Wholesale electricity prices rose across Southeast Europe during 26 October–1 November 2026, increasing procurement costs in Serbia and Montenegro. At the same time, a sharp rebound in German prices narrowed Hungary’s premium over Germany. Weekly benchmarks in Serbia, Hungary, Romania and Bulgaria approached €285–287/MWh.
The reporting week ran from Monday, 26 October, to Sunday, 1 November 2026, in Europe/Belgrade time; the comparison period was 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.
Weekly exchange prices and regional spreads
Serbia’s SEEPEX weekly average reached €286.55/MWh, up 8.6% from €263.79/MWh. Montenegro’s BELEN average 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 weekly averages did not capture the full exposure within individual delivery intervals. The highest retrieved Serbian day-ahead interval was €499.99/MWh, while Montenegro’s reached €555.09/MWh. Suppliers and generators with delivery commitments may need to replace shortfalls during such high-priced intervals when forecasts are wrong or production is unavailable, pushing costs above those indicated by a baseload benchmark.
Hungary’s HUPX weekly average increased 5.9% to €284.63/MWh from €268.78/MWh. Serbia consequently traded at a €1.91/MWh premium to Hungary, reversing the €4.99/MWh discount recorded a week earlier. Serbian obligations hedged through Hungarian contracts therefore remained exposed to changes between the hedging reference and the delivery market, even when a hedge protects against a general price rise.
Germany’s weekly average climbed 71.4% to €230.24/MWh from €134.35/MWh. Hungary’s premium over Germany contracted from €134.43/MWh to €54.39/MWh, a fall of almost 60%, 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.
Prices across western and eastern SEE markets
Among the complete weekly series assessed, western SEE markets recorded the strongest percentage increases. Slovenia’s BSP average 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’s average gained 15.1% to €266.06/MWh.
The northern Italian IPEX bidding zone rose 7.9% to €267.32/MWh. Montenegro traded at a €5.76/MWh premium to that benchmark, compared with €4.09/MWh previously. The relationship provides a reference for Adriatic trading, but weekly averages do not establish the direction or profitability of individual transactions over the Montenegro–Italy interconnector.
Romania’s OPCOM weekly average was €287.26/MWh, up 11.1% from €258.48/MWh. 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, reducing another regional sourcing differential. Weekday comparisons also showed narrower spreads in Albania and North Macedonia. ALPEX averaged approximately €287.48/MWh during 26–30 October, compared with €258.12/MWh during 19–23 October, a rise of roughly 11.4%.
MEMO’s corresponding average increased approximately 10.8% to €295.38/MWh from €266.66/MWh. The ALPEX and MEMO figures exclude weekends and use rounded daily observations, so they are narrower comparisons than the complete weekly averages reported for other markets.
Demand, generation and cross-border schedules
Regional operating data showed a mixed supply picture. Reported consumption averaged 33,535 MW during 26–29 October, 5.7% higher than in the corresponding Monday–Thursday period a week earlier. Net imports rose 8.4% to approximately 4,002 MW.
Wind generation recovered 66.3% to approximately 4,449 MW, and hydro output increased 9.4% to 4,321 MW. Solar production 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.
These matched operational comparisons exclude Friday forecasts and do not represent full-week 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 fell to approximately 573 MW from 863 MW, despite its higher exchange price. These movements show that national net trading positions and wholesale benchmarks can move in different directions, while commercial schedules alone do not establish which transmission constraints were binding.
Romanian availability and negative-price intervals
Romanian generation availability remained a concern. A ministry statement reported on 30 October said both Cernavodă reactors remained in safe shutdown. The emergency alert had been extended by 30 days on 28 October amid concerns about maintaining sufficient reserves during peak consumption.
The previously discussed assumption of a 1 November restart had not become confirmed operating availability. Reporting during the week instead indicated a possible mid-November return of one reactor, conditional on Danube flows.
No negative prices were recorded in the complete retrieved weekly series for Serbia, Montenegro, Hungary, Romania, Bulgaria, Greece, Croatia, Slovenia, Austria or northern Italy. Those markets also had no negative intervals in 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 depend on charging costs, losses, operating restrictions and balancing revenues.
Solar projects, grid investment and market coupling
OMV Petrom announced on 28 October that three solar parks developed with Renovatio, with combined capacity of approximately 130 MW, had entered commercial operation and were supplying Romania’s grid. The projects are at Țăndărei, Bucovăț and Căzănești and required approximately €78 million, including about €26 million in PNRR grants. OMV Petrom holds a 50% stake, 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 27 October contract 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 support covering 50% of eligible costs.
Equipment procurement advanced during the week; commissioning and any increase in usable transfer capability remain future milestones. Montenegro and Italy also 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 remained distinct 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 remained material data gaps; meanwhile, the narrowing gap with Germany did not lower the electricity costs facing southeastern buyers.