Southeastern Europe’s day-ahead electricity market increased for 19 August, with the regional move reflecting two different trading patterns. Hungary, Romania, Bulgaria, Slovenia and Croatia clustered tightly around €168/MWh, while Albania traded at a premium and Serbia, Montenegro and North Macedonia at discounts. The central SEE corridor therefore showed strong integration, while peripheral markets remained more exposed to local supply and cross-border conditions.
Central SEE base prices converge while peripheral markets diverge
The HUPX Hungarian base price settled at €167.99/MWh, up €3.5/MWh from the previous session. Romania’s OPCOM reached €168.04/MWh, only €0.06/MWh above HUPX, while Bulgaria’s IBEX settled at €167.72/MWh. Slovenia’s BSP was €167.94/MWh and Croatia’s CROPEX at €167.91/MWh, leaving the five markets separated by just €0.33/MWh.
Germany remained slightly cheaper at €166.03/MWh, while Austria stood at €167.21/MWh. Italy traded higher at €175.49/MWh, maintaining a premium of €7.50/MWh over HUPX, and Greece rose by €6.2/MWh to €159.88/MWh. Across Hungary and nine compared SEE exchanges, the unweighted average base price was about €163.93/MWh.
The highest-to-lowest spread reached €26.83/MWh, driven by Albania at €178.03/MWh versus Serbia at €151.20/MWh. The strongest daily increases were recorded in peripheral markets: Albania gained €25.4/MWh, North Macedonia added €19.2/MWh, and Serbia rose by €18.2/MWh. Montenegro increased by only €1.4/MWh to €156.01/MWh.
Northern imports rise as demand forecasts increase; solar up, wind down
The physical balance pointed to stronger demand as a key driver of the move, with forecast regional electricity consumption increasing to 32,004 MW, up 1,246 MW. At the same time, the Hungary-SEE system shifted sharply toward imports, with net imports reaching 1,720 MW, compared with approximately -36 MW a day earlier.36 MW a day earlier.36 MW a day earlier.36 MW a day earlier.36 MW a day earlier.36 MW a day earlier.36 MW a day earlier.36 MW a day earlier.36 MW a day earlier.36 MW a day earlier.36 MW a day earlier.36 MW a day earlier.36 MW a day earlier.36 MW a day earlier.36 MW a day earlier.36 MW a day earlier.36 MW a day earlier.36 MW a day earlier.36 MW a day earlier.36 MW a day earlier.————————–
The Hungary-SEE system shifted sharply toward imports, with net imports reaching 1,720 MW compared with approximately -36 MW a day earlier. Flows from the CORE region, mainly Austria and Slovakia toward Hungary and Slovenia, jumped to 2,298 MW, an increase of 1,825 MW . Around 580 MW was also flowing toward Italy during the same period.
The renewable outlook showed solar generation expected to increase by 1,266 MW to 7,866 MW, while wind generation was forecast to decline by 1,169 MW to just 673 MW . The changes were broadly neutral in average megawatt terms but differed in timing, with additional solar concentrated in daylight hours and lower wind affecting more of the daily profile after sunset.
Hourly price spikes dominate; evening peaks reach €214–€226/MWh across markets
The hourly curve on HUPX showed a daily minimum of €127.5/MWh at H14 before rising to a maximum of €214.6/MWh at H21 . The base price was €168/MWh, with the conventional peak block averaging €158.3/MWh and off-peak hours averaging €177.7/MWh . The pattern reflected an evening scarcity effect as H21 falls outside the standard daytime peak block and coincides with solar output disappearing.
A similar structure appeared across central markets: Romania fell to €127.5/MWh and peaked at €214.7/MWh at H21 . Slovenia ranged between €127.8/MWh and €209.4/MWh and also reached its high at H21 . Bulgaria hit €214.4/MWh at H21 and Austria €209.9/MWh, while Croatia peaked slightly earlier at H20 with €217.3/MWh . Greece recorded an intraday low of €100.1/MWh at H10 before climbing to €214.4/MWh at H21 .
The southern Balkan markets displayed sharper versions of the same intraday pattern: Serbia’s SEEPEX averaged €151.20/MWh with an intraday low of €103.1/MWh at H12 and a maximum of €215/MWh at H20 . Montenegro averaged €156.01/MWh, fell to €100.1/MWh before reaching €220/MWh at H20 . North Macedonia averaged €154.6/MWh with a minimum of €90/MWh and maximum of €226.3/MWh at H21 .
Nuclear outage in Romania; forward prices firm; fuel support mixed with power premium
Albania remained the most expensive market in the regional comparison, with its base price reaching €178.03/MWh and an off-peak block averaging €207.9/MWh . The daily maximum reached €250/MWh at H21 even though prices fell as low as €93.6/MWh during the day . Intraday spreads were substantial across these systems: Albania recorded more than €156/MWh between its minimum and maximum prices, Serbia about €112/MWh and North Macedonia more than €136/MWh .
Romania faced an additional supply-side constraint as both 680 MW units at the Cernavoda nuclear plant remained unavailable due to low Danube flows reducing cooling-water availability . The outage removed approximately 1.36 GW of nuclear capacity, while Romania restarted almost 300 MW at Unit 4 of the Rovinari coal plant as renewable generation and imports continued supporting the system . Despite this outage, OPCOM remained almost perfectly aligned with HUPX on the session .
The forward market was firmer but less stressed than day-ahead pricing: Hungarian Week 35 traded at €151/MWh, Week 36 at €148/MWh, September 2026 at €158.5/MWh and Calendar 2026 at €128.5/MWh . These contracts gained between €0.5/MWh and €2/MWh on the day . Fuel and carbon markets showed support alongside mixed direction in gas: CEGH gas rose to €63.77/MWh while EU allowances reached €82.31/t; September and fourth-quarter gas forwards were at €65/mwh and increased by €2/mwh for September and by €1/mwh for fourth quarter; API-2 coal was $122/t for September and $126/t for Q4; Greek gas fell to €54.36/mwh .
The session’s prompt structure showed electricity premiums despite supportive fuel conditions: HUPX day-ahead remained almost €17/mwh above Week 35 and about €9.49/mwh above September . Demand increased by more than 1.2 GW while wind generation fell by almost 1.17 GW and northern imports increased by more than 1.8 GW . Solar output increases kept midday prices under control but its disappearance coincided with higher evening prices across multiple markets .
