Southeast European day-ahead electricity markets opened the week with a sharp weekday repricing, but the increase was far from uniform. HUPX rose by €44.90/MWh to €125.90/MWh, while Slovenia followed at €126.01/MWh. Prices across Romania, Bulgaria and Greece settled close to €110–114/MWh, but Serbia, Montenegro and Albania remained substantially cheaper.
The resulting price map points to renewed market fragmentation rather than a region-wide shortage. Hungary traded €28.37/MWh above Serbia, €30.66/MWh above Montenegro and €41.62/MWh above Albania. The Hungary-Greece spread reached €15.74/MWh, while Slovenia traded almost exactly in line with HUPX.
Serbia’s SEEPEX price increased by €24.90/MWh to €97.53/MWh, a sizeable weekday recovery but still one of the lowest levels in the region. Montenegro moved in the opposite direction, falling by €6.30/MWh to €95.24/MWh, while Albania declined slightly to the regional minimum of €84.28/MWh. North Macedonia rose to €104.73/MWh.
Romania settled at €114.46/MWh, Bulgaria at €110.26/MWh and Greece at €110.16/MWh. The very small €0.10/MWh Bulgaria-Greece spread indicates effective price convergence across the southern part of the interconnected Bulgarian-Greek zone, even as both markets remained more than €15/MWh below Hungary.
The largest external price signal came from Italy, where the national day-ahead average reached €152.11/MWh. Italy consequently traded at a premium of €26.21/MWh to HUPX, €41.85/MWh to Bulgaria and more than €54/MWh to Serbia. Germany settled at €119.11/MWh, leaving HUPX at a €6.79/MWh premium, while Austria reached €128.93/MWh, only €3.03/MWh above Hungary.
The Monday demand rebound was strong. Forecast regional consumption increased by 3,957 MW, or approximately 14.3%, to an average 31,616 MW. Yet net imports fell by 832 MW to only 959 MW. The apparent contradiction is explained by a substantial improvement in renewable generation.
Forecast solar production increased by 2,598 MW to 7,894 MW, while wind rose by 1,089 MW to 2,168 MW. Combined solar and wind therefore reached 10,062 MW, an increase of 3,687 MW. Renewable growth covered approximately 93% of the entire increase in demand between Sunday and Monday.
Solar alone was equivalent to around 25% of average regional consumption, while combined solar and wind represented almost 32%. Net imports covered only about 3% of consumption, compared with approximately 6.5% on Sunday. The implied domestic generation requirement was close to 30.66 GW.
This explains why the region could accommodate a nearly 4 GW increase in consumption without calling for additional aggregate imports. It does not, however, explain the sharp Hungarian price increase on its own. The price separation indicates that generation availability was geographically misaligned with demand and transfer capacity.
Imports from Austria and Slovakia into the Hungary-Slovenia and wider SEE area declined by 905 MW to 2,027 MW. At the same time, the region continued to send approximately 1,181 MW toward Italy. Hungary therefore remained exposed to a tighter northern and central European balance while lower-priced generation was concentrated further south and east.
The country-level power balance reinforces this conclusion. Hungary was a net importer of approximately 1,042 MW, while Croatia imported 839 MW, Serbia 445 MW and Romania 314 MW. Bulgaria was the principal regional exporter at approximately 1,275 MW, while Greece exported around 380 MW.
Bulgaria’s export position is particularly important. Seven-day commercial-flow averages show Bulgarian deliveries of approximately 475 MW to Romania, 269 MW to Serbia and 335 MW to Greece during baseload hours. Bulgarian exports to Greece fell to around 80 MW during peak hours, indicating that the southern market becomes materially tighter as evening demand increases.
Serbia remained dependent on several surrounding systems. Average flows included deliveries from Bulgaria, Bosnia and Herzegovina, Hungary and North Macedonia, particularly during peak hours. However, SEEPEX remained €12.63/MWh below Bulgaria and €28.37/MWh below Hungary. The disconnect suggests that available interconnection capacity, border nominations and the configuration of commercial flows prevented the Serbian price from fully following neighbouring import costs.
Croatia’s 839 MW net-import requirement was supported by substantial flows from Hungary and Slovenia. Seven-day averages showed Hungary-to-Croatia deliveries of approximately 571 MW in baseload and 709 MW in peakload, alongside Slovenia-to-Croatia flows of around 550 MW and 503 MW, respectively. Croatia nevertheless settled at €119.72/MWh, below both Hungary and Slovenia, reflecting the combined effect of imports, domestic generation and different hourly price structures.
The hourly curves show a pronounced two-part trading day. Hungarian prices remained around or above €120/MWh during the early hours, strengthened through the morning ramp and then fell towards approximately €65–75/MWh during the solar-intensive midday period. Prices subsequently accelerated above €150/MWh, with the evening peak approaching €180/MWh.
Romania and Slovenia displayed broadly similar shapes. Greece experienced deeper late-morning compression, followed by a strong afternoon recovery. Unlike the preceding Sunday, when several markets recorded zero or near-zero prices during the solar window, Monday’s higher industrial and commercial demand kept the midday floors positive.
The strongest merchant opportunity consequently moved away from simple cross-market baseload trading and towards intraday shape management. The spread between the midday trough and evening peak was close to or above €100/MWh in several markets. This remains highly supportive for battery storage, flexible hydro, demand response and generators capable of shifting output into the evening ramp.
The daily price increase was not supported by a parallel rise in fuel or carbon markets. Austrian CEGH gas was unchanged at €49.72/MWh, Greek gas declined to €43.55/MWh, and EU carbon allowances remained near €79.20/tCO₂. Average 2026 gas forwards fell by €1/MWh to €50/MWh, while 2026 coal declined by €4.50/t to €114/t.
Hungarian forward electricity also softened. Week 29 fell by €6/MWh to €131/MWh, Week 30 declined by €4.50/MWh to €128/MWh, and the average 2026 contract eased to €131.50/MWh. The Hungarian premium to Germany narrowed to €13/MWh for Week 29 and €21.50/MWh for Week 30.
The combination of sharply higher day-ahead prices and weaker forward contracts identifies Monday’s move as a calendar, load-shape and transmission event rather than the beginning of a broader fuel-driven rally. The regional generation balance remains relatively comfortable: Danube flow was reported at approximately 5,346 cubic metres per second, close to its long-term seasonal level, while forecast renewable availability was strong.
For Serbia and Montenegro, the immediate market signal is comparatively favourable for buyers but more challenging for unhedged renewable producers. Their discounts to Hungary and Italy reduce domestic procurement costs while limiting the value available to generators unable to secure cross-border access, storage flexibility or an export-indexed offtake structure. The €84–98/MWh price range across Albania, Montenegro and Serbia, against €126/MWh in Hungary and €152/MWh in Italy, places interconnection access and hourly dispatch flexibility at the centre of the region’s trading value.