Southeastern Europe’s day-ahead electricity market moved higher for 19 August, but the regional increase masked two distinct trading patterns. Hungary, Romania, Bulgaria, Slovenia and Croatia converged tightly around €168/MWh, while Albania remained at a premium and Serbia, Montenegro and North Macedonia traded at significant discounts. The central SEE corridor therefore showed strong price integration, while peripheral markets remained more sensitive to local supply and cross-border conditions.
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 at €167.94/MWh and Croatia’s CROPEX at €167.91/MWh. The five markets were separated by just €0.33/MWh, creating an exceptionally tight central SEE price zone.
Germany remained slightly cheaper at €166.03/MWh, while Austria stood at €167.21/MWh. Italy continued to trade higher at €175.49/MWh, maintaining a premium of €7.50/MWh over HUPX. Greece rose by €6.2/MWh to €159.88/MWh, leaving it below the central cluster. The overall picture was therefore one of strong central convergence, positioned between cheaper southern Balkan markets and more expensive Italian and Albanian markets.
Across Hungary and the nine SEE exchanges included in the comparison, the unweighted average base price was approximately €163.93/MWh. The highest-to-lowest spread nevertheless reached €26.83/MWh, largely because Albania reached €178.03/MWh while Serbia remained at €151.20/MWh. This dispersion highlights the continuing difference between the tightly coupled central markets and the more volatile peripheral Balkan systems.
The strongest daily increases were recorded in the peripheral markets. Albania gained €25.4/MWh, North Macedonia increased by €19.2/MWh and Serbia by €18.2/MWh. Montenegro rose by a more modest €1.4/MWh to €156.01/MWh. Serbia remained €16.79/MWh below HUPX, North Macedonia was €13.38/MWh lower and Montenegro €11.98/MWh lower. Albania, meanwhile, carried a €10.04/MWh premium over Hungary.
The physical balance points to stronger demand as one of the main drivers of the move. Forecast regional electricity consumption increased to 32,004 MW, up 1,246 MW from the previous day. 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. Flows from the CORE region, mainly Austria and Slovakia toward Hungary and Slovenia, jumped to 2,298 MW, an increase of 1,825 MW.
The shift in cross-border flows is particularly significant because it shows that the region was relying much more heavily on northern imports to cover stronger consumption. At the same time, around 580 MW was flowing toward Italy, meaning the Hungary-SEE area could remain a net importer while still exporting electricity toward the higher-priced Italian market. This configuration helped keep HUPX closely aligned with Austria and Romania while remaining below Italy.
Renewable forecasts added another important dimension. Solar output was 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. Although the two changes were broadly neutral in average megawatt terms, their timing was very different. Additional solar generation was concentrated during daylight hours, while the loss of wind generation affected a much wider part of the day and became particularly important after sunset.
The hourly price curves clearly reflected this shift. HUPX reached a daily minimum of €127.5/MWh at H14 before climbing to a maximum of €214.6/MWh at H21. The base price was €168/MWh, while the conventional peak block averaged €158.3/MWh and off-peak hours averaged €177.7/MWh. The apparent inversion is explained by the strong evening spike: H21 falls outside the standard daytime peak block, and the disappearance of solar generation coincided with higher evening demand.
A similar pattern appeared across the central markets. Romania fell to €127.5/MWh and peaked at €214.7/MWh at H21, while Slovenia moved between €127.8/MWh and €209.4/MWh, also reaching its high at H21. Bulgaria reached €214.4/MWh at H21 and Austria €209.9/MWh, while Croatia peaked slightly earlier at H20 at €217.3/MWh. Greece recorded a deeper daytime trough of €100.1/MWh at H10 before rising to €214.4/MWh at H21.
The hourly profiles therefore point to a market where evening scarcity is becoming more important than the baseload price itself. Strong solar generation suppresses prices during the middle of the day, but the market becomes considerably tighter once solar production disappears. The transition from high renewable output to evening demand is consequently one of the key trading signals in the current regional market.
The southern Balkan markets showed an even sharper version of the same pattern. Serbia’s SEEPEX price reached €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, falling to €100.1/MWh before reaching €220/MWh at H20. North Macedonia averaged €154.6/MWh, with a minimum of €90/MWh and a maximum of €226.3/MWh at H21.
Albania remained the most expensive market in the regional comparison. Its base price reached €178.03/MWh, while the off-peak block averaged €207.9/MWh and the daily maximum reached €250/MWh at H21. Prices nevertheless fell as low as €93.6/MWh during the day, demonstrating that the high average was driven primarily by a very strong evening ramp rather than by uniformly elevated prices throughout the session.
The resulting intraday spreads were substantial. Albania recorded a difference of more than €156/MWh between its minimum and maximum prices, while Serbia saw a spread of roughly €112/MWh and North Macedonia more than €136/MWh. Such volatility increases the potential value of flexible resources including hydropower, battery storage and demand response, as well as available cross-border capacity.
Romania faced an additional supply-side challenge as both 680 MW units at the Cernavoda nuclear plant remained unavailable because low Danube flows had reduced cooling-water availability. The outage removed approximately 1.36 GW of nuclear capacity. Romania responded by restarting almost 300 MW at Unit 4 of the Rovinari coal plant, while renewable generation and imports continued to support the system.
Despite the significant nuclear outage, OPCOM remained almost perfectly aligned with HUPX. Romania therefore avoided the large price premium that might otherwise have been expected from the loss of both Cernavoda reactors. Replacement thermal generation, renewable output and access to neighbouring markets appear to have prevented a major local price dislocation. Nevertheless, the evening peak above €214/MWh showed that post-solar supply remained tight.
The forward market was firmer but considerably less stressed than the day-ahead segment. Hungarian Week 35 power 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. HUPX day-ahead therefore remained almost €17/MWh above Week 35 and €9.49/MWh above September, indicating a clear prompt premium.
Fuel and carbon markets provided some additional support. CEGH gas rose to €63.77/MWh, while EU allowances reached €82.31/t. September and fourth-quarter gas forwards stood at €65/MWh, increasing by €2/MWh and €1.5/MWh respectively. API-2 coal was priced at $122/t for September and $126/t for Q4. Greek gas moved in the opposite direction, falling to €54.36/MWh. Overall, the fuel complex was supportive, but the size of the electricity premium suggests that the move was driven primarily by power-system conditions rather than fuel costs.
For traders, the most important feature of 19 August is therefore the distinction between baseload convergence and hourly scarcity. Hungary, Romania, Bulgaria, Slovenia and Croatia offered very limited geographical base-price differentiation, with all five markets clustered within €0.33/MWh. Greater opportunities and risks remained in the peripheral spreads, particularly Albania against HUPX and the discounted Serbia-Montenegro-North Macedonia group.
The physical system reinforced this structure. Demand increased by more than 1.2 GW, wind generation fell by almost 1.17 GW and northern imports increased by more than 1.8 GW. Stronger solar generation kept midday prices under control, but its disappearance exposed the system to much higher evening prices. The repeated €210-€226/MWh evening peaks, together with Albania’s €250/MWh maximum, show where marginal capacity was being valued.
The regional market is therefore pricing the current tightness primarily as a short-term balancing and shape problem, rather than as a broad repricing of the entire forward curve. Central SEE markets are increasingly capable of moving together under favourable cross-border conditions, but the sharp evening ramps and persistent peripheral spreads show that regional convergence remains incomplete. For the coming sessions, the key variables will be the evolution of demand, wind availability, solar output after sunset, northern imports and the ability of flexible generation and storage to cover the evening ramp.