Run-of-river facilities are closely tied to immediate river flows and have limited ability to choose generation timing. Reservoir plants can shift output across hours, days or seasons within constraints set by water levels and downstream obligations. Pumped-storage facilities can arbitrage electricity prices but consume more electricity while pumping than they later return and do not create additional water or net energy.
Gas marginality risk rises when hydro weakens
The region is also losing a hedge against gas prices and electricity imports as hydro availability falls. Hydropower typically limits the number of hours when gas-fired generation becomes marginal in the merit order. When hydro output weakens, gas plants are called more frequently, particularly during the evening transition from strong photovoltaic production to peak residential and cooling demand.
Week 26 showed this linkage across multiple markets . Lower hydro availability increased reliance on thermal generation and cross-border supply in Greece, Romania and Serbia as well as neighboring systems. Bulgaria remained a major exporter despite its sharp hydro decline, while other domestic generation compensated to support export commitments.
The effect becomes more pronounced when gas prices rise . A hydro shortfall during a low-gas-price period may be manageable for system costs. The same shortfall when European gas approaches €60/MWh can have a larger impact on wholesale electricity prices because replacement generation carries higher fuel costs.
Drought turns water allocation into an energy policy constraint
Water allocation is increasingly treated as an energy-policy issue as drought affects multiple uses of shared resources . July’s Danube conditions highlighted competition between energy users and non-energy users for the same water system components used for conventional hydropower and pumped storage as well as nuclear cooling needs. The same system also supports agriculture, freight transport, tourism, ecosystems and community water needs.
This creates policy and contractual complexity for operators balancing competing requirements . Maximizing short-term electricity production may conflict with maintaining navigation depths, irrigation supplies, ecological flows or cooling reserves. On cross-border rivers, upstream decisions can influence downstream generation potential and available water for power production.
Hydropower valuations therefore require more than historic production averages . Investors are expected to assess water-management rules, bilateral treaties, climate scenarios, environmental constraints and how priority is assigned to competing uses during drought conditions. A plant’s installed capacity may remain unchanged even if dependable summer energy output falls substantially.
Pumped-storage plans advance alongside asset modernization debates
Pumped storage has moved toward the center of regional investment discussions after renewed cooperation between Serbia and Romania . The July project signal was a refreshed initiative for Iron Gate III, known in Serbia as Đerdap 3. On July 16, the two governments signed a memorandum to exchange information and assess potential joint pumped-storage development upstream of the existing Iron Gate I complex.
Serbia plans spatial planning and technical documentation work during 2026 following the memorandum . Final project parameters including configuration details such as number of units, installed capacity and reservoir size have not been determined yet. Feasibility work is expected to define those elements along with front-end engineering and design expected to last 36 months. A preliminary completion objective of 2036 was reported alongside an indicative investment estimate exceeding €2.63 billion, with cost and timetable subject to further studies.
The project is not yet positioned as committed capacity because key items remain unresolved . Bilateral water governance arrangements, environmental studies, hydrological modelling requirements, financing structures, transmission upgrades and treatment of impacts on existing Danube plants are still under discussion. The memorandum advances coordination but does not represent a final investment decision.
Turbine refurbishment, efficiency improvements and digitalized reservoir dispatch are among modernization approaches discussed alongside new development . Capacity uprates and pumping capability between established reservoirs are described as options that can deliver benefits with lower permitting and environmental risk than building a new large dam at a greenfield site. Existing locations often have grid connections and established water rights that may reduce barriers compared with new infrastructure facing longer environmental reviews and stronger public scrutiny.
Monitoring shifts from installed capacity to hydrological trajectories
The region’s assessment framework increasingly focuses on dependable flexible output under realistic dry-year conditions rather than headline installed capacity alone . Hydropower remains central to Southeast European electricity markets but its role changes across seasons: wet periods support large volumes of relatively low-cost renewable electricity while dry periods require allocation of limited strategic reserves across highest-value hours and essential water uses.
For the remainder of summer 2026, market participants are expected to track rainfall patterns, reservoir trajectories, river flows and operator dispatch rather than rely only on installed hydropower capacity . Continued drought would be expected to reinforce evening power premiums along with higher gas consumption and import requirements. Meaningful rainfall could reverse conditions comparatively quickly in systems with substantial reservoir storage.
The long-term investment message highlighted in the source material is that hydropower should be assessed as climate-exposed infrastructure . Projects able to store energy reliably across wider ranges of hydrological conditions would command a premium over assets whose economics depend heavily on historical average inflows . In Southeast Europe, value is described as shifting from megawatts installed toward how reliably those megawatts can be delivered when systems need them most.
