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 traded at approximately €139/MWh and €136/MWh, respectively, after stronger renewable generation forecasts reshaped regional power balances and cross-border flows.
Despite the wider spread, 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 the role of renewable output forecasts, transmission capacity and generation location in day-ahead pricing.
In the Serbian market, SEEPEX rose by €6.5/MWh from the previous day. Hungary’s HUPX was broadly stable at €223.94/MWh, while Romania’s OPCOM increased to €221.67/MWh. Slovenia’s BSP reached €222.15/MWh and Croatia’s CROPEX settled at €221.87/MWh.
Montenegro’s BELEN increased slightly to €209.17/MWh, while North Macedonia’s MEMO declined to €210.38/MWh. Southern markets moved in the opposite direction, with Greece’s HENEX dropping by €85.6/MWh to €138.95/MWh. Albania’s ALPEX fell by €76.8/MWh to €136.01/MWh, and Bulgaria’s IBEX weakened to €214.50/MWh.
The Serbia–Greece day-ahead differential reached €95.72/MWh. Serbia traded almost €99/MWh above Albania, while Hungary’s premium over Greece widened to €84.99/MWh. The gap reflected differences in cross-border capacity, contractual schedules and national generation portfolios affecting local supply conditions.
Greek renewable outlook lifts exports while southern spot prices drop
Greece was identified as the main driver of downward pressure on regional prices. 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.
Commercial schedules showed average Greek exports of approximately 962 MW to Bulgaria, 395 MW to North Macedonia and 274 MW to Albania. Daytime pricing fell sharply alongside the export increase, with Greece’s average peak-period price dropping to €73.8/MWh. Off-peak hours averaged €204.1/MWh, and Greece’s minimum hourly price reached zero.
The export flow did not remove price differences with neighbouring markets. Bulgaria continued trading more than €75/MWh above Greece, indicating that additional cross-border transfers were insufficient for price convergence. The realised outcomes for traders were described as dependent on transmission rights, capacity costs, scheduling arrangements and balancing exposure rather than exchange spreads alone.
Northern demand keeps Serbia and Hungary reliant on imports as flows change
The regional improvement in availability was linked to higher renewable generation forecasts across Hungary and Southeast Europe. Average solar output was projected to rise by approximately 1,945 MW to 4,053 MW, while wind generation was expected to increase by another 582 MW to 5,639 MW. Combined wind and solar output was forecast at almost 9.7 GW, supporting regional generation rising to 29,278 MW.
The increase in supply did not translate evenly across countries. Serbia’s forecast consumption rose to 3,866 MW, while domestic generation was projected at only 2,636 MW. Its import requirement climbed to 1,230 MW, from
1,027 MW on Tuesday
and imports were expected to cover almost 32% of demand.
Hungary faced a larger import need under the same forecast period. Consumption was projected at
5,086 MW
against domestic generation of 3,062 MW
leaving net imports at 2,024 MW
approximately 40% of demand.
Romania shifted in the opposite direction.
It moved from net imports of 114 MW on Tuesday to projected net exports of 555 MW on Wednesday.
Commercial schedules indicated Romanian deliveries into Hungary averaging about 1,009 MW.
The contrasting positions across Serbia, Hungary, Greece and Romania were cited as part of why declining regional import requirements did not lead to a uniform fall in wholesale prices across bidding zones.
CROSS-BORDER FLOWS IN MONTENEGRO AND FORWARD PRICES SIGNAL WINTER COSTS
The Montenegro market provided an example of cross-border trading activity alongside domestic balance constraints. BELEN settled at €209.17/MWh, about €25.50/MWh below Serbia, while Montenegro was forecast to record a modest net surplus of 36 MW. Commercial schedules included average exports of around 204 MW to Serbia.
The same schedules projected imports into Montenegro from Italy and Albania at 164 MW and 92 MW respectively. The flows were described as reflecting potential roles for Montenegro in regional trading and transit given its connections with Italy and neighbouring Western Balkan systems.
A separate set of signals came from forward markets despite the sharp decline in Greek southern spot prices for Wednesday delivery. Hungarian week-43 baseload advanced by €20/MWh to €266/MWh and week-44 increased by €17/MWh to €257/MWh. The Hungarian November 2026 contract rose by €7.50/MWh in the latest session to €244.50/MWh.
A comparable German November baseload traded at €199/MWh, leaving Hungary with a €45.50/MWh forward premium versus Germany; Hungarian week-43 power carried an even larger €59/MWh premium over Germany. Italian November electricity was quoted at €234.50/MWh.
The forward cost picture also reflected fuel and carbon market levels cited in the report: Austrian CEGH gas reference increased to €88.19/MWh and November gas forwards rose to €88.50/MWh. European carbon allowances remained elevated at around €88.05 per tonne despite a modest daily decline.
Bosnia Ugljevik outage risk intersects balancing uncertainty for traders and buyers
An additional risk highlighted for connected markets came from Bosnia and Herzegovina regarding coal supply constraints at Ugljevik coal-fired power station. The plant was expected to cease operations from October 15 due to continuing coal shortages and difficulties developing additional mining capacity.
Bosnia’s projected electricity export surplus was already forecast to decline to 216 MW from 472 MW on Tuesday. A prolonged interruption could increase import requirements within Bosnia and alter electricity availability across connected Western Balkan markets depending on replacement generation, contracted imports and outage duration.
The report also linked market exposure beyond average day-ahead prices for traders, utilities and industrial buyers with volatile renewables alongside thermal-generation uncertainty. It cited hourly purchasing costs, imbalance settlement and delivery reliability as key considerations under these conditions.
Differing intraday ranges point to flexibility needs across bidding zones
The intraday structure on Wednesday showed wide hourly spreads across several markets cited in the report. Greece’s hourly day-ahead prices ranged from zero up 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 up to approximately €292/MWh.
The report noted that such intraday differences can indicate potential revenue opportunities for battery energy storage systems, pumped-storage hydropower and flexible industrial consumption when accounting for operational parameters rather than relying on raw price ranges alone.
No achievable trading revenue could be assumed without considering charging and discharging efficiency, network charges, operating restrictions, capacity availability and balancing costs mentioned in the report.
The same market movements were presented as reinforcing procurement needs for renewable developers, power traders and electricity-intensive industrial consumers through better forecasting combined with flexible capacity and more sophisticated electricity procurement approaches under these day-ahead spreads.