Hungary’s day-ahead electricity premium over Germany widened to almost €75/MWh for Oct. 8 delivery, even as wind and solar generation recovered across Southeast Europe. The divergence highlights how cross-border transmission constraints and outages are increasingly preventing cheaper electricity from reaching the region’s tightest markets.
German day-ahead electricity prices fell €52.68/MWh to €139.35/MWh, while Hungary’s HUPX benchmark increased €3.47 to €214.28/MWh. The resulting €74.93/MWh spread was one of the clearest indications that regional transmission capacity, rather than overall European generation, is becoming a key driver of short-term electricity prices in Southeast Europe.
Austria also traded below Hungary at €188.88/MWh, while scheduled imports into the monitored Hungary-SEE region from Austria and Slovakia declined by around 542 MW to 1.53 GW.
Within Southeast Europe, price movements were mixed. Serbia’s SEEPEX benchmark dropped €18.58/MWh to €179.39/MWh, widening its discount to Hungary to €34.89/MWh even as scheduled net imports increased to around 988 MW.
Montenegro rose €11.39 to €208.80/MWh, Bulgaria gained €9.80 to €208.40/MWh and Albania climbed €9.40 to €221.53/MWh, the highest monitored SEE daily average. Romania was little changed at €209.38/MWh, while Croatia fell to €200.81/MWh and Slovenia to €197.10/MWh. Greece remained cheaper at €165.25/MWh, while North Macedonia averaged €167.78/MWh.
Regional demand increased only modestly, by around 284 MW to 29.94 GW, indicating that the price movements were not primarily driven by consumption. At the same time, supply conditions improved, with forecast wind generation increasing by around 959 MW to 2.32 GW and solar generation rising by 470 MW to 6.12 GW.
Total scheduled generation climbed to approximately 27.94 GW, reducing regional net imports by about 466 MW to 2.00 GW. Romania recorded the largest improvement, with its scheduled import requirement falling from roughly 1.44 GW to 314 MW as forecast generation increased by more than 1 GW to 5.21 GW.
However, the improvement remains vulnerable because Romanian nuclear output is still unavailable. Without Cernavodă generation, the system remains more dependent on weather-sensitive renewable production and electricity imports from neighbouring markets.
Slovenia also recorded a major shift, moving from a roughly 251 MW import position to around 469 MW of scheduled exports. Hungary moved in the opposite direction, with scheduled imports increasing to approximately 1.70 GW as domestic generation declined to around 3.06 GW, reinforcing the country’s reliance on Slovakia, Romania and other neighbouring systems.
Bulgaria remained a major regional electricity exporter, but its scheduled surplus fell sharply to about 826 MW from 1.50 GW. Demand increased while forecast generation declined, adding pressure to a market that is also facing new nuclear operating constraints.
Output from both Kozloduy units 5 and 6 was reduced by around 90 MW each because of critically low Danube water levels. Kozloduy had already been operating unit 5 under a low-water regime, but extending restrictions to both operating reactors increases the regional significance of the situation.
Bulgaria has become one of Romania’s important marginal sources of imported electricity, meaning reduced Kozloduy availability could have wider consequences for regional supply. The development adds another layer of hydrological risk to a market already affected by weak Romanian nuclear availability.
Bosnia and Herzegovina remained an important regional exporter, with scheduled net exports of roughly 386 MW, supplying electricity to Serbia and Montenegro. Croatia continued to import around 703 MW, Albania 148 MW and Montenegro about 30 MW. Greece remained a net exporter, although its scheduled surplus narrowed to approximately 240 MW.
Hourly volatility moderated compared with earlier sessions. Serbia traded between approximately €110.60 and €250.10/MWh, a considerably narrower range than the previous day’s €45.90-295.10/MWh. Hungary ranged from roughly €139.80 to €266.50/MWh, while Greece moved between zero and around €256.60/MWh.
No monitored SEE market recorded a negative day-ahead price. Albania posted the highest regional hourly maximum at approximately €300/MWh, while Montenegro reached around €273/MWh. Although the narrower ranges reduced immediate arbitrage opportunities compared with the extreme volatility seen earlier in October, they did not eliminate the broader value of flexibility.
Repeated daily price swings of more than €100/MWh continue to strengthen the case for batteries, pumped-storage hydropower and active demand-side management, particularly in markets where transmission constraints can amplify differences between neighbouring power exchanges.
Turkey remained a dramatically cheaper source of electricity than the rest of the region. Its provisional day-ahead average was around TRY3,006/MWh, equivalent to approximately €55/MWh. That placed Turkish electricity more than €150/MWh below Bulgaria, yet scheduled exports into Bulgaria remained at only around 100 MW.
The substantial price difference illustrates the economic value of additional cross-border transmission capacity. Cheap generation is available relatively close to Southeast European markets, but existing network limitations prevent enough electricity from reaching higher-priced areas to materially reduce wholesale prices.
A similar pattern can be seen farther north, where Germany’s €139/MWh day-ahead price had limited impact on Hungary, where the market cleared above €214/MWh. The divergence reinforces the growing importance of transmission availability in determining regional price formation.
Hungarian forward prices also strengthened even as German spot electricity prices fell sharply. Week 42 increased to around €216/MWh, November climbed to approximately €219.50/MWh and Calendar 2027 reached about €157.50/MWh.
Higher gas and carbon prices provided additional support, with CEGH gas trading around €78.93/MWh and EU allowances near €85.25/tonne. The forward curve indicates that traders are not expecting Germany’s sharp spot-price decline to automatically translate into sustained relief for Southeast European markets.
Hungary remains heavily dependent on imports, Romania continues to operate without its nuclear generation, and Bulgaria’s export capacity is increasingly exposed to low Danube water levels. Together, these factors are maintaining a structural scarcity premium across parts of the region.
For generators, traders and lenders, the Oct. 8 market reinforces a broader shift already visible across Southeast Europe. Renewable generation is increasing and physical balances can improve rapidly, but the commercial value of electricity is increasingly determined by where it is produced, when it is available and whether the grid can deliver it.
The nearly €75/MWh Hungary-Germany spread demonstrates that in Southeast Europe, transmission scarcity can outweigh even a major decline in neighbouring wholesale electricity prices.
