Southeast European day-ahead electricity prices declined sharply across most markets on Tuesday, with Serbia, Greece and Hungary recording some of the largest drops. Higher renewable generation forecasts and increased regional electricity production eased import requirements despite rising consumption.
Serbia’s SEEPEX registered one of the steepest corrections, with the baseload price falling €43.4/MWh to €241.69/MWh, down from €285.1/MWh a day earlier. Hungary’s HUPX declined by €26.1 to €241.30/MWh, bringing the Serbian and Hungarian baseload prices virtually into alignment.
Greece recorded a €33.7/MWh drop to €224.85/MWh, the lowest price among the region’s major markets. North Macedonia fell by €25 to €259.84/MWh, but remained the most expensive market in Southeast Europe.
Romania and Bulgaria continued to trade at a premium. OPCOM settled at €255.49/MWh, €14.19 above Hungary, while Bulgaria’s IBEX reached €254.58/MWh, maintaining a €13.28 premium over HUPX.
The price movements indicate that the extreme tightness seen across Eastern Europe on Monday had eased. However, persistent transmission constraints and generation risks continued to separate Romania and Bulgaria from cheaper markets farther west and south.
The main downward pressure came from stronger renewable generation availability.
Regional solar output forecasts increased by almost 2 GW day on day to 4.26 GW, while forecast wind generation rose by slightly more than 1 GW to 3.51 GW. Together, the additional 3 GW of expected renewable output provided a substantial increase in lower-marginal-cost electricity supply.
Demand also strengthened. Aggregate consumption across Hungary and Southeast Europe rose by 626 MW to 32.94 GW, yet net regional imports fell by 608 MW to 4.01 GW.
Imports from the main Austrian and Slovak direction declined by 219 MW to approximately 4.38 GW.
Trade flows also shifted in Italy’s favour less than on the previous day, with Southeast Europe moving to net exports of around 155 MW towards Italy, compared with imports of approximately 400 MW a day earlier. This represented a swing of more than 550 MW.
Regional generation reached around 28.9 GW, up from 27.7 GW on Monday. The increase in domestic production covered most of the rise in consumption while reducing the region’s dependence on imported electricity.
The combination of stronger demand, higher generation and lower imports is central to understanding Tuesday’s price decline. Prices fell not because demand weakened, but because improved supply availability and stronger renewable output eased the regional balance.
Serbia’s prices fall despite a wider import deficit
Serbia illustrated the growing influence of regional market conditions on domestic electricity prices.
Average consumption increased to approximately 4.21 GW, from 4.05 GW, while generation edged down to around 3.27 GW. The country’s net import requirement consequently widened to about 935 MW, compared with 722 MW a day earlier.
Despite the deteriorating domestic supply balance, SEEPEX prices fell by more than €43/MWh.
This highlights the importance of regional fundamentals in Serbian price formation. Serbia continued to draw electricity from neighbouring markets as the broader Southeast European price structure weakened.
Commercial flows showed electricity entering Serbia from Bosnia and Herzegovina, Croatia and Bulgaria, while Serbia also supplied electricity northwards to Hungary during part of the day.
SEEPEX peak prices averaged €253.1/MWh, while off-peak prices fell to €230.2/MWh. The daily minimum reached €165.1/MWh, and the maximum stood at €314.4/MWh.
The Serbian-Hungarian baseload spread narrowed to just €0.39/MWh, effectively bringing the two markets to price parity.
This represents a marked change from periods when Serbia has traded at a significant scarcity premium over HUPX.
Montenegro trades below neighbouring markets
Montenegro recorded a more moderate decline, with BELEN baseload prices falling by €8 to €230.55/MWh. This placed the market approximately €10.75 below Hungary and more than €11 below Serbia.
The country’s electricity balance was also close to equilibrium. Average consumption stood at around 356 MW, while generation reached approximately 369 MW, leaving a small net export position of about 13 MW. Montenegro had been a net importer the previous day.
BELEN peak prices averaged €233/MWh, while off-peak prices settled at €228.1/MWh.
The relatively balanced domestic supply position helped Montenegro trade closer to Greece’s lower price level than to the more expensive markets in Romania, Bulgaria and North Macedonia.
Albania moves against the regional trend
Albania was the main exception to the widespread price decline.
ALPEX baseload prices rose by €36.9/MWh to €251.67/MWh, moving the market from among the cheaper regional destinations on Monday into the upper end of the Southeast European price range.
Hourly prices were particularly volatile. Peak electricity averaged €221.8/MWh, while off-peak prices reached €281.5/MWh. Prices fluctuated between €20/MWh and €400/MWh during the day.
North Macedonia remained the region’s most expensive baseload market at €259.84/MWh, despite its daily decline of €25/MWh.
Across the main Southeast European markets, baseload prices ranged from €224.85/MWh in Greece to €259.84/MWh in North Macedonia, a difference of approximately €35/MWh.
Albania’s price increase underscores how national generation conditions and hourly supply-demand dynamics can produce outcomes that diverge from the wider regional trend.
German price recovery narrows the spread with Hungary
The most significant structural price difference remained between Germany and Hungary.
German day-ahead baseload prices rose by €38.5 to €155.11/MWh, while HUPX fell to €241.30/MWh.
As a result, the Hungary-Germany spread narrowed by almost €65/MWh to €86.18/MWh.
Although the reduction was substantial, the remaining differential indicates that cheaper western European electricity was still unable to flow fully into Hungary and Southeast Europe.
Austria traded at €247.66/MWh and Italy at €246.67/MWh, leaving both markets slightly more expensive than Hungary.
The resulting price structure remained fragmented. Germany was significantly cheaper, Austria and northern Italy traded close to Southeast European levels, and Romania, Bulgaria and North Macedonia retained the highest premiums.
The narrowing of the German-Hungarian spread offers some relief, but the remaining gap points to persistent regional market separation.
Forward prices remain elevated despite the spot correction
The decline in day-ahead prices did not translate into weaker forward electricity prices.
Hungarian week-45 power increased by €6.5 to €301/MWh, while week-46 contracts rose by €5.5 to €271/MWh. November electricity gained €8 to €280.50/MWh, and calendar-year 2026 power increased by €4 to €182/MWh.
November contracts therefore remained almost €40/MWh above Tuesday’s HUPX spot settlement.
Energy commodity markets also strengthened. Austrian CEGH gas rose by €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, by contrast, eased to €149.5/t.
Higher gas and carbon prices, combined with continuing uncertainty over electricity generation, are helping sustain a substantial risk premium in forward power contracts.
Romania faces uncertainty surrounding nuclear and hydropower availability, while Bulgaria has been dealing with low Danube water levels affecting the operating environment around Kozloduy. These constraints remain relevant as the market approaches November and seasonal reductions in solar output begin to take effect.
Tuesday’s spot-price correction therefore does not yet signal a broad easing of the regional winter outlook.
Instead, the market is displaying two distinct trends. Stronger renewable forecasts and improved generation availability are putting downward pressure on immediate prices, while fuel costs, cross-border transmission constraints and concerns about generation security continue to support forward valuations.
For Southeast European traders, the east-west price differential remains a key indicator. The Hungary-Germany spread has contracted significantly, but at more than €86/MWh, it still demonstrates the region’s limited ability to benefit fully from cheaper German electricity.
Until that gap narrows further, sharp daily corrections are more likely to reflect volatility within a structurally tight regional market than the beginning of a sustained decline in Southeast European power prices.
