Southeast European day-ahead electricity prices opened the week sharply higher, with the return of weekday consumption colliding with weaker wind generation, historically poor Serbian hydrology and widening congestion against Germany. The strongest price formation remained concentrated in the central and western part of the region, where 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, rising by €56.40/MWh from Sunday. Romania closely tracked Hungary at €178.07/MWh, only €0.51/MWh below HUPX, while Croatia cleared at €179.23/MWh. The near alignment of Hungary, Romania, Slovenia and Croatia formed a relatively compact central regional price cluster between €178/MWh and €180/MWh.
The broader market was far from converged. Germany cleared at €128.09/MWh, leaving the Hungarian premium over Germany at €50.48/MWh, up by almost €34/MWh in one day. That spread provides the clearest indication that the price increase was not simply the result of a general continental move. Germany rose by €22.60/MWh, but HUPX advanced more than twice as much, exposing the additional scarcity value carried by transmission capacity into Hungary and the wider SEE market.
The tightest premium emerged in Serbia and Montenegro. SEEPEX jumped by €73.10/MWh to €185.23/MWh, the largest absolute daily increase among the observed regional exchanges. Serbia traded €6.66/MWh above Hungary, while Montenegro’s BELEN price stood €17.54/MWh above HUPX and only €1.60/MWh below Italy. These levels place both markets within the expensive Adriatic and central Balkan price zone rather than the cheaper southern Balkan cluster.
Albania cleared at only €136.03/MWh, North Macedonia at €138.07/MWh, Greece at €153.96/MWh and Bulgaria at €158.08/MWh. The Albanian discount to Hungary reached €42.54/MWh, while North Macedonia traded €40.50/MWh below HUPX. Greece was cheaper by €24.61/MWh and Bulgaria by €20.49/MWh.
The resulting price map was unusually fragmented. The difference between Montenegro and neighbouring Albania reached approximately €60/MWh, despite their 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. Such separations point to transmission constraints, commercial allocation limits and different national generation positions rather than a uniform regional shortage.
The principal demand signal came from the transition from Sunday to Monday. Forecast regional consumption increased by 4,072 MW, or almost 14 per cent, to an average 33,440 MW. Hungary contributed 673 MW of the increase, with demand reaching 5,126 MW. Greece rose by 541 MW to 6,859 MW, Romania and Bulgaria together increased by 1,476 MW to 9,516 MW, and Slovenia and Croatia added 1,305 MW, reaching 10,211 MW.
Temperatures alone do not explain the movement. 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 shock was therefore driven primarily by the weekday load recovery and the composition of available supply, rather than by a sudden region-wide temperature spike.
Renewable output delivered mixed signals. Forecast solar generation increased by 1,976 MW to 8,367 MW, supported by the return of stronger daytime production. Wind, however, declined by 980 MW to only 1,561 MW, a fall of almost 39 per cent. The loss of wind removed a large portion of the incremental solar contribution and left the evening ramp exposed to thermal generation, imports and limited hydro flexibility.
The hourly profiles confirm that the pressure was concentrated outside the strongest solar-production window. HUPX and Romania’s OPCOM remained relatively subdued around midday before rising steeply during the evening. Both markets approached or exceeded €400/MWh around hours 20 and 21. Slovenia’s BSP profile was even more severe, climbing to approximately €500/MWh during the evening peak. Greece also recorded an evening maximum close to €280/MWh.
This intraday structure matters more than the daily average alone. Solar generation suppressed prices during the middle of the day, but it could not cover the combined effect of falling output after sunset, recovering industrial demand and weak wind. The system consequently required expensive dispatchable generation during a narrow group of evening hours. Traders faced a classic steep-ramp market: modest midday prices followed by scarcity pricing once photovoltaic production declined.
Regional net imports increased to an average 1,981 MW, up by 440 MW from Sunday. Imports from the 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, meaning that SEE was exporting toward Italy on a net basis despite its own tightening balance. Compared with Sunday, this represented a 459 MW movement that further reduced the net benefit of higher northern imports.
This combination explains the widening Hungarian-German spread. Central and southeastern Europe absorbed more electricity from Austria and Slovakia, but additional transfer capacity was insufficient to transmit Germany’s cheaper price level into Hungary. The HUPX premium therefore expanded to €50.48/MWh, even with average core imports approaching 2.9 GW.
The seven-day commercial-flow structure reinforces this interpretation. Large scheduled flows continued from Bulgaria toward Romania, from Romania toward Hungary and from Hungary toward Croatia, while Hungary remained a major exporter toward Slovakia on the reported commercial 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. These simultaneous north-south and west-east transactions demonstrate that regional prices cannot be read purely from national production balances: allocated capacity, loop flows and competing border nominations materially affect the marginal price in each zone.
Hydrology remains the deeper structural concern. Serbian hydroelectric output has fallen to historically low levels amid persistent drought, reducing the availability of low-variable-cost production and peak-shaving capability. The effect is particularly important for Serbia because hydro normally provides both energy and flexibility during morning and evening ramps. Weak reservoir conditions force the system to rely more heavily on lignite units, imports and expensive short-duration balancing purchases.
Danube conditions add another risk layer. 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 to be operating normally, but the regional market continues to assign value to the possibility of further nuclear and hydro constraints. Hungary’s Paks plant has already faced operational pressure from exceptionally low Danube levels, while Romania’s Cernavoda and Bulgaria’s Kozloduy remain exposed to prolonged heat and cooling-water limitations.
The Monday price increase therefore reflects both actual scarcity and precautionary pricing. Available nuclear capacity may still be operating, but traders must account for the asymmetric effect of any further restriction. A nuclear derating during weak hydro conditions would have to be replaced by gas-fired generation or additional imports precisely when cross-border capacity is already carrying a substantial premium.
Fuel markets provide little protection against this risk. Austrian CEGH gas stood at €60.27/MWh, with the September contract around €60/MWh and the fourth-quarter contract at €59.50/MWh. Greek gas was assessed at €53.09/MWh, up by €1.70/MWh. EU carbon allowances remained at €81.26 per tonne, while September API2 coal traded at approximately $123 per tonne.
At these input prices, gas-fired power generation remains expensive even before start-up costs, balancing exposure and plant-specific efficiency are considered. Coal generation retains a lower fuel cost for some regional assets, but its carbon burden at an EUA price above €81/t materially raises the delivered marginal cost. The consequence is a high thermal floor during hours when hydro, nuclear and renewable production cannot satisfy demand.
The Hungarian forward curve also shows that the market does not regard the current tightness as a single-day anomaly. Week 32 traded at €269/MWh, despite falling by €13/MWh in the latest session. That contract stood more than €90/MWh above Monday’s already elevated HUPX daily average. Week 33 rose by €10/MWh to €194.50/MWh, while September advanced to €174/MWh. Calendar 2026 remained unchanged at €124.50/MWh.
The shape of the curve concentrates the risk in the immediate delivery period. The Hungarian premium over Germany reached €138/MWh for Week 32, €60/MWh for Week 33 and €35.50/MWh for September, before narrowing to €20.50/MWh for Calendar 2026. Traders are pricing an acute near-term regional constraint, followed by gradual normalisation rather than a permanent separation of the Hungarian and German markets.
For short-term positioning, the central risk remains the evening peak. Strong solar forecasts can produce attractive midday purchase opportunities, but they do not remove exposure to hours 18–22. The decline in wind generation, limited Serbian hydro flexibility and uncertainty surrounding Danube-dependent nuclear output leave the region vulnerable to another sharp evening ramp. The HUPX, OPCOM and BSP profiles already demonstrate how quickly prices can move from low midday levels to €400–500/MWh scarcity intervals.
Serbia and Montenegro carry particularly pronounced upside exposure because their prices are sitting above the central Hungarian-Romanian cluster and close to Italy. Albania and North Macedonia remain cheaper, but the scale of their discount also implies that available interconnection capacity is failing to fully monetise the arbitrage. Greece and Bulgaria occupy an intermediate position, supported by lower average prices but still exposed to sharp evening revaluation as solar output fades.
Weather forecasts point toward renewed heat through the middle of the week. The regional temperature excluding Greece is expected to rise from 27.1°C on 3 August to around 28.8°C on 5 August, while Hungary is forecast to reach 31.3°C. Greece is projected near 29.4–29.7°C, Serbia around 30°C, and Croatia between 28.5°C and 28.8°C. Higher cooling demand will therefore arrive before the hydrological position has had an opportunity to recover.
The immediate trading bias remains firm for the evening and peak products, with greater volatility than the baseload averages imply. Midday prices retain downside sensitivity to the 8.4 GW solar forecast, but the region’s physical balance becomes materially tighter once that production falls away. With wind limited to 1.6 GW, net imports near 2 GW, core-border congestion priced at more than €50/MWh and thermal fuel costs elevated, the market enters the week with scarce flexibility and a pronounced premium for deliverable evening power.