Day-ahead electricity prices in Southeast Europe rose sharply on Friday, with Serbia posting the highest market level among the monitored exchanges. The move was linked to weaker wind generation, higher cross-border import requirements and persistent supply constraints pushing wholesale prices towards €280/MWh. Serbia’s SEEPEX baseload average climbed to €277.57/MWh, while Hungary’s HUPX increased to €269.23/MWh.
Romania’s day-ahead average reached €261.92/MWh and Bulgaria’s market settled at €256.57/MWh. Montenegro’s BELEN price rose to €239.78/MWh, extending upward pressure across the Western Balkans. Greece recorded the largest percentage increase, with HENEX rising by €45.6/MWh to €206.18/MWh.
North Macedonia’s market increased by €29.3/MWh to €251.64/MWh, while Bulgaria gained €23.3/MWh. Albania’s HENEX price rose by €7.5/MWh to €257.08/MWh. The regional price rally also coincided with continued separation from Western Europe.
Regional price levels and hourly scarcity signals
Germany traded at €210.67/MWh, leaving Hungary at a €58.57/MWh premium despite Germany rising faster during the latest session. Hungary’s premium over Greece narrowed to €63.05/MWh from about €92.3/MWh. Hourly profiles showed stronger scarcity signals than the daily averages.
Serbia’s maximum hourly price reached €405.10/MWh at hour 19, while Hungary peaked at €382.30/MWh in the same hour. Albania approached €400/MWh, with a maximum of €399/MWh, while Romania and Bulgaria reached €356.90/MWh and €354.70/MWh. Serbia’s off-peak average stood at €284.60/MWh, above its peak-period average of €270.50/MWh.
Hungary showed a similar pattern, with off-peak power averaging €281/MWh against €257.40/MWh during peak hours. Greece displayed an intraday pattern with its minimum hourly price falling to zero around midday and its maximum rising to €321.10/MWh. The contrast reflected zero-price solar hours alongside higher-priced periods.
Deteriorating generation balance and changing import flows
The price increases occurred alongside a forecast decline in regional electricity consumption of 428 MW, to 31,810 MW. Forecast wind generation fell by 1,662 MW to 2,909 MW, while net imports increased by 1,023 MW to 3,385 MW. Forecast electricity production declined by 1,450 MW, to 28,425 MW.
The loss of wind output was only partly offset by a 233 MW increase in solar generation. Cross-border schedules showed a major adjustment at the Italian borders, with net exports of approximately 79 MW to Italy on Thursday switching to net imports of 679 MW on Friday, a swing of 758 MW. Imports through the Austrian and Slovak corridors increased by only
The combined imports through the Austrian and Slovak corridors increased by only 83 MW to 2,766 MW. This indicated that the additional regional import requirement was met mainly through changes in Italian border schedule direction and volumes rather than a substantial expansion of supplies from Central Europe.
Bulgaria, Romania and Greece: consumption, production and surplus shifts
Bulgaria recorded a change in its electricity balance as forecast consumption increased by 628 MW to 4,361 MW while domestic production fell by 248 MW to 4,245 MW. Bulgaria moved from being a net exporter of 760 MW on Thursday to a net importer of 116 MW on Friday. Romania’s net import requirement rose from 641 MW to 818 MW as domestic generation fell against broadly unchanged demand.
Serbia and Montenegro: national balances and scheduled cross-border deliveries
The Serbia national electricity balance provided an explanation for its elevated market price as forecast consumption fell from 3,969 MW to 3,753 MW while domestic generation declined from 2,942 MW to 2,693 MW. The resulting net import requirement increased slightly to approximately 1,061 MW, equivalent to more than 28% of forecast consumption. Commercial schedules showed deliveries into Serbia from Bosnia and Herzegovina, Bulgaria, North Macedonia and Montenegro.
Bosnia and Herzegovina scheduled an average 435 MW towards Serbia, Bulgaria 304 MW, North Macedonia 317 MW and Montenegro 165 MW. Serbia maintained average scheduled exports of 406 MW towards Hungary despite its overall import deficit. The difference between scheduled flows reflected contractual obligations and transmission arrangements rather than only the gap between national daily-average spot prices.
The SEEPEX premium data showed Serbia at €8.34/MWh above Hungary and €37.79/MWh above Montenegro for the session referenced in the market report. For traders these differences were linked to transmission capacity constraints, nomination risks and differences between hourly market prices. For Serbian industrial buyers the main concern remained securing reliable electricity when domestic generation could not fully cover consumption.
Montenegro presented a contrasting physical balance with forecast domestic generation at 348 MW against consumption of 330 MW for an approximate net export position of 18 MW. Despite this surplus position, commercial schedules included average imports of 268 MW from Italy alongside exports of 165 MW towards Serbia and 72 MW towards Kosovo.
Forward contracts and fuel-linked benchmarks for thermal generation costs
The forward electricity market reinforced expectations for near-term pricing strength as Hungarian week 43 baseload was quoted at €269.50/MWh while week 44 stood at €260/MWh and November delivery at €243.50/MWh. The week 43 contract carried a premium of €75.50/MWh over Germany which narrowed to €67/MWh for week 44 and €50.50/MWh for November.
The forward rally accelerated between October 7 and October 15 as Hungary’s week 43 contract gained approximately 28.95%, compared with gains of 15.82% in Germany and 12.26% in Italy. Longer-dated pricing showed a smaller premium as Hungary’s calendar 2027 baseload contract stood at €168.50/MWh compared with Germany at €145/MWh.
Austrian CEGH gas was quoted at approximately €87.21/MWh while November gas futures were at €87.50/MWh after falling by €1/MWh since the prior reference point. European carbon allowances declined approximately €1.30 to €85.84 per tonne during the same period described in the report.
Hourly spreads for flexibility markets amid wind-dependent conditions
The report linked spot electricity moves more strongly than gas or carbon changes as short-term generation availability shifted across the region described for Friday trading conditions.
The same session included Greece’s midday minimum hourly price falling to zero alongside a maximum hourly price of €321.10/MWh later in the day, illustrating intraday volatility for flexible resources.
The immediate outlook remained sensitive to wind forecasts, thermal generation availability, cross-border nominations and temperatures as reflected in expectations embedded in the forward curve for elevated prices into coming weeks.