Southeast European day-ahead electricity prices rose sharply on Friday, with Serbia becoming the region’s most expensive market. Weaker wind generation, higher cross-border import requirements and persistent supply constraints pushed wholesale prices towards €280/MWh. Serbia’s SEEPEX market led the move, while hourly data showed peaks well above daily averages.
Serbia’s SEEPEX climbed €24.8/MWh to €277.57/MWh, the highest daily baseload average among the monitored markets. Hungary’s HUPX exchange increased €16.4/MWh to €269.23/MWh, while Romania reached €261.92/MWh and Bulgaria €256.57/MWh. Montenegro’s BELEN market rose to €239.78/MWh, extending upward pressure across the Western Balkans.
The price increases occurred alongside a forecast 428 MW decline in regional electricity consumption 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. The gap between weaker consumption and higher prices aligned with renewable availability and cross-border conditions rather than demand growth.
The largest percentage increase was recorded in Greece, where HENEX jumped €45.6/MWh to €206.18/MWh, remaining the cheapest monitored market. North Macedonia rose €29.3/MWh to €251.64/MWh, Bulgaria gained €23.3/MWh, and Albania increased €7.5/MWh to €257.08/MWh. Across the region, the daily moves were accompanied by continued separation from Western Europe.
Regional price premiums versus Germany and intraday scarcity signals
Germany traded at €210.67/MWh, leaving Hungary at a €58.57/MWh premium. Hungary’s premium over Greece narrowed to €63.05/MWh from about €92.3/MWh. The session also showed stronger scarcity signals in hourly profiles than in 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, recording a maximum of €399/MWh, while Romania and Bulgaria reached €356.90/MWh and €354.70/MWh. These peaks indicated tighter conditions during specific hours.
The daily averages also masked differences between peak and off-peak pricing shapes. 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 peak-hour average of €257.40/MWh.
A contrasting intraday profile appeared in Greece, where the minimum hourly price fell to zero around midday while the maximum rose to €321.10/MWh. The combination of zero-price solar hours and higher prices at other times highlighted variability across the day-ahead curve.
Deteriorating generation balance and shifting cross-border flows
The physical market change centered on a weaker generation balance across the region. Forecast electricity production declined by 1,450 MW to 28,425 MW, with wind losses only partly offset by a 233 MW increase in solar generation. This shift coincided with higher import needs.
A key adjustment appeared at Italian borders in cross-border schedules. The monitored region moved from net exports of approximately 79 MW to Italy on Thursday to net imports of 679 MW on Friday, a swing of 758 MW. At the same time, combined imports through Austrian and Slovak corridors increased by only 83 MW, reaching 2,766 MW.
Bulgaria recorded one of the largest changes in its electricity balance as forecast consumption rose 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 increased from 641 MW to 818 MW, reflecting lower domestic generation against broadly unchanged demand. Greece remained a major regional exporter, but its surplus contracted from 1,657 MW to 1,176 MW as generation fell. The trading pattern showed that rising prices could coincide with changing import requirements across interconnected markets.
Centring on Serbia’s import dependence and forward pricing for weeks ahead
A national balance explained part of Serbia’s 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.
Selling schedules indicated 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 day-ahead pricing spread reflected differing commercial conditions across borders, with Serbia showing an €8.34/MWh premium over Hungary and €37.79/MWh premium over Montenegro. For traders and industrial buyers, these differences were linked to transmission capacity constraints and nomination risks as well as variations between hourly market prices.
The physical balance in Montenegro contrasted with Serbia’s position as domestic generation was forecast at 348 MW against consumption of 330 MW for an export position of approximately 18 MW. Commercial schedules still connected Montenegro closely with regional flows through average imports of 268 MW from Italy alongside exports of 165 MW towards Serbia and 72 MW towards Kosovo.
Nearing-term forward contracts track short-term scarcity alongside gas and carbon moves
The forward electricity market reinforced strength in near-term expectations for Hungary’s baseload contracts quoted for week delivery periods and November delivery. Hungarian week 43 baseload was quoted at €269.50/MWh, week 44 stood at €260/MWh and November delivery was €243.50/MWh.
The week 43 contract carried a premium of €75.50/MWh over Germany, narrowing to €67/MWh for week 44 and €50.50/MWh for November delivery. Between October 7 and October 15, Hungary’s week 43 contract gained approximately 28.95%, compared with gains of 15.82% in Germany and 12.26% in Italy.
A longer-dated view showed a smaller spread as Hungary’s calendar 2027 baseload contract stood at €168.50/MWh compared with Germany at €145/MWh for a difference of €23.50/MWh relative to weekly spreads near term.
The cost components for thermal generation included gas and carbon prices moving less than spot electricity during the session described here. The Austrian CEGH gas indicator was approximately €87.21/MWh while November gas futures were quoted at €87.50/MWh down €1/MWh; European carbon allowances declined approximately €1.30 to €85.84 per tonne.
The immediate outlook remained sensitive to wind forecasts, thermal generation availability, cross-border nominations and temperatures based on how spot conditions were reflected in the forward curve for coming weeks.
An hourly maximum in Serbia reached €405/MWh during hour 19 while net imports returned to more than 3.3 GW across Southeast Europe on Friday’s trading day-ahead session.