Southeast European electricity prices moved sharply higher as warmer weather lifted consumption, wind output weakened and the evening ramp exposed renewed transmission and flexible-generation constraints. HUPX increased by €17.3/MWh to €151.07/MWh, but the regional move was far from uniform: Slovenia reached €161.42/MWh, Croatia €157.15/MWh and Romania €150.05/MWh, while Albania remained at €112.50/MWh.
The regional price range widened to €53.41/MWh, measured between Italy at €165.91/MWh and Albania. More important than the baseload dispersion was the hourly divergence. Slovenia reached €372.60/MWh at H20, Croatia €340.40/MWh, Romania €287.80/MWh and Hungary €275.80/MWh. These prices contrasted with midday lows of €30.50/MWh in Greece, €49.20/MWh in Albania, €51.00/MWh in Bulgaria and €90.10/MWh in Hungary.
The market therefore produced two distinct trading conditions within the same delivery day: relatively comfortable solar-intensive midday hours and a much tighter evening system once photovoltaic output declined.
Hungary’s premium shifts into the evening curve
Hungary’s baseload premium over Germany widened by €4.9/MWh to €14.65/MWh. HUPX was also €14.68/MWh above Greece, €11.68/MWh above Serbia, €24.48/MWh above Montenegro and €38.57/MWh above Albania.
The baseload spreads understate the shape of the market. Hungary’s peakload price was €136.50/MWh, compared with €109.10/MWh in Germany, creating a peak-period premium of €27.40/MWh. Off-peak prices were almost aligned at €165.60/MWh in Hungary and €163.70/MWh in Germany. The Hungary-Germany spread was therefore primarily an evening flexibility premium rather than a uniform shortage across the full day.
HUPX fell to €90.10/MWh at H13 before rising to €275.80/MWh at H20, producing an intraday range of €185.70/MWh. The maximum price was 27% above the previous day’s maximum of €216.80/MWh. Such a curve creates strong gross arbitrage value for battery storage, although realised revenues depend on round-trip efficiency, intraday liquidity, imbalance exposure and access to ancillary-service markets.
The western corridor was even tighter. Slovenia’s maximum-minus-minimum range reached €274.70/MWh, while Croatia recorded €243.20/MWh. Both markets moved from a discount or near-parity relationship with Hungary on the previous day to premiums of €10.35/MWh for Slovenia and €6.08/MWh for Croatia. Their extreme H20 prices point to a localised scarcity event in the Slovenia-Croatia corridor rather than a region-wide fuel-cost movement.
Italy remained the most expensive baseload market at €165.91/MWh, but its hourly range was comparatively narrow, between €142.40/MWh and €198.30/MWh. Italy consequently traded €14.84/MWh above Hungary on a baseload basis while falling well below HUPX, BSP and CROPEX during the critical evening hour.
Higher demand absorbed the solar increase
Regional consumption climbed by 1,540 MW, or approximately 4.8%, to 33,397 MW. The detailed balance indicates a regional average temperature of about 25.7°C, supporting higher cooling demand.
The largest consumption increase was concentrated in Romania and Bulgaria, where combined demand rose by 839 MW to 9,690 MW. Greece increased by 307 MW to 7,503 MW, while Slovenia and Croatia together added 363 MW, reaching 9,804 MW. Hungary was comparatively stable at 4,878 MW, up only 42 MW.
Forecast solar generation increased by 450 MW to 7,574 MW, but forecast wind fell by 249 MW to 1,816 MW. Solar therefore supplied more energy during the middle of the day without solving the evening capacity requirement. The reduction in wind output amplified the ramp once solar production declined.
Total regional generation increased by approximately 1,248 MW to 32,547 MW, slightly less than the increase in consumption. Net imports consequently rose by 292 MW to 850 MW, an increase of more than 50% from the previous day. Core inflows from Austria and Slovakia into Hungary and Slovenia increased by 374 MW to 1,830 MW.
The daily balance shows why the market could remain adequately supplied in energy terms while still producing severe hourly price spikes. Regional imports moved into negative territory during parts of the solar-intensive period, before rising rapidly during the evening. The system’s central issue was not total daily energy availability but the location and timing of flexible capacity.
Hungary and Croatia remain the main import centres
Hungary’s own balance deteriorated despite almost unchanged demand. Consumption increased by 43 MW to 4,878 MW, while generation fell by 320 MW to 3,692 MW. Net imports consequently rose from 824 MW to 1,185 MW.
Commercial schedules show Hungary receiving average inflows of approximately 1,073 MW from Slovakia, 796 MW from Romania, 256 MW from Serbia and 136 MW from Austria. It simultaneously supplied approximately 646 MW to Croatia and 466 MW to Slovenia. Hungary therefore remained both a major importing market and an important transit point into the higher-priced western Balkan corridor.
Croatia was the region’s largest net importer at 1,222 MW, compared with 1,185 MW on the previous day. Consumption rose to 2,537 MW, while domestic generation reached only 1,315 MW. Average scheduled inflows included roughly 646 MW from Hungary, 426 MW from Slovenia, 63 MW from Serbia and 88 MW from Bosnia and Herzegovina.
Slovenia imported 329 MW on balance. It received approximately 621 MW from Austria and 466 MW from Hungary, while supplying 426 MW to Croatia and 331 MW to Italy. These transit obligations help explain why a relatively modest national deficit could coincide with the region’s highest baseload and hourly prices.
Bulgaria and Greece support the regional export balance
Bulgaria remained the largest net exporter at 1,372 MW. Its consumption jumped by 678 MW to 3,862 MW, but generation increased by 652 MW to 5,234 MW, preserving almost the entire export position.
Bulgaria supplied approximately 1,307 MW to Romania, 289 MW to Serbia and 181 MW to North Macedonia. At the same time, it received 306 MW from Greece and approximately 100 MW from Turkey. The Bulgarian system therefore served as a central redistribution point between Greece, Romania and the central Balkans.
Greece strengthened its export position from 568 MW to 769 MW. Generation rose by 508 MW to 8,272 MW, outpacing the 307 MW increase in demand. Greece exported approximately 306 MW to Bulgaria, 87 MW to Albania, 211 MW to North Macedonia and 214 MW to Italy.
The Greek price of €136.39/MWh remained below Bulgaria, Romania and Hungary, consistent with northbound commercial schedules during the tighter hours. Greece still recorded a pronounced solar-shaped curve, falling to €30.50/MWh at H13 before reaching €196.70/MWh at H22.
Romania occupied the middle of this supply chain. It moved from a net export position of 89 MW to net imports of 144 MW, even though it continued to send 796 MW to Hungary. Romania compensated by importing approximately 1,307 MW from Bulgaria. Its €28.3/MWh day-on-day price increase, to €150.05/MWh, reflected the combined effect of higher domestic consumption, lower generation and strong transit demand toward Hungary.
Serbia’s price catches up as its import requirement narrows
SEEPEX recorded the largest day-on-day baseload increase among the monitored markets, rising by €31.2/MWh to €139.39/MWh. Serbia’s discount to Hungary compressed from more than €25/MWh to €11.68/MWh.
Consumption increased by 88 MW to 3,620 MW, but generation rose more strongly, by 309 MW to 3,352 MW. Net imports consequently declined from 489 MW to 269 MW.
Serbia imported from Bulgaria, North Macedonia, Bosnia and Herzegovina and Romania while exporting to Hungary, Croatia and Montenegro. The most important reversal occurred on the Hungary border: Serbia moved from a small average import on the previous day to an export of approximately 256 MW, rising to 348 MW during peak hours. That direction was consistent with the HUPX premium.
Serbia’s curve remained less extreme than Hungary’s. SEEPEX fell to €80.50/MWh at H13 and peaked at €215.00/MWh at H22. Its later maximum reflects the southward progression of the evening scarcity period, with Slovenia, Croatia, Hungary and Romania peaking at H20, Italy and North Macedonia around H21, and Serbia, Greece, Bulgaria and Montenegro at H22.
Montenegro and North Macedonia face weaker domestic balances
Montenegro’s BELEN price rose by €22.6/MWh to €126.59/MWh, leaving it €24.48/MWh below Hungary and €30.56/MWh below Croatia. Consumption increased to 442 MW, generation fell to 291 MW, and net imports widened from 101 MW to 151 MW.
Montenegro continued to export approximately 338 MW to Italy while receiving electricity from Bosnia and Herzegovina, Serbia, Kosovo and Albania. The country’s net deficit therefore coexisted with substantial transit toward Italy. Its hourly price ranged from €80.00/MWh at H12 to €200.00/MWh at H22.
North Macedonia moved from a 20 MW net export to an 81 MW net import as consumption rose by 82 MW to 421 MW and generation declined to 340 MW. MEMO increased by €21.0/MWh to €125.72/MWh, but remained €25.35/MWh below HUPX.
Albania was the regional outlier. Generation of 983 MW slightly exceeded consumption of 974 MW, allowing a modest 9 MW export, while ALPEX rose only €8.7/MWh to €112.50/MWh. Its peakload average of €76.80/MWh remained far below its €148.20/MWh off-peak average, reflecting deep daytime price suppression followed by a much firmer evening curve.
Fuel costs strengthen without a full forward-market repricing
The thermal cost environment became more supportive. CEGH gas rose by €2.4/MWh to €54.44/MWh, the Greek gas benchmark increased by €0.9/MWh to €45.10/MWh, and EU allowances gained €1.3/t to €81.39/t. Coal softened by $1/t to $118/t, leaving gas and carbon as the stronger marginal-price drivers.
The Hungarian forward curve did not fully follow the day-ahead spike. Week 30 remained at €120/MWh, while Week 31 held at €133/MWh. Current HUPX baseload therefore traded €31.07/MWh above Week 30 and €18.07/MWh above Week 31. The curve continues to price the immediate scarcity event as partly temporary.
Longer Hungarian contracts strengthened: the average-2026 product rose by €1.5/MWh to €138.50/MWh, while Calendar 2026 gained €2.5/MWh to €121.50/MWh. The forward Hungary-Germany spread widened to €22/MWh for Week 31 and €21.50/MWh for the average-2026 product. The market is distinguishing between a potentially reversible daily spike and a more persistent structural premium linked to import dependence, thermal availability and constrained north-south transmission.
The decisive signal from 15 July is the widening value gap between midday electricity and dependable evening supply. Solar growth is increasing daytime energy availability, but dispatchable generation, storage and usable cross-border capacity are increasingly setting the commercial value of electricity after sunset.
