Southeast European day-ahead electricity prices opened the week higher as weekday demand returned while wind output weakened and Serbian hydrology remained under pressure. Congestion against Germany also widened. In the central and western part of the region, Italy cleared 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 premiums widen versus Germany
The market did not converge beyond the central cluster, 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 tightest 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 was €17.54/MWh above HUPX and only €1.60/MWh below Italy. These levels placed both markets in an expensive Adriatic and central Balkan price zone rather than a cheaper southern Balkan cluster.
A fragmented price pattern also appeared across other exchanges, with Albania 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.
Differing zones show large spreads despite interconnection
The gap between Montenegro and neighbouring Albania reached about €60/MWh, despite physical interconnection and participation in the same wider Balkan system . The spread between Italy and Albania was almost €62/MWh, while Serbia traded around €47/MWh above North Macedonia.
The demand shift from Sunday to Monday provided the main signal for the move in prices . Forecast regional consumption increased by 4,072 MW, or almost 14%, to an average of 33,440 MW. Hungary accounted for 673 MW of the increase, taking demand to 5,126 MW.
Solar rises while wind falls; evening hours drive scarcity pricing
The temperature picture did not align with the size of the price change, with the regional average broadly stable at 27.1°C. Greece warmed to 28°C, while Hungary was forecast at 30.1°C. The day-ahead move therefore tracked weekday load recovery alongside changes in available supply.
Renewables showed mixed signals: forecast solar generation increased by 1,976 MW to 8,367 MW. Wind declined by 980 MW to 1,561 MW, a drop of almost 39%. With weaker wind output, the evening ramp relied more on thermal generation, imports and limited hydro flexibility.
The hourly profiles indicated pressure outside the strongest solar-production window . HUPX and Romania’s OPCOM stayed subdued around midday before rising steeply during the evening, approaching or exceeding €400/MWh around hours 20 and 21.. Slovenia’s BSP climbed to roughly €500/MWh during the evening peak**, while Greece recorded an evening maximum close to **€280/MWh..
Nets imports rise; Italy-to-SEE flow turns negative on a net basis
The intraday structure reflected solar suppression during midday that did not offset later declines after sunset combined with higher demand and weak wind . Prices required expensive dispatchable generation during a narrow set of evening hours as photovoltaic output fell.
Regional 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.. At the same time, the net Italy-to-SEE position was reported at **negative 876 MW**, indicating SEE exported toward Italy on a net basis despite its own tightening balance.
Nominations and commercial flows run across borders; hydrology remains constrained
This shift coincided with an expansion of the Hungarian-German spread as additional transfer capacity did not transmit Germany’s lower price level into Hungary . The HUPX premium expanded to **€50.48/MWh**, even with average core imports approaching **2.9 GW..
A seven-day commercial-flow structure showed scheduled movements including flows from Bulgaria toward Romania, Romania toward Hungary and Hungary toward Croatia . Hungary remained a major exporter toward Slovakia on the reported schedule, while Slovenia 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.
The deeper structural constraint was hydrology in Serbia, where hydroelectric output fell to historically low levels amid persistent drought . Weak reservoir conditions reduce low-variable-cost production and peak-shaving capability that hydro normally provides during morning and evening ramps. The system therefore leaned more on lignite units, imports and short-duration balancing purchases.
Danube flows are low; fuel prices support a high thermal floor risk
The Danube added another risk layer, with river flow at the relevant measurement point around **4,534 cubic metres per second**, well below the long-term seasonal profile . Bulgaria’s Kozloduy nuclear power plant was reported operating normally, but market pricing still reflected potential nuclear and hydro constraints.
Paks faced operational pressure tied to exceptionally low Danube levels, while Romania’s Cernavoda and Bulgaria’s Kozloduy remained exposed to prolonged heat and cooling-water limitations . Fuel markets offered limited protection against further tightening risk: Austrian CEGH gas stood at **€60.27/MWh**, with September around **€60/MWh** and fourth quarter at **€59.50/MWh**.
Nuclear gas prices rise; forward curve keeps near-term premiums elevated
Greek gas was assessed at **€53.09/MWh**, up by **€1.70/MWh** . EU carbon allowances were **€81.26 per tonne**, while September API2 coal traded around **$123 per tonne** . With these input levels, gas-fired power remained expensive even before start-up costs are considered.
The Hungarian forward curve indicated current tightness was not treated as a single-day event . Week 32 traded at **€269/MWh**, down by **€13/MWh** in the latest session, still more than **€90/MWh** above Monday’s elevated HUPX daily average . Week 33 rose by **€10/MWh** to **€194.50/MWh**, September advanced to **€174/MWh**, and calendar 2026 stayed unchanged at **€124.50/MWh**.
Tightness concentrates in evening peaks; temperatures expected to rise midweek
The curve shape concentrated risk in immediate delivery products: Hungarian premiums over Germany reached **€138/MWh for Week 32**, **€60/MWh for Week 33** and **€35.50/MWh for September**, narrowing to **€20.50/MWh for calendar 2026** . The near-term delivery period therefore carried higher separation versus Germany than later contracts.
The short-term focus remained on evening peak exposure as solar declines after midday do not remove sensitivity for hours 18–22 . Wind forecasts were limited to **1.6 GW**, net imports were near **2 GW**, core-border congestion was priced above **€50 per Mwh** ,and thermal fuel costs were elevated . This combination left limited flexibility entering the week for deliverable evening power.
