Southeast Europe entered the second half of July with a power system that appeared sufficiently supplied on the surface but showed increasing signs of underlying vulnerability. Average electricity demand across Hungary and Southeast Europe increased only slightly, from 31,520 MW in the first half of July to 31,732 MW in the second period, while generation expanded across all major technologies. Despite this, spot electricity prices continued rising, cross-border price differences widened and the region remained a net importer.
The main challenge was not the total amount of electricity produced, but the quality, location and availability of generation during critical hours. The system increasingly depended on resources capable of responding during evening demand peaks and periods of lower renewable output, when solar generation declined and hydrological limitations reduced flexibility.
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, gas-fired generation also increased by 142 MW and coal generation by 84 MW, showing that additional renewable production did not remove the need for dispatchable thermal capacity.
Higher summer temperatures, hydrological restrictions and nuclear cooling risks pushed thermal generators into a stronger market role, particularly during evening hours and periods of limited renewable availability. As a result, electricity prices remained influenced by the cost of flexible conventional generation rather than by the low marginal cost of daytime solar output.
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 largest price increase occurred outside the immediate Southeast European cluster, with Italy reaching €172.22/MWh, more than €31/MWh higher than in the previous period. Austria also increased to €125.49/MWh.
Greece was the regional exception, with prices falling to €108.34/MWh due to a generation mix where renewable sources already cover a significant share of annual electricity production. However, lower Greek prices did not translate into full regional convergence because transmission limitations and different supply conditions continued to separate markets.
The regional balance improved, but price convergence remained limited. Hungary and Southeast Europe stayed net importers by an average of 1,216 MW, although the deficit narrowed by 533 MW. Electricity exports towards Italy increased to 1,108 MW, up by 275 MW, showing that high Italian prices continued attracting Balkan electricity westward, even while the region itself relied on imports from Austria and Slovakia.
Commercial flows therefore reflected two simultaneous market conditions: a structurally short Central and Southeast European region and an even more expensive Italian market absorbing available supply. Cross-border capacity remained a decisive factor in determining where electricity could flow and where scarcity premiums emerged.
Commodity markets added further pressure. Average CEGH gas prices increased to €60.65/MWh, rising by more than €12/MWh, while Greek gas averaged €48.61/MWh. EU carbon allowances climbed to €82.07/tCO₂. At these input levels, a modern combined-cycle gas turbine with approximately 55% efficiency faces fuel costs above €110/MWh before including carbon costs, operational expenses and start-up costs.
Coal-fired generation also faced significant carbon-related costs, which could add roughly €70–90/MWh depending on plant efficiency and emissions intensity. The resulting electricity prices therefore reflected a market increasingly supported by high-cost thermal generation, rather than by low-cost renewable production during daytime hours.
Hydrological conditions transformed normal summer tightening into a broader regional stress situation. Danube inflows at Serbia’s Đerdap hydropower complex fell to around 1,500 cubic metres per second. Đerdap 1 operated at approximately 20% of installed capacity, while Đerdap 2 operated at around 30%. Lower river levels also reduced cooling capacity at Kostolac, where several thermal units reduced output by approximately one-third.
Romania disconnected Unit 1 of the Cernavodă nuclear power plant under severe drought procedures, while Unit 2 continued operating only under enhanced monitoring. Hungary’s Paks nuclear power plant also reduced production as Danube temperatures and water levels approached operational limits. Slovenia expected a significant decline in hydropower output, while Bosnia and Herzegovina’s Ugljevik thermal power plant remained unavailable due to a combination of coal supply problems and technical issues.
These events highlight a broader correlation risk that traditional power adequacy assessments often underestimate. Hydro, coal and nuclear generation are normally considered separate sources of firm capacity, but extreme drought conditions can affect all three simultaneously. Hydropower loses available energy, river-cooled thermal plants face operational restrictions, and nuclear reactors may approach environmental and safety limits.
Solar generation provides valuable daytime support, but it cannot fully cover the evening demand ramp without additional energy storage, flexible gas capacity or stronger regional interconnections. The increasing share of renewables therefore raises the importance of flexibility rather than simply adding more generation capacity.
For the remainder of the summer, electricity price risks are expected to remain concentrated during evening peak periods, low-wind conditions and periods of reduced cross-border availability. The reduction in regional import requirements should not be interpreted as evidence of abundant reserve capacity.
The improved balance was achieved through a combination of stronger wind output, higher gas and coal generation and continued imports, while several major dispatchable assets operated below normal capability. The current market signal points towards greater 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.
