Southeastern European electricity markets posted a mixed performance on 11 August 2026, with prices falling in Hungary and several closely linked Central European markets, while Greece, Bulgaria, Albania and Montenegro recorded notable increases.
Hungary’s HUPX day-ahead baseload price declined by €5.10 to €151.44/MWh. Romania followed at €149.54/MWh, while Slovenia, Croatia, Serbia and Albania also cleared at levels close to €150/MWh, highlighting strong regional price coupling around the Hungarian market.
Price movements were more pronounced elsewhere in the region. Albania recorded the largest increase, rising €18.30 to €149.84/MWh, while Montenegro gained €14.60 to €155.59/MWh. Bulgaria advanced €11.40 to €146.72/MWh. Greece rose by €11.80 but remained the lowest-priced market in the region at €115.78/MWh.
Italy continued to post 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 the spread narrowed by €16.90 compared with the previous day.
Solar weighs on daytime prices
Hungary’s hourly price profile showed a sharp contrast between solar-rich daytime hours and the evening peak. The HUPX minimum price was €62.70/MWh in hour 13, while the maximum reached €245.10/MWh in hour 21, creating a spread of more than €182/MWh.
The peak-load block averaged €125.10/MWh, compared with €177.80/MWh during off-peak hours. The unusual price pattern reflects the impact of strong solar generation during the day, followed by significantly tighter conditions during the evening ramp and overnight period.
Similar patterns were observed in neighboring markets. Germany briefly recorded a negative price of €0.10/MWh before climbing to €199/MWh in hour 21. Greece also registered zero-priced hours around midday, while evening prices reached €241/MWh.
Regional solar generation was forecast to increase by 1,461 MW to 8,653 MW, while wind output was expected to decline by 660 MW to 2,616 MW. Higher solar production therefore eased daytime market conditions, while weaker wind generation contributed to tighter balances later in the day.
Demand and imports rise
Regional electricity consumption was forecast at 34,426 MW, up by 2,010 MW, or around 6.2%, from the previous day. Net imports increased from 982 MW to 1,569 MW, while imports from core Central European markets rose by 527 MW to 2,649 MW.
Hungarian electricity consumption climbed to 4,963 MW. With domestic generation estimated at 2,926 MW, the country required average net imports of 2,037 MW, an increase of 191 MW from the previous day. Slovakia, Romania and Austria were the main sources of electricity imports.
Romania also moved further into a net-import position, with average imports rising to 476 MW from 195 MW previously. Greece remained a significant regional exporter, recording an average surplus of 1,666 MW.
The flow data indicate that Hungary’s price premium over Germany continued to attract electricity from Central Europe. However, the persistence of a spread exceeding €40/MWh suggests that transmission constraints and local evening scarcity continued to limit full price convergence.
Hungarian prompt power contracts weaken
Hungarian prompt electricity contracts moved lower despite rising fuel prices. The Week 34 contract fell by €6.50 to €154.50/MWh, while Week 35 declined by the same amount to €153.50/MWh.
The September contract proved more resilient, increasing by €0.50 to €163.50/MWh, while the calendar contract gained €3 to €126.50/MWh. The movements point to a clear divergence between weaker near-term contracts and firmer deferred power.
Hungarian premiums over Germany also narrowed. The HU-DE Week 34 spread fell by €12.50 to €23.50/MWh, while the September spread declined by €4.50 to €27.50/MWh. The movements suggest that traders reduced the immediate Hungarian scarcity premium while maintaining expectations of tighter conditions further along the curve.
Higher fuel costs support deferred power
European gas and coal prices increased sharply. CEGH September gas rose by €5 to €62/MWh, while the fourth-quarter contract gained €5.50 to €62.50/MWh. September API-2 coal increased by €6 to €121.50/MWh, with fourth-quarter coal reaching €124.50/MWh.
Carbon prices provided only limited relief, with EU allowances falling by €1 to €82.27 per tonne. Despite the decline in carbon, the combined movement in gas, coal and emissions costs points to higher thermal generation costs, supporting deferred electricity prices.
The overall market picture remains mixed. Higher solar generation and the gradual recovery of output at Hungary’s Paks nuclear power plant are weighing on prompt baseload prices. At the same time, lower wind generation, stronger electricity demand and rising fuel costs are maintaining evening scarcity and supporting longer-dated contracts.
In the near term, wind generation, evening demand and cross-border import availability will remain the key market drivers. Further recovery at Paks or stronger imports from Central Europe could narrow Hungary’s price premium. Conversely, weaker wind output, higher temperatures or renewed generation restrictions linked to low Danube water levels could increase the risk of another sharp evening price spike.