Electricity prices across southeast Europe rose during 26 October–1 November, increasing procurement costs for Serbian and Montenegrin buyers even as the region’s premium over Germany narrowed sharply. The shift altered cross-border trading margins and hedging exposure ahead of the winter period.
Hungary’s premium over Germany fell by almost 60% to €54.39/MWh, although the narrowing was driven primarily by a strong rebound in German electricity prices rather than by weaker costs in southeast Europe. Weekly benchmarks in Serbia, Hungary, Romania and Bulgaria approached €285–287/MWh, keeping absolute power costs elevated across the region.
The reporting period covers Monday, 26 October, through Sunday, 1 November 2026, compared with 19–25 October, using Europe/Belgrade time. The time-weighted averages cover 168 delivery hours in the reporting week and 169 hours in the preceding week because of the seasonal clock change.
Serbia’s SEEPEX averaged €286.55/MWh, up 8.6% from €263.79/MWh. Montenegro’s BELEN increased 8.4% to €273.09/MWh, compared with €251.81/MWh previously. Serbia therefore maintained a €13.46/MWh premium over Montenegro, slightly wider than the €11.98/MWh differential recorded in the previous week.
The relatively modest change in the bilateral spread, however, masked significant exposure during 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 obligations, such price extremes can be more important than the weekly baseload average. Forecast errors, outages or unavailable production during high-priced hours can force replacement purchases at substantially higher costs than those suggested by the average market price.
Hungary’s HUPX averaged €284.63/MWh, increasing 5.9% from €268.78/MWh. Serbia consequently moved to a €1.91/MWh premium over Hungary, reversing the €4.99/MWh discount recorded a week earlier.
The reversal highlights the residual basis risk associated with hedging Serbian electricity obligations through Hungarian contracts. A hedge can protect against a broad market increase without eliminating changes in the price differential between the hedging reference and the actual delivery market.
Germany recorded the strongest percentage increase among the major markets, with its weekly average rising 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, significantly reducing the average gross price advantage of sourcing against the German benchmark.
The remaining spread was still substantial, although actual trading margins depended on individual delivery hours, available transmission rights and transaction costs.
Western SEE markets recorded some of the strongest percentage increases in the complete weekly dataset. 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, while the northern Italian IPEX bidding zone increased 7.9% to €267.32/MWh. Montenegro’s premium over northern Italy consequently widened to €5.76/MWh from €4.09/MWh.
The relationship provides a useful reference for trading across the Adriatic, although weekly averages alone cannot 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. 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, compared with €229.42/MWh previously. Hungary’s premium over Greece narrowed from €39.36/MWh to €29.59/MWh, reducing another important regional sourcing differential.
Available weekday comparisons showed similar tightening in Albania and North Macedonia. ALPEX averaged approximately €287.48/MWh during 26–30 October, compared with €258.12/MWh during 19–23 October, representing 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 are based on rounded daily observations, making them narrower comparisons than the complete weekly averages reported for the other markets.
The operational data pointed to a more complex supply picture than a simple renewable-generation shortfall. Reported regional consumption averaged 33,535 MW during 26–29 October, 5.7% higher than during the corresponding Monday–Thursday period a week earlier. Net imports increased 8.4% to approximately 4,002 MW.
Wind production recovered strongly, rising 66.3% to approximately 4,449 MW, while hydro generation increased 9.4% to 4,321 MW. Solar output, however, fell 36.1% to approximately 2,987 MW, while gas-fired generation increased 12.4% to around 6,161 MW.
The combination of higher demand and weaker solar generation therefore absorbed much of the improvement in wind and hydro availability. The operational comparison excludes Friday forecasts and should not be interpreted as a complete weekly generation or reservoir balance.
Bulgaria’s dependence on imports also became more pronounced. Commercial schedules during 26–30 October showed average net imports of approximately 504 MW, compared with just 29 MW during 19–23 October.
Greece supplied Bulgaria throughout the working week, while Turkey maintained scheduled exports into Bulgaria of 100 MW on each weekday. Southern supply therefore remained important to the regional balance despite the narrowing price differentials.
Bosnia and Herzegovina’s reported weekday net exports recovered to approximately 276 MW, from 145 MW, providing additional support to the regional balance. Croatia’s reported weekday imports, meanwhile, declined to approximately 573 MW from 863 MW, despite its higher exchange price.
These contrasting movements demonstrate that a country’s physical trading position and wholesale benchmark can move in different directions. Commercial schedules alone are also insufficient to determine which transmission constraints were binding during individual periods.
Romanian generation availability remained a significant concern. A ministry statement issued on 30 October said that both Cernavodă reactors remained in safe shutdown. The emergency alert had been extended for another 30 days on 28 October amid concerns over maintaining sufficient reserves during periods of 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. None of those markets recorded negative intervals in the preceding week either.
For storage investors, the week highlighted the importance of capturing high-value delivery intervals, rather than relying exclusively on negative-price charging opportunities. Actual storage returns, however, depend on charging costs, round-trip losses, operating restrictions and balancing-market revenues.
New infrastructure developments offered longer-term responses to the region’s supply and network pressures. 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 at Țăndărei, Bucovăț and Căzănești required approximately €78 million of investment, including around €26 million in PNRR grants. OMV Petrom holds a 50% stake, equivalent to approximately 65 MW of attributable capacity. 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 designed to improve control over active-power flows. The contract is worth €11.5 million excluding VAT.
The investment forms part of GreenSwitch, supported through EU CEF Energy funding covering 50% of eligible costs. Equipment procurement progressed during the week, while commissioning and any resulting 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, meaning investors must distinguish between the existing physical interconnection and future coordinated market allocation.
HUPX’s renewed Inside Information Platform became available on 27 October, alongside revised publication rules. Improved access to outage information can support trading decisions, although the available weekly evidence does not establish whether the changes have reduced imbalance costs.
Full-week exchange volumes, intraday transaction prices, balancing costs, imbalance settlements and border-specific congestion measures remain important data gaps. Nevertheless, the main price signal was clear: the narrowing gap with Germany reduced regional trading differentials without reducing the electricity costs faced by southeastern European buyers.
The week therefore points to a market in which winter procurement risk remains elevated. German prices moved sharply closer to the SEE market, but Serbia, Montenegro and the wider region continued to face high absolute power prices, significant hourly volatility and growing dependence on cross-border flows to balance demand and supply.
