Electricity prices rose across Southeast Europe during 26 October–1 November 2026, increasing procurement costs in Serbia and Montenegro even as the region’s premium over Germany contracted sharply. Weekly benchmarks approached €285–287/MWh in Serbia, Hungary, Romania and Bulgaria. The reporting period ran from Monday, 26 October, through Sunday, 1 November, compared with 19–25 October, in Europe/Belgrade time.
Weekly prices and regional spreads
The time-weighted averages covered 168 delivery hours in the reporting week and 169 hours in the preceding week, which included the clock change. 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 weekly averages concealed larger differences in 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 during these most expensive intervals, pushing costs well above those suggested by a baseload benchmark.
Hungary’s HUPX averaged €284.63/MWh, an increase of 5.9% from €268.78/MWh. Serbia therefore moved to a €1.91/MWh premium over Hungary, after trading €4.99/MWh below it the previous week. Serbian electricity obligations hedged through Hungarian contracts remain exposed to changes between the hedging reference and the delivery market, even when the hedge protects against a general price increase.
Germany’s weekly average rose 71.4% to €230.24/MWh, from €134.35/MWh. As a result, Hungary’s premium over Germany narrowed from €134.43/MWh to €54.39/MWh, a fall of almost 60%. The remaining spread was still substantial, but executable trading margins depended on delivery periods, available transmission rights and transaction costs.
Price movements across Southeast European markets
Western SEE markets recorded the strongest percentage increases among the complete weekly series assessed. 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 relationship provides a reference for trading across the Adriatic, but weekly averages do not establish the direction or profitability of individual transactions through the Montenegro–Italy interconnector.
Romania’s OPCOM averaged €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. Available weekday comparisons also showed tighter 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, an increase of roughly 11.4%.
MEMO’s corresponding average rose approximately 10.8% to €295.38/MWh, from €266.66/MWh. These figures exclude weekends and use rounded daily observations, making the comparison narrower than the complete weekly averages reported for other markets.
Regional generation, demand and cross-border schedules
Operational data showed a more complex supply picture than a simple 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 increased 8.4% to approximately 4,002 MW.
Wind production recovered 66.3% to approximately 4,449 MW, while hydro generation rose 9.4% to 4,321 MW. Solar output fell 36.1% to approximately 2,987 MW, and gas-fired generation increased 12.4% to approximately 6,161 MW. Higher demand and weaker solar production absorbed much of the improvement in wind and hydro availability.
These matched operational comparisons exclude Friday forecasts and do not represent complete weekly generation or reservoir balances. Bulgaria’s import dependence became more pronounced: commercial schedules during 26–30 October showed average net imports of approximately 504 MW, 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. The contrasting movements show that a country’s net trading position and wholesale benchmark can move in different directions, while commercial schedules alone do not establish which transmission constraints were binding.
Romanian availability and negative-price intervals
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 having sufficient reserves during peak consumption. The previously discussed 1 November restart assumption had not become confirmed operating availability.
Reporting during the week instead pointed to a possible mid-November return of one reactor, conditional on Danube flows. Negative prices were absent from the complete retrieved weekly series for Serbia, Montenegro, Hungary, Romania, Bulgaria, Greece, Croatia, Slovenia, Austria and northern Italy. Those markets also recorded 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 require assessment of charging costs, losses, operating restrictions and balancing revenues.
Solar and grid infrastructure developments
OMV Petrom announced on 28 October that three solar parks developed with Renovatio, with total 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 on 27 October a 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 funding 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 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.
Market information and remaining data gaps
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.
The price signal was nevertheless clear: the narrowing gap with Germany reduced regional trading differentials without lowering the electricity bill facing Southeast European buyers.