The Southeast European day-ahead electricity market started 6 August 2026 with a divide between a tightly linked Hungarian–Romanian–Slovenian–Croatian price zone and more discounted pricing in Greece, Bulgaria and North Macedonia. Higher regional consumption and reduced availability of conventional generation supported upward pressure on central European prices. The same session also coincided with stronger solar output and lower gas, carbon and forward power prices.
Day-ahead price split across connected markets
In the central cluster, Hungary’s HUPX base price rose by €6.2/MWh to €182.42/MWh, while Romania settled at €182.90/MWh. Slovenia and Croatia recorded the highest levels in the group at €183.34/MWh and €183.35/MWh. The spread between the four markets stayed below €1/MWh, indicating strong convergence across the northern and western part of Southeast Europe.
Outside that interconnected set, prices diverged further. 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 and North Macedonia at €158.52/MWh, while Greece fell by €10/MWh to €141.63/MWh. Germany remained at €99.51/MWh, while Italy recorded the region’s highest price at €198.35/MWh.
Hungary-Germany spread widens amid cross-border constraints
The Hungary–Germany price spread widened to €82.91/MWh, rising by more than €17/MWh versus the previous session. Hungary traded €40.79/MWh above Greece and around €16/MWh below Italy. The gap was attributed to transmission limitations, uneven generation availability and restricted cross-border flexibility rather than fuel costs alone.
The hourly profile showed evening demand as the main driver of higher prices in Hungary’s market area. HUPX posted a minimum of €102.80/MWh at noon before reaching a maximum of €298.20/MWh at hour 21. Hungary’s peak-hour average was €164.60/MWh, while its off-peak average reached €200.20/MWh.
Hourly patterns in Hungary, Germany and Romania
Germany followed a similar shape tied to solar output but at a lower level overall. Prices dropped to minus €1.40/MWh during hour 14, while the German peak-hour average was only €46.10/MWh. The contrast between negative German midday prices and Hungarian evening prices approaching €300/MWh pointed to differences in how power could be delivered across borders during peak hours.
Romania tracked Hungary closely, with a base price of €182.90/MWh and an evening peak of €301.60/MWh. Slovenia and Croatia displayed near-identical patterns, with daily maximum prices of €285.30/MWh and €288.80/MWh respectively.
Serbia’s day-ahead pricing and import needs
Serbia’s SEEPEX price fell by €1.3/MWh to €175.41/MWh, slightly below Hungary’s level after the increase in the central zone prices. The Serbian peak-hour average rose to €153.90/MWh, while off-peak prices stayed elevated at €197/MWh. Despite reaching €326/MWh during hour 20, higher prices in other hours were limited enough to keep the daily average below HUPX.
Serbia’s average electricity consumption forecast decreased by 92 MW to 3,918 MW, while generation fell by about 180 MW to 3,400 MW. Net imports were therefore estimated at 518 MW, or around 13% of average demand.
Commercial schedules indicated strong inflows from Bulgaria and North Macedonia, with smaller volumes arriving from Hungary and Bosnia and Herzegovina. Serbia also continued exporting electricity toward Romania and Montenegro, functioning as both a deficit market and a transit hub within the region.
Northern supply mix: coal-led Serbia and deficit Hungary
The Serbian generation mix remained dominated by coal-fired power plants supplying 77% of output, followed by hydropower at 19%, wind at 3% and gas at around 1%. Thermal generation continued to provide domestic price support as reliance on imports increased during high-demand periods.
Across the wider Hungary–Southeast European region, average consumption was forecast at 34,728 MW, up 518 MW from the previous day. Regional generation increased by only around 290 MW to 32,585 MW, leaving net imports at 2,143 MW.
Hungary remained the largest structural deficit market within the central cluster, with consumption forecast at 5,249 MW against generation of only 2,949 MW. That created a net import requirement of 2,300 MW. Domestic generation declined by 179 MW, while nuclear output was particularly weak at only 171 MW, compared with 872 MW on 31 July.
Nuclear weakness in Hungary; renewable-led Greece; exporter Bulgaria
The Hungarian system relied on imports averaging about 1,229 MW from Slovakia, 922 MW from Austria and 657 MW from Romania. Solar production averaged 1,508 MW, while gas supplied 913 MW and coal provided 257 MW. Import dependence increased significantly during evening hours when solar generation disappeared.
Greece showed the opposite balance in regional flows: Greek generation rose to 8,971 MW, while consumption reached 7,499 MW, supporting average exports of 1,472 MW. Greece exported electricity toward Bulgaria, Italy, North Macedonia, Albania and Turkey.
Greek day-ahead pricing declined to €141.63/MWh, supported by strong renewable generation with solar at 31% of output and wind at 21%. Gas accounted for 36%, hydropower for 8% and coal for only 4%. Even with high renewables reducing daytime prices and supporting exports, grid constraints prevented full regional price convergence.
Bulgaria remained among the strongest exporters relative to domestic demand, with generation of 5,285 MW against consumption of 3,990 MW. Exports were estimated at 1,295 MW, supplying Romania, Serbia and North Macedonia while Bulgaria’s price increased to €170.56/MWh. The rise was linked to demand pressure from northern markets.
Croatia’s deficit; forward prices fall on weaker commodities
Croatia’s electricity deficit widened to 1,151 MW, as consumption increased alongside lower domestic generation availability. Imports from Slovenia and Hungary helped cover demand while Croatia’s price converged almost completely with Slovenia and Romania at €183.35/MWh. The level reflected the marginal value of constrained central European supply.
(Forward markets)
(Forward power)
The forward electricity curve moved in the opposite direction from day-ahead pricing changes during the same period. Hungarian September 2026 power declined by €8.50/MWh to €157/MWh, while the Week 33 contract fell by €7.50/MWh to €173.50/MWh. The Hungary–Germany Week 33 premium narrowed to €45.50/MWh as the September spread declined to €32.50/MWh.
The decline in forward contracts was supported by weaker commodity markets including Austrian CEGH gas falling to €55.37/MWh, Greek gas declining to {}…………………………..