South-east European day-ahead electricity prices moved sharply lower across most interconnected markets for Thursday delivery, as a substantial increase in forecast renewable generation loosened the regional balance and German prices fell heavily. The retreat was far from uniform, however: Serbia and particularly Albania moved against the regional direction, while a strengthening Italian market widened the north-south price divide and kept cross-border capacity towards Italy heavily utilised.
Hungarian HUPX base fell by €12.36/MWh from Wednesday to €171.64/MWh. Romania followed at €174.58/MWh, down about €11.9/MWh, while Bulgaria fell €13/MWh to €172.36/MWh and Greece lost roughly €11.2/MWh to €173.25/MWh. Slovenia dropped even more sharply to €167.08/MWh, Croatia to €168.53/MWh, Montenegro to €165.92/MWh and North Macedonia to €167.45/MWh.
Serbia broke with that pattern. SEEPEX gained €5.2/MWh to €168.02/MWh, while Albania recorded by far the largest upward move, with ALPEX jumping more than €30/MWh to €184.06/MWh. The result left Albania trading at a €12.42/MWh premium to Hungary, compared with discounts of €3.63/MWh for Serbia, €5.72/MWh for Montenegro and €4.19/MWh for North Macedonia.
The day’s clearest price signal nevertheless came from outside SEE. German day-ahead power dropped to about €125.54/MWh, leaving Hungary at a €46.10/MWh premium to Germany, around €15.7/MWh wider than a day earlier. At the opposite end of the regional system, the Italian South zone rose to approximately €205.52/MWh, around €33.88/MWh above HUPX. Italy’s national day-ahead price was also elevated at about €204/MWh, compared with €197.4/MWh previously.
That produced a pronounced three-way market structure: cheap Germany to the northwest, a relatively tightly grouped central and south-east European block around €165-175/MWh, and expensive Italy above €200/MWh. Albania sat between the SEE cluster and Italy after its sharp daily increase.
The main bearish influence across the central SEE block was renewable availability. Regional solar output was forecast at 8.223 GW, an increase of 1.325 GW from the previous day, while wind was forecast to increase by another 251 MW to 1.711 GW. Regional electricity demand, by comparison, was expected to rise by only 288 MW to 34.028 GW.
The supply improvement reduced the need for net imports despite the modest increase in consumption. Aggregate HU+SEE generation was indicated at about 31.671 GW, roughly 503 MW higher than the previous day, while net imports fell by 214 MW to 2.357 GW. Imports from Austria and Slovakia into Hungary and Slovenia remained high at about 3.312 GW, almost unchanged day on day, but the region simultaneously increased exports towards Italy to 1.402 GW, from 1.130 GW previously.
The combination explains much of Thursday’s unusual pricing pattern. Additional solar output depressed the daytime peak block, while high-cost thermal generation and increasingly valuable evening flexibility kept evening and overnight prices much stronger.
HUPX provides one of the clearest examples. Although the Hungarian baseload contract averaged €171.64/MWh, the conventional peak block cleared at only €147.9/MWh, compared with an off-peak price of €195.3/MWh. The hourly minimum fell to €82.2/MWh at hour 12, before the market climbed to €251.2/MWh at hour 21.
The same solar-driven inversion was visible almost everywhere in SEE. Romania’s peak block averaged about €146.8/MWh against €202.4/MWh off-peak; Greece stood at €146.2/MWh peak against €200.3/MWh off-peak; Bulgaria at €144.4/MWh versus €200.3/MWh; and Croatia at €148.7/MWh against €188.3/MWh.
Serbia showed the same shape despite its higher baseload settlement. SEEPEX peak power averaged €153.1/MWh, while off-peak traded at €183/MWh. The market bottomed at €114/MWh in hour 11 before reaching €250/MWh in hour 20. Albania was considerably tighter, with its lowest hour still at €136/MWh and its daily maximum reaching €265.5/MWh in hour 21.
The persistence of the inverted peak/off-peak structure is increasingly important for regional trading. Solar is no longer simply lowering the daily average. It is compressing prices during conventional business-hour peaks while concentrating scarcity into the evening ramp and parts of the overnight period. The result is a much steeper intraday shape and greater value for flexible gas plants, hydro reservoirs, storage and cross-border capacity around sunset.
Serbia’s divergence from its neighbours can be traced partly to a weaker domestic balance. Serbian consumption was forecast to fall to 3.664 GW from 3.813 GW, but generation was expected to decline more sharply, to 3.071 GW from 3.388 GW. Net imports consequently increased to an average 593 MW, from 425 MW a day earlier.
Commercial schedules illustrate the pressure. Serbia was importing on average about 230 MW from Bosnia and Herzegovina, 253 MW from Croatia, 142 MW from Hungary, 133 MW from Romania and 79 MW from Bulgaria, while at the same time scheduled flows remained directed from Serbia towards Montenegro and, on a smaller base-load basis, North Macedonia. The resulting position left Serbia more dependent on neighbouring systems just as much of the broader region was seeing lower prices.
This helps explain why SEEPEX rose while Croatian, Hungarian, Bulgarian and Romanian prices declined. Serbia’s €168.02/MWh price was still below the four eastern and central markets supplying much of its import requirement, but the spread narrowed considerably.
Albania’s move was more extreme. Domestic generation declined from around 1.061 GW to 1.000 GW, while demand remained close to 1.16 GW, increasing its net import requirement to roughly 160 MW, from 107 MW previously.
In a relatively small market with limited domestic thermal flexibility, the combination of lower available generation, import dependence and the evening ramp was sufficient to lift ALPEX well above the rest of the western Balkans. Its €184.06/MWh base price was approximately €16/MWh above Serbia and more than €18/MWh above Montenegro.
Cross-border schedules also show how strongly Italy is now influencing SEE price formation.
The region was scheduled to export an average 1.402 GW to Italy. That figure can be almost completely reconstructed from three corridors: around 585 MW from Montenegro to Italy, 414 MW from Greece to Italy and 403 MW from Slovenia to Italy.
Italy therefore acted as the principal premium destination for surplus SEE electricity. With the Italian national market near €204/MWh and southern Italy above €205/MWh, the economics strongly favoured north-to-south and east-to-west exports wherever transmission capacity was available.
Montenegro provides the most striking example. Although the country itself remained a net importer of around 149 MW, commercial schedules through the Italy interconnector averaged about 585 MW towards Italy. The market was effectively importing energy from Bosnia, Serbia, Albania and Kosovo while maintaining high exports across the Adriatic, demonstrating the increasing importance of Montenegro as a transit and trading hub rather than treating its national balance in isolation.
Slovenia showed a similar transit pattern. It was a net importer of approximately 297 MW, yet scheduled about 403 MW to Italy and 724 MW to Croatia, supported by nearly 993 MW of imports from Austria and 431 MW from Hungary.
Hungary remained the pivotal northern transit market. Domestic consumption eased from 4.840 GW to 4.601 GW, while generation increased from 3.768 GW to 3.933 GW, cutting net imports from 1.072 GW to 668 MW. Gross flows remained considerably larger than that net figure: Hungary received about 1.614 GW from Slovakia and 706 MW from Austria, while simultaneously sending 836 MW to Croatia, 560 MW to Romania, 431 MW to Slovenia and 142 MW to Serbia on a base-load average basis.
The Hungarian hourly balance was even more revealing. The market remained a large importer during off-peak hours, averaging about 1.801 GW of net imports, but switched to an average 466 MW net export position during the peak block. Solar therefore changed not only the price curve but also the direction and scale of regional flows within the same delivery day.
Bulgaria remained one of the strongest underlying exporters. Generation was forecast at 4.920 GW against demand of 4.015 GW, leaving average exports near 905 MW. Commercial schedules included roughly 482 MW towards Romania, 262 MW towards Greece, 131 MW towards North Macedonia and 79 MW towards Serbia.
Greece also moved into a substantially larger export position. Demand increased to 8.038 GW, but generation rose faster to 8.476 GW, lifting net exports to around 438 MW, compared with only 81 MW previously. Its largest single external schedule was the 414 MW flow towards Italy, helping keep the Greek price closely aligned with Bulgaria, Romania and Hungary despite higher Greek consumption.
Romania represented the opposite case. Its net import requirement increased to about 939 MW from 755 MW, as generation fell to 4.862 GW while consumption eased only to 5.801 GW. Yet OPCOM still fell nearly €12/MWh to €174.58/MWh, suggesting that regional coupling, greater Bulgarian exports and the broad fall in continental prices outweighed the deterioration in Romania’s domestic balance.
The fuel complex offered some additional relief but did not remove the evening scarcity premium. Austrian CEGH gas was indicated near €66.49/MWh, down around €1.5/MWh, while Greek gas was around €66.02/MWh. EU carbon allowances stood at approximately €82.68/t, down €1.7/t. September and fourth-quarter gas forwards were both around €67/MWh, while API2 coal contracts were close to $127/t.
Hungarian forward power nevertheless remained below Thursday’s spot settlement. Week 36 traded near €154.50/MWh, Week 37 at €156/MWh and September at €163/MWh, compared with the €171.64/MWh day-ahead price. September eased by about €2/MWh, while the Week 36 contract gained only €0.50/MWh. The curve therefore continues to price some normalisation from the current elevated spot environment.
The broader trading signal from Thursday is consequently less bearish than the fall in headline baseload prices initially suggests. Renewable availability has loosened the daytime regional balance and pushed most SEE markets lower, but scarcity has migrated rather than disappeared. Evening hours remain close to or above €250/MWh across several exchanges, Italy is maintaining a substantial premium and Serbia and Albania have demonstrated how quickly individual markets can disconnect when their domestic balances tighten.
For traders, the increasingly important spread is therefore no longer only country against country. The more significant opportunity is emerging between solar-heavy midday hours and the evening ramp, layered on top of persistent German-SEE and SEE-Italy congestion. Thursday’s market — with Germany around €125/MWh, the core SEE cluster around €165-175/MWh, Albania at €184/MWh and Italy above €200/MWh — is a clear illustration of how renewable output, transmission capacity and evening flexibility are now setting three different prices across the same interconnected European trading corridor.
