In the second half of June, natural gas prices fell while electricity prices rose across parts of Southeast Europe. CEGH gas declined to €43.06/MWh from €49.35/MWh, and Greek gas decreased to €41.37/MWh from €46.14/MWh. Despite the lower fuel costs, electricity benchmarks moved higher during the same period.
Hungary’s HUPX increased to €149.01/MWh, up €48.7/MWh versus the first half of June. Romania’s OPCOM reached €146.80/MWh, rising by €47.6/MWh. Similar increases were recorded in Croatia, Slovenia and Serbia, with CROPEX at €136.67/MWh, BSP Slovenia at €134.33/MWh, and SEEPEX at €114.87/MWh.
Demand growth and warmer temperatures coincide with higher power prices
The rise in electricity prices was linked to stronger demand in the HU+SEE region. Average electricity consumption climbed to 31,414 MW in the second half of June from 28,054 MW in the first half, an increase of 3,360 MW. Average temperatures in HU+SEE excluding Greece rose from 20.3°C to 25.5°C.
The warmer conditions increased air-conditioning demand, particularly during evening hours when solar generation declined. This shift raised the need for flexible generation during periods when supply from solar was lower. The market conditions therefore reflected both weather-driven load changes and generation availability at specific times.
Flexible capacity constraints rather than overall generation shortage
Generation data indicated that the region did not face a broad shortage of capacity overall, but did experience limited flexibility at critical hours. Gas-fired generation increased by 1,177 MW, coal output rose by 476 MW, and nuclear generation increased by 922 MW. Wind production expanded by 841 MW, while solar generation grew by 894 MW.
Hydropower declined slightly, falling by 130 MW. The data point to a timing issue between renewable output and peak demand periods rather than an absence of total generation. Solar reduced daytime prices but required faster evening ramping when output dropped.
Midday supply versus evening scarcity drives late-hour premiums
A key signal from June was a widening gap between midday abundance and evening scarcity across several markets. Late-hour price premiums were reported in Hungary, Romania, Croatia and Slovenia. The pattern indicated that electricity value increasingly depended on timing rather than only total production.
Hungary emerged as a main reference point for scarcity due to strong demand growth and dependence on imports. Additional factors cited included nuclear cooling constraints at Paks and limited flexibility during peak periods. This combination aligned with higher evening-hour prices despite lower gas costs.
Market assessment shifts toward system conditions and flexibility assets
The June outcome showed that traditional gas-price indicators were not sufficient for interpreting Southeast European electricity markets. A broader assessment was described as requiring weather patterns, nuclear availability, hydropower conditions, solar generation profiles, cross-border transmission capacity and balancing resources. The month also demonstrated that falling gas prices can coincide with rising electricity prices when demand growth outpaces flexible supply.
The implications for investors highlighted storage and other flexibility options alongside conventional generation adjustments. The focus included pumped hydro and demand-side solutions as well as flexible generation resources. Standalone solar projects were noted as facing increased exposure to midday price compression compared with hybrid solar-plus-storage configurations.
The same investment framing extended to wind assets paired with balancing strategies and industrial power purchase agreements with flexible demand mechanisms. These elements were presented as offering stronger long-term value relative to standalone solar exposure under the June pricing pattern.
