South-east European day-ahead electricity prices strengthened across most markets for delivery on 21 July, with the regional average masking wider hourly divergence. The spread reflected differences between solar-heavy midday pricing, more expensive evening generation and the availability of cross-border transmission capacity. Hungary, Romania, Bulgaria, Greece, Slovenia and Croatia traded within a relatively narrow €137–142/MWh band. Serbia remained cheaper, while Montenegro traded at a significant premium and Albania diverged sharply from surrounding markets.
Demand, solar and wind outlook underpin import needs
The regional power system entered Tuesday with forecast electricity consumption of 33,986 MW, up by 983 MW or nearly 3% from Monday. Net imports increased by 303 MW to 2,112 MW. Gross imports from Austria and Slovakia into Hungary and Slovenia edged up to 3,396 MW. The higher import requirement came despite forecast solar generation rising by 1,428 MW to 8,389 MW.
Wind output was expected to decline by 212 MW to 1,258 MW. Combined solar and wind generation was therefore about 1,216 MW higher than the previous day. Regional generation was estimated at 31,873 MW, only 680 MW higher day on day. With consumption up by 983 MW, the resulting shortfall of 303 MW was covered through higher net imports.
HUPX settlement and intraday range show evening repricing
HUPX settled at €137.37/MWh, gaining €9.80/MWh from Monday. Romania closed slightly above Hungary at €138.68/MWh, while Bulgaria finished at €138.17/MWh. Slovenia traded at €141.93/MWh, Croatia at €141.11/MWh, and Greece at €142.21/MWh. Austria was almost aligned with Hungary at €138.31/MWh, leaving a spread of just €0.94/MWh.
EPEX Germany rose to €112.96/MWh, but the Hungarian premium remained at €24.41/MWh. The spread was virtually unchanged despite higher imports from the north-west into the region. This pointed to constraints beyond German generation availability. Value continued to accumulate along the transmission route into central and south-eastern Europe where evening flexibility and cross-border transfer capacity were scarce.
The regional price profile showed a larger swing than baseload settlements alone. HUPX peakload averaged only €110.10/MWh, compared with €164.70/MWh for off-peak delivery. Prices fell to a minimum of €46.40/MWh in hour 14, before rising to a maximum of €211.50/MWh in hour 20. The intraday range therefore reached €165.10/MWh.
Solar-heavy peak product contrasts with expensive off-peak hours
This pattern reflected an inversion of the conventional peak–off-peak relationship during summer trading in the region. The peak product included the solar-heavy middle of the day, while off-peak delivery captured expensive night-time and late-evening hours. As a result, a peakload hedge did not necessarily cover the highest priced hours in the daily profile. For generators, traders and industrial consumers, exposure increasingly concentrated in the sunset ramp and evening periods rather than across a standard daytime peak block.
Romania showed a similar structure on OPCOM, where the settlement was €138.68/MWh. Peakload averaged €113.10/MWh, while off-peak settled at €164.30/MWh. The minimum was recorded at €62.90/MWh in hour nine, with a maximum of €208.70/MWh in hour 20. Bulgaria followed a comparable hourly path with prices falling to
Bulgaria’s minimum was set at
Bulgaria’s prices dropped to
Bulgaria followed a comparable profile with prices falling to
Bulgaria followed a comparable profile with prices falling to €63.50/MWh in hour nine before climbing to €208.70/MWh in hour 20.
Balkan market spreads: Greece, Italy exports and Montenegro premium
Greece recorded one of the largest daily increases in baseload prices, rising by
to
Greece’s baseload settlement increased by €17.30/MWh to finish at
Greece recorded one of the largest daily increases in baseload prices, rising €17.30/MWh to €142.21/MWh on 21 July delivery.
The Greek peakload settled at
Peakload settled at €115.10/MWh, well below off-peak at €169.30/MWh on OPCOM delivery on 21 July.
The evening maximum reached €216.50/MWh in hour 21 as Greek demand rose to
Greek demand increased by 280 MW to reach 8,508 MW while Greece remained a net importer at 606 MW.
Bulgarian exports provided the principal balancing route into Greece on the day-ahead market. Bulgaria exported an average of 979 MW southward compared with 787 MW on Monday, including 928 MW during peak hours and 1,030 MW off-peak hours.
Bulgaria also maintained total net exports of 1,090 MW supported by generation of 5,199 MW against consumption of 4,109 MW on Tuesday’s forecast basis for delivery on 21 July.
Greece continued exporting an average of 232 MW to Italy even while importing heavily from Bulgaria on day-ahead schedules for 21 July.
This coincided with Italy’s national day-ahead price reaching €177.30/MWh, placing it €35.09/MWh above Greece and €39.93/MWh above Hungary for the same delivery date.
Southeast European exports scheduled towards Italy remained substantial at approximately 1,200 MW but were down by 130 MW versus Monday’s level for delivery on 21 July.
The Italian price profile differed structurally from solar-heavy SEE markets because its national minimum remained at €156.90/MWh compared with €46.40/MWh in Hungary and €63.50/MWh in Bulgaria and Greece; Serbia’s minimum was €60.10/MWh.
SERBIA discount versus Montenegro’s BELEN premium; ALPEX falls in Albania
Montenegro was the most expensive SEE market outside Italy on BELEN day-ahead trading for delivery on 21 July.
BELEN jumped by €27.60/MWh to settle at €148.64/MWh, establishing an €11.27/MWh premium versus HUPX and an €17.16/MWh premium versus Serbia.
The Montenegrin peakload price reached €135.70/MWh while off-peak traded at €161.60/MWh; daily minimum was €75/MWh in hour 13 and maximum was €209.10/MWh in hour 21.
The domestic balance in Montenegro remained structurally short with consumption forecast at 491 MW against generation of 338 MW and net imports of 153 MW for Tuesday’s schedules delivering on 21 July.
The country nevertheless scheduled an average of 584 MW towards Italy through the undersea interconnector including 589 MW during peak hours; these exports were supported by inflows from Bosnia and Herzegovina, Serbia, Albania and Kosovo.
The Italian market’s demand contributed to BELEN’s premium alongside limited domestic flexibility reflected in the latest available generation mix for 20 July consisting of approximately 200 MW coal, 94 MW hydro and only 11 MW wind.
Serbia moved in the opposite direction as SEEPEX edged up by only €0.20/MWh to settle at €131.48/MWh for delivery on 21 July.
This left Serbia about €5.90/MWh below Hungary and approximately €10–11/MWh below Romania, Bulgaria, Greece, Slovenia and Croatia based on their respective settlements for that date.
The limited baseload movement concealed a shift in hourly shape: peakload declined from €116.80/MWh to €109/MWh while off-peak increased from €145.80/MWh to €154/MWh for delivery on Tuesday’s date.
The minimum fell to €60.10/MWh in hour 11 but the evening maximum remained elevated at €201/MWh in hour 20 as Serbian consumption rose from 3,452 MW to 3,512 MW.
Serbian generation increased from 3,030 MW to 3,121 MW while net imports declined modestly from 423 MW to 391 MW for day-ahead schedules delivering on 21 July.
Serbia imported an average of 270 MW from Bosnia and Herzegovina and 263 MW from Croatia while exporting 184 MW towards Montenegro; imports were concentrated in peak hours when Serbia’s net deficit widened to 672 MW versus only 111 MW off-peak.
This imbalance between peak and off-peak flows mattered more than SEEPEX’s relatively soft baseload movement as coal contributed approximately 2,455 MW or about 78% of reported generation on 20 July alongside hydropower supply of 577 MW and wind output of 135 MW; gas-fired output was negligible at 8 MW.
