Albania’s ALPEX day-ahead price fell almost 19% to €307.15/MWh for delivery on 10 November 2026, while Romania, Bulgaria and Hungary rose above €400/MWh. The comparison of exchange prices shows regional spreads widening, including larger discounts for buyers in Serbia and Montenegro against Hungary.
Price movements widen regional gaps
ALPEX, Albania’s electricity exchange, recorded the largest daily movement among the markets reviewed, with its price down from €377.35/MWh for 9 November delivery. Both delivery days were working days, separating Tuesday’s price movements from Monday’s rebound after the weekend; full-day operating outcomes for Tuesday were still incomplete.
Romania’s OPCOM day-ahead price rose 5.7% to €410.31/MWh, Bulgaria’s IBEX gained 8.4% to €402.60/MWh, and Hungary’s HUPX increased 7.3% to €400.29/MWh. Serbia’s SEEPEX rose 2.4% to €360.85/MWh, while Montenegro’s BELEN gained 2.2% to €353.21/MWh.
Serbia’s discount to Hungary widened to €39.44/MWh from €20.68/MWh, while Montenegro’s grew to approximately €47.09/MWh from €27.58/MWh. Montenegro’s price was €7.64/MWh below Serbia’s, reversing the relationship during the previous completed week, when Montenegro’s average price was higher.
Average prices rose in Serbia, Montenegro and Hungary even as their maximum quarter-hour prices declined. Serbia’s most expensive quarter-hour fell to €477.99/MWh from €580.01/MWh, Montenegro’s to €475/MWh from €500/MWh, and Hungary’s to €562.88/MWh from €634.88/MWh, leaving buyers with higher average procurement costs but more moderate sharpest price spikes.
Greece’s HEnEx day-ahead price fell 3.4% to €337.91/MWh, and North Macedonia’s MEMO declined approximately 4.2% to €349.49/MWh. Hungary’s premium over Greece widened to approximately €62.39/MWh from €23.22/MWh.
Croatia’s CROPEX price rose 4.9% to €389.02/MWh, Slovenia’s BSP/ADEX increased 4.3% to €384.41/MWh, and Austria’s day-ahead price gained 5.6% to €378.15/MWh. Italy’s IPEX Italian North zone price fell 3.2% to €310.16/MWh, widening Montenegro’s premium over the benchmark to €43.05/MWh.
That Montenegro–Italian North spread does not by itself establish an executable return across the Adriatic: realising it depends on transmission access, losses and the relevant Italian landing-zone price.
Demand, imports and Romanian supply
Provisional regional operating figures for 9 November put average demand at 36,192 MW and net imports at 4,777 MW. Wind generation was 1,472 MW, solar output 2,554 MW, gas-fired production 8,818 MW and hydro generation 5,620 MW. Dispatchable generation helped meet the return of weekday demand as renewable output weakened from Sunday.
Tuesday forecasts indicated consumption of 36,337 MW, solar generation of 2,951 MW and wind output of 1,511 MW. Scheduled regional net imports declined to 4,130 MW, but the change was uneven across markets.
Hungary’s scheduled import requirement increased to 2,204 MW from 1,635 MW. Serbia’s scheduled imports declined to 708 MW from 789 MW, while Montenegro’s fell to 13 MW from 63 MW; Montenegro also scheduled approximately 593 MW of imports from Italy, reflecting its role as a transit market as well as its domestic supply needs.
Bosnia and Herzegovina’s scheduled net exports increased to 180 MW from 102 MW. Turkey’s scheduled contribution to the regional aggregate fell to approximately 46 MW from 150 MW, and its scheduled exports to Bulgaria dropped to zero. Comparable Turkish wholesale prices consistently converted into euros were unavailable.
Nuclearelectrica confirmed that Cernavodă Unit 1 disconnected on the evening of 9 November after a fault in the Romanian plant’s conventional section. Repairs were continuing, but no firm restart time had been given.
The unit disconnected after Tuesday’s day-ahead auction, creating a subsequent intraday and balancing risk, but the timing does not show that the outage caused the auction’s higher cleared prices. An earlier company disclosure forecast Cernavodă Unit 2 synchronisation on 10 November and nominal output on 11 November, after water conditions became sufficient for restart.
At the time the figures were prepared, neither Unit 2’s synchronisation nor its full output had been verified, while Unit 1’s renewed outage complicated the anticipated recovery. Cernavodă’s reconnection sequence remained the clearest near-term test of whether Romanian supply pressure would ease or create further intraday procurement needs.
Trading considerations
No negative-price intervals appeared in the complete day-ahead series reviewed for Serbia, Montenegro, Hungary, Romania, Bulgaria, Greece, Croatia, Slovenia, Austria and Italian North on 9 or 10 November. Greece’s cheapest Tuesday quarter-hour reached €0.01/MWh.
Comparable daily trading volumes, intraday volume-weighted prices, settled imbalance prices and balancing procurement costs were unavailable. Verified transmission-capacity, congestion and reservoir measurements were also insufficient to quantify their contribution to the price changes.
Wider regional spreads increase the importance for traders and industrial buyers of matching hedges to local delivery exposure and usable transmission capacity. For storage investors, higher average prices alongside lower maximum prices make interval spreads and reserve revenues separate factors to assess.
