Montenegro’s BELEN day-ahead average rose 8.2% to €295.37/MWh for the delivery week of 2–8 November 2026, overtaking Serbia as regional demand strengthened and solar and hydro generation weakened. BELEN and SEEPEX weekly market data show Montenegro moved from a €13.46/MWh discount to Serbia in the preceding week to a €4.18/MWh premium.
Serbia’s SEEPEX day-ahead average increased 1.6% to €291.19/MWh. The weekly period ran Monday through Sunday in Europe/Belgrade time and was compared with 26 October–1 November; full-week comparisons use time-weighted delivery averages, not volume-weighted trading prices.
Weekly prices and regional demand
Despite higher weekly averages, the highest delivery intervals fell in both markets. SEEPEX’s peak declined to €422.61/MWh from €499.99/MWh, while BELEN’s fell to €400.03/MWh from €555.09/MWh.
Other exchanges with complete comparable weekly series also recorded higher averages. Hungary’s HUPX rose 2.2% to €290.98/MWh, Romania’s OPCOM increased 2.1% to €293.33/MWh, and Bulgaria’s IBEX gained 2.7% to €291.84/MWh.
Croatia’s CROPEX rose 5.8% to €286.53/MWh, Slovenia’s BSP/ADEX increased 6.7% to €285.14/MWh, and Greece’s HEnEx gained 6.1% to €270.67/MWh. Serbia’s weekly premium over Hungary narrowed to €0.21/MWh from €1.91/MWh, while Hungary’s premium over Greece contracted to €20.31/MWh from €29.59/MWh.
The narrower gaps reduced average price separation between several regional markets, but do not establish that individual delivery periods or border capacities were unconstrained.
Albania’s ALPEX weekday average rose 11.7% to approximately €321.00/MWh for 2–6 November, from €287.48/MWh for 26–30 October. Its highest reported interval reached €700/MWh on 5 November.
North Macedonia’s MEMO averaged approximately €303.76/MWh on weekdays 2–6 November, up 2.8% from €295.38/MWh. Comparable weekend observations were unavailable for Albania and North Macedonia, preventing full-week price comparisons.
Demand, generation and imports
Across Hungary and SEE, reported average demand during 2–5 November rose 5.2% to 35,286 MW from the corresponding Monday-to-Thursday period a week earlier. Net imports into the aggregate increased 5.4% to 4,219 MW.
Over the same four days, wind generation increased 19.7% to 5,326 MW, while solar output fell 21.0% to 2,359 MW and hydro generation declined 5.7% to 4,073 MW. Gas-fired output rose 10.5% to 6,808 MW.
The regional operating comparison uses matched four-day observations, excludes Friday forecasts and omits unavailable weekend data. The combination of higher demand, lower solar and hydro output, and higher gas generation is consistent with greater demand for dispatchable generation and imports.
Verified weekly reservoir and inflow measurements were unavailable, so the figures do not determine whether lower hydro output reflected water availability or operating decisions.
Serbia averaged approximately 4,358 MW of demand and 3,136 MW of generation during 2–5 November, with net imports of 1,221 MW, equivalent to about 28% of consumption. Montenegro averaged 341 MW of demand, 157 MW of generation and 184 MW of imports, which covered approximately 54% of consumption; reported coal generation was zero throughout those four days.
Bosnia and Herzegovina’s reported net exports averaged approximately 91 MW during 2–6 November, down from 276 MW during 26–30 October. The country moved into a small net import position on Thursday and Friday, reducing export supply available to neighbouring markets; no comparable Bosnian exchange-price benchmark was established.
Average net imports into the Hungary–SEE aggregate from Italy increased to approximately 1,017 MW during 2–5 November from 313 MW during 26–29 October, while imports from Austria and Slovakia declined. Turkey supplied approximately 150 MW during the latest four-day period; a verified comparable Turkish wholesale-price series and consistent currency conversion were unavailable.
Austria’s weekly day-ahead average rose 7.7% to €286.54/MWh, while Italy’s IPEX North zone increased 2.3% to €273.50/MWh. Montenegro’s premium over Italian North widened to €21.87/MWh from €5.76/MWh.
The Montenegro–Italian North difference is a regional benchmark, not a directly executable spread across the Montenegro–Italy cable, because Italian landing-zone prices, losses and transmission rights also affect trading returns. Comparable weekly available-capacity and congestion data were unavailable.
Supply and market changes
Romanian nuclear operator Nuclearelectrica reconnected Cernavodă Unit 1 on the afternoon of 6 November. Recorded national nuclear output subsequently averaged approximately 518 MW on 8 November.
The restart improved Romanian supply towards the end of the week, but reconnection alone did not establish a return to full nominal output.
No negative-price delivery intervals appeared in the complete weekly series reviewed for Serbia, Montenegro, Hungary, Romania, Bulgaria, Greece, Croatia, Slovenia, Austria and Italian North, unchanged from the preceding week. Greece’s lowest delivery interval remained marginally positive at €0.01/MWh.
Comparable full-week negative-price counts were unavailable for Albania and North Macedonia. North Macedonia’s electricity market operator MEMO announced on 5 November that negative electricity prices would be introduced from 19 November 2026.
The future effective date is relevant to bidding systems, renewable curtailment decisions and negative-price provisions in power purchase agreements; it does not describe prices realized during the reporting week.
Storage and renewable project contracts
NGEN and NextGrid Energy formally opened Croatia’s 60 MW/120 MWh BESS Šibenik on 4 November. Its entire capacity had already been committed to Croatian transmission system operator HOPS for automatic frequency restoration reserve services since September.
The opening was not a fresh November addition to merchant trading capacity, and the project should not be valued solely against day-ahead spreads.
Rezolv Energy, backed by Actis and Mubadala, announced a 10-year virtual power purchase agreement with Ahold Delhaize on 5 November. The agreement covers 370,000 MWh annually from the planned 1,300 MWp Dama Solar and 300 MW Dunarea East projects, with commercial operation expected in 2029.
The power purchase agreement provides long-term contracted exposure supporting project development, but the announcement did not establish financial close or operating capacity. Its contract price and value were undisclosed.
Verified, consistently defined weekly comparisons were unavailable for exchange trading volumes, intraday volume-weighted prices, balancing procurement costs and settled imbalance prices. Higher day-ahead prices alone cannot establish that liquidity improved, balancing became more expensive or storage revenues increased.
For traders and buyers, Montenegro’s move above Serbia alongside narrower Serbia–Hungary pricing highlights the need to assess local price exposure separately from regional hedges. For investors, transmission access, reserve commitments, renewable production profiles and contract settlement terms determine how much value a project can capture.
