Southeast European day-ahead electricity prices fell sharply for delivery on 2 June, with markets across Hungary, Romania, Bulgaria, Serbia, Croatia and Slovenia converging close to the €121/MWh level after the prior session’s rally. Hungary’s HUPX day-ahead contract settled at €121.92/MWh, down almost €29/MWh from the previous day. Romania’s OPCOM and Bulgaria’s IBEX both cleared at €121.21/MWh.
Serbia’s SEEPEX closed at €120.90/MWh, while Croatia’s CROPEX settled at €121.66/MWh. Slovenia’s BSP finished at €121.75/MWh. The regional market remained highly coupled, with only limited price divergence between Central European and Southeast European bidding zones.
Greece trades at discount as solar oversupply persists
Greece continued to trade at a substantial discount to the rest of the region, with HENEX settling at €96.31/MWh. The lower Greek price was supported by strong renewable generation and persistent solar oversupply during daylight hours. Market participants continued to monitor increasing renewable penetration in Greece, including recurring negative-price episodes and midday oversupply conditions.
The discount kept export economics attractive toward neighbouring Balkan markets and Italy. Greece remained the largest importing market, drawing approximately 1.66 GW from neighbouring systems. Romania and Bulgaria maintained net exporter positions, while Serbia and Croatia relied on imports during parts of the trading day.
Demand rises while generation and imports adjust
Regional fundamentals pointed to adequate supply despite a significant increase in weekday demand. Total electricity consumption across the SEE system rose to 28.2 GW, an increase of about 1.4 GW versus the previous trading day as industrial load returned after the weekend period. Regional generation increased by 1.33 GW, enabling the market to absorb higher demand without significant import support.
Net imports across the monitored markets fell sharply to just 84 MW, compared with almost 1.2 GW one day earlier. This reflected a growing ability of domestic generation resources to meet regional demand requirements during the session.
Solar output declines as gas, coal and hydro cover demand
The generation mix shifted during the session as solar output declined by approximately 684 MW. Thermal generation compensated for the renewable decrease, with gas-fired output rising by 753 MW. Coal-fired generation increased by 314 MW, while hydro contributed an additional 254 MW.
Gas-fired plants became the primary marginal technology across much of the region, particularly during morning and evening peak demand periods when solar generation was unavailable. Hydropower accounted for approximately 25% of regional generation and remained the single largest source in the mix.
The remaining shares were roughly 20%