Day-ahead electricity prices for 8 November delivery fell 16.4% in Greece and 10.1% in Serbia, while Montenegro retained a premium over neighbouring markets. A regional day-ahead assessment available at 08:51 CET showed Romania’s Cernavodă Unit 1 had reconnected to the grid on 6 November as prices eased across the region.
The assessment covered delivery from 00:00 to 24:00 CET on 8 November 2026 and compared prices with Saturday, 7 November. Prices were fixed before delivery, so they do not represent intraday transactions or realised system conditions. The preceding Sunday, 1 November, is a separate weekend comparison.
Greece’s HEnEx averaged €208.82/MWh, down €40.82/MWh, or 16.4%, from €249.64/MWh on Saturday and 20.3% below 1 November. Hungary’s premium over Greece widened to €42.86/MWh from €14.42/MWh on Saturday. The wider differential increased the potential gross spread for northbound sourcing, although executable margins depended on delivery intervals, transmission access and associated costs.
Serbia’s SEEPEX averaged €246.83/MWh, down €27.69/MWh, or 10.1%, from €274.52/MWh on Saturday and 5.6% below 1 November. The Sunday benchmark was also below Friday’s €307.65/MWh. Hungary’s HUPX averaged €251.68/MWh, down 4.7% from €264.06/MWh.
Serbia shifted from a €10.46/MWh premium over Hungary on Saturday to a €4.86/MWh discount on Sunday. The reversal reduced the Serbian premium evident on Saturday for suppliers hedging Serbian obligations through Hungarian contracts, showing that the relationship between a delivery market and a hedging reference can reverse quickly.
Montenegro’s BELEN averaged €264.22/MWh, down 5.3% from €279.04/MWh on Saturday. Its premium over SEEPEX widened to €17.39/MWh from €4.52/MWh, although its price was 1.5% below the preceding Sunday. Serbia’s Sunday interval prices ranged from €165.24/MWh to €323.81/MWh, compared with €218.08/MWh to €328.07/MWh in Montenegro. Lower daily averages did not eliminate the cost of replacing electricity during expensive intervals.
Regional prices and generation
Romania’s OPCOM averaged €250.89/MWh, down 4.9% from €263.80/MWh on Saturday. Bulgaria’s IBEX averaged €250.85/MWh, down 3.3% from €259.49/MWh, leaving the two markets almost level and both above Serbia. Croatia’s CROPEX averaged €249.07/MWh, down 5.4%, while Slovenia’s BSP averaged €248.29/MWh, down 5.6%.
Austria averaged €246.51/MWh, down 6.3%, and the northern Italian IPEX bidding zone averaged €243.21/MWh, down 5.9%. Montenegro’s premium over northern Italy remained approximately €21/MWh and was little changed from Saturday. The spread provides a reference for Adriatic sourcing economics but does not establish unused interconnector capacity or the profitability of individual transactions.
Germany’s benchmark averaged €242.13/MWh, down 6.8%. Hungary’s premium over Germany widened to €9.55/MWh from €4.23/MWh on Saturday, but remained modest compared with the much larger differentials observed during October. The assessment used complete quarter-hourly delivery-price observations to calculate time-weighted daily averages, rather than transaction-volume-weighted averages.
Nuclearelectrica operates Romania’s Cernavodă nuclear plant, where Unit 1 was reconnected to the grid on the afternoon of 6 November. Romanian nuclear output averaged approximately 253 MW on 7 November, and the latest available observation reached 524 MW at 07:00 CET on 8 November. The readings indicated increasing production but did not establish sustained full-load operation or a return of Unit 2.
Additional Romanian generation can reduce replacement-import requirements and improve regional supply availability, but its precise contribution to Sunday’s price decline could not be separated from weekend demand, renewable conditions and other changes. In Slovenia, Šoštanj Unit 6 could again operate without restrictions after repairs and successful start-up tests supervised by GE, according to an operational update dated 7 November. Further turbine work remains necessary next year, while the cause of the failure and total repair costs were still being assessed.
Operational data and market developments
The latest verified regional operational figures showed consumption of 35,067 MW and net imports of 5,094 MW on 5 November. Estimates for 6 November were forecasts at the time, not realised outcomes. Current Sunday demand, wind, solar and hydro comparisons were unavailable across the full region.
Bosnia and Herzegovina’s latest reported operational balance showed approximately 39 MW of net imports on 5 November; a verified Sunday balance was unavailable. The latest verified weekday commercial schedules showed 100 MW of Turkish exports into Bulgaria on 6 November. Sunday schedules and available cross-border capacity for Turkey were not verified, and earlier flows and current price differences were insufficient to identify binding transmission constraints.
Sunday prices could not be independently verified for Albania’s ALPEX or North Macedonia’s MEMO. The latest verified 6 November delivery prices were €322.58/MWh on ALPEX and €307.62/MWh on MEMO, not Sunday market levels. ALPEX’s consultation on proposed revisions to its market rules closed on 8 November. The proposals covered general conditions, trading, clearing and settlement procedures, and definitions; they remained proposals rather than confirmed effective rules.
No negative-price intervals appeared in the complete Sunday series for Serbia, Montenegro, Hungary, Romania, Bulgaria, Greece, Croatia, Slovenia, Austria or northern Italy, nor in those markets’ Saturday series. Greece’s lowest Sunday observation was €0.01/MWh, close to zero but still positive. The absence of negative prices did not remove opportunities for storage.
Croatia’s 60 MW/120 MWh BESS Šibenik was developed through NextGrid Energy using NGEN technology. Its entire capacity had been dedicated to HOPS automatic frequency-restoration reserve since September, so the opening ceremony on 4 November did not mark an additional 60 MW entering service that day. The battery received support from the EU Modernisation Fund alongside equity from EBRD, Raiffeisen pension funds and IE-ENERGY, while retaining market revenue risk.
