On 7 July 2026, the SEE-Hungary day-ahead market showed prices shaped by cross-border price differences, local balancing constraints, Italy’s higher pricing, and uneven availability of conventional generation. The price pattern reflected the interaction between import dependence, scheduled flows across borders, and how individual systems maintained balance during tighter hours. Most Southeast European hubs stayed clustered around €102–108/MWh, while Italy National remained at €142.36/MWh.
Germany’s day-ahead price fell to €72.80/MWh, widening the HUPX-Germany spread to €34.04/MWh. Central Europe therefore saw weaker pricing, but Hungary and the wider SEE region continued to trade at a premium. The premium persisted as regional systems still required imports and some available supply was redirected toward Italy’s higher-priced market.
Spot prices across SEE hubs
Hungary’s HUPX settled at €106.85/MWh, down €9.6/MWh versus the previous session, but still above German levels. Other hubs were also in a similar range, with OPCOM (Romania) at €103.81/MWh, IBEX (Bulgaria) at €103.03/MWh, HENEX (Greece) at €103.51/MWh, BSP (Slovenia) at €103.11/MWh, CROPEX (Croatia) at €102.34/MWh, and ALPEX (Albania) at €103.56/MWh.
Serbia and North Macedonia were the main upward outliers within SEE, with SEEPEX at €108.01/MWh and MEMO at €108.84/MWh. Montenegro moved lower, falling sharply to €93.85/MWh. These differences occurred alongside a market balance that did not converge toward Germany’s lower pricing.
Consumption, imports and cross-border flows
Regional consumption increased to 32,075 MW, up 1,604 MW day on day. Total net imports rose to 1,979 MW, an increase of 556 MW. Imports from the core European direction strengthened as Austria and Slovakia supplied 3,244 MW, up 549 MW.
The physical balance helped explain why prices did not align with Germany’s lower level. While lower Central European prices supported the SEE-Hungary system, they were not sufficient to remove the regional premium tied to import dependence and internal flow patterns toward higher-priced destinations.
Italy’s premium and commercial scheduling effects
The strongest commercial signal came from Italy’s persistent price premium. Even with the wider HU+SEE region remaining a net importer, scheduled flows still moved 1,083 MW toward Italy, where prices reached €142.36/MWh. This supported a trading pattern in which Central Europe supplied electricity into Hungary and Slovenia while capacity was redirected toward southern and western markets.
A cross-border optimisation example appeared in Montenegro’s schedules versus its clearing price. BELEN cleared at €93.85/MWh, but commercial schedules showed exports toward Italy of 425 MW during base hours and 438 MW during peak hours. Montenegro remained a net importer overall at 160 MW, indicating that interconnection capacity enabled trading aligned with regional price differences.
Tighter conditions in Serbia and structural imbalance in Hungary
Serbia remained among the tighter markets in SEE as SEEPEX increased by €10.2/MWh to €108.01/MWh. The price placed Serbia above Hungary, Romania, Bulgaria, Greece, Croatia, Slovenia and Albania. Serbia recorded 3,476 MW consumption, 2,974 MW generation, and 502 MW net imports.
The peak-hour pressure was reflected in Serbia’s commercial balance reaching -785 MW during peak hours, compared with -219 MW during off-peak periods. Serbia imported from Bosnia and Herzegovina, Croatia, Hungary, Bulgaria and North Macedonia while exporting toward Romania and Montenegro.
Hungary showed a similar structural imbalance in its supply-demand position. Consumption reached 4,662 MW, while domestic generation stood at 3,695 MW, leaving net imports of 967 MW. The market relied heavily on Austrian and Slovak flows while still supporting exports toward Croatia, Slovenia and Romania during certain periods.
Nuclear return in Romania; Bulgaria supply role; Greece near regional average
Romania’s price declined to €103.81/MWh. The return of Cernavoda Unit 1 restored approximately 700 MW of nuclear capacity following scheduled maintenance. The additional output improved supply conditions particularly during evening periods when solar generation declines.
Romania still recorded net imports of 596 MW, indicating less tightness rather than full oversupply. Bulgaria continued to act as a main supply contributor with generation of 5,074 MW against consumption of 3,809 MW, resulting in net exports of 1,266 MW. Power flowed toward Romania, Serbia, North Macedonia and Greece.
Bulgaria’s surplus position coincided with IBEX staying close to regional prices because interconnectors absorbed much of the available generation. Greece traded near the regional average at €103.51/MWh. Greece recorded consumption of 7,192 MW** and generation of 7,274 MW**, with base exports of 82 MW and peak exports of 630 MW.
Greece exported toward North Macedonia, Albania and Italy while importing from Bulgaria.
Tighter spot conditions versus forward market easing signals
The forward market showed a different direction compared with the immediate spot environment. Hungarian Week 29 prices fell to €132/MWh**, down €14/MWh**, while Week 30 dropped to **€126/MWh**, down **€7.5/MWh**.
The Hungarian Week 29 premium over Germany narrowed to €19.5/MWh** as fuel markets softened alongside spot prices for gas forwards: CEGH gas at **€45.71/MWh** and Greek gas at **€42.87/MWh**. Lower coal forwards were also reported while EU carbon allowances increased to **€81.79/t**.
The forward curve indicated some relief from current tightness without returning fully to normal conditions based on how it priced structural differences between Germany, Hungary, SEE and Italy.
Main spreads highlighted for trading focus on spreads rather than convergence alone
The trading picture remained consistent across the region: SEE spot prices softened but a structural premium persisted between Germany and Hungary as well as between SEE hubs and Italy National pricing at **€142.36/MWh**. Serbia faced tighter domestic conditions reflected in SEEPEX at **€108.01/MWh**, while Montenegro cleared significantly lower at **€93.85/MWh** despite exports toward Italy shown in commercial schedules.
For generators and investors, flexibility during high-value hours remained central as hydro output timing, gas dispatch windows, batteries operation and demand response interact with cross-border capacity constraints.