Southeast European day-ahead electricity prices opened the week sharply higher as weekday consumption returned alongside weaker wind generation, historically poor Serbian hydrology and wider congestion against Germany. The highest price levels were concentrated in the central and western part of the region, with Italy at €197.71/MWh, Montenegro at €196.11/MWh, Serbia at €185.23/MWh and Slovenia at €180.30/MWh.
Hungary’s HUPX settled at €178.57/MWh, up by €56.40/MWh from Sunday. Romania cleared at €178.07/MWh, only €0.51/MWh below HUPX, while Croatia finished at €179.23/MWh. Hungary, Romania, Slovenia and Croatia clustered between €178/MWh and €180/MWh.
Central cluster versus wider regional divergence
The market did not converge across borders, with Germany clearing at €128.09/MWh. The Hungarian premium over Germany reached €50.48/MWh, rising by almost €34/MWh in one day. Germany increased by €22.60/MWh, while HUPX advanced more than twice as much.
The largest premium was reported in Serbia and Montenegro, where SEEPEX rose by €73.10/MWh to €185.23/MWh. Serbia traded at €6.66/MWh above Hungary, while Montenegro’s BELEN price stood at €17.54/MWh above HUPX and only €1.60/MWh below Italy. These levels placed both markets in the expensive Adriatic and central Balkan zone rather than the cheaper southern Balkan cluster.
Around the rest of the region, Albania cleared at €136.03/MWh, North Macedonia at €138.07/MWh, Greece at €153.96/MWh and Bulgaria at €158.08/MWh. Albania’s discount to Hungary was €42.54/MWh, while North Macedonia traded at €40.50/MWh below HUPX. Greece was cheaper by €24.61/MWh, and Bulgaria by €20.49/MWh.
A fragmented price map across interconnected markets
The day-ahead price pattern was unusually fragmented despite shared system participation across the Balkans. The gap between Montenegro and neighbouring Albania reached approximately €60/MWh. The spread between Italy and Albania was almost €62/MWh, while Serbia traded around €47/MWh above North Macedonia.
This dispersion pointed to constraints affecting how prices form locally, including transmission limits and commercial allocation factors alongside differences in national generation positions rather than a single uniform regional shortage.
Load recovery, solar support and weaker wind output
The main demand signal came from the transition from Sunday to Monday, when forecast regional consumption increased by 4,072 MW, or almost 14%, to an average of 33,440 MW. Hungary contributed 673 MW, with demand reaching 5,126 MW. Greece rose by 541 MW to 6,859 MW.
The remaining increases included Romania and Bulgaria together adding 1,476 MW to reach 9,516 MW, while Slovenia and Croatia added a combined 1,305 MW, reaching 10,211 MW. Temperature changes alone did not explain the move: the regional average stayed broadly stable at
The regional average remained at
The regional average was broadly stable at
The regional average was broadly stable at 27.1°C, while Greece warmed to 28°C and Hungary was forecast at 30.1°C.
(The price change was therefore linked primarily to weekday load recovery and supply conditions rather than a sudden temperature spike.) Renewable generation showed mixed signals: forecast solar output increased by 1,976 MW to 8,367 MW as daytime production strengthened.
(Wind declined by 980 MW to 1,561 MW, a drop of almost 39%.) The reduction in wind removed part of the incremental solar contribution and left the evening ramp more dependent on thermal generation, imports and limited hydro flexibility.
Tightness concentrated in evening hours and higher net imports into SEE
The hourly profiles showed pressure outside the strongest solar-production window. HUPX and Romania’s OPCOM were relatively subdued around midday before rising steeply during the evening, approaching or exceeding €400/MWh around hours 20 and 21.
BSP in Slovenia climbed to approximately €500/MWh during the evening peak, while Greece recorded an evening maximum close to €280/MWh.
Solar output suppressed prices during midday but did not offset falling production after sunset combined with recovering industrial demand and weak wind output.
The region’s net imports averaged 1,981 MW, up by 440 MW from Sunday. Imports from core markets through Austria and Slovakia rose by 191 MW to 2,852 MW.
The net Italy-to-SEE position was reported at negative 876 MW, indicating SEE exported toward Italy on a net basis despite tightening conditions domestically; compared with Sunday this was a 459 MW movement that reduced the net benefit of higher northern imports.
Northern flows versus commercial schedules; hydrology and Danube constraints remain key inputs for pricing risk
The widening Hungarian-German spread reflected that additional transfer capacity did not transmit Germany’s lower price level into Hungary despite average core imports approaching 2.9 GW; HUPX premium expanded to €50.48/MWh.
The seven-day commercial-flow structure showed scheduled flows continuing from Bulgaria toward Romania, from Romania toward Hungary and from Hungary toward Croatia, while Hungary remained a major exporter toward Slovakia on the reported schedule.
(Slovenia also supplied Croatia and Italy.) In the southern Balkans, Albania and North Macedonia generally directed electricity toward Greece, while Montenegro’s commercial position favoured exports toward Albania, Serbia and Kosovo.
(Hydrology remained a structural concern.) Serbian hydroelectric output fell to historically low levels amid persistent drought, reducing low-variable-cost production and peak-shaving capability; hydro normally provides both energy and flexibility during morning and evening ramps.
Bweak reservoir conditions forced greater reliance on lignite units, imports and expensive short-duration balancing purchases.
Nuclear exposure tied to river flow; fuel costs support a higher thermal floor in tight hours
A second risk layer came from Danube conditions: river flow at the relevant measurement point was approximately 4,534 cubic metres per second, well below the long-term seasonal profile.
Bulgaria’s Kozloduy nuclear power plant was reported operating normally; however the market continued assigning value to potential further nuclear or hydro constraints as trading conditions tightened.
Paks faced operational pressure from exceptionally low Danube levels, while Romania’s Cernavoda and Bulgaria’s Kozloduy remained exposed to prolonged heat and cooling-water limitations.
The fuel picture provided limited protection against further tightening: Austrian CEGH gas stood at €60.27/MWh with September around €60/MWh and fourth-quarter around €59.50/MWh; Greek gas was assessed at €53.09/MWh up by €1.70/MWh.