Southeast European day-ahead electricity prices for Wednesday delivery diverged sharply by geography, with Serbia recording the region’s highest wholesale price at €234.67/MWh. Greece and Albania were quoted at approximately €139/MWh and €136/MWh, respectively. The shift was linked to stronger renewable generation forecasts that changed regional power balances and cross-border electricity flows.
The price spread widened even though the region’s aggregate supply position improved. Forecast net electricity imports across Hungary and Southeast Europe fell by 814 MW to 2,104 MW, while electricity consumption rose to 31,382 MW. The figures pointed to a growing role for renewable output, transmission capacity and the geographic distribution of generation in shaping wholesale prices.
In the Serbian market, SEEPEX increased by €6.5/MWh from the previous day. Hungary’s HUPX was broadly stable at €223.94/MWh. Romania’s OPCOM rose to €221.67/MWh, Slovenia’s BSP reached €222.15/MWh, and Croatia’s CROPEX settled at €221.87/MWh.
Montenegro’s BELEN edged up to €209.17/MWh, while North Macedonia’s MEMO declined to €210.38/MWh. Southern markets moved in the opposite direction, with Greek HENEX falling by €85.6/MWh to €138.95/MWh. Albania’s ALPEX dropped by €76.8/MWh to €136.01/MWh, while Bulgaria’s IBEX weakened to €214.50/MWh.
Serbia-Greece spreads widen as southern prices collapse
The Serbia–Greece price differential reached €95.72/MWh, reflecting the gap between the two bidding zones on Wednesday delivery. Serbia traded almost €99/MWh above Albania, and Hungary’s premium over Greece widened to €84.99/MWh. This represented a reversal of near parity recorded one day earlier.
The divergence reflected how additional generation in one part of the region did not automatically translate into lower prices elsewhere under Wednesday’s conditions. Cross-border capacity, contractual schedules and national generation portfolios were cited as factors producing different local supply conditions across bidding zones.
Greek export outlook rises on forecast generation increase
Greece was identified as the main source of downward pressure on regional prices in the day-ahead outcome for Wednesday delivery. Forecast electricity generation increased to 7,002 MW, up from 5,488 MW, while domestic consumption fell to 5,293 MW. As a result, Greece’s projected net electricity exports rose to 1,709 MW, compared with just 81 MW on Tuesday.
The commercial schedules showed average Greek exports of approximately 962 MW to Bulgaria, 395 MW to North Macedonia and 274 MW to Albania. Daytime pricing in Greece also shifted lower, with the average peak-period price falling to €73.8/MWh. Off-peak hours were quoted at €204.1/MWh, and Greece’s minimum hourly price reached zero.
The higher export flow did not remove price differences with neighbouring markets in the day-ahead results. Bulgaria continued trading at more than €75/MWh above Greece, indicating that additional cross-border transfers were not enough for price convergence under available conditions.
The reported export pattern suggested potential cross-border trading opportunities for market participants, although realised economics depended on transmission rights, capacity costs, scheduling arrangements and balancing exposure rather than exchange spreads alone.
Northern import needs persist despite improved regional supply outlook
The regional improvement in electricity availability was supported by higher renewable generation forecasts across Hungary and Southeast Europe. Average solar output was projected to increase by approximately 1,945 MW to 4,053 MW. Wind generation was expected to rise by another 582 MW to 5,639 MW.
Together, wind and solar output was forecast at almost 9.7 GW, supporting an increase in regional generation to 29,278 MW, from 28,226 MW. The benefits were described as unevenly distributed across countries based on consumption and domestic production levels.
Serbia’s forecast electricity consumption increased to 3,866 MW, while domestic generation was projected at only 2,636 MW. Its resulting import requirement rose to 1,230 MW, compared with 1,027 MW
