Southeastern European electricity markets delivered a divided performance on 11 August 2026. Prices declined across Hungary and most closely coupled Central European markets, while Greece, Bulgaria, Albania and Montenegro recorded strong gains.
Hungary’s HUPX day-ahead baseload price fell by €5.10 to €151.44/MWh. Romania followed at €149.54/MWh, with Slovenia, Croatia, Serbia and Albania also clearing close to €150/MWh. The narrow differences among these markets indicate strong regional coupling around the Hungarian benchmark.
Elsewhere, price movements were more pronounced. Albania gained €18.30 to reach €149.84/MWh, Montenegro rose €14.60 to €155.59/MWh, and Bulgaria advanced €11.40 to €146.72/MWh. Greece increased by €11.80 but remained the region’s lowest-priced southeastern market at €115.78/MWh.
Italy retained the highest price in the region at €181.14/MWh, representing a premium of €29.71/MWh over Hungary. Germany cleared at €110.38/MWh, leaving HUPX €41.05/MWh higher. The Hungarian premium over Greece stood at €35.66/MWh, although that spread narrowed by €16.90 from the previous day.
Solar weighs on daytime prices
Hungary’s hourly profile revealed a pronounced separation between solar hours and the evening peak. The HUPX minimum was €62.70/MWh at hour 13, while the maximum reached €245.10/MWh at hour 21. The difference between the daily minimum and maximum was therefore more than €182/MWh.
The peak-load block averaged only €125.10/MWh, compared with an off-peak average of €177.80/MWh. This unusual inversion reflects low prices during solar-rich daytime hours and much higher prices during the evening ramp and overnight period.
The same basic pattern appeared across several neighboring markets. Germany briefly entered negative territory, reaching a minimum of minus €0.10/MWh, before rising to €199/MWh in hour 21. Greece recorded zero-priced hours around midday but climbed to €241/MWh during the evening.
Regional solar generation was forecast to increase by 1,461 MW to 8,653 MW. Wind output, however, was expected to fall by 660 MW to 2,616 MW. Stronger solar supply therefore eased daytime conditions, while weaker wind contributed to tighter evening balances.
Demand and imports rise sharply
Regional electricity consumption was forecast at 34,426 MW, an increase of 2,010 MW, or approximately 6.2%, from the previous day. Net imports rose from 982 MW to 1,569 MW, while imports from the core Central European markets increased by 527 MW to 2,649 MW.
Hungarian consumption climbed to 4,963 MW. With domestic generation estimated at 2,926 MW, the country required average net imports of 2,037 MW—191 MW more than the previous day. Slovakia, Romania and Austria were the principal sources of Hungarian imports.
Romania moved deeper into a net-import position, importing an average of 476 MW compared with 195 MW previously. Greece remained a major regional exporter, delivering an average surplus of 1,666 MW.
The flow data indicate that Hungary’s premium over Germany continued to attract power from Central Europe. However, the persistence of a spread above €40/MWh suggests that transmission availability and local evening scarcity continued to prevent full price convergence.
Prompt Hungarian forwards weaken
Hungarian prompt power contracts moved lower even as fuel prices increased. Week 34 fell by €6.50 to €154.50/MWh, while Week 35 declined by the same amount to €153.50/MWh.
The September contract was more resilient, rising by €0.50 to €163.50/MWh, while the calendar contract increased by €3 to €126.50/MWh. This produced a clear separation between weaker prompt weeks and firmer deferred power.
Hungarian premiums over Germany also narrowed. The HU-DE Week 34 spread declined by €12.50 to €23.50/MWh, while the September spread contracted by €4.50 to €27.50/MWh. The movements suggest that traders reduced the near-term Hungarian scarcity premium without abandoning expectations of tighter conditions later in the curve.
Fuel costs support deferred power
European gas and coal contracts rose sharply. CEGH September gas gained €5 to €62/MWh, while the fourth-quarter contract climbed €5.50 to €62.50/MWh. September API-2 coal increased by €6 to €121.50, with fourth-quarter coal reaching €124.50.
Carbon provided only a limited offset. EU allowances declined by €1 to €82.27 per tonne. The combined movement in gas, coal and carbon nevertheless implies higher thermal generation costs, offering support to deferred electricity prices.
The overall market signal is therefore mixed. Higher solar production and recovering output at Hungary’s Paks nuclear power plant are weighing on prompt baseload prices. At the same time, reduced wind generation, stronger consumption and rising fuel costs are sustaining evening-hour scarcity and supporting longer-dated contracts.
In the near term, the most important variables will be wind performance, evening demand and cross-border import availability. Further recovery at Paks or stronger core imports could reduce the Hungarian premium. Conversely, additional wind underperformance, hotter weather or renewed generation constraints linked to low Danube water levels would increase the risk of another evening price surge.
