Southeastern European electricity markets showed mixed pricing on 11 August 2026. Prices declined in Hungary and several closely linked Central European markets, while Greece, Bulgaria, Albania and Montenegro recorded increases.
Day-ahead price moves across regional hubs
On the day-ahead market, Hungary’s HUPX baseload price fell by €5.10 to €151.44/MWh. Romania cleared at €149.54/MWh, followed by Slovenia, Croatia, Serbia and Albania at levels close to €150/MWh. The report cited strong regional price coupling around the Hungarian market.
Elsewhere, Albania posted the largest rise, increasing by €18.30 to €149.84/MWh. Montenegro gained €14.60 to €155.59/MWh, while 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 remained the highest-priced market in the region at €181.14/MWh, 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 was €35.66/MWh, although the spread narrowed by €16.90 versus the previous day.
Hourly profile shows solar-linked daytime softness
In Hungary, the hourly price pattern contrasted solar-rich daytime hours with the evening peak. The HUPX minimum was €62.70/MWh in hour 13, while the maximum reached €245.10/MWh in hour 21, producing 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 report attributed the pattern to strong solar generation during daytime followed by tighter conditions during the evening ramp and overnight period.
Similar shapes appeared in neighboring markets, including Germany and Greece. Germany briefly recorded a negative price of €0.10/MWh before rising to €199/MWh in hour 21, while Greece had zero-priced hours around midday and reached €241/MWh in the evening.
Regional generation forecasts pointed to higher solar output and lower wind production during the period assessed. Solar was expected to increase by 1,461 MW to 8,653 MW, while wind output was forecast to decline by 660 MW to 2,616 MW.
Demand growth and higher net imports
Regional electricity consumption was forecast at 34,426 MW, up by 2,010 MW or about 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 on the forecast basis. With domestic generation estimated at 2,926 MW, Hungary required average net imports of 2,037 MW, up by 191 MW from the previous day.
Slovakia, Romania and Austria were listed as main sources of imports into Hungary. Romania also moved further into net-import status with average imports rising to 476 MW from 195 MW previously.
Greece remained a regional exporter with an average surplus of 1,666 MW. Flow data were described as showing that Hungary’s premium over Germany continued to attract Central European electricity despite a spread exceeding €40/MWh that persisted alongside transmission constraints and local evening scarcity.
Prompt contract declines amid firmer deferred pricing
Hungarian prompt power contracts weakened even as fuel prices rose. The Week 34 contract fell by €6.50 to €154.50/MWh and Week 35 declined by the same amount to €153.50/MWh.
The September contract increased by €0.50 to €163.50/MWh while the calendar contract gained €3 to €126.50/MWh. The movements were described as showing weaker near-term contracts alongside firmer deferred power.
Premiums versus Germany narrowed across contract tenors as well. The HU-DE Week 34 spread fell by €12.50 to €23.50/MWh and the September spread declined by €4.50 to €27.50/MWh.
Gas, coal and carbon costs shift higher for thermal margins
European gas and coal prices increased sharply in the period assessed for contract pricing support. CEGH September gas rose by €5 to €62/MWh and the fourth-quarter contract gained €5.50 to reach €62.50/MWh.
API-2 coal for September increased by €6 to €121.50/MWh with fourth-quarter coal rising to €124.50/MWh. EU carbon allowances fell by €1 to stand at €82.27 per tonne.
The report said that despite lower carbon prices, combined changes across gas, coal and emissions costs pointed to higher thermal generation costs supporting deferred electricity prices.
Paks output recovery and wind weakness tied to evening tightness
The overall market picture was described as mixed across prompt and longer-dated segments in Hungary’s power pricing context on Paks. Higher solar generation and a gradual recovery of output at Hungary’s Paks nuclear power plant were cited as weighing on prompt baseload prices.
At the same time, lower wind generation combined with stronger electricity demand and rising fuel costs were said to maintain evening scarcity conditions supporting longer-dated contracts.
Near-term drivers were listed as wind generation levels, evening demand and cross-border import availability into Hungary from Central Europe. Further recovery at Paks or stronger imports could narrow Hungary’s price premium over Germany.
The report also flagged potential upside risk for evening prices if wind output weakens further or if higher temperatures coincide with renewed generation restrictions linked to low Danube water levels affecting hydropower availability.