The 9 July 2026 session shows a cleaner but still tight SEE market: demand eased, regional net imports fell sharply, but prices remained clustered around €120/MWh because lower solar output, stronger thermal dispatch and a firm Italian premium kept the system bid. The clearest market signal is not outright scarcity, but price convergence around Hungary, Romania, Bulgaria, Greece, Croatia and Slovenia, while Italy stayed structurally premium and Serbia/North Macedonia remained discounted.
HUPX settled at €123.62/MWh, down €4.5/MWh day on day, but the decline was modest considering the sharp fall in regional import needs. Romania’s OPCOM came in 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. This produced a tight central SEE band around €120–123/MWh, effectively showing that the regional marginal price was aligned across most coupled or commercially connected markets. Serbia was the main outlier at €107.23/MWh, a discount of €16.40/MWh to HUPX, while North Macedonia was the day’s low at €103.05/MWh. Italy remained the high-price sink at €153.73/MWh, a premium of €30.11/MWh to HUPX.
The regional balance softened materially. Total SEE+Hungary consumption was reported at 31,575 MW, down 920 MW day on day, while net regional imports fell to 907 MW, a drop of 1,639 MW. Imports from the Core area via AT+SK fell to 1,865 MW, down 1,689 MW, which explains why the HUPX–Germany spread almost disappeared. Germany rose sharply to €124.21/MWh, leaving HUPX only €0.59/MWh below Germany. That is a major change from the previous trading pattern: the Core was no longer a clearly cheaper supplier for Hungary/SEE, so the region had to price more on its own internal generation stack and Italian export opportunity.
The generation mix was less supportive than the headline demand decline suggests. Solar output fell by 760 MW to 6,236 MW, while wind also slipped to 1,141 MW. Hydro improved by 279 MW to 5,362 MW, but coal rose 294 MW to 6,514 MW and gas increased 236 MW to 4,546 MW. This is the core price-formation story: demand fell, but renewable softness forced more thermal generation into the stack, keeping spot prices around €120/MWh rather than allowing a deeper correction.
The intraday profile stayed highly shaped. HUPX’s minimum was €36.7/MWh at H15, while the maximum reached €206.1/MWh at H22. Germany, Romania, Bulgaria, Greece, Croatia and Slovenia followed a similar solar-trough/evening-ramp pattern, with low prices mostly around H11–H15 and peak prices around H21–H22. Serbia was especially interesting: SEEPEX averaged only €107.23/MWh, but its maximum reached €227/MWh at H22, the highest visible evening spike among the SEE markets in the daily table. That means the Serbian daily average looked soft, but the evening scarcity signal was still strong.
Italy was the main regional pull. Italy National averaged €153.73/MWh, with a minimum still very high at €136/MWh, meaning Italy offered a premium not just in the evening but across much of the day. This explains the continued commercial relevance of southbound and westbound flows. Montenegro remained a transit-sensitive market: even though Montenegro was a net importer by 113 MW, the ME > IT flow averaged 397 MW, rising to 507 MW in peak. In practical trading terms, Montenegro was not simply a domestic balance story; it was part of the wider SEE-to-Italy arbitrage chain.
Bulgaria was again the strongest exporter in the region, with net exports of 1,235 MW. Bulgarian generation reached 4,983 MW against consumption of 3,749 MW, supported by nuclear, coal and solar. Bulgaria exported toward Romania, Serbia, North Macedonia and Greece, keeping IBEX aligned close to Romania and Greece around €120/MWh. Bulgaria’s role is important because it acted as a regional stabiliser while still pricing close to the marginal SEE band.
Serbia remained structurally short despite the discounted average price. Consumption stood at 3,441 MW, generation at 2,975 MW, and net imports at 466 MW. Serbia imported heavily in peak, with total peak import at 777 MW, while its daily average price stayed below HUPX by more than €16/MWh. That spread suggests Serbia was not priced as a regional scarcity centre on the daily average, but the €227/MWh evening print shows the local market can still become tight when solar fades and cross-border flexibility is constrained.
Hungary’s balance was softer but still import-dependent. Consumption fell to 4,298 MW, generation was 3,636 MW, and net imports were 662 MW. The Hungarian profile is notable because it showed heavy off-peak import dependence but a positive peak export balance in the flow table. That kind of profile points to a shaped trading day: Hungary imported lower-cost volumes during weaker hours, while stronger peak-hour pricing allowed outward commercial positioning when spreads opened.
Romania was less short than earlier in the week, with consumption at 5,755 MW, generation at 5,481 MW, and net imports of 274 MW. The Romanian mix remained relatively balanced: hydro, nuclear, gas and coal all contributed meaningfully, while solar softened. OPCOM’s €119.97/MWh close alignment with Bulgaria and Greece confirms that Romania was not setting a separate premium, but rather trading inside the broader eastern SEE price cluster.
Greece was almost balanced, with consumption of 7,122 MW, generation of 7,093 MW and only 29 MW of net imports. Gas remained important in the Greek stack, while solar output was substantial but not enough to produce a separate Greek discount. HENEX at €120.01/MWh was almost identical to Romania and Bulgaria, showing that Greece’s market was being pulled into the regional price band despite its own gas-heavy generation structure.
Forward markets were more constructive than spot. CEGH gas rose to €50.03/MWh, up €2.6/MWh, Greek gas increased to €45.01/MWh, and coal forwards also strengthened. EUA slipped to €79.04/t, but the move was not enough to offset the fuel-led support in power forwards. Hungarian Week 29 rose to €133.50/MWh, Week 30 to €130/MWh, and Hungarian Avg-26 to €131.50/MWh. The forward curve therefore still prices Hungary above the current spot settlement, suggesting traders are not treating the daily easing in demand as a bearish structural shift.
The trading read is that the market has moved from heat-led scarcity into a more spread-driven structure. The immediate demand pressure eased, but lower solar, weaker wind and firmer fuel prices kept the marginal stack supported. The key monitor for the next session is whether Core imports remain reduced now that Germany has repriced upward. A renewed German discount would pressure HUPX and the eastern SEE cluster lower; continued German strength would leave Italy’s €30/MWh premium as the dominant export signal and keep SEE prices anchored close to €120/MWh despite lower consumption.
