Southeast European electricity prices rose during 19–25 October despite a sharp fall in Germany, as lower wind and nuclear generation increased regional import requirements. The shift widened trading spreads and raised supply costs for consumers across the Balkans. Hungary’s premium over Germany more than doubled to €134.43/MWh, while Montenegro’s weekly price increased 13.6% and Greece’s rose 23%.
Serbia remained among the region’s most expensive markets, although its premium over Montenegro narrowed and it returned to a discount against Hungary. The comparison covers Monday, 19 October, through Sunday, 25 October 2026, against 12–18 October. Weekly averages include the extra delivery hour from Sunday’s clock change: the period covered 169 hours, compared with 168 hours the previous week.
The divergence underlined the importance of matching hedging contracts to delivery-market exposure. Lower German prices offered limited relief to southeastern buyers, while changing price relationships between neighbouring exchanges affected the economics of cross-border sourcing.
Weekly exchange prices and regional spreads
Serbia’s SEEPEX averaged €263.79/MWh, up 6.4% from €247.89/MWh. Daily prices reached €300.22/MWh on 19 October and €317.08/MWh on 20 October, then fell to €211.42/MWh on 21 October. Prices subsequently recovered, closing Sunday at €261.92/MWh.
The weekly benchmark masks differences in exposure across delivery days. Suppliers buying replacement electricity and renewable generators correcting forecast errors faced substantially different conditions depending on when the power was delivered. Montenegro’s BELEN averaged €251.81/MWh, up from €221.65/MWh the previous week.
As a result, Serbia’s premium over Montenegro narrowed to €11.98/MWh from €26.23/MWh. The increase in Montenegro raised the potential value of available output for generators, but increased replacement-power costs for suppliers and producers whose delivery commitments exceeded their generation. The narrower spread also reduced the average gross price difference for traders moving electricity towards Serbia.
Hungary’s HUPX rose 8.9% to €268.78/MWh, from €246.87/MWh. Serbia shifted from a €1.02/MWh premium over Hungary to a €4.99/MWh discount, highlighting the changing relationship between the Serbian delivery market and its main regional hedging reference. The German-Luxembourg weekly average, by contrast, fell 26.4% to €134.35/MWh.
With Hungary’s price increasing as Germany’s declined, the Hungarian premium over Germany widened to €134.43/MWh from €64.31/MWh. This spread is relevant to utilities, traders and lenders assessing procurement strategies. Hedging against a broader European price level leaves exposure to the difference between the reference contract and the market where electricity must be delivered.
Greece had the largest percentage increase among the complete weekly market series assessed, with HEnEx averaging €229.42/MWh, up from €186.57/MWh. Negative prices were absent from the retrieved Greek series, compared with 52 negative quarter-hours, equivalent to 13 hours, the previous week. Zero-price intervals remained.
Hungary’s premium over Greece narrowed to €39.36/MWh from €60.29/MWh, reducing the average price incentive for northbound sourcing. Actual margins still depended on delivery intervals, access to borders and transaction costs. Romania’s OPCOM averaged €258.48/MWh, an increase of 7.5%, while Bulgaria’s IBEX rose 8.3% to €255.49/MWh.
Prices rose less sharply further west. Croatia’s CROPEX averaged €237.03/MWh, up 2.8%, and Slovenia’s BSP reached €231.56/MWh, an increase of 2%. Austria rose 5.2% to €231.18/MWh, while the northern Italian IPEX bidding zone increased 6.7% to €247.73/MWh.
Weekday prices and supply conditions
Available weekday figures showed a marked tightening in Albania and North Macedonia. ALPEX averaged approximately €258.12/MWh during 19–23 October, compared with €215.56/MWh during 12–16 October, an increase of approximately 19.7%. MEMO’s corresponding average rose 21.4% to €266.66/MWh from €219.72/MWh.
These comparisons exclude weekends and therefore cover a narrower period than the complete weekly averages reported for other markets. Operational figures indicate that weaker supply contributed more to the tightening than demand growth. Reported regional consumption averaged 31,714 MW during 19–22 October, just 0.9% above the corresponding Monday–Thursday period a week earlier.
Despite the limited change in consumption, net imports increased 38.5% to approximately 3,691 MW from 2,665 MW. Over the same matched periods, reported wind generation fell 46% to 2,675 MW, while nuclear production declined 9.1% to 2,742 MW. Solar output rose 32.6% to 4,678 MW, but did not offset the combined decline in wind and nuclear generation.
Gas-fired production increased 15.6% to approximately 5,480 MW, adding dispatchable supply. Hydro output was broadly unchanged at approximately 3,951 MW and provided little additional support in the matched figures. These operational comparisons exclude Friday’s demand and renewable forecasts, covering reported production and consumption during the first four weekdays rather than complete weekly fundamentals.
Cross-border schedules and intraday trading
Bulgaria’s export cushion remained weak. Commercial schedules for 19–23 October showed an average net import position of approximately 29 MW, compared with average net exports of 69 MW during 12–16 October. Greece supplied Bulgaria throughout the working week, while Turkey scheduled exports of 100 MW into Bulgaria on each weekday.
Bosnia and Herzegovina’s reported weekday net exports fell to approximately 145 MW from 307 MW, reducing another source of regional supply. The country continued commercial exports towards Serbia while importing from Croatia. Montenegro’s Italian connection also remained significant, with reported weekday schedules showing average imports of approximately 275 MW from Italy alongside exports to neighbouring markets.
The flows reflect Montenegro’s role in regional transit as well as domestic supply. Price differences and commercial schedules alone do not show which network constraints were binding. Border-specific capacity and congestion data were insufficient to attribute the weekly spreads to individual transmission bottlenecks.
A change in trading infrastructure took effect on 20 October, when ADEX launched a common intraday continuous environment for Serbia, Hungary and Slovenia. BSP took operational responsibility, bringing the markets into a shared M7 trading environment with more harmonised procedures and trade-limit management. Participants retain access to each individual market for which they hold admission.
The arrangement can simplify intraday position management across the three exchanges. Its immediate significance is operational; comparable weekly evidence does not yet establish higher liquidity or lower balancing costs.
Investment and flexibility projects
Investment developments moved forward at different stages across the region. In Serbia, discussions with JICA on 22 October focused on accelerating procedures for the Bistrica pumped-storage project. Its environmental and social impact assessment is being finalised for submission in December, and most technical issues were described as resolved.
Financial close and the start of construction were not announced. In Montenegro, EPCG signed four cooperation documents on 20 October involving EBRD, Rudnik uglja Pljevlja, Qair, Akuo Energy and Mantel Capture. The proposals cover renewable generation, batteries, district heating, thermal storage and potential carbon capture at Pljevlja.
The EBRD framework includes solar generation and storage at the former mining complex. The documents establish development relationships, while project-level financing and investment decisions remain to follow. Romania, meanwhile, recorded an ownership transaction disclosed on 21 October.
The transaction transferred Spark Terminal, developer of a 153 MW standalone battery project at Borzești, from RNV Infrastructure of Renovatio Group to SANY International. EY-Parthenon Romania advised on financial and tax due diligence. The announcement did not establish the project’s operating status, storage duration or transaction price.
Comparable full-week exchange volumes, intraday prices, balancing costs, imbalance settlements and reservoir inventories remain material gaps in the regional assessment. Day-ahead averages represent time-weighted delivery prices, not volume-weighted trading results. The clearest commercial pressure is the widening gap between southeastern delivery prices and Germany’s benchmark: Hungary’s premium exceeded €134/MWh, while Montenegro narrowed its price gap with Serbia, making hedge location nearly as consequential as purchase timing.