Electricity prices across Southeast Europe rose sharply for delivery on October 15, with Hungary and Serbia trading above €250/MWh as changing electricity balances in Romania, stronger regional demand and lower forecast wind generation increased pressure on cross-border markets.
Hungary’s HUPX day-ahead baseload price climbed by €28.9/MWh to €252.81/MWh, while Serbia’s SEEPEX increased by €18.1/MWh to €252.74/MWh, leaving the two markets almost perfectly aligned. Romania’s OPCOM rose by €26.8/MWh to €248.44/MWh, while Bulgaria’s IBEX gained €18.8/MWh to €233.29/MWh.
Albania recorded the largest daily increase, with ALPEX prices jumping by €113.6/MWh to €249.56/MWh, bringing the market close to price levels in Serbia and Hungary. Montenegro’s BELEN rose by €14/MWh to €223.17/MWh, while North Macedonia’s MEMO reached €222.30/MWh.
The latest trading session highlighted a widening divide between expensive Central and Eastern European electricity markets and the comparatively cheaper Greek market, where greater renewable energy availability continued to weigh on daytime prices.
Romania’s import reversal reshapes regional electricity balances
Romania recorded one of the most significant changes in regional electricity trading, shifting from scheduled net exports of 749 MW on October 14 to net imports of 629 MW on October 15. The 1,378 MW reversal substantially altered the country’s average daily electricity balance.
Romanian electricity consumption increased from 5,724 MW to 6,096 MW, while forecast domestic generation declined from 6,473 MW to 5,467 MW. The combination of higher demand and lower domestic output significantly increased Romania’s reliance on electricity imports from neighbouring markets, particularly Bulgaria.
Scheduled commercial flows from Bulgaria to Romania rose to approximately 1,278 MW, compared with 657 MW a day earlier. At the same time, Romanian exports to Hungary dropped sharply from 1,213 MW to just 121 MW.
These changing flows affected electricity availability across Central Europe and contributed to the stronger price relationship between Romania and Hungary.
Across Hungary and the wider Southeast European region, net electricity imports increased by 565 MW to 2,267 MW, against forecast consumption of 32,017 MW, up 749 MW day on day.
Imports from Austria and Slovakia towards Hungary and Slovenia reached 2,661 MW, an increase of 890 MW, highlighting the region’s continued dependence on northern and western electricity supply corridors.
Serbia remains a major import market despite stronger domestic generation
Serbia continued to face a substantial electricity deficit, although higher domestic generation reduced its scheduled import requirement.
Forecast electricity consumption increased to 3,975 MW, compared with 3,820 MW the previous day. Domestic generation rose from 2,628 MW to 2,948 MW, reducing net imports from 1,192 MW to 1,027 MW.
Commercial schedules indicated that Serbia was expected to import an average of approximately 370 MW from Bulgaria, 354 MW from North Macedonia, 293 MW from Bosnia and Herzegovina, 214 MW from Romania and 183 MW from Montenegro.
At the same time, Serbia was scheduled to export 476 MW to Hungary, underlining its importance in regional electricity trading and transit arrangements.
Despite stronger domestic generation, Serbia’s wholesale electricity price remained among the highest in the region. SEEPEX recorded an hourly maximum of €368.6/MWh at hour 20, compared with a minimum of €189.9/MWh at hour 14.
The nearly €179/MWh intraday price difference illustrates the potential commercial value of flexible generation, demand response and battery energy storage, particularly for market participants able to shift electricity consumption or delivery from lower-priced daytime periods to evening demand peaks.
Montenegro maintains a price discount against Serbia and Hungary
Montenegro retained a modest net export position as both domestic electricity consumption and generation declined.
Average demand fell from 420 MW to 362 MW, while generation decreased from 456 MW to 378 MW. The system was therefore scheduled to record net exports of approximately 16 MW, down from 36 MW the previous day.
BELEN’s baseload price of €223.17/MWh represented a discount of approximately €29.57/MWh against Serbia and €29.64/MWh against Hungary.
Montenegro’s trading position continued to reflect the importance of its cross-border infrastructure. Commercial schedules indicated average imports of approximately 192 MW from Italy, alongside exports of 183 MW to Serbia.
The contrast between daily average prices and scheduled electricity flows highlights a key trading consideration: profitable cross-border positions cannot be assessed using baseload price spreads alone. Hourly price differences, allocated transmission capacity, contracted delivery positions and congestion charges remain decisive factors.
For traders operating between Montenegro, Italy and Serbia, the distribution of hourly price spreads may be more important than the average daily price differential.
Greek renewable generation widens the north-south price gap
Greece remained the region’s principal lower-priced electricity market, with its HENEX day-ahead baseload price averaging €160.54/MWh, despite increasing by €21.6/MWh from the previous session.
The Hungarian premium over Greece widened to €92.28/MWh, while the Hungarian-German spread increased to €65.51/MWh, compared with approximately €44.9/MWh a day earlier.
German baseload prices rose more moderately to €187.30/MWh, reinforcing the divergence between Germany and higher-priced Southeast European markets.
Greek electricity prices fell to zero during hour 14 before recovering to an evening maximum of €296.5/MWh. The average peak-period price of €97.3/MWh remained well below the off-peak average of €223.7/MWh, reflecting pronounced daytime price weakness.
Greece was scheduled to export approximately 1,700 MW on a net basis, including substantial electricity flows towards Bulgaria and North Macedonia.
Bulgaria also shifted from net imports of 74 MW to net exports of 717 MW, supported by a marked increase in forecast generation.
These flows demonstrate the growing influence of renewable generation in southern Europe on regional electricity trading. However, existing interconnections remain insufficient to eliminate substantial price differences between neighbouring electricity markets.
Solar generation recovery fails to fully offset lower wind output
Regional renewable forecasts indicated a significant change in the electricity generation mix.
Average solar generation was forecast to reach 5,932 MW, an increase of 2,631 MW from the previous day. Wind generation, however, was expected to decline by 1,571 MW to 5,114 MW.
The increase in combined renewable output therefore provided only a partial offset to changes in demand and generation from other sources.
This changing balance helps explain why stronger solar availability did not prevent a broad increase in day-ahead baseload prices. Higher solar generation can depress hourly prices around midday without materially reducing evening scarcity or the need for dispatchable generation capacity.
For renewable energy producers, these market conditions increase the importance of capture-price management, accurate generation forecasting and storage integration.
For utilities and large industrial consumers, the price movements reinforce the distinction between securing electricity volumes through conventional power purchase agreements and managing actual hourly exposure to market prices.
Forward markets maintain a significant Hungarian premium
Forward electricity markets continued to reflect substantial regional risk premiums.
Hungary’s week-43 forward baseload contract increased to €270/MWh, compared with €201.50/MWh for the corresponding German contract, producing a premium of €68.50/MWh.
Hungary’s November baseload contract stood at €242.50/MWh, against €195/MWh in Germany. The Hungarian calendar-year 2027 baseload contract was quoted at €168.50/MWh, compared with €145.50/MWh in Germany.
The wider forward premium suggests that traders continue to price regional supply risks, fuel costs and interconnection constraints beyond immediate day-ahead volatility.
EU carbon allowances were quoted at approximately €87.14 per tonne, slightly lower on the day, while November coal futures declined to €148 per tonne.
The modest easing in carbon and coal prices was insufficient to prevent the sharp increase in regional spot electricity prices, indicating that physical supply-demand balances and transmission conditions remained important immediate price drivers.
Energy storage investment gains commercial relevance
Sharp hourly price differences are strengthening the investment case for flexible electricity assets, particularly battery energy storage systems capable of combining wholesale market arbitrage with balancing and ancillary services.
Romania is emerging as one of the more active regional markets. Helleniq Energy plans to develop at least 500 MW of battery storage capacity over the next three years, while R.Power is advancing a standalone battery project rated at 100 MW/200 MWh in Studina alongside its larger Scornicesti development.
Such projects could provide additional flexibility during periods when renewable generation and electricity demand become increasingly misaligned.
However, wide spot price spreads do not automatically translate into bankable storage revenues. Investors must account for round-trip efficiency, battery degradation, network charges, imbalance settlement, trading restrictions and the possibility that additional storage capacity will gradually compress the price spreads underpinning investment assumptions.
The October 15 trading session points to a regional electricity market increasingly characterised by strong price alignment between Serbia and Hungary, substantial north-south price differences and rapidly changing import requirements.
For electricity traders, generators and industrial buyers, the challenge is no longer limited to securing sufficient annual electricity volumes. It increasingly involves managing the hourly timing, location and flexibility of supply in a market where renewable generation can push prices lower during the day, while rising demand and transmission constraints can restore scarcity within hours.
