Wholesale power prices rose across Southeast Europe from 26 October to 1 November 2026, increasing procurement costs in Serbia and Montenegro. At the same time, the region’s price premium over Germany narrowed sharply, changing cross-border trading margins and hedging exposure ahead of winter. Weekly benchmarks in Serbia, Hungary, Romania and Bulgaria approached €285–287/MWh.
The reporting week ran from Monday, 26 October, through Sunday, 1 November, in Europe/Belgrade time, and was compared with 19–25 October. Time-weighted averages covered 168 delivery hours in the reporting week and 169 hours in the preceding week, which included the clock change. Hungary’s premium over Germany fell almost 60% to €54.39/MWh, largely as German electricity prices rebounded.
Serbia’s SEEPEX averaged €286.55/MWh, up 8.6% from €263.79/MWh. Montenegro’s BELEN rose 8.4% to €273.09/MWh, from €251.81/MWh. Serbia’s premium over Montenegro widened to €13.46/MWh from €11.98/MWh.
The change in the bilateral weekly spread masked larger differences between individual delivery intervals. Serbia’s highest retrieved day-ahead interval reached €499.99/MWh, while Montenegro’s reached €555.09/MWh. For suppliers and generators with delivery commitments, forecast errors or unavailable production can require replacement purchases in the most expensive intervals, pushing costs above those implied by a weekly average.
Price spreads and regional benchmarks
Hungary’s HUPX averaged €284.63/MWh, up 5.9% from €268.78/MWh. Serbia consequently moved to a €1.91/MWh premium over Hungary, having traded €4.99/MWh below it a week earlier. Serbian electricity obligations hedged through Hungarian contracts remain exposed to movements in the difference between the hedge reference and the delivery market, even when the hedge protects against a general price increase.
Germany’s weekly average climbed 71.4% to €230.24/MWh, from €134.35/MWh. Hungary’s premium over Germany narrowed from €134.43/MWh to €54.39/MWh, reducing the average gross price advantage of sourcing against the German benchmark. The remaining spread was still substantial, but executable margins depended on delivery periods, available transmission rights and transaction costs.
Among the complete weekly series assessed, western SEE markets recorded the strongest percentage increases. Slovenia’s BSP rose 15.4% to €267.30/MWh, from €231.56/MWh, while Croatia’s CROPEX increased 14.3% to €270.92/MWh, from €237.03/MWh. Austria gained 15.1% to €266.06/MWh.
The northern Italian IPEX bidding zone rose 7.9% to €267.32/MWh. Montenegro’s premium over that market widened to €5.76/MWh from €4.09/MWh. The spread provides a reference for Adriatic trading, but weekly averages do not determine the direction or profitability of individual transactions through the Montenegro–Italy interconnector.
Further east, Romania’s OPCOM averaged €287.26/MWh, up 11.1% from €258.48/MWh, and Bulgaria’s IBEX increased 11.2% to €284.10/MWh, from €255.49/MWh. Greece’s HEnEx also rose 11.2%, reaching €255.04/MWh against €229.42/MWh previously. Hungary’s premium over Greece narrowed to €29.59/MWh from €39.36/MWh.
Weekday comparisons also showed narrowing differentials in Albania and North Macedonia. ALPEX averaged approximately €287.48/MWh during 26–30 October, compared with €258.12/MWh during 19–23 October, an increase of roughly 11.4%. MEMO’s corresponding average rose approximately 10.8% to €295.38/MWh, from €266.66/MWh; the figures exclude weekends and use rounded daily observations, so they are narrower comparisons than the complete weekly averages reported for other markets.
Regional supply and generation
Operational data showed a more complex supply picture than a straightforward shortfall in renewable generation. Reported regional consumption averaged 33,535 MW during 26–29 October, up 5.7% from the corresponding Monday–Thursday period a week earlier. Net imports rose 8.4% to approximately 4,002 MW.
Wind production recovered 66.3% to approximately 4,449 MW, and hydro generation increased 9.4% to 4,321 MW. Solar output fell 36.1% to approximately 2,987 MW, while gas-fired generation rose 12.4% to approximately 6,161 MW. Higher demand and lower solar output absorbed much of the improvement in wind and hydro availability.
The matched operational comparisons exclude Friday forecasts and do not represent complete weekly generation or reservoir balances. Bulgaria’s import dependence increased: commercial schedules showed average net imports of approximately 504 MW during 26–30 October, compared with 29 MW during 19–23 October. Greece supplied Bulgaria throughout the working week, while Turkey scheduled exports of 100 MW into Bulgaria each weekday.
Bosnia and Herzegovina’s reported weekday net exports recovered to approximately 276 MW from 145 MW, providing additional support. Croatia’s reported weekday imports declined to approximately 573 MW from 863 MW, despite its higher exchange price. A country’s net trading position and wholesale benchmark can move in different directions, and commercial schedules alone do not identify which transmission constraints were binding.
Romanian generation availability remained a concern. A ministry statement reported on 30 October said both Cernavodă reactors remained in safe shutdown, while an emergency alert was extended by 30 days on 28 October amid concerns about sufficient reserves during peak consumption. The previously discussed 1 November restart assumption had not become confirmed operating availability; reporting during the week instead indicated a possible mid-November return of one reactor, conditional on Danube flows.
Infrastructure and market developments
No negative prices appeared in the complete retrieved weekly series for Serbia, Montenegro, Hungary, Romania, Bulgaria, Greece, Croatia, Slovenia, Austria and northern Italy; the same markets also recorded no negative intervals the preceding week. For storage investors, the week highlighted the potential importance of capturing expensive delivery intervals rather than relying exclusively on negative-price charging opportunities. Actual returns still require assessment of charging costs, losses, operating restrictions and balancing revenues.
OMV Petrom announced on 28 October that three solar parks developed with Renovatio, with a combined capacity of approximately 130 MW, had entered commercial operation and were supplying Romania’s grid. The projects, at Țăndărei, Bucovăț and Căzănești, required approximately €78 million, including about €26 million in PNRR grants. OMV Petrom holds 50%, equivalent to approximately 65 MW of attributable capacity, and forecast gross annual production is approximately 200,000 MWh.
In Croatia, HOPS and KONČAR announced a contract on 27 October for a phase-shifting transformer at Gračac, intended to improve control of active-power flows. The contract is worth €11.5 million excluding VAT. The investment is part of GreenSwitch, which receives EU CEF Energy funding covering 50% of eligible costs; equipment procurement advanced during the week, while commissioning and any increase in usable transfer capability remain future milestones.
Montenegro and Italy continued preparations for market coupling, with CGES and Terna working on cross-border capacity calculation and allocation. Regulatory approvals remained outstanding, so the existing physical connection must be distinguished from future coordinated market allocation. HUPX’s renewed Inside Information Platform became available on 27 October alongside revised publication rules; improved access to outage disclosures supports trading decisions, although comparable weekly evidence did not establish lower imbalance costs.
Full-week exchange volumes, intraday transaction prices, balancing costs, imbalance settlements and border-specific congestion measures remain material data gaps. The reported price movement was clear: a narrower gap with Germany reduced regional trading differentials without lowering the electricity bills facing southeastern buyers.