Power prices surged across Southeast Europe on 10 August as the return of weekday demand, weaker wind generation and constrained cross-border capacity tightened regional electricity balances.
Hungary’s HUPX day-ahead baseload price increased by €59.2/MWh to €156.57/MWh, representing a rise of around 61% compared with Sunday. Romania followed closely at €155.75/MWh, while Croatia, Slovenia, Serbia and Austria settled within a relatively narrow range of €153–154/MWh.
Serbia recorded the strongest daily increase among the surveyed markets, with the SEEPEX day-ahead baseload price rising by €70.5/MWh to €153.32/MWh.
The price structure revealed three distinct regional zones. Hungary and the northern and central Southeast European markets formed a closely coupled group around €153–157/MWh. Albania, Bulgaria, Montenegro and North Macedonia traded in a middle range of €131–141/MWh, while Greece remained the cheapest market at €103.99/MWh. Italy recorded the highest price at €178.89/MWh.
The significant differences between neighbouring markets point to transmission congestion and limited cross-border capacity. Hungary traded at a premium of €38.66/MWh over Germany and €52.57/MWh over Greece, indicating that lower-cost electricity available elsewhere in the region could not fully reach the more expensive central European markets.
Evening scarcity drives intraday prices
The Hungarian hourly price profile showed a pronounced solar-driven duck-curve effect. HUPX fell to a daily low of €82.9/MWh around noon before climbing sharply to €269.1/MWh at 20:00. The resulting intraday range exceeded €186/MWh.
Hungary’s peak-load average stood at €142.5/MWh, below the €170.6/MWh average recorded during off-peak hours. Strong solar generation suppressed prices during the daytime, while the rapid decline in photovoltaic output during the evening coincided with the most constrained period of the day.
Similar price patterns were recorded in neighbouring markets. Romania reached €268.6/MWh at 20:00, while Serbia recorded a daily peak of €302/MWh at 21:00. Greece followed a different pattern, with prices falling to zero during the late morning before rising to €211.5/MWh at 23:00.
The hourly data indicate that evening delivery periods are becoming the key source of short-term price and imbalance risk, rather than the daily baseload price alone.
Demand rebound offsets renewable gains
Regional electricity demand was forecast to increase by 4,031 MW from Sunday to 33,432 MW, as commercial and industrial consumption returned following the weekend.
Solar generation increased by a substantial 3,743 MW, but forecast wind output declined by 830 MW. After accounting for changes in solar and wind production, the residual electricity requirement increased by approximately 1,118 MW.
Net imports increased by only 294 MW, leaving around 824 MW of additional demand to be covered by thermal, hydro, nuclear and other dispatchable generation.
Hungary remained particularly reliant on imports from neighbouring systems, recording average net imports of 1,984 MW. Romania shifted from a net export position of 698 MW on Sunday to net imports of 208 MW on Monday. Bulgaria, meanwhile, more than doubled its net exports to 1,348 MW, including significant deliveries towards Romania.
Across the wider region, imports from Austria and Slovakia reached 2,219 MW, while another 1,056 MW continued to flow towards Italy, where electricity prices remained the highest among the surveyed markets.
Fuel markets provide little support for rally
The broader fuel and carbon markets provided limited evidence of a sustained increase in power-generation costs. Austrian CEGH gas was virtually unchanged at €56.60/MWh, EU carbon allowances remained flat at €83.29/t, while coal prices recorded only modest gains.
Hungarian forward power prices also weakened at the front of the curve. Week 33 declined by €9/MWh to €165.50/MWh, while Week 34 and September contracts eased slightly to €161/MWh and €163/MWh respectively.
Despite the decline, Hungary continued to trade at significant premiums to Germany. The spread stood at €37/MWh for Week 33, €36/MWh for Week 34 and €32/MWh for September. At the calendar horizon, the premium narrowed to €20.50/MWh, suggesting that market participants expect the most acute regional tightness to remain primarily a near-term phenomenon.
The spot-price surge therefore appears to be driven mainly by power-system fundamentals rather than a broad increase in generation costs. The combination of the weekday demand rebound, weaker wind availability and constrained transmission capacity created a temporary tightening of regional balances.
Market attention will remain focused on evening demand, wind forecast revisions and cross-border flows between Bulgaria, Romania and Hungary. Low Danube water levels and their potential impact on nuclear and hydropower availability represent an additional source of uncertainty.
Any improvement in wind generation or cross-border transmission availability could quickly reduce the elevated Hungarian premium. Until then, however, evening prices across central Southeast Europe remain vulnerable to further scarcity-driven spikes.