The Southeast European day-ahead electricity market began Tuesday with a summer pattern featuring strong solar output at midday and constrained availability of thermal and nuclear generation outside those hours. Weak hydrological conditions and a more expensive evening ramp contributed to higher prices during the transition as solar generation fell. Prices did not rise uniformly across the region, with Slovenia, Italy, Croatia and Romania recording the highest baseload levels, while Greece, Bulgaria, Albania and Montenegro traded significantly lower.
The market structure reflected increasing pressure on system balancing as solar penetration rises. Daylight periods can bring abundant supply, but limited dispatchable resources, insufficient storage capacity and reduced hydro flexibility leave markets exposed during the evening transition. The resulting price formation was fragmented across countries rather than aligned to a single regional signal.
Baseload price range across major Southeast European markets
Hungary’s HUPX baseload price increased by €8.30/MWh to €186.90/MWh, a daily rise of 4.6%. Romania settled slightly higher at €188.24/MWh, while Slovenia recorded the highest directly observed Southeast European baseload at €194.61/MWh. Croatia followed at €191.92/MWh and Italy’s national day-ahead market reached €194.94/MWh.
Southern markets remained cheaper: Greece traded at €155.03/MWh, Bulgaria at €157.03/MWh, Albania at €153.56/MWh and Montenegro at €159.55/MWh. North Macedonia increased to €165.43/MWh, while Serbia remained near the middle of the regional curve at €174.64/MWh.
The spread between the highest and lowest major SEE markets reached €41.05/MWh, measured between Slovenia and Albania. Including Germany and Italy widened the difference to €45.15/MWh. The separation indicated that available cross-border transmission capacity was not sufficient to fully align regional electricity values during the evening scarcity period.
Hourly volatility peaks around H20
Daily baseload averages did not show the full extent of the hourly imbalance. HUPX reached a minimum of €76.50/MWh at H14 when solar production was strongest before rising sharply to €418.90/MWh at H20. Romania followed a similar profile, reaching €433.90/MWh at H20, while Slovenia posted the strongest evening increase with a peak of €507.60/MWh.
Croatia reached €478.80/MWh and Serbia climbed to €496.80/MWh during the same evening scarcity window around H20. For comparison, Germany peaked at €240/MWh, Austria at €245.40/MWh and Italy’s national market at €267.40/MWh. The largest pressure was concentrated in the Hungary–Romania–Western Balkans corridor where flexible supply was more limited.
The event was not a system-wide shortage across all delivery hours but a short-duration scarcity concentrated around H20. It rewarded flexible resources able to respond during the evening ramp, including gas-fired generation, pumped storage, batteries and demand-side flexibility. Traditional baseload averages became less representative of costs faced by consumers with demand concentrated after sunset.
Demand forecast, generation levels and import dependence
Regional electricity consumption was forecast at an average of 34,191 MW, up 1,445 MW or 4.4% versus Monday. Temperatures rose by almost 1°C across the region, with Greece expected to average 28.6°C.
Hungary’s consumption stayed relatively stable at 5,023 MW, while demand increased in several larger SEE markets including Romania at 5,923 MW, Greece at 7,251 MW, Serbia at 4,030 MW and Croatia at 2,589 MW. Higher consumption combined with weak hydro conditions and limited flexible generation continued to add pressure on regional electricity balances.
Estimated regional generation increased to 32,604 MW, around 5.2% higher than Monday, allowing net imports to fall from 1,740 MW to 1,587 MW despite stronger demand. Imports still covered about 4.6% of total regional demand, indicating continued dependence on external supply during tighter conditions.
Structural deficits by market and export anchors
The regional average deficit masked differences between individual markets in import positions. Hungary remained the largest structural importer with average imports of 2,269 MW, equivalent to about 45% of domestic consumption. Croatia imported 1,197 MW (more than 46% of demand), while Serbia recorded a deficit of 496 MW.
Romania imported 437 MW, Montenegro 305 MW, Slovenia 84 MW and Kosovo 142 MW on average across the period described in Trading Note 4/8: Evening scarcity widens SEE power spreads as Hungary and Romania face supply pressure . Montenegro had the largest relative supply gap with imports covering almost 62% of forecast consumption; domestic generation was estimated at only 187 MW versus demand of 492 MW.
BELEN’s day-ahead price fell by €36.60/MWh to €159.55/MWh without indicating stronger domestic supply conditions in Montenegro . Prices were instead influenced by surrounding imports from Bosnia and Herzegovina, Serbia and Albania as well as flows via the Italian interconnector.
Bulgaria and Greece were the main southeastern export anchors in expected flows described for Tuesday’s outlook period . Bulgaria was expected to export 1,425 MW, equivalent to more than 36% of domestic consumption, while Greece’s net exports reached 1,506 MW, or approximately 21% of demand.
Cross-border corridors and changing flow directions
Northern imports from Austria and Slovakia into Hungary and Slovenia averaged 2,475 MW, around 7.4% lower than Monday . Bulgaria supplied approximately 1,536 MW towards Romania and 366 MW towards Serbia.
Greece continued supporting neighbouring markets through exports of 456 MW towards Bulgaria, 433 MW towards North Macedonia and 157 MW towards Albania . Greece also maintained a full scheduled export position of 500 MW towards Italy during the period described.
Romania acted as both a deficit market and a transit hub . While importing from Bulgaria it exported 953 MW towards Hungary and 237 MW towards Moldova; overall it averaged a net import position of 437 MW with flow direction changing through the day.
Solar-driven shifts in peak/off-peak pressure
The traditional split between peak and off-peak became less useful under current summer conditions . Hungary’s average import position was 2,269 MW but imports rose to 3,096 MW during off-peak hours, compared with 1,441 MW during peak periods.
This shift reflected solar-driven changes in system balance as hours after sunset combined falling solar output with rising residential and commercial demand . As a result “off-peak” did not necessarily correspond to lower system pressure during these hours.
Generation mix behind pricing patterns
The generation mix supported the observed pricing profile across delivery hours . Regional coal output increased by 1,235 MW to 7,034 MW, while gas-fired generation rose by 766 MW to 5,408 MW. Hydropower improved by 778 MW to 5,451 MW, but remained below levels needed to restore normal flexibility.
Solar production increased to 7,471 MW, while wind declined by 832 MW to only 1,747 MW. Nuclear generation remained weak at 3,348 MW, limiting stable low-carbon baseload availability during the evening transition .
Sensitivity in Hungary’s evening scarcity exposure
Hungary remained among the most exposed markets during evening scarcity hours . Nuclear production averaged only 174 MW, while gas-fired generation increased to 942 MW. Solar contributed 1,422 MW, representing approximately half of domestic daylight production but unavailable when prices reached their highest levels after sunset.
