South-east European day-ahead electricity markets opened September on a firmer footing, with a sharp recovery in Serbian prices and a tightly grouped Hungary-Romania-Bulgaria-Greece cluster reflecting stronger weekday demand, rising regional imports and continued sensitivity to the evening ramp.
Hungary’s HUPX base price settled at €176.74/MWh, up €3.3/MWh day on day. Romania was marginally higher at €177.28/MWh, while Bulgaria and Greece were almost fully aligned at €174.59/MWh and €174.68/MWh, respectively. Albania traded at €174.42/MWh.
Serbia delivered the most pronounced move, with SEEPEX jumping €34/MWh to €166.25/MWh after Monday’s comparatively weak €132/MWh level. Croatia settled at €170.05/MWh, Slovenia at €168.53/MWh, Montenegro at €158.50/MWh and North Macedonia at just €148.46/MWh.
Italy remained the regional premium market at €198.82/MWh, around €22.08/MWh above HUPX, while Germany traded at only €143.80/MWh, leaving Hungary at a €32.94/MWh premium to the German market.
The price map therefore continued to show three distinct layers. Romania, Hungary, Bulgaria, Greece and Albania formed a core cluster around €174-177/MWh. Croatia and Serbia sat roughly €7-11/MWh below Hungary, while Montenegro and North Macedonia remained substantially discounted. At the two external ends of the system, Germany was significantly cheaper and Italy materially more expensive.
That structure continued to encourage a north-to-south and west-to-east transit pattern through central Europe and the Balkans.
The most important balance change was demand. Regional consumption was forecast at 33.27 GW, around 2.40 GW higher day on day. Net imports consequently increased by 614 MW to 2.87 GW, while inflows from the core Austria-Slovakia direction rose by 708 MW to 3.58 GW.
Renewable output also improved sharply, but not enough to absorb the demand increase. Solar generation was forecast to rise by about 1.53 GW to 7.38 GW, while wind increased by roughly 369 MW to 1.46 GW. Combined incremental solar and wind output therefore covered most, but not all, of the increase in consumption.
At the same time, the region was still sending around 1.10 GW towards Italy, up from 1.03 GW the previous day. The SEE system was therefore simultaneously importing heavily from central Europe while exporting into the higher-priced Italian market.
This is an important trading signal. The regional deficit was not simply the result of inadequate aggregate generation. The price structure continued to pull electricity through the system: cheaper northern supply entered through Austria and Slovakia, while the Italian premium drew volumes out of Slovenia, Montenegro and other western Balkan routes.
The German-Hungarian spread narrowed sharply. HUPX’s premium to Germany fell to €32.94/MWh from about €61.6/MWh a day earlier after the German day-ahead market rebounded much more strongly than Hungary.
That narrowing normally reduces the economics of moving marginal power eastwards from Germany. Yet core imports into the SEE-Hungary area still increased to 3.58 GW, indicating that the regional demand recovery outweighed the reduced price differential.
Italy provided the opposite signal. Its almost €199/MWh base price maintained a sufficiently large premium to keep SEE-to-Italy exports above 1 GW.
Evening hours remain the tight point
The hourly curves are more revealing than the daily averages.
HUPX fell as low as around €80/MWh during hour 11, before climbing to a maximum of €276.50/MWh at hour 20. Romania followed an almost identical profile, with its maximum reaching about €283/MWh around hour 20.
The same general shape appeared across Bulgaria, Greece, Croatia and Slovenia: a pronounced daytime trough followed by a steep evening re-pricing as solar production declined.
The charts in the report’s market section show the Hungarian, Romanian, Bulgarian and Greek curves moving almost synchronously through the evening ramp, while Germany remained materially below the eastern markets for much of the day.
This leaves the familiar SEE intraday problem intact. Additional solar is increasingly effective in suppressing prices during daylight hours but does considerably less to solve the system’s scarcity after sunset.
The resulting spread between midday and evening values is becoming at least as important for traders as the spread between national markets.
For flexible generation, batteries and hydro operators, this creates increasingly attractive shifting value. For baseload buyers, however, the daily average understates the cost exposure concentrated in the evening block.
Serbia tightens as demand returns
Serbia was the clearest example of the weekday reset.
Consumption rose to 3.87 GW from 3.57 GW, while domestic generation increased to 3.34 GW from 3.14 GW. The generation increase therefore covered only part of the roughly 291 MW demand rise, and Serbian net imports increased to 521 MW from 434 MW.
Commercial flows show Serbia receiving around 247 MW from Hungary, 218 MW from Bosnia and Herzegovina, 141 MW from Bulgaria and 136 MW from Croatia on a base-load average basis. Serbia simultaneously exported around 120 MW to Montenegro and about 105 MW towards Romania.
That tightening of the Serbian balance coincided with SEEPEX rising by €34/MWh to around €166/MWh.
Serbia nevertheless remained about €10.5/MWh below HUPX. The market therefore moved sharply higher without completely converging with Hungary.
The distinction is important for cross-border traders. Monday’s unusually weak Serbian base price largely disappeared, but there was still value in Hungary-Serbia and Bulgaria-Serbia optimisation where available capacity permitted.
The Serbian curve also displayed a strong evening spike, reaching around €253/MWh, confirming that the day-on-day increase was not simply a higher flat baseload price but reflected much tighter peak-hour conditions.
Romania becomes the eastern balancing risk
Romania remains the more important structural risk to the eastern SEE market.
Its day-ahead price of €177.28/MWh was the highest among the closely coupled Hungary-Romania-Bulgaria-Greece group.
Romanian consumption was around 5.81 GW, against generation of only 4.79 GW, producing net imports of approximately 1.03 GW, compared with 704 MW the previous day.
Most strikingly, the daily balance showed zero nuclear production. Romania was receiving about 746 MW from Hungary and 314 MW from Bulgaria on a base-load flow basis, while maintaining a smaller export towards Moldova.
The deficit is consistent with the continuing loss of Cernavoda nuclear output. Romanian authorities have extended emergency energy measures through September as low Danube levels constrain the nuclear plant and raise the risk of weaker domestic supply during periods of strong demand.
That makes Romania one of the most important variables for the regional market during early September. A prolonged nuclear shortfall can pull additional Hungarian and Bulgarian electricity eastwards, competing with supply that would otherwise be available for Serbia, Croatia or further south.
Bulgaria is currently providing part of that buffer.
Its system remained a significant exporter, with generation of about 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 base-load basis.
The combination helps explain why Bulgarian and Greek prices stayed almost exactly aligned despite substantial bilateral flows.
Hungary remains the regional transit hub
Hungary itself remained a net importer despite trading above most neighbouring SEE markets.
Hungarian demand increased sharply to 4.73 GW, while generation stood at about 3.90 GW, leaving average net imports of 826 MW.
The underlying flows were much larger than that net figure suggests.
Hungary received around 1.62 GW from Slovakia and 837 MW from Austria, while sending approximately 746 MW towards Romania, 707 MW towards Croatia, 311 MW towards Slovenia and 247 MW towards Serbia.
The hourly profile was particularly notable: Hungary was a net importer of almost 2 GW in off-peak hours, but shifted to an average 336 MW net export position during peak hours.
That is increasingly characteristic of the Hungarian market.
HUPX is functioning not simply as a deficit market but as a redistribution hub between cheaper northern supply and higher-value eastern and southern destinations. This means the HUPX price can remain at a sizeable premium to Germany even while Hungary imports substantial volumes from Austria and Slovakia.
Montenegro retains Italian export value
Further south, Montenegro remained one of the cheapest SEE markets at €158.50/MWh, a discount of more than €18/MWh to HUPX and roughly €40/MWh to Italy.
Montenegro nevertheless recorded a small net export position of about 79 MW, with generation around 535 MW against consumption of 456 MW.
Its commercial flows illustrate the importance of transit rather than the national balance alone. Around 516 MW was scheduled from Montenegro towards Italy, while Montenegro simultaneously received approximately 328 MW from Bosnia and Herzegovina and 120 MW from Serbia.
The Italy-Montenegro spread therefore remains one of the stronger physical trading signals in the region, provided interconnector capacity is secured.
Forward market adds risk premium
The forward curve suggests traders are not treating the current tightness as a purely one-day event.
Hungarian Week 37 power was assessed at €175.50/MWh, up 16.2% over seven days, while Week 38 stood at €179.50/MWh, around 9.1% higher over the same period.
Hungarian October power reached €181/MWh, compared with €173.50/MWh on 28 August, while Cal-27 base increased to €137.50/MWh.
The geographical forward stack remains pronounced. Week 37 Germany was around €139/MWh, Hungary €175.50/MWh and Italy €203.50/MWh, leaving Hungary about €36.50/MWh above Germany but approximately €28/MWh below Italy.
The configuration closely mirrors the day-ahead market and reinforces the role of Hungary as the price bridge between cheaper central-western Europe and premium southern markets.
Fuel markets are adding to that risk premium.
CEGH gas was around €69/MWh, the October forward near €71/MWh, Q1 2027 around €69/MWh, while EU carbon allowances were assessed near €83.1/t and October coal around €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 one of higher prices but of wider intraday optionality.
Strong solar output should continue to limit the midday market, but the return of weekday demand, Romania’s nuclear deficit, elevated gas prices and persistent Italian import pull leave the evening block exposed.
The key trading indicators for the next 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 move towards Italy, the regional system has relatively little room for an additional supply shock before evening prices reprice sharply higher.