Southeast European day-ahead electricity prices fell sharply across most markets on Tuesday, with the largest declines in Serbia, Greece and Hungary. Higher forecasts for renewable generation and increased regional output reduced import requirements, even as consumption rose.
Serbia’s SEEPEX baseload price dropped €43.4/MWh to €241.69/MWh, from €285.1/MWh a day earlier. Hungary’s HUPX fell €26.1 to €241.30/MWh, leaving the Serbia-Hungary baseload spread at just €0.39/MWh.
Greece declined €33.7 to €224.85/MWh, the lowest major price in the region. North Macedonia fell €25 to €259.84/MWh but remained the most expensive SEE market.
Romania and Bulgaria retained a premium over Hungary: OPCOM settled at €255.49/MWh, €14.19 higher than HUPX, while Bulgaria’s IBEX reached €254.58/MWh, a €13.28 premium. Monday’s extreme tightness in eastern Europe eased, but structural congestion and generation risks continued to distinguish Romania and Bulgaria from lower-priced markets farther west and south.
Renewable output rises as regional imports decline
The main downward pressure on prices came from stronger renewable availability. Regional solar generation forecasts rose by almost 2 GW day on day to 4.26 GW, while forecast wind output increased by slightly more than 1 GW to 3.51 GW.
Together, the forecast gains added around 3 GW of generation with lower marginal costs. This offset higher demand: aggregate consumption in Hungary and SEE increased by 626 MW to 32.94 GW, while net regional imports fell by 608 MW to 4.01 GW.
Imports from the core Austrian and Slovak direction decreased by 219 MW to about 4.38 GW. The SEE system also shifted to exports of around 155 MW toward Italy, compared with roughly 400 MW of imports a day earlier, a swing of more than 550 MW.
Regional generation reached around 28.9 GW, up from 27.7 GW on Monday. The additional domestic output absorbed most of the increase in consumption and allowed overall import dependence to fall.
Consumption rose while imports declined, as improved generation availability and stronger renewable supply outweighed the demand increase. In Serbia, average consumption climbed to around 4.21 GW from 4.05 GW, while generation edged down to about 3.27 GW.
Serbia’s price falls as its import position widens
Serbia’s net import position consequently widened to approximately 935 MW, from 722 MW a day earlier, even as SEEPEX fell by more than €43/MWh. The move reflected the importance of regional conditions, rather than domestic fundamentals alone, in Serbian price formation.
Serbia drew electricity from several neighbouring markets as the wider SEE price structure weakened. Commercial flows showed electricity moving into Serbia from Bosnia and Herzegovina, Croatia and Bulgaria, while Serbia also supplied power northward toward Hungary during part of the day.
SEEPEX peak prices averaged €253.1/MWh, and off-peak electricity fell to €230.2/MWh. The daily low was €165.1/MWh and the maximum was €314.4/MWh.
The Serbia-Hungary baseload spread narrowed to just €0.39/MWh, effectively bringing the two markets to parity. This contrasted with periods when Serbia has carried a material scarcity premium over HUPX.
Montenegro prices lower, while Albania moves higher
Montenegro traded substantially lower, with BELEN baseload down €8 to €230.55/MWh. That was around €10.75 below Hungary and more than €11 below Serbia.
Montenegro’s system was close to physical balance: consumption averaged around 356 MW and generation reached about 369 MW. The resulting net export position was around 13 MW, following net imports the previous day.
BELEN peak prices averaged €233/MWh, compared with €228.1/MWh off-peak. The relatively balanced domestic position kept Montenegro’s price closer to Greece than to the higher-priced Romanian, Bulgarian and North Macedonian markets.
Albania was the main exception to the regional decline. ALPEX rose €36.9 to €251.67/MWh, moving from among the lower-priced markets on Monday into the upper part of the SEE range.
Albania’s hourly profile was highly volatile: peak prices averaged €221.8/MWh, while off-peak prices reached €281.5/MWh. Prices ranged from €20/MWh to €400/MWh during the day.
North Macedonia remained the region’s highest-priced baseload market at €259.84/MWh, despite its €25 daily decline. Across the core SEE markets, prices ranged from €224.85/MWh in Greece to €259.84/MWh in North Macedonia, a difference of around €35/MWh.
German discount narrows as forward prices remain elevated
The largest structural spread remained between Germany and Hungary. German day-ahead baseload rose €38.5 to €155.11/MWh, while HUPX fell to €241.30/MWh.
The Hungary-Germany spread narrowed by almost €65/MWh to €86.18/MWh. Although substantially smaller than in recent sessions, the differential remained wide, indicating that cheaper western European electricity could not fully reach Hungary and Southeast Europe.
Austria traded at €247.66/MWh and Italy at €246.67/MWh, leaving both slightly above Hungary. Germany remained much cheaper, Austria and northern Italy were near SEE levels, and Romania, Bulgaria and North Macedonia carried the highest premiums.
The sharp day-ahead decline was not reflected in the forward curve. Hungarian week-45 power rose €6.5 to €301/MWh, week 46 increased €5.5 to €271/MWh, and November gained €8 to €280.50/MWh.
Calendar 2026 increased €4 to €182/MWh. November power consequently remained almost €40/MWh above Tuesday’s HUPX spot settlement.
Fuel and carbon markets also strengthened. Austrian CEGH gas rose €2.6 to €97.71/MWh, Greek gas increased to €86.08/MWh, and EU carbon allowances gained €1.9 to €88.19/t; November coal eased to €149.5/t.
Expensive gas, firmer carbon and unresolved generation risks kept a substantial risk premium in forward electricity prices. Romania faced uncertainty over nuclear and hydropower availability, while Bulgaria was dealing with low Danube levels affecting the operating environment around Kozloduy.
Those constraints remained particularly relevant as the market approached November and solar production entered its seasonal decline. Tuesday’s spot correction therefore did not yet represent a broad easing of the regional winter outlook.
Stronger renewable output and improved generation lowered immediate prices, while fuel costs, limited cross-border capacity and generation-security concerns kept the forward curve elevated. For SEE traders, the east-west differential remained a key indicator: the Hungary-Germany spread had narrowed sharply but was still more than €86/MWh.
That gap continued to show the structural separation between Southeast Europe and cheaper German supply. Until it contracts more decisively, day-to-day corrections such as Tuesday’s remain volatility within a regionally tight market rather than evidence of a sustained decline in SEE power prices.