Day-ahead settlements across central SEE exchanges
The 9 July 2026 Southeast European electricity market session delivered wholesale prices concentrated around €120/MWh despite easing electricity demand and a sharp fall in regional net imports. The session was characterised by strong price convergence across Hungary, Romania, Bulgaria, Greece, Croatia and Slovenia, while Italy stayed structurally more expensive. Serbia and North Macedonia traded at lower levels relative to the regional cluster.
On the main day-ahead venues, Hungary’s HUPX settled at €123.62/MWh, down €4.5/MWh versus the previous day. Romania’s OPCOM closed at €119.97/MWh, Bulgaria’s IBEX at €119.92/MWh, Greece’s HENEX at €120.01/MWh, Croatia at €121.23/MWh and Slovenia at €122.50/MWh. These results placed the core SEE markets within a narrow €120–123/MWh band.
Key outliers: Serbia, North Macedonia and Italy
Serbia’s SEEPEX recorded an average price of €107.23/MWh, which was €16.40/MWh below HUPX. North Macedonia posted the lowest regional level at €103.05/MWh. Italy remained the highest-priced market in the region with an Italian national average of €153.73/MWh. The Italian premium was more than €30/MWh over Hungary.
The spread between Italy and neighbouring markets supported cross-border trading opportunities cited for southbound and westbound flows. Montenegro also featured as a transit point, with net imports of 113 MW. Average Montenegro-to-Italy flows were 397 MW, rising to 507 MW during peak hours.
Demand, imports and cross-border flows
Regional supply-demand conditions improved during the session as total SEE plus Hungary electricity consumption fell to 31,575 MW, down 920 MW day on day. Regional net imports declined to 907 MW, a drop of 1,639 MW compared with the previous day. Imports from Core Europe through Austria and Slovakia also decreased sharply to 1,865 MW, down 1,689 MW.
Germany’s price increase to €124.21/MWh brought HUPX close to the German market level. This reduced the relative advantage of cheaper Core-area electricity for Hungary and SEE referenced in the session data.
Generation mix: weaker renewables and higher thermal output
Lower renewable availability coincided with generation changes that supported higher prices despite softer demand. Solar production fell by 760 MW to 6,236 MW, while wind generation decreased to 1,141 MW. Hydro generation increased by 279 MW to 5,362 MW but did not offset weaker solar and wind output.
Thermal generation rose across coal and gas categories during the session. Coal generation increased by 294 MW to 6,514 MW, while gas-fired output rose by 236 MW to 4,546 MW.
Intraday volatility linked to renewable cycles
Intraday pricing reflected renewable production patterns across multiple markets including Germany, Romania, Bulgaria, Greece, Croatia and Slovenia. HUPX recorded a low of €36.70/MWh during hour H15 and an evening peak of €206.10/MWh at hour H22. The pattern described included lower midday prices followed by significant evening ramps.
Serbia showed the strongest evening volatility among the analysed markets even though its daily average remained relatively low. Serbia reached €227/MWh at H22, identified as the highest evening spike among the SEE markets covered in the review.
Country balances: Bulgaria exports; Serbia and Hungary import; Romania and Greece near balance
Bulgaria recorded net exports of 1,235 MW, with generation of 4,983 MW against consumption of 3,749 MW. The Bulgarian mix was supported by nuclear, coal and solar output cited as contributing factors for exports flowing toward Romania, Serbia, North Macedonia and Greece.
Serbia remained structurally short despite its lower average price level. Serbian consumption stood at 3,441 MW, while domestic generation reached 2,975 MW for net imports of 466 MW; peak imports reached 777 MW. The review also highlighted that Serbia’s gap between its lower daily average and its €227/MWh evening peak indicated vulnerability during reduced solar generation periods.
Hungary also depended on imports in the session data provided. Consumption fell to 4,298 MW, generation reached 3,636 MW and net imports were 662 MW.
Romania moved closer to balance with consumption of 5,755 MW, generation of 5,481 MW and net imports of 274 MW. OPCOM’s settlement at €119.97/MWh was cited as confirmation that Romania traded within the wider regional band rather than establishing a separate premium.
Greece was almost fully balanced with consumption of 7,122 MW, generation of 7,093 MW and only 29 MW of net imports. Despite gas playing an important role in Greece’s generation mix as described in the review, strong renewable availability limited divergence; HENEX settled almost exactly alongside Romania and Bulgaria.
Forward curves: gas higher; coal firmer; carbon slightly lower
The forward market outlook described differed from spot conditions with gas futures rising on CEGH and in Greece. CEGH gas futures increased to €50.03/MWh, while Greek gas rose to €45.01/MWh.
Coal prices strengthened while EU carbon allowances declined slightly to €79.04/t, which was described as not enough to offset fuel-driven support in forward pricing.
Hungarian power forwards remained elevated with Week 29 contracts at €133.50/MWh, Week 30 at €130/MWh and the 2026 average at €131.50/MWh.
[No additional subheading]
The session assessment in the review stated that Southeast Europe shifted from heat-driven tightness toward a more spread-driven and fuel-sensitive structure as demand eased but thermal requirements increased alongside weaker solar output and softer wind generation.
The review pointed to upcoming sensitivity around whether German prices remain elevated; it also noted that a return of cheaper Core European imports could push HUPX and eastern SEE markets lower while continued German strength together with Italy’s persistent premium could keep regional prices anchored near €120/MWh despite softer demand.
