June sent a strong signal to Southeast European power markets: late-month heat, surging cooling demand, and limited system flexibility outweighed the impact of lower natural gas prices. Comparing 16–30 June with 1–15 June, electricity prices rose sharply across most regional markets. Hungary’s HUPX climbed to €149.01/MWh, an increase of €48.7/MWh, while Romania’s OPCOM reached €146.80/MWh, up €47.6/MWh. Croatia and Slovenia followed at €136.67/MWh and €134.33/MWh, respectively. Serbia’s SEEPEX increased to €114.87/MWh, Montenegro’s BELEN averaged €108.63/MWh, while Bulgaria and Greece recorded more moderate gains, ending the period at €99.72/MWh and €95.72/MWh, leaving Hungary with the region’s highest price premium.
The primary catalyst was higher electricity demand driven by rising temperatures. Average consumption across the HU+SEE region increased from 28,054 MW in the first half of June to 31,414 MW during the second half, representing a jump of 3,360 MW. At the same time, average temperatures across HU+SEE excluding Greece climbed from 20.3°C to 25.5°C, while Greece warmed from 24.1°C to 26.7°C. As temperatures increased, the market shifted from a renewable-friendly shoulder season into an early-summer period characterized by tighter supply conditions. By the end of June, the region had moved from occasional export surpluses into significant import dependency, with HU+SEE averaging -466 MW in net exports during the second half and falling to -2,682 MW on 30 June.
Power generation expanded across nearly all technologies, but it was not enough to offset the surge in demand. Gas-fired generation increased by 1,177 MW to 4,757 MW, coal output rose by 476 MW to 5,014 MW, nuclear generation climbed by 922 MW to 4,901 MW, while wind and solar production increased by 841 MW and 894 MW, respectively. Hydropower was the only major source to decline slightly, falling by 130 MW to 6,098 MW. Despite this, the regional generation mix remained heavily weighted toward renewables, with solar accounting for 23%, hydro 20%, coal 17%, gas 16%, nuclear 16%, and wind 8%. However, market pricing was increasingly determined by the availability of flexible capacity during evening hours rather than average renewable production.
Perhaps the most significant market development was the growing importance of dispatchability and flexibility. Strong solar production pushed midday electricity prices close to zero or even into negative territory in several markets, while evening price spikes became increasingly extreme. During the reporting period, Hungary recorded a maximum hourly price of €923.1/MWh, Romania €954.6/MWh, Slovenia €1,041.5/MWh, Croatia €946.6/MWh, and Serbia €800/MWh. These price movements demonstrate that regional electricity markets are increasingly valuing storage, ramping capability, interconnector capacity and flexible generation rather than simply total energy output.
Lower fuel costs did little to restrain electricity prices. Average CEGH natural gas prices declined from €49.35/MWh to €43.06/MWh, while Greek gas prices fell from €46.14/MWh to €41.37/MWh. Meanwhile, EU carbon allowance (EUA) prices increased from €77.85/t to €80.31/t. The second-half June price rally was therefore driven primarily by weather conditions, nuclear operating constraints, import dependence and evening residual-load scarcity rather than higher fuel costs.
Hungary emerged as the key stress point within the regional market. Electricity demand reached a new summer peak of 7,488 MW on 29 June, while the Paks Nuclear Power Plant faced temporary operating restrictions after Danube cooling-water temperatures exceeded environmental thresholds. Government authorities granted a temporary exemption that limited the reduction in nuclear output to 40 MW instead of a potential 640 MW, helping stabilize the system. Even so, the combination of exceptional heat, high demand, nuclear cooling challenges and import requirements positioned HUPX as the premium pricing benchmark across Southeast Europe.
Romania highlighted another emerging market trend. Despite setting a new dispatchable solar generation record of 2,952 MW, combined with approximately 1,930 MW of prosumer capacity that pushed total midday solar output close to 5 GW, the country still averaged -637 MW in net imports during the second half of June. This clearly illustrates the widening gap between abundant midday renewable generation and evening supply shortages, reinforcing the investment case for battery storage, flexible gas generation, demand response and stronger transmission infrastructure.
Greece continued to act as the region’s southern balancing hub. Although its average wholesale electricity price remained relatively low at €95.72/MWh, the country averaged 1,385 MW of net exports during the observed period. Supported by a generation mix of 36% gas, 33% solar and 22% wind, Greece exported both surplus renewable energy and flexible gas-fired generation northward into Bulgaria, North Macedonia and Albania while maintaining system stability.
Serbia’s market presented a mixed but strategically important picture. SEEPEX averaged €114.87/MWh, while the day-ahead market achieved a record monthly trading volume of 569,139 MWh, representing a 12.6% year-on-year increase. The country remained structurally import-dependent, averaging -706 MW in net exports, with electricity generation still dominated by coal (66%) and hydropower (32%). These market fundamentals continue to support investment in Serbia’s planned 1 GW solar program combined with at least 200 MW / 400 MWh of battery storage, ongoing financing discussions for the Bistrica pumped-storage project, and new wind developments including Alibunar.
Montenegro’s results further demonstrated the importance of reliable domestic generation. While BELEN averaged €108.63/MWh, the country remained a net electricity importer at -77 MW. State utility EPCG spent approximately €142 million on electricity imports during 2025 due to the outage at TPP Pljevlja and weak hydrological conditions. Around 780 GWh of imported electricity replaced lost thermal generation, while another 320 GWh compensated for lower hydropower production. Planned transmission upgrades by CGES at Perucica and Pljevlja could enable approximately 550 MW of new renewable energy connections, while improvements along the Trebinje–Perucica–Podgorica–Vau i Dejes corridor could increase cross-border transfer capacity to around 600 MW.
Across the region, the investment landscape is becoming increasingly clear. Battery storage, grid modernization and hybrid renewable projects are rapidly shifting from complementary assets to essential infrastructure. Bulgaria has expanded its storage portfolio with several new battery projects, including Solarpro’s 602 MWh Burgas facility, while Hungary commissioned new storage systems in Tiszaujvaros and Ajka. Romania continues to develop a broad pipeline of solar-plus-storage facilities, standalone batteries, hybrid PPAs and major transmission investments. These technologies are ideally positioned to capitalize on widening intraday price spreads by storing inexpensive midday solar generation and supplying electricity during expensive evening peak periods.
Overall, Southeast Europe is entering a fundamentally new electricity pricing regime. The traditional market structure, dominated by thermal baseload generation balanced by hydropower, is gradually being replaced by a system in which solar defines daytime prices, gas and imports determine evening price peaks, and interconnector availability drives local scarcity premiums. June’s market data clearly show that rapid renewable expansion alone does not reduce market volatility. Without sufficient storage capacity, stronger grids and greater system flexibility, renewable growth can actually amplify intraday price swings. As a result, the strongest long-term investment opportunities are increasingly concentrated in hybrid solar-storage projects, wind generation paired with balancing solutions, pumped-storage facilities, grid-scale batteries, and industrial power purchase agreements featuring hourly matching and flexibility mechanisms.