Southeast European day-ahead electricity markets started September on a firmer footing, with Serbian prices recording a sharp recovery and the Hungary-Romania-Bulgaria-Greece cluster remaining tightly aligned. The market structure reflected stronger weekday demand, increased regional imports and continued sensitivity to the evening ramp, as solar generation declined later in the day.
Hungary’s HUPX base price settled at €176.74/MWh, an increase of €3.3/MWh from the previous day. Romania was marginally higher at €177.28/MWh, while Bulgaria and Greece remained almost fully aligned at €174.59/MWh and €174.68/MWh, respectively. Albania traded at €174.42/MWh, keeping the core regional markets within a relatively narrow price range.
Serbia recorded the largest day-on-day increase, with SEEPEX rising by €34/MWh to €166.25/MWh after Monday’s comparatively low level of €132/MWh. Croatia settled at €170.05/MWh, Slovenia at €168.53/MWh, Montenegro at €158.50/MWh and North Macedonia at €148.46/MWh.
Italy remained the region’s premium electricity market, with a base price of €198.82/MWh, approximately €22.08/MWh above HUPX. Germany, meanwhile, traded at just €143.80/MWh, leaving Hungary with a €32.94/MWh premium over the German market.
The resulting price map continued to reveal three distinct regional layers. Romania, Hungary, Bulgaria, Greece and Albania formed a core cluster around €174-177/MWh. Croatia and Serbia traded approximately €7-11/MWh below Hungary, while Montenegro and North Macedonia remained significantly cheaper. At the external ends of the regional system, Germany was substantially cheaper, while Italy remained considerably more expensive.
This price structure continued to encourage north-to-south and west-to-east electricity flows through Central Europe and the Balkans. Lower-priced northern supply continued moving into the SEE region, while higher prices in Italy maintained demand for electricity flowing south and west.
Demand and renewable generation
The most significant change in the regional balance came from stronger electricity demand. Regional consumption was forecast at 33.27 GW, approximately 2.40 GW higher than the previous day. Net imports consequently increased by 614 MW to 2.87 GW, while inflows from the Austria-Slovakia direction rose by 708 MW to 3.58 GW.
Renewable generation also increased substantially, but the additional output was not sufficient to fully offset the rise in consumption. Solar generation was forecast to increase by around 1.53 GW to 7.38 GW, while wind production rose by approximately 369 MW to 1.46 GW. Together, the additional solar and wind generation covered most, but not all, of the increase in regional demand.
At the same time, the SEE region continued to send around 1.10 GW towards Italy, up from approximately 1.03 GW on the previous day. The region was therefore simultaneously importing significant volumes from Central Europe while exporting electricity to the higher-priced Italian market.
This configuration provides an important trading signal. The regional deficit was not simply caused by insufficient overall generation. Instead, the price structure continued to pull electricity through the system, with cheaper northern supply entering via Austria and Slovakia while Italy’s premium prices attracted exports from Slovenia, Montenegro and other western Balkan routes.
German-Hungarian spread narrows
The German-Hungarian price spread narrowed sharply, with HUPX’s premium over Germany falling to €32.94/MWh from approximately €61.6/MWh a day earlier. The change followed a stronger rebound in the German day-ahead market compared with Hungary.
Under normal conditions, a narrower spread would reduce the economic incentive to move marginal electricity eastwards from Germany. However, core imports into the SEE-Hungary area still increased to 3.58 GW, indicating that the recovery in regional demand outweighed the impact of the smaller price differential.
Italy provided the opposite market signal. Its nearly €199/MWh base price maintained a sufficiently large premium to support SEE-to-Italy exports above 1 GW, keeping the western and southern transmission corridors commercially attractive.
Evening hours remain the tight point
The hourly price curves provide a clearer picture of market tightness than daily averages. HUPX prices fell to around €80/MWh during hour 11 before climbing sharply to a maximum of €276.50/MWh at hour 20. Romania followed a very similar pattern, with prices reaching approximately €283/MWh around hour 20.
A similar profile was visible in Bulgaria, Greece, Croatia and Slovenia, with prices falling substantially during daylight hours before increasing sharply during the evening ramp as solar generation declined.
The synchronized movement of the Hungarian, Romanian, Bulgarian and Greek markets during the evening hours highlights a persistent SEE market constraint. Germany remained materially cheaper than the eastern markets for much of the day, reinforcing the importance of cross-border flows during periods of tighter regional supply.
The key issue for traders is that additional solar capacity is highly effective at reducing daytime prices but has a much smaller impact after sunset. As a result, the spread between midday and evening prices is becoming increasingly important alongside traditional cross-border price differentials.
For flexible generation, battery storage and hydro operators, this creates greater value in shifting electricity from low-price daytime periods into the evening. For baseload consumers, however, daily average prices can underestimate the exposure created by elevated evening prices.
Serbia tightens as demand returns
Serbia provided the clearest example of the weekday market reset. Electricity consumption increased to 3.87 GW from 3.57 GW, while domestic generation rose to 3.34 GW from 3.14 GW. The increase in generation therefore covered only part of the approximately 291 MW rise in demand, causing Serbian net imports to increase to 521 MW from 434 MW.
Commercial flows showed Serbia receiving around 247 MW from Hungary, 218 MW from Bosnia and Herzegovina, 141 MW from Bulgaria and 136 MW from Croatia on a baseload average basis. At the same time, Serbia exported approximately 120 MW to Montenegro and around 105 MW towards Romania.
The tightening Serbian balance coincided with SEEPEX rising by €34/MWh to €166.25/MWh. Despite the sharp increase, Serbia remained approximately €10.5/MWh below HUPX, indicating that the market strengthened without fully converging with Hungary.
For cross-border traders, this distinction remains important. Monday’s unusually weak Serbian price largely disappeared, but opportunities remained in Hungary-Serbia and Bulgaria-Serbia optimisation where available transmission capacity allowed.
Serbia’s hourly curve also showed a pronounced evening price spike, reaching around €253/MWh. This confirms that the day-on-day increase was not simply a higher baseload price but reflected significantly tighter conditions during peak hours.
Romania becomes the eastern balancing risk
Romania remains one of the most important structural risks for the eastern SEE market. Its day-ahead price reached €177.28/MWh, making it the highest-priced market within the closely connected Hungary-Romania-Bulgaria-Greece group.
Romanian electricity consumption stood at around 5.81 GW, while generation reached only 4.79 GW, resulting in net imports of approximately 1.03 GW, compared with 704 MW the previous day.
The most notable feature of the Romanian balance was zero nuclear production. Romania received approximately 746 MW from Hungary and 314 MW from Bulgaria on a baseload flow basis, while maintaining a smaller export flow towards Moldova.
The deficit is consistent with the continuing loss of Cernavoda nuclear output. Romanian authorities have extended emergency energy measures into September as low Danube water levels constrain nuclear generation and increase the risk of weaker domestic supply during periods of strong demand.
This makes Romania a key variable for the regional market in early September. A prolonged nuclear outage could pull additional electricity from Hungary and Bulgaria towards the east, competing with supply that would otherwise be available for Serbia, Croatia and other southern markets.
Bulgaria is currently providing part of that regional supply buffer. Its system remained a significant exporter, with generation of approximately 4.97 GW against consumption of 4.02 GW, leaving net exports close to 954 MW.
Commercial schedules included approximately 314 MW towards Romania, 141 MW towards Serbia, 124 MW towards North Macedonia and 475 MW towards Greece on a baseload basis. These flows help explain why Bulgarian and Greek prices remained almost perfectly aligned despite substantial bilateral electricity transfers.
Hungary remains the regional transit hub
Hungary continued to operate as a major regional transit hub, remaining a net importer despite trading above several neighboring SEE markets. Hungarian demand increased to 4.73 GW, while generation stood at approximately 3.90 GW, leaving average net imports of around 826 MW.
The underlying cross-border flows were considerably larger than the net figure suggests. Hungary received approximately 1.62 GW from Slovakia and 837 MW from Austria, while sending around 746 MW towards Romania, 707 MW towards Croatia, 311 MW towards Slovenia and 247 MW towards Serbia.
The hourly balance was particularly notable. Hungary was a net importer of almost 2 GW during off-peak hours, but shifted to an average net export position of approximately 336 MW during peak periods.
This pattern is becoming increasingly characteristic of the Hungarian market. HUPX is functioning not only as a deficit market but also as a redistribution hub, connecting lower-cost northern supply with higher-value destinations in eastern and southern Europe.
Montenegro retains Italian export value
Further south, Montenegro remained one of the cheapest SEE markets, with a price of €158.50/MWh. This represented a discount of more than €18/MWh to HUPX and approximately €40/MWh to Italy.
Despite its lower price, Montenegro maintained a small net export position of approximately 79 MW, with generation around 535 MW against consumption of 456 MW.
Its commercial flows highlight the importance of transit economics rather than the domestic balance alone. Approximately 516 MW was scheduled from Montenegro towards Italy, while the country simultaneously received around 328 MW from Bosnia and Herzegovina and 120 MW from Serbia.
The substantial Italy-Montenegro price differential therefore remains one of the strongest physical trading signals in the region, provided sufficient interconnector capacity is available.
Forward market adds risk premium
The forward electricity market indicates that traders are not treating the current tightness as a one-day phenomenon. Hungarian Week 37 power was assessed at €175.50/MWh, up 16.2% over seven days, while Week 38 stood at €179.50/MWh, approximately 9.1% higher over the same period.
Hungarian October power reached €181/MWh, compared with €173.50/MWh on August 28, while Cal-27 baseload increased to €137.50/MWh.
The geographical forward price structure remains pronounced. Week 37 Germany was around €139/MWh, Hungary €175.50/MWh and Italy €203.50/MWh, leaving Hungary approximately €36.50/MWh above Germany but around €28/MWh below Italy.
This configuration closely mirrors the day-ahead market structure and reinforces Hungary’s role as the price bridge between lower-priced Central and Western European markets and premium southern markets.
Fuel markets are also contributing to the regional risk premium. CEGH gas was around €69/MWh, with October gas near €71/MWh and Q1 2027 around €69/MWh. EU carbon allowances were assessed at approximately €83.1/t, while October coal stood near €133.50/t. Hungarian Week 37, Week 38 and October power all strengthened in the latest session.
For the SEE power complex, the immediate signal is therefore not simply higher electricity prices, but greater intraday price optionality. Strong solar generation should continue to suppress prices during daylight hours, while the return of weekday demand, Romania’s nuclear deficit, elevated gas prices and continued Italian import demand leave the evening market particularly exposed.
The key indicators for the coming sessions will be the HUPX-Germany spread, Romanian net imports, Austria-Slovakia inflows into Hungary, the Serbia-Hungary differential and the Italian premium. With core imports already above 3.5 GW while more than 1 GW continues to flow towards Italy, the regional system has limited room for an additional supply disruption before evening prices could reprice sharply higher.
