Southeast European electricity markets recorded a sharp divergence in day-ahead prices for Wednesday delivery, with Serbia registering the region’s highest wholesale price at €234.67/MWh, while prices in Greece and Albania fell to approximately €139/MWh and €136/MWh, respectively. The widening gap reflected stronger renewable generation forecasts and their impact on regional power balances and cross-border electricity flows.
The divergence emerged despite an improvement in the region’s overall electricity supply position. Forecast net electricity imports across Hungary and Southeast Europe declined by 814 MW to 2,104 MW, while electricity consumption increased to 31,382 MW. The figures highlight the growing influence of renewable generation, transmission capacity and the geographical distribution of electricity production on wholesale market prices.
Serbia’s SEEPEX market increased by €6.5/MWh from the previous day, while Hungary’s HUPX remained 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 also increased slightly to €209.17/MWh, while North Macedonia’s MEMO declined to €210.38/MWh.
Southern European markets moved in the opposite direction. Greek HENEX prices fell by €85.6/MWh to €138.95/MWh, while Albania’s ALPEX declined by €76.8/MWh to €136.01/MWh. Bulgaria also recorded a decline, although less pronounced, with IBEX falling to €214.50/MWh.
The resulting Serbia-Greece price differential reached €95.72/MWh, while Serbia traded almost €99/MWh above Albania. Hungary’s premium over Greece widened to €84.99/MWh, reversing the near parity recorded just one day earlier. The differences demonstrate how additional electricity generation in one part of Southeast Europe does not automatically translate into lower prices elsewhere when cross-border capacity, commercial schedules and national generation portfolios create different local supply conditions.
Greece was the main source of downward pressure on southern regional prices. Forecast electricity generation increased to 7,002 MW, from 5,488 MW the previous day, while domestic consumption declined to 5,293 MW. As a result, projected net electricity exports surged to 1,709 MW, compared with only 81 MW on Tuesday.
Commercial schedules showed average Greek exports of approximately 962 MW to Bulgaria, 395 MW to North Macedonia and 274 MW to Albania. The additional southern supply coincided with significantly lower daytime prices, with Greece’s average peak-period price falling to €73.8/MWh compared with €204.1/MWh during off-peak hours. The minimum hourly price reached zero.
Despite the sizeable Greek export flows, significant price differences remained with neighbouring markets. Bulgaria continued to trade more than €75/MWh above Greece, indicating that additional cross-border electricity transfers were not sufficient to achieve full price convergence.
For regional traders, these differences can create cross-border trading opportunities, although the actual commercial value depends on transmission rights, capacity costs, scheduling arrangements and balancing exposure rather than exchange price spreads alone.
The improvement in regional electricity availability was supported by a strong rebound in renewable generation forecasts. Across Hungary and Southeast Europe, average solar output was projected to increase by approximately 1,945 MW to 4,053 MW, while wind generation was expected to rise by another 582 MW to 5,639 MW. Combined wind and solar generation was therefore forecast at almost 9.7 GW, contributing to an increase in total regional generation to 29,278 MW from 28,226 MW the previous day.
The benefits of stronger renewable output were not evenly distributed across the region. Serbia’s forecast electricity consumption increased to 3,866 MW, while domestic generation was projected at only 2,636 MW. Its resulting import requirement climbed to 1,230 MW, compared with 1,027 MW on Tuesday, meaning imports were expected to cover almost 32% of Serbian electricity demand.
Hungary faced an even larger import requirement, with forecast consumption of 5,086 MW against domestic generation of 3,062 MW. This left projected net imports at 2,024 MW, equivalent to approximately 40% of demand. Romania, by contrast, moved from net imports of 114 MW on Tuesday to projected net exports of 555 MW on Wednesday, with commercial schedules indicating average Romanian deliveries to Hungary of around 1,009 MW.
The contrasting positions of Serbia, Hungary, Greece and Romania help explain why falling regional import requirements did not lead to a uniform decline in wholesale electricity prices. Electricity availability and prices increasingly depend on where generation is located and whether available transmission capacity allows surplus power to reach markets with higher demand.
Montenegro’s market provided another example of the importance of regional electricity flows. BELEN settled at €209.17/MWh, around €25.50/MWh below Serbia, while Montenegro itself was forecast to record only a modest net electricity surplus of 36 MW.
Commercial schedules included average exports of approximately 204 MW to Serbia, alongside imports from Italy and Albania of 164 MW and 92 MW, respectively. These flows underline Montenegro’s potential role as a regional electricity trading and transit hub, supported by its connections with Italy and neighbouring Western Balkan markets.
For suppliers and trading companies, the commercial value increasingly lies in managing transmission access, hourly price differences and contractual delivery obligations rather than relying exclusively on domestic generation. The comparison with Serbia also highlights the potential value of additional flexible generation and battery storage when neighbouring bidding zones experience substantial price differences.
Forward electricity markets continued to signal expensive supply conditions despite the sharp decline in southern spot prices. Hungarian week-43 baseload power increased by €20/MWh to €266/MWh, while week-44 power rose by €17/MWh to €257/MWh. The Hungarian November 2026 contract also increased to €244.50/MWh.
German November baseload power traded at €199/MWh, leaving Hungary with a €45.50/MWh forward premium. Hungarian week-43 power carried an even larger €59/MWh premium over Germany, while Italian November electricity was quoted at €234.50/MWh.
Fuel markets added to the pressure on forward electricity prices. The Austrian CEGH gas reference increased to €88.19/MWh, while November gas forwards rose to €88.50/MWh. European carbon allowances remained elevated at approximately €88.05 per tonne despite a modest daily decline.
Another source of uncertainty comes from Bosnia and Herzegovina, where the Ugljevik coal-fired power plant was expected to cease operations from October 15 due to continuing coal shortages and difficulties in developing additional mining capacity. The country’s projected electricity export surplus had already fallen to 216 MW, from 472 MW on Tuesday.
A prolonged interruption at Ugljevik could increase Bosnia and Herzegovina’s import requirements and affect electricity availability across connected Western Balkan markets. The ultimate impact will depend on replacement generation, contracted imports and the duration of the outage.
For traders, utilities and industrial electricity buyers, the combination of volatile renewable generation and uncertainty surrounding thermal power plants creates risks beyond average day-ahead prices. Hourly purchasing costs, imbalance exposure and delivery reliability are becoming increasingly important factors in electricity procurement strategies.
Wednesday’s price structure also strengthened the commercial case for flexible electricity assets. Greece’s hourly day-ahead prices ranged from zero to €245/MWh, while Serbia recorded a minimum of €192/MWh and a maximum of €317/MWh. Montenegro’s hourly range extended from €140/MWh to approximately €292/MWh.
Such significant hourly price differences create potential revenue opportunities for battery energy storage, pumped-storage hydropower and flexible industrial consumption. However, the observed price spreads cannot be treated as achievable trading revenue without accounting for charging and discharging efficiency, network charges, operating restrictions, capacity availability and balancing costs.
For renewable developers, power traders and electricity-intensive industrial consumers, the latest market movements underline the growing importance of combining generation investment with accurate forecasting, flexible capacity and more sophisticated electricity procurement. Southeast Europe can increasingly experience renewable oversupply in southern markets at the same time as expensive electricity imports in Serbia and Hungary, making the ability to move, store and hedge electricity an increasingly important part of the regional power market.
