The Southeast European day-ahead market entered 6 August 2026 with a pronounced split between the tightly connected Hungarian–Romanian–Slovenian–Croatian price area and the increasingly discounted markets of Greece, Bulgaria and North Macedonia. Stronger regional consumption and reduced conventional availability maintained pressure on the central markets, even as solar generation expanded and gas, carbon and forward-power contracts moved lower.
Hungary’s HUPX base price rose by €6.2/MWh to €182.42/MWh, while Romania settled marginally higher at €182.90/MWh. Slovenia and Croatia formed the top of the central cluster at €183.34/MWh and €183.35/MWh respectively. The spread among these four markets was less than €1/MWh, demonstrating strong price convergence across the northern and western part of the region.
This convergence stopped at the surrounding borders. Austria traded at €174.16/MWh, Serbia at €175.41/MWh, Montenegro at €173.91/MWh and Albania at €176.88/MWh. Bulgaria cleared at €170.56/MWh, North Macedonia at €158.52/MWh, and Greece fell by €10/MWh to €141.63/MWh. Germany was substantially lower at €99.51/MWh, while Italy remained the region’s premium destination at €198.35/MWh.
The resulting Hungary–Germany spread widened to €82.91/MWh, up by more than €17/MWh from the previous session. Hungary also carried a €40.79/MWh premium over Greece and traded approximately €16/MWh below Italy. These spreads are too large to be explained by fuel costs alone. They reflect transmission constraints, uneven conventional generation availability and the limited ability of cheaper German and Greek daytime electricity to reach the Hungarian and central SEE load centres.
The hourly structure provides an even clearer picture. HUPX recorded a minimum of €102.80/MWh at hour 12, before rising to a maximum of €298.20/MWh at hour 21. Hungary’s peak-load average was €164.60/MWh, but its off-peak contract averaged a much higher €200.20/MWh. This inversion shows that the most expensive hours were concentrated in the evening and overnight blocks rather than in the conventional daytime peak period.
Germany experienced the same solar-shaped curve but at a much lower price level. Its minimum fell to minus €1.40/MWh at hour 14, and the German peak average was only €46.10/MWh. The gap between negative German midday prices and Hungarian evening prices approaching €300/MWh illustrates the commercial value of cross-border capacity, flexible generation and battery storage. It also confirms that a growing volume of solar generation does not necessarily reduce the daily average price when grid bottlenecks prevent the midday surplus from being carried into the evening scarcity period.
Romania closely tracked Hungary, with a base price of €182.90/MWh, a peak average of €165.30/MWh and an off-peak average of €200.50/MWh. Its maximum reached €301.60/MWh at hour 21. Slovenia and Croatia followed a similar profile, although their daily maxima were slightly lower at €285.30/MWh and €288.80/MWh. These near-identical curves indicate that the central cluster was responding to a shared evening capacity constraint rather than separate national supply shocks.
Serbia remained moderately discounted to Hungary. SEEPEX declined by €1.3/MWh to €175.41/MWh, leaving Serbia €7.01/MWh below HUPX. The Serbian peak average increased to €153.90/MWh, while the off-peak average remained elevated at €197/MWh. The market reached €326/MWh at hour 20, higher than the Hungarian maximum, but Serbia’s lower prices during other hours kept the daily base below HUPX.
Serbia’s forecast consumption eased by 92 MW to an average 3,918 MW, while generation declined by around 180 MW to 3,400 MW. The country consequently required net imports of 518 MW, up from 429 MW in the previous session. This represented approximately 13% of average national demand.
The commercial schedule showed Serbia importing heavily from Bulgaria and North Macedonia. Average flows towards Serbia amounted to approximately 336 MW from Bulgaria and 315 MW from North Macedonia, while smaller volumes arrived through Hungary and Bosnia and Herzegovina. Serbia simultaneously scheduled exports towards Romania and Montenegro, showing that its position was not simply that of a final deficit market but also that of an important transit and redistribution node.
Serbian peak-hour net imports increased to 858 MW, compared with a base-load average of 518 MW. That difference explains why SEEPEX still reached €326/MWh during the evening despite trading below Hungary on the daily average. The country’s thermal fleet remained the principal domestic price anchor: the latest available generation mix showed coal providing 77% of output, hydro 19%, wind 3% and gas around 1%.
The wider Hungary and SEE region was forecast to consume an average 34,728 MW, an increase of 518 MW from the previous day. Regional generation rose by only around 290 MW to 32,585 MW, leaving net imports of 2,143 MW. Import dependence therefore increased by 228 MW even though the regional average temperature fell by almost 1°C to approximately 27.8°C.
Gross scheduled inflows from Austria and Slovakia into Hungary and Slovenia increased to 3,076 MW, up by 233 MW. The region continued exporting electricity towards Italy, but the average export fell from 827 MW to 757 MW. It also exported approximately 278 MW towards Ukraine and Moldova and 101 MW towards Turkey.
Hungary was the largest structural deficit within the central cluster. Its consumption was forecast at 5,249 MW, against generation of only 2,949 MW, producing net imports of 2,300 MW. Domestic production declined by 179 MW, more than twice the 78 MW reduction in consumption.
Hungary’s nuclear output remained particularly weak. The latest generation breakdown showed an average of just 171 MW, compared with 872 MW on 31 July. Gas-fired generation supplied 913 MW, coal 257 MW, and solar averaged 1,508 MW. Hungary consequently imported approximately 1,229 MW from Slovakia, 922 MW from Austria and 657 MW from Romania, while sending 496 MW towards Croatia and smaller volumes towards Serbia.
The Hungarian market is therefore being supported by a combination of reduced nuclear availability and heavy reliance on imports during evening hours. Solar can cover a large share of midday demand, but it cannot replace the missing nuclear baseload after sunset. The low nuclear contribution also leaves Hungary more exposed to cross-border congestion and the availability of Romanian, Slovak and Austrian supply.
Greece occupied the other side of the regional balance. Greek generation increased to 8,971 MW, while consumption rose to 7,499 MW, allowing the country to export an average 1,472 MW. Scheduled exports included approximately 699 MW towards Bulgaria, 424 MW towards Italy, 333 MW towards North Macedonia and smaller volumes towards Albania and Turkey.
The Greek price fell to €141.63/MWh, with a zero-price minimum at hour 10 and a maximum of €255.50/MWh at hour 23. Greece’s peak average declined to €94.70/MWh, while the off-peak average remained at €188.60/MWh. The latest generation mix showed solar supplying 31%, wind 21%, gas 36%, hydro 8% and coal only 4%. High renewable production therefore depressed daytime prices and supported exports, although transmission constraints prevented full price convergence with Bulgaria, Serbia and Hungary.
Bulgaria remained the region’s strongest net exporter relative to domestic demand. Generation reached 5,285 MW, against consumption of 3,990 MW, leaving exports of 1,295 MW. Bulgaria sent an average 1,516 MW towards Romania, 336 MW towards Serbia and 237 MW towards North Macedonia, while absorbing significant electricity from Greece. Its price rose by €4.2/MWh to €170.56/MWh, reflecting the pull from Romania and Serbia despite cheaper Greek supply entering from the south.
Croatia’s deficit widened from 922 MW to 1,151 MW, as consumption increased to 2,523 MW and generation slipped to 1,372 MW. The country received around 656 MW from Slovenia and 496 MW from Hungary. Croatia’s price nevertheless converged almost completely with Slovenia and Romania at €183.35/MWh, confirming that imported supply was available but priced at the marginal value of the constrained central market.
Forward markets moved in the opposite direction from the day-ahead contracts. Hungarian September 2026 power fell by €8.50/MWh to €157/MWh, while the Week 33 contract declined by €7.50/MWh to €173.50/MWh. The equivalent Hungary–Germany Week 33 premium narrowed to €45.50/MWh, and the September spread eased to €32.50/MWh.
The fall in the forward curve was supported by weaker commodities. Austrian CEGH gas declined by €3.20/MWh to €55.37/MWh, the Greek gas reference fell to €51.06/MWh, and EU carbon allowances eased to €81.09/t. September gas was quoted at €54/MWh, while September coal fell to $114/t.
The combination of rising spot prices and falling fuel and forward contracts identifies the current premium as primarily a short-term power-system and transmission issue. The immediate trading signal remains concentrated in the evening ramp, where reduced Hungarian nuclear availability, Serbian import requirements and central-market congestion are sustaining prices well above the marginal economics indicated by gas and carbon. Greek and German midday supply remains abundant, but its value is being trapped behind borders precisely when Hungary, Romania, Slovenia and Croatia require greater flexibility.
