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 supply-demand balance and German prices fell heavily. The decline was far from uniform, however. Serbia and particularly Albania moved against the broader regional trend, while a strengthening Italian market widened the north-south price divide and kept cross-border capacity towards Italy heavily utilised.
Hungarian HUPX baseload fell by €12.36/MWh from Wednesday to €171.64/MWh. Romania followed at €174.58/MWh, down by around €11.9/MWh, while Bulgaria declined by €13/MWh to €172.36/MWh and Greece lost approximately €11.2/MWh to €173.25/MWh. Slovenia recorded an even sharper fall to €167.08/MWh, while Croatia dropped to €168.53/MWh, Montenegro to €165.92/MWh and North Macedonia to €167.45/MWh.
Serbia was one of the few exceptions to the regional decline. SEEPEX increased by €5.2/MWh to €168.02/MWh, while Albania posted the strongest upward movement in the region, with ALPEX jumping by more than €30/MWh to €184.06/MWh. Albania consequently traded at a €12.42/MWh premium to Hungary, while Serbia, Montenegro and North Macedonia remained below the HUPX price.
The clearest external price signal came from Germany, where day-ahead power dropped to around €125.54/MWh. This left Hungary trading at a €46.10/MWh premium to Germany, widening the spread by approximately €15.7/MWh compared with the previous day. At the other end of the regional system, Italian prices continued to strengthen, with the South zone reaching around €205.52/MWh, approximately €33.88/MWh above HUPX. Italy’s national day-ahead price was also elevated at around €204/MWh.
The result was a pronounced three-way market structure, with Germany representing the low-price end of the system, central and south-east European markets clustering mostly between €165/MWh and €175/MWh, and Italy remaining above €200/MWh. Albania moved closer to the Italian price level following its sharp daily increase.
The main bearish influence across central and south-east Europe was the increase in renewable generation. Regional solar output was forecast at 8.223 GW, up by 1.325 GW from the previous day, while wind generation was expected to increase by another 251 MW to 1.711 GW. Electricity demand, meanwhile, was projected to rise by only 288 MW to 34.028 GW.
This improvement in renewable availability reduced the region’s overall need for imports. Aggregate HU+SEE generation was estimated at around 31.671 GW, approximately 503 MW higher than the previous day, while net imports declined by 214 MW to 2.357 GW. Imports from Austria and Slovakia into Hungary and Slovenia remained high at around 3.312 GW, but exports from the region towards Italy increased to 1.402 GW from 1.130 GW.
The combination of stronger solar generation and continued thermal constraints produced a clear inversion between daytime and evening prices. Additional renewable output pushed down prices during the traditional daytime peak period, while higher-cost thermal generation and the need for flexibility supported significantly stronger evening and overnight prices.
Hungary provided one of the clearest examples of this pattern. Although the HUPX baseload contract averaged €171.64/MWh, the conventional peak block settled at only €147.9/MWh, compared with an off-peak price of €195.3/MWh. Hourly prices fell to €82.2/MWh at hour 12 before climbing sharply to €251.2/MWh at hour 21.
The same pattern was visible across much of south-east Europe. Romania’s peak block averaged around €146.8/MWh compared with €202.4/MWh during off-peak hours. Greece recorded €146.2/MWh during the peak period and €200.3/MWh off-peak, while Bulgaria stood at €144.4/MWh versus €200.3/MWh. Croatia showed a similar structure, with peak prices at €148.7/MWh and off-peak prices at €188.3/MWh.
Serbia also displayed a strong intraday price spread despite its higher baseload settlement. SEEPEX peak power averaged €153.1/MWh, while off-peak electricity traded at €183/MWh. The Serbian market reached a daily low of €114/MWh in hour 11 before climbing to €250/MWh in hour 20. Albania remained significantly tighter, with its lowest hourly price still at €136/MWh and its daily maximum reaching €265.5/MWh in hour 21.
The persistence of this structure is becoming increasingly important for regional power trading. Solar generation is no longer simply reducing the average daily electricity price. Instead, it is compressing prices during daylight hours while concentrating scarcity around the evening ramp and, in some cases, overnight periods. This is increasing the value of flexible gas-fired generation, hydropower reservoirs, battery storage and cross-border transmission capacity.
Serbia’s divergence from neighbouring markets was partly linked to a weaker domestic balance. Serbian electricity consumption was forecast to decline to 3.664 GW from 3.813 GW, but generation was expected to fall even more sharply, to 3.071 GW from 3.388 GW. As a result, average net imports increased to around 593 MW from 425 MW a day earlier.
Commercial schedules reflected this growing dependence on neighbouring systems. Serbia was importing approximately 230 MW from Bosnia and Herzegovina, 253 MW from Croatia, 142 MW from Hungary, 133 MW from Romania and 79 MW from Bulgaria. At the same time, scheduled flows continued towards Montenegro and, to a smaller extent, North Macedonia. The tighter domestic balance helped support SEEPEX even as most neighbouring markets moved lower.
Albania experienced an even more significant tightening of its domestic position. Generation declined from around 1.061 GW to 1.000 GW, while demand remained close to 1.16 GW. This increased the country’s net import requirement to approximately 160 MW from 107 MW previously.
In a relatively small market with limited domestic thermal flexibility, lower generation and increased import dependence were enough to push ALPEX significantly above the rest of the western Balkans. Its €184.06/MWh baseload price stood around €16/MWh above Serbia and more than €18/MWh above Montenegro.
Cross-border schedules also highlighted the growing influence of Italy on south-east European price formation. The region was scheduled to export an average of around 1.402 GW to Italy, largely through three major corridors: approximately 585 MW from Montenegro, 414 MW from Greece and 403 MW from Slovenia.
Italy therefore remained the main premium destination for regional electricity exports. With the Italian national market trading close to €204/MWh and the South zone above €205/MWh, the economics strongly favoured exports towards Italy wherever transmission capacity was available.
Montenegro provided one of the most striking examples of the increasingly complex regional flow structure. Although the country remained a net importer of around 149 MW, commercial schedules showed approximately 585 MW flowing towards Italy. Montenegro was effectively importing electricity from neighbouring markets while maintaining substantial exports across the Adriatic, reinforcing its role as an important transit and trading hub.
Slovenia showed a similar pattern. The country was a net importer of approximately 297 MW while simultaneously scheduling around 403 MW of exports to Italy and 724 MW to Croatia. These exports were supported by significant imports from Austria and Hungary.
Hungary remained the pivotal northern transit market. Domestic consumption declined from 4.840 GW to 4.601 GW, while generation increased from 3.768 GW to 3.933 GW, reducing net imports from 1.072 GW to 668 MW. Gross flows remained significantly larger than the net position, with Hungary receiving substantial volumes from Slovakia and Austria while simultaneously exporting to Croatia, Romania, Slovenia and Serbia.
The Hungarian hourly balance was particularly revealing. The country remained a major importer during off-peak hours, averaging around 1.801 GW of net imports, but switched to an average net export position of approximately 466 MW during the peak block. Solar generation therefore influenced not only the shape of prices but also the direction of regional electricity flows within the same day.
Bulgaria remained one of the strongest underlying exporters in the region. Generation was forecast at 4.920 GW against demand of 4.015 GW, leaving average exports close to 905 MW. Major scheduled flows included exports towards Romania, Greece, North Macedonia and Serbia.
Greece also strengthened its export position. Demand increased to 8.038 GW, but generation rose faster to 8.476 GW, lifting net exports to around 438 MW from only 81 MW previously. The largest external flow was approximately 414 MW towards Italy, helping maintain relatively close price alignment between Greece, Bulgaria, Romania and Hungary.
Romania moved in the opposite direction from a physical balance perspective. Its net import requirement increased to around 939 MW from 755 MW as generation declined to 4.862 GW while consumption eased only slightly to 5.801 GW. Nevertheless, OPCOM prices fell by nearly €12/MWh to €174.58/MWh, indicating that regional market coupling and increased Bulgarian exports outweighed the deterioration in Romania’s domestic balance.
The fuel complex offered some additional relief, although it did not eliminate the evening scarcity premium. Austrian CEGH gas was indicated near €66.49/MWh, down by around €1.5/MWh, while Greek gas traded close to €66.02/MWh. EU carbon allowances stood at approximately €82.68/t, also lower on the day. September and fourth-quarter gas contracts remained near €67/MWh, while API2 coal was close to $127/t.
Hungarian forward power continued to trade below the elevated day-ahead market. 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 settlement. The forward curve therefore continued to signal expectations of some normalisation from the current high spot-price environment.
The broader market signal was consequently less bearish than the decline in headline baseload prices initially suggested. Renewable generation loosened the daytime balance and pushed most south-east European markets lower, but scarcity shifted into the evening rather than disappearing entirely. Several exchanges continued to record hourly prices near or above €250/MWh, while Italy maintained a substantial premium and Serbia and Albania demonstrated how quickly individual markets can diverge when domestic balances tighten.
For traders, the increasingly important spread is no longer limited to differences between national markets. A growing opportunity is emerging between solar-heavy midday hours and the evening ramp, layered on top of persistent German-SEE and SEE-Italy price differentials and transmission constraints. Thursday’s market, with Germany around €125/MWh, the core SEE region largely between €165/MWh and €175/MWh, Albania at €184/MWh and Italy above €200/MWh, offered a clear illustration of how renewable output, cross-border capacity and evening flexibility are increasingly creating multiple price zones across the interconnected European power market.