June delivered one of the clearest signals yet that South East Europe’s electricity market is moving beyond a simple fuel-cost model. In the second half of the month, CEGH gas fell to €43.06/MWh from €49.35/MWh, while Greek gas moved down to €41.37/MWh from €46.14/MWh. Yet power prices moved the other way. HUPX Hungary rose to €149.01/MWh, up €48.7/MWh from the first half of June, while Romania’s OPCOM reached €146.80/MWh, up €47.6/MWh. Croatia, Slovenia and Serbia followed the same upward curve, with CROPEX at €136.67/MWh, BSP Slovenia at €134.33/MWh and SEEPEX at €114.87/MWh. The data point is blunt: lower gas did not prevent a power-price rally because the market was no longer pricing gas alone. It was pricing heat, residual load, dispatchability and evening scarcity.
The demand side explains the first part of the move. Average HU+SEE consumption increased to 31,414 MW in the second half of June from 28,054 MW in the first half, a jump of 3,360 MW. The region moved from moderate early-summer conditions into a heat-driven market, with average HU+SEE temperature excluding Greece rising from 20.3°C to 25.5°C. That change brought air-conditioning load into the evening curve, exactly when solar output begins to fade and flexible generation becomes more valuable.
The generation mix tells the second part of the story. Gas-fired output rose by 1,177 MW, coal rose by 476 MW, nuclear rose by 922 MW, wind increased by 841 MW and solar increased by 894 MW, while hydro slipped by 130 MW. That combination is important because it shows that the market did not lack megawatts in an average sense. It lacked the right megawatts at the right hours. Solar helped during the day, but it also sharpened the evening ramp. Wind helped, but not always at the hours of peak stress. Hydro remained essential but did not expand enough to neutralise the late-day residual-load requirement.
That is why June’s real market story sits in the spread between daytime abundance and evening scarcity. Hungary, Romania, Croatia and Slovenia all showed strong late-hour premiums. HUPX became the region’s scarcity reference, not because Hungary alone dictated the fundamentals, but because it sat at the intersection of heat demand, import dependence, nuclear cooling sensitivity and cross-border congestion. Once the system moved into the evening peak, the marginal megawatt was no longer cheap solar or average gas. It was dispatchable capacity, import availability or demand response.
For traders, the June data confirm that gas screens are no longer enough to read SEE power. The correct market view now requires a combined model of weather, nuclear availability, hydro storage, solar profile, interconnector nominations and balancing capacity. A gas-price decline can coexist with a power-price rally when cooling demand rises faster than flexible supply. That is exactly what happened in June.
For investors, the same movement strengthens the commercial case for batteries, pumped storage, flexible gas, hybrid plants and industrial demand response. Merchant solar alone is more exposed to midday cannibalisation. Solar paired with storage, wind paired with balancing services, and industrial PPAs with flexible load clauses now carry a stronger revenue logic. June was not a contradiction between cheaper gas and expensive power. It was the first clean summer signal that SEE electricity is becoming a flexibility market.
