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 increased only marginally, from 31,520 MW in the first half of July to 31,732 MW in the second half, while generation expanded across all major technologies.
Despite stronger overall supply, spot electricity prices continued rising, cross-border price differences widened and the region remained a net importer. The key challenge was not the total volume of electricity available, but the timing, flexibility and geographical availability of generation during critical periods.
The system increasingly relied on resources capable of responding during evening demand peaks and periods of lower renewable output, when solar generation declined and hydrological constraints reduced the availability of flexible power.
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, while solar output increased by 87 MW.
However, thermal generation also expanded. Gas-fired output increased by 142 MW, while coal generation rose by 84 MW, showing that additional renewable production did not eliminate the need for dispatchable conventional capacity.
Higher summer temperatures, lower hydrological availability and nuclear cooling risks strengthened the role of thermal generators, particularly during evening hours and periods of limited renewable production. As a result, electricity prices remained influenced by the cost of flexible generation rather than by the low marginal cost of midday solar power.
Hungary’s HUPX baseload price averaged €124.03/MWh, increasing by €3.48/MWh compared with 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 price increase occurred outside the immediate Southeast European region, with Italy reaching €172.22/MWh, more than €31/MWh higher than in the previous period. Austria also recorded higher prices, rising to €125.49/MWh.
Greece remained the regional exception, with prices declining to €108.34/MWh due to its increasing share of renewable generation. However, lower Greek prices did not lead to full market convergence because transmission limitations and different national supply conditions continued to separate regional markets.
The overall regional balance improved, but price differences remained significant. Hungary and Southeast Europe continued to operate as net importers, with an average deficit of 1,216 MW, although the gap narrowed by 533 MW.
At the same time, electricity exports towards Italy increased to 1,108 MW, up by 275 MW, highlighting the continued pull of high Italian prices. The region therefore experienced two simultaneous market dynamics: a structurally constrained Central and Southeast European system and a more expensive Italian market absorbing available supply.
Cross-border transmission capacity remained a crucial factor in determining where electricity could flow and where scarcity premiums emerged. Physical availability of interconnections increasingly influenced market outcomes alongside generation costs.
Commodity markets added additional pressure. 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 faces fuel costs exceeding €110/MWh before carbon costs, operating expenses and start-up costs are included. Coal-fired generation also faced significant carbon exposure, potentially adding €70–90/MWh depending on efficiency and emissions intensity.
The electricity market was therefore increasingly supported by higher-cost thermal generation, rather than by low-cost renewable electricity available during daytime hours.
Hydrological conditions turned normal summer market tightening into a wider regional stress event. Danube inflows at Serbia’s Đerdap hydropower complex declined to around 1,500 cubic metres per second, reducing output at one of the country’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 also 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 a combination of coal supply challenges and technical issues.
The situation highlights a broader system correlation risk that traditional adequacy assessments often underestimate. Hydro, coal and nuclear generation are normally viewed as separate sources of reliable capacity, but extreme drought conditions can affect all three simultaneously.
Hydropower loses available energy, river-cooled thermal plants face operational restrictions and nuclear facilities may approach environmental operating limits. A single hydrological event can therefore reduce the availability of multiple generation technologies at the same time.
Solar generation provides valuable support during daylight hours, but it cannot fully cover the evening demand ramp without additional energy storage, flexible gas capacity and stronger regional interconnections. The growth of renewables is therefore increasing the importance of flexibility rather than simply expanding generation capacity.
For the remainder of the summer, electricity price risks are expected to remain concentrated during evening peaks, low-wind periods and periods of reduced cross-border availability.
The improvement in regional supply balance should not be interpreted as evidence of comfortable reserve margins. The system relied on a combination of stronger wind generation, higher gas and coal output and continued imports, while several major dispatchable assets operated below normal capability.
The current market environment points towards increasing intraday price volatility. Low or even negative midday prices remain possible during periods of strong solar production, but scarcity premiums can rise rapidly once solar output declines and the system returns to water-constrained or fuel-intensive generation conditions.
