The 9 July 2026 Southeast European electricity market session showed a more balanced but still tight market environment. Electricity demand eased and regional net imports declined significantly, yet wholesale prices remained concentrated around €120/MWh. Lower solar generation, increased thermal dispatch and continued strength in the Italian market premium kept prices elevated. The main market signal was not an immediate supply shortage, but rather strong price convergence across central SEE markets, including Hungary, Romania, Bulgaria, Greece, Croatia and Slovenia. Meanwhile, Italy remained structurally more expensive, while Serbia and North Macedonia traded at a discount.
The regional price cluster was clearly visible across the main day-ahead exchanges. HUPX Hungary settled at €123.62/MWh, down €4.5/MWh compared with the previous day, but the decline was limited despite the sharp reduction in regional import requirements. 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. Together, these markets formed a narrow €120–123/MWh regional price band, reflecting stronger alignment between interconnected SEE markets.
The main price exceptions were Serbia, North Macedonia and Italy. Serbia’s SEEPEX average price was €107.23/MWh, creating a discount of €16.40/MWh compared with HUPX, while North Macedonia recorded the lowest regional price at €103.05/MWh. At the opposite end of the market, Italy remained the regional price leader at €153.73/MWh, maintaining a premium of more than €30/MWh over Hungary. The continued Italian premium remained an important driver of cross-border trading opportunities.
Regional supply-demand conditions improved during the session. Total SEE plus Hungary electricity consumption declined to 31,575 MW, a decrease of 920 MW day on day, while regional net imports dropped to 907 MW, down by 1,639 MW. Imports from the Core European region through Austria and Slovakia also declined sharply to 1,865 MW, a reduction of 1,689 MW. As a result, the traditional advantage of cheaper Core-area electricity for Hungary and SEE weakened. Germany’s price increase to €124.21/MWh brought HUPX almost level with the German market, forcing SEE prices to increasingly reflect regional generation conditions rather than external imports.
Despite lower demand, the generation mix remained supportive of higher prices. Solar production declined by 760 MW to 6,236 MW, while wind generation also decreased to 1,141 MW. Hydro generation improved by 279 MW to 5,362 MW, but this was not enough to offset weaker renewable output. At the same time, coal generation increased by 294 MW to 6,514 MW, while gas-fired generation rose by 236 MW to 4,546 MW. The key market driver was therefore the shift toward more expensive thermal generation as renewable availability weakened.
Intraday price patterns remained strongly shaped by renewable production cycles. HUPX recorded a low of €36.70/MWh during H15, while the evening peak reached €206.10/MWh at H22. Similar solar-driven patterns appeared across Germany, Romania, Bulgaria, Greece, Croatia and Slovenia, with lower prices during midday hours and significant evening ramps. Serbia showed the strongest evening volatility: although its daily average remained relatively low, the market reached €227/MWh at H22, the highest evening spike among the analysed SEE markets.
Italy continued to act as the region’s main price anchor. The Italian national average reached €153.73/MWh, with even the daily minimum remaining high at €136/MWh. This indicates that Italy’s premium was not limited only to evening scarcity but was present throughout much of the trading day. The persistent spread supported the commercial importance of southbound and westbound electricity flows. Montenegro remained a strategically important transit market, with net imports of 113 MW while maintaining average Montenegro-to-Italy flows of 397 MW, increasing to 507 MW during peak hours.
Bulgaria continued to play a stabilising role in the regional market, recording net exports of 1,235 MW. Bulgarian generation reached 4,983 MW, compared with consumption of 3,749 MW, supported by nuclear, coal and solar output. Electricity exports from Bulgaria flowed toward Romania, Serbia, North Macedonia and Greece, helping keep regional prices aligned around the €120/MWh level.
Serbia remained structurally short despite its lower average price. Consumption stood at 3,441 MW, while domestic generation reached 2,975 MW, leaving the country with 466 MW of net imports. Peak imports reached 777 MW, highlighting continued dependence on regional support during tighter hours. The gap between Serbia’s lower daily average and its €227/MWh evening peak shows that the market was not experiencing constant scarcity, but remained vulnerable during periods of reduced solar generation and limited cross-border flexibility.
Hungary also remained dependent on imports, although its balance improved compared with previous sessions. Consumption fell to 4,298 MW, generation reached 3,636 MW, and net imports stood at 662 MW. The Hungarian market displayed a shaped trading profile, with imports during lower-priced hours and stronger commercial positioning during peak periods when regional spreads widened.
Romania moved closer to balance, with consumption at 5,755 MW, generation at 5,481 MW and net imports of 274 MW. Its diverse generation mix, including hydro, nuclear, gas and coal, helped keep prices aligned with the wider SEE cluster. OPCOM’s settlement at €119.97/MWh confirmed that Romania was trading within the regional band rather than establishing a separate premium.
Greece remained almost fully balanced, with consumption of 7,122 MW, generation of 7,093 MW and only 29 MW of net imports. Although gas continued to play an important role in the Greek generation mix, strong renewable availability prevented a larger price divergence. HENEX settled almost exactly alongside Romania and Bulgaria, confirming Greece’s integration into the wider SEE price structure.
Forward markets indicated a more cautious outlook than the spot market. CEGH gas futures increased to €50.03/MWh, while Greek gas rose to €45.01/MWh. Coal prices also strengthened, while EU carbon allowances declined slightly to €79.04/t, not enough to offset fuel-driven support. 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, suggesting traders continue to price a firm medium-term market environment.
The overall market assessment is that Southeast Europe has moved from a period of extreme heat-driven tightness into a more spread-driven and fuel-sensitive market structure. Lower demand reduced immediate pressure, but weaker solar generation, softer wind output and stronger thermal requirements kept prices supported. The key factor for upcoming sessions will be whether German prices remain elevated. A return of cheaper Core European imports could push HUPX and the eastern SEE markets lower, while continued German strength and Italy’s persistent premium could keep regional prices anchored near €120/MWh despite softer demand.