Southeast Europe entered the second half of July with a power system that appeared adequately supplied at the aggregate level, but showed increasing signs of structural vulnerability. Average electricity demand across Hungary and Southeast Europe rose from 31,520 MW in the first half of July to 31,732 MW in the second half. Generation expanded across all major technologies.
Even with stronger overall supply, spot electricity prices continued rising and cross-border price differences widened. The region remained a net importer. The main issue was not the total volume of electricity available, but the timing, flexibility and geographical availability of generation during critical periods.
Demand growth, generation mix and thermal output changes
The system increasingly depended on resources able to respond during evening demand peaks and during periods of lower renewable output. These conditions coincided with declining solar generation and hydrological constraints that reduced flexible power availability. The regional generation mix averaged 22% solar, 21% coal, 18% nuclear, 17% hydro, 15% gas and 7% wind.
Wind generation recorded the largest increase between the two half-month periods, rising by 477 MW. Solar output increased by 87 MW. Thermal generation also expanded during the same interval.
Gas-fired output increased by 142 MW, while coal generation rose by 84 MW. This indicated that higher renewable production did not remove the need for dispatchable conventional capacity. Summer conditions also affected operational constraints for non-thermal sources.
Price movements across national markets and cross-border effects
Higher summer temperatures, lower hydrological availability and nuclear cooling risks strengthened the role of thermal generators, particularly during evening hours and when renewable output was limited. Electricity prices therefore remained influenced by the cost of flexible generation rather than by low marginal cost solar power at midday. Hungary’s HUPX baseload price averaged €124.03/MWh, up €3.48/MWh versus the first half of July.
Romania averaged €121.72/MWh, Serbia €111.16/MWh, Croatia €122.99/MWh, Slovenia €126.85/MWh and Montenegro €122.74/MWh. The strongest increase outside the immediate Southeast European region was Italy at €172.22/MWh, more than €31/MWh higher than in the previous period. Austria also recorded higher prices, rising to €125.49/MWh.
Greece was the regional exception, with prices declining to €108.34/MWh as its renewable share increased. Lower Greek prices did not produce full market convergence because transmission limitations and different national supply conditions continued to separate regional markets.
Regional balance, exports to Italy and commodity cost pressure
The overall regional balance improved while price differences remained significant. Hungary and Southeast Europe continued operating as net importers with an average deficit of 1,216 MW, although the gap narrowed by 533 MW. Exports towards Italy increased to 1,108 MW, up by 275 MW.
This reflected two simultaneous market dynamics: a structurally constrained Central and Southeast European system alongside a more expensive Italian market absorbing available supply. Cross-border transmission capacity remained crucial for determining electricity flows and where scarcity premiums emerged. Physical interconnection availability increasingly influenced outcomes alongside generation costs.
Commodity markets added further pressure through higher gas prices and carbon costs. Average CEGH gas prices increased to €60.65/MWh, rising by more than €12/MWh, while Greek gas prices averaged €48.61/MWh. EU carbon allowances climbed to €82.07/tCO₂.
At these levels, a modern combined-cycle gas turbine operating at around 55% efficiency faced fuel costs exceeding €110/MWh before carbon costs, operating expenses and start-up costs are included. Coal-fired generation also carried significant carbon exposure, potentially adding €70–90/MWh depending on efficiency and emissions intensity.
Drought impacts on hydro, thermal cooling and nuclear operations
Hydrological conditions shifted normal summer tightening into a wider regional stress event affecting multiple technologies at once. Danube inflows at Serbia’s Đerdap hydropower complex declined to around 1,500 cubic metres per second, reducing output at one of Serbia’s most important generation assets. Đerdap 1 operated at approximately 20% of installed capacity while Đerdap 2 operated at around 30%.
Lower river levels also affected cooling conditions at the Kostolac thermal power complex, forcing some units to reduce output by around one-third. Romania disconnected Unit 1 of the Cernavodă nuclear power plant under drought-related operating procedures while Unit 2 continued operating under enhanced monitoring. Hungary’s Paks nuclear power plant reduced production as Danube water temperatures and levels approached operational limits.
Slovenia expected a significant decline in hydropower generation while Bosnia and Herzegovina’s Ugljevik thermal power plant remained unavailable due to coal supply challenges and technical issues. The drought-related situation illustrated correlation risk across hydro, coal and nuclear generation during extreme conditions when all can be affected simultaneously.
Flexibility needs for evening peaks amid renewables growth
A single hydrological event can reduce availability across multiple generation technologies at the same time by limiting hydropower energy availability, constraining river-cooled thermal plants and bringing nuclear facilities closer to environmental operating limits. Solar generation supports daytime hours but cannot fully cover the evening demand ramp without additional energy storage, flexible gas capacity and stronger regional interconnections.
The remainder of the summer kept electricity price risks concentrated during evening peaks, low-wind periods and periods of reduced cross-border availability. The improvement in regional supply balance did not indicate comfortable reserve margins because the system relied on stronger wind output alongside higher gas and coal production plus continued imports while several major dispatchable assets operated below normal capability.
The market environment pointed towards increasing intraday price volatility as low or even negative midday prices remained possible during strong solar production periods while scarcity premiums could rise rapidly once solar output declined and conditions returned to water-constrained or fuel-intensive generation settings.
