The Southeast European day-ahead electricity market entered 6 August 2026 with a clear divide between the tightly connected Hungarian–Romanian–Slovenian–Croatian price zone and the increasingly discounted markets of Greece, Bulgaria and North Macedonia. Higher regional consumption and reduced conventional generation availability kept pressure on central European prices, despite stronger solar output and declining gas, carbon and forward power prices.
Hungary’s HUPX base price increased by €6.2/MWh to €182.42/MWh, while Romania settled slightly higher at €182.90/MWh. Slovenia and Croatia recorded the highest prices within the central cluster at €183.34/MWh and €183.35/MWh respectively. The price difference between these four markets was less than €1/MWh, highlighting strong market convergence across the northern and western part of Southeast Europe.
The convergence weakened beyond these interconnected markets. 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, while Greece dropped by €10/MWh to €141.63/MWh. Germany remained significantly cheaper at €99.51/MWh, whereas Italy continued to record the region’s highest price at €198.35/MWh.
The resulting Hungary–Germany price spread widened to €82.91/MWh, increasing by more than €17/MWh compared with the previous session. Hungary also traded €40.79/MWh above Greece and around €16/MWh below Italy. Such large differences cannot be explained only by fuel costs and instead reflect transmission limitations, uneven generation availability and restricted cross-border flexibility.
The hourly price pattern showed that the main pressure came from evening demand. HUPX recorded a minimum of €102.80/MWh at noon before reaching a maximum of €298.20/MWh at hour 21. Hungary’s peak-hour average stood at €164.60/MWh, while its off-peak average reached €200.20/MWh, indicating that the most expensive periods were concentrated in evening and overnight hours rather than the traditional daytime peak.
Germany followed a similar solar-driven curve but at a much lower price level. Prices fell to minus €1.40/MWh during hour 14, while the German peak average was only €46.10/MWh. The difference between negative German midday prices and Hungarian evening prices approaching €300/MWh demonstrates the growing importance of cross-border capacity, flexible generation and battery storage in managing renewable volatility.
Romania closely followed Hungary, with a base price of €182.90/MWh and an evening peak of €301.60/MWh. Slovenia and Croatia showed almost identical patterns, with daily maximum prices of €285.30/MWh and €288.80/MWh respectively. The similarity between these markets suggests that the central European price zone was responding to a shared evening capacity constraint rather than isolated national supply problems.
Serbia remained slightly below Hungary, with the SEEPEX price falling by €1.3/MWh to €175.41/MWh. The Serbian peak-hour average increased to €153.90/MWh, while off-peak prices remained elevated at €197/MWh. Although the market reached €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 declined by 92 MW to 3,918 MW, while generation decreased by approximately 180 MW to 3,400 MW. As a result, the country required net imports of 518 MW, representing around 13% of average demand. Commercial schedules showed strong inflows from Bulgaria and North Macedonia, while smaller volumes arrived from Hungary and Bosnia and Herzegovina.
At the same time, Serbia continued exporting electricity towards Romania and Montenegro, demonstrating that it remained not only a deficit market but also an important regional transit and redistribution hub. Peak-hour imports increased to 858 MW, explaining why SEEPEX reached €326/MWh despite a lower daily average than Hungary.
The Serbian generation mix remained dominated by coal-fired power plants, which supplied 77% of output, followed by hydropower at 19%, wind at 3% and gas at around 1%. Thermal generation continued to provide the country’s main domestic price support, while reliance on imports increased during periods of high demand.
Across the wider Hungary and 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. Import dependence therefore continued to rise despite slightly cooler weather conditions.
Hungary remained the largest structural deficit market within the central cluster. Consumption was forecast at 5,249 MW, compared with generation of only 2,949 MW, creating a net import requirement of 2,300 MW. Domestic generation declined by 179 MW, while nuclear output remained particularly weak at only 171 MW compared with 872 MW on 31 July.
The Hungarian system relied heavily on imports from neighbouring markets, including approximately 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 257 MW. The country’s dependence on imports increased significantly during evening hours when solar generation disappeared.
Greece represented the opposite side of the regional balance. Greek generation increased to 8,971 MW while consumption reached 7,499 MW, allowing average exports of 1,472 MW. The country exported electricity towards Bulgaria, Italy, North Macedonia, Albania and Turkey.
Greek prices declined to €141.63/MWh, supported by strong renewable generation. Solar accounted for 31% of output, wind for 21%, gas for 36%, hydropower for 8% and coal for only 4%. High renewable production reduced daytime prices and supported exports, although grid constraints prevented full regional price convergence.
Bulgaria remained one of the strongest exporters relative to domestic demand. Generation reached 5,285 MW compared with consumption of 3,990 MW, resulting in exports of 1,295 MW. The country supplied Romania, Serbia and North Macedonia, while its price increased to €170.56/MWh due to demand pressure from northern markets.
Croatia’s electricity deficit widened to 1,151 MW as consumption increased and domestic generation declined. Imports from Slovenia and Hungary helped cover demand, while the Croatian price converged almost completely with Slovenia and Romania at €183.35/MWh, reflecting the marginal value of constrained central European supply.
Forward electricity markets moved in the opposite direction from day-ahead prices. 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, while the September spread declined to €32.50/MWh.
The decline in forward prices was supported by weaker commodity markets. Austrian CEGH gas fell to €55.37/MWh, Greek gas prices declined to €51.06/MWh, and EU carbon allowances eased to €81.09/t. September gas traded around €54/MWh, while coal prices dropped to $114/t.
The combination of higher spot electricity prices and weaker fuel costs indicates that the current market premium is driven mainly by short-term power-system constraints rather than underlying generation economics. The strongest pressure remains concentrated in evening hours, when lower nuclear availability in Hungary, Serbian import needs and congestion across central Southeast Europe are keeping prices elevated.
While Greece and Germany continue to have abundant low-cost solar generation during the day, much of that electricity cannot reach the markets that need it most during evening demand peaks. The growing importance of grid flexibility, storage capacity and stronger regional interconnections is becoming increasingly evident across Southeast Europe.