The Southeast European day-ahead market entered Tuesday with a familiar summer imbalance: abundant solar generation during the middle of the day, constrained thermal and nuclear availability outside solar hours, weak hydro conditions and an increasingly expensive evening ramp. The result was not a uniform regional price increase but a fragmented market in which Slovenia, Italy, Croatia, Romania and Hungary carried the highest baseload prices, while Greece, Bulgaria, Albania and Montenegro remained materially cheaper.
Hungary’s HUPX baseload price increased by €8.30/MWh to €186.90/MWh, a daily gain of 4.6 per cent. Romania settled slightly higher at €188.24/MWh, while Slovenia led the directly observed SEE markets at €194.61/MWh. Croatia followed at €191.92/MWh, and the Italian national price reached €194.94/MWh.
The southern markets cleared much lower. Greece traded at €155.03/MWh, Bulgaria at €157.03/MWh, Albania at €153.56/MWh and Montenegro at €159.55/MWh. North Macedonia rose more strongly to €165.43/MWh, while Serbia occupied the middle of the regional curve at €174.64/MWh.
The difference between the highest and lowest principal markets reached €41.05/MWh within SEE, measured between Slovenia and Albania. Including Germany and Italy, the range widened to €45.15/MWh. This dispersion matters more than the regional average because it shows that available cross-border capacity was not sufficient to equalise the value of electricity across the evening scarcity window.
The daily baseload figures also understate the severity of the hourly imbalance. HUPX fell to its minimum of €76.50/MWh at H14, when solar output was strongest, before climbing to €418.90/MWh at H20. Romania followed the same profile, reaching €433.90/MWh at H20. Slovenia recorded the most pronounced evening spike at €507.60/MWh, while Croatia reached €478.80/MWh and Serbia €496.80/MWh.
Germany, by comparison, peaked at €240/MWh, Austria at €245.40/MWh and Italy’s national market at €267.40/MWh. The evening separation between Central Europe and the Hungary–Romania–western Balkan cluster was therefore substantially larger than the baseload spreads suggest.
This was a scarcity event concentrated around H20, not a general shortage across all delivery hours. It rewarded dispatchable generation, storage and flexible demand capable of responding during the evening transition, while leaving baseload averages increasingly poor indicators of the actual cost faced by industrial consumers with load concentrated after sunset.
Regional electricity consumption was forecast at an average 34,191 MW, an increase of 1,445 MW, or 4.4 per cent, from Monday. The regional temperature increased by almost 1°C, while Greek temperatures were expected to average 28.6°C. Hungary’s demand remained broadly stable at 5,023 MW, but consumption increased in most of the larger SEE systems, including Romania to 5,923 MW, Greece to 7,251 MW, Serbia to 4,030 MW and Croatia to 2,589 MW.
Estimated regional generation rose to 32,604 MW, approximately 5.2 per cent above Monday, allowing net imports to decline from 1,740 MW to 1,587 MW despite higher consumption. Imports nevertheless supplied around 4.6 per cent of total regional demand.
The apparently manageable regional deficit conceals large differences between national systems. Hungary remained the most important structural importer, taking an average 2,269 MW, equivalent to about 45 per cent of its consumption. Croatia imported 1,197 MW, also more than 46 per cent of demand. Serbia’s deficit was 496 MW, Romania imported 437 MW, Montenegro 305 MW, Slovenia 84 MW and Kosovo 142 MW.
Montenegro had the largest relative deficit, with imports covering almost 62 per cent of forecast consumption. Domestic generation was estimated at only 187 MW against demand of 492 MW. The decline in Montenegro’s BELEN price by €36.60/MWh to €159.55/MWh therefore did not reflect improved domestic supply. It resulted from the pricing and availability of surrounding imports, particularly through Bosnia and Herzegovina, Serbia, Albania and the Italian cable.
Bulgaria and Greece formed the main southeastern supply anchors. Bulgaria was expected to export 1,425 MW, equivalent to more than 36 per cent of domestic consumption, while Greece’s net exports reached 1,506 MW, or roughly 21 per cent of its demand. Bosnia and Herzegovina exported 245 MW, North Macedonia 157 MW and Albania a marginal 10 MW.
The flow pattern produced two distinct regional supply axes. Northern imports from Austria and Slovakia into Hungary and Slovenia averaged 2,475 MW, down approximately 7.4 per cent from Monday. At the same time, Bulgaria directed about 1,536 MW towards Romania and 366 MW towards Serbia. Greece exported 456 MW towards Bulgaria, 433 MW towards North Macedonia, 157 MW towards Albania and the full 500 MW scheduled towards Italy.
Romania operated as a transit market as much as a deficit market. It imported heavily from Bulgaria while exporting 953 MW towards Hungary and 237 MW towards Moldova. Romania’s aggregate position was an average net import of 437 MW, but the country switched to a 109 MW net export position during peak hours, while importing almost 984 MW off-peak. The direction of its flows changed substantially across the day as solar output, Bulgarian exports and Hungarian scarcity interacted.
The northern import requirement was concentrated outside the conventional peak block. Hungary’s average import position was 2,269 MW, but imports increased to 3,096 MW off-peak, compared with 1,441 MW during peak hours. In this summer market structure, “off-peak” includes the evening hours after solar production collapses, making the traditional peak/off-peak distinction less useful for assessing system tightness.
The generation mix behind Monday’s market provides the clearest explanation for Tuesday’s pricing. Regional coal generation increased by 1,235 MW to 7,034 MW, gas-fired generation rose by 766 MW to 5,408 MW, and hydro increased by 778 MW to 5,451 MW. Solar output rose to 7,471 MW, but wind generation dropped by 832 MW to only 1,747 MW. Nuclear production remained depressed at 3,348 MW.
Hungary was especially exposed. Its nuclear output averaged only 174 MW on Monday, while gas-fired generation increased to 942 MW. Solar contributed 1,422 MW, half of Hungarian domestic production, but this output was unavailable during the evening price spike. Hungary therefore depended on imports from Slovakia, Austria and Romania while simultaneously maintaining exports towards Croatia and smaller flows towards neighbouring systems.
For Tuesday, regional solar output was forecast at 8,700 MW, an increase of 1,229 MW, or 16.5 per cent, while wind was expected at 1,842 MW, only 95 MW higher. Solar alone was capable of covering approximately 25.4 per cent of average regional consumption, but its concentration around midday explains why stronger renewable production did not prevent prices above €400/MWh in the evening.
The solar forecast supported the common regional minimum of approximately €76.50/MWh at H14 across Hungary, Romania, Slovenia, Croatia, Austria and Germany. Yet the same synchronisation intensified the post-sunset ramp. Systems that could not bring sufficient hydro, nuclear, gas or cross-border imports into the market during H19-H21 experienced the steepest price increases.
Serbia illustrates the distinction between a cheaper baseload price and genuine system security. SEEPEX fell by €10.60/MWh to €174.64/MWh, placing Serbia at a €12.25/MWh discount to HUPX. Its peak price, however, was almost unchanged at €158/MWh, while its maximum hourly price reached €496.80/MWh.
Most of Serbia’s daily price reduction occurred in the off-peak block, which declined from €210.90/MWh to €191.30/MWh. The country remained a net importer of 496 MW, with the deficit widening to 797 MW during peak hours. Bulgaria supplied an average 366 MW and North Macedonia 358 MW, while Serbia exported smaller volumes towards Romania, Montenegro and Croatia.
Serbian coal plants provided 2,944 MW on Monday, representing approximately 79 per cent of the reported domestic generation mix. Hydro recovered to 621 MW from 416 MW on Sunday but remained too weak to restore the flexibility normally available from the Drina and Danube portfolios. Wind production dropped to 110 MW, leaving the system dependent on lignite availability and southeastern imports during the most expensive hours.
The SEEPEX discount should consequently be read as a locational and hourly pricing outcome, rather than evidence of comfortable supply. A market capable of printing an average of €174.64/MWh and a maximum of almost €500/MWh presents substantial shape risk to utilities, suppliers and industrial buyers whose demand is not flat.
Croatia and Slovenia carried an even larger scarcity premium. CROPEX rose by €12.70/MWh to €191.92/MWh, while BSP increased by €14.30/MWh to €194.61/MWh. Croatia imported 1,197 MW against domestic generation of 1,391 MW, relying on an average 672 MW from Slovenia and 424 MW from Hungary. Slovenia, despite a nearly balanced daily position, exported 672 MW to Croatia while importing 720 MW from Austria.
The resulting transit pressure helps explain the €507.60/MWh Slovenian and €478.80/MWh Croatian evening maxima. Slovenia and Croatia were priced above Italy on a baseload basis even though Italy remained the principal regional demand sink, receiving approximately 829 MW from SEE.
Southern SEE avoided the same baseload premium because Greece and Bulgaria retained stronger export capability. HENEX increased only €1.10/MWh to €155.03/MWh, while IBEX declined by €1.10/MWh to €157.03/MWh. Both markets reached evening maxima of about €278/MWh, well below Hungary, Romania, Serbia, Croatia and Slovenia.
Greece’s peak average remained particularly low at €112.20/MWh, supported by solar, wind and a substantial gas-fired fleet. On Monday, Greek gas generation averaged 2,778 MW, solar 3,031 MW, wind 1,396 MW and hydro 792 MW. Bulgaria continued to benefit from approximately 1,890 MW of nuclear generation, alongside coal, solar and cross-border imports from Greece.
North Macedonia’s MEMO price rose by €27.40/MWh to €165.43/MWh, driven by a €34.90/MWh increase in the peak block and stronger exports. The country’s net export position increased from 43 MW to 157 MW, with substantial deliveries towards Serbia and Kosovo. Albania rose by €17.50/MWh to €153.56/MWh, but remained the cheapest SEE market despite returning to a marginal export position.
Fuel markets softened, but not enough to remove the thermal premium from regional electricity. CEGH gas declined by €1.40/MWh to €58.92/MWh, while Greek gas increased to €53.99/MWh. EU carbon allowances eased to €80.86/t, September coal fell to $118/t, and September gas traded at €58.50/MWh.
Hungarian forward power declined across the curve. Week 33 fell by €12/MWh to €182.50/MWh, Week 34 dropped to €159/MWh, September to €167/MWh and the 2026 calendar contract to €122.50/MWh. The €23.50/MWh difference between Week 33 and Week 34 indicates that the market continues to price the present tightness as an acute prompt event rather than a permanent repricing of the forward curve.
The HUPX premium over Germany narrowed by €13.40/MWh to €37.11/MWh, largely because German baseload rose by €21.70/MWh to €149.79/MWh. Hungary’s premium over Greece widened by €7.20/MWh to €31.86/MWh. Forward HU-DE spreads remained elevated at €53.50/MWh for Week 33, €34.50/MWh for Week 34 and €34.50/MWh for September, preserving the value of north-to-southeast transmission exposure.
The immediate trading signal remains concentrated in hourly shape rather than outright baseload direction. Strong solar forecasts support the midday trough, but restricted nuclear availability, limited wind output and drought-sensitive hydro leave H19-H22 exposed to abrupt repricing. Flexible gas units, pumped storage, batteries and interruptible industrial demand retain a disproportionately high value in that window.
Industrial hedging based exclusively on baseload contracts would have left buyers exposed to hourly prices approaching €500/MWh in Serbia, Croatia and Slovenia. The same profile creates a strong capture opportunity for storage and flexible generation, with the spread between the common midday minimum and the evening maximum reaching approximately €342/MWh in Hungary, €357/MWh in Romania, €431/MWh in Slovenia and €427/MWh in Serbia.
The region is producing enough electricity on a daily basis to keep average net imports relatively modest. It is not producing the right volume of dispatchable electricity in the right locations during the evening ramp. That distinction is now setting prices across the SEE market.
