Electricity prices across southeastern Europe increased sharply for Monday, October 12, as demand rebounded after the weekend and forecast wind generation fell. The change lifted Serbian prices above €230/MWh and pushed Hungary, Romania and Bulgaria towards €235/MWh. The higher level of spot pricing translated into increased procurement costs for suppliers and industrial buyers.
Forward market indications suggested traders expected expensive electricity to extend beyond Monday. Hungary’s week 42 contract settled at €244.50/MWh, with week 43 close behind at €244/MWh. The forward pricing changes were cited alongside the rise in regional day-ahead averages.
Day-ahead price moves in Serbia, Montenegro, Bulgaria, Romania and Hungary
Serbia’s SEEPEX day-ahead average climbed by €45.20/MWh to €230.76/MWh, leaving it €4.12/MWh below Hungary. Montenegro’s BELEN increased by €43.10/MWh to €208.46/MWh, maintaining a discount of €26.42/MWh versus the Hungarian benchmark.
Bulgaria’s IBEX recorded the highest regional average at €235.50/MWh, up €60.30/MWh. Romania’s OPCOM followed at €235.29/MWh, an increase of €59.20/MWh, while Hungary’s HUPX rose by €48.80/MWh to €234.88/MWh. The three markets were separated by less than €1/MWh based on their daily averages.
The narrow gap between daily averages left limited room for trading margins based only on average price differences. Hourly spreads and transmission availability were identified as factors that would determine whether specific cross-border trades remained attractive.
Regional price increases beyond the core SEE exchanges
Prices rose in other markets as well, with Croatia reaching €226.98/MWh and Slovenia at €224.94/MWh. Both markets increased by €53.30/MWh. Greece gained €58.90/MWh to €218.04/MWh.
Albania rose to €222.35/MWh, while North Macedonia remained the lowest in the regional comparison at €198.47/MWh, up €7.60/MWh.
Demand recovery and wind output decline shape the supply outlook
The supply-demand outlook shifted with higher consumption alongside lower wind output forecasts. Forecast average demand across Hungary and SEE coverage increased by 3,605 MW to 30,588 MW, about 13.4% above Sunday. Forecast wind generation fell by 2,358 MW to 1,397 MW, a decline of nearly 63%.
Solar output was expected to rise by 1,219 MW to 4,379 MW, offsetting part of the wind reduction. Combined wind and solar generation nonetheless fell by about 1,139 MW. With demand higher than Sunday, the forecasts implied around 4,744 MW more supply would need to come from other generation or imports.
Regional net imports increased only 300 MW to 3,719 MW. Imports through monitored Austria–Slovakia routes into Hungary and Slovenia rose by 395 MW to 3,140 MW. The figures indicated that additional imports alone would not fully cover the change in demand and renewable availability.
Germany pricing, Hungarian premiums and forward spreads; gas and carbon costs
The price increase extended beyond southeastern Europe into Germany’s day-ahead market. Germany’s day-ahead average jumped by €74.90/MWh to €197.23/MWh, exceeding Hungary’s daily rise. As a result, Hungary’s premium over Germany narrowed by €26.10/MWh to €37.65/MWh.
The daily-average narrowing did not establish conditions for individual borders or specific hours because it reflected overall differentials rather than hourly transmission outcomes.
Forward markets showed a firmer regional premium for Hungary versus Germany, with Hungary’s week 42 spread widening to €75.50/MWh. Week 43 reached €70/MWh, while Hungarian November power rose by €4.50/MWh to €231.50/MWh.
Gas prices added to cost pressure in parallel with electricity moves. Austrian CEGH gas stood at €80.80/MWh, while November gas increased by €2.50/MWh to €83/MWh. Carbon allowances were unchanged at €86.94 per tonne.
For Serbian buyers, immediate exposure was electricity priced close to Hungary, Romania and Bulgaria levels discussed for Monday trading. Montenegro retained a meaningful discount versus the Hungarian benchmark, but Monday’s increase illustrated how quickly procurement costs can rise when working-day demand returns alongside weaker wind supply forecasts.