Southeast European wholesale electricity prices increased during 19–25 October 2026, despite a sharp decline in Germany. Lower wind and nuclear generation increased regional import requirements, widening price spreads and raising supply costs for consumers across the Balkans. Hungary’s premium over Germany more than doubled, while prices also rose in Montenegro and Greece.
The comparison covers Monday, 19 October, through Sunday, 25 October 2026, against 12–18 October. Weekly averages include the additional delivery hour created by Sunday’s clock change: the reporting week comprised 169 hours, compared with 168 hours a week earlier. Germany’s weekly average fell as prices in several Southeast European markets increased.
Weekly prices and cross-market 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 recovered later in the week, closing Sunday at €261.92/MWh.
The weekly benchmark masks differences in conditions across delivery days. Suppliers purchasing replacement electricity and renewable producers correcting forecast errors faced substantially different conditions depending on the delivery day. Montenegro’s BELEN averaged €251.81/MWh, compared with €221.65/MWh the previous week.
Serbia’s premium over Montenegro narrowed to €11.98/MWh from €26.23/MWh. Higher prices increased the potential value of available output for Montenegrin generators, but raised replacement-power costs for suppliers and producers whose delivery commitments exceeded generation. The narrower spread also reduced the average gross price difference available to 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 variability of the relationship between Serbia’s delivery market and its principal regional hedging reference. Montenegro’s weekly price rose 13.6%, while Greece’s increased 23%.
The German-Luxembourg weekly average declined 26.4% to €134.35/MWh as Hungary’s price rose. Hungary’s premium over Germany widened to €134.43/MWh from €64.31/MWh. Serbia remained among the region’s most expensive markets, although its premium over Montenegro narrowed and it returned to a discount against Hungary.
The widening gap is relevant to utilities, traders and lenders assessing electricity procurement strategies. Hedging against the broader European price level leaves exposure to the difference between the reference contract and the market where electricity must be delivered. Cheaper German power offered limited relief to southeastern buyers, while changing price relationships between neighbouring exchanges altered the economics of cross-border sourcing.
Prices across Southeast European markets
Greece recorded the largest percentage increase among the complete weekly market series assessed. HEnEx averaged €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 continued to depend on delivery intervals, border access and transaction costs. Romania’s OPCOM averaged €258.48/MWh, an increase of 7.5%.
Bulgaria’s IBEX rose 8.3% to €255.49/MWh. Further west, Croatia’s CROPEX averaged €237.03/MWh, up 2.8%, and Slovenia’s BSP reached €231.56/MWh, a 2% increase. Austria rose 5.2% to €231.18/MWh, while the northern Italian IPEX bidding zone increased 6.7% to €247.73/MWh.
Available weekday data showed substantial 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.
The ALPEX and MEMO comparisons exclude weekends, so they cover a narrower period than the complete weekly averages reported for other markets. The differing price movements increased the importance of matching hedging contracts to delivery-market exposure. Serbia remained among the region’s most expensive markets, despite the change in its price relationship with Hungary and Montenegro.
Supply, demand and cross-border flows
Operational figures indicate that weaker supply contributed more to the market 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. Net imports nevertheless increased 38.5% to approximately 3,691 MW from 2,665 MW.
Across those 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 that increase did not offset the combined reduction 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, providing little additional support in the matched figures. These operational comparisons exclude Friday’s demand and renewable forecasts. They cover reported production and consumption during the first four weekdays, rather than complete weekly fundamentals.
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 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 exporting commercially towards Serbia while importing from Croatia. Montenegro’s connection with Italy also remained important, with reported weekday schedules indicating average imports of approximately 275 MW from Italy alongside exports towards neighbouring markets.
The scheduled flows illustrate Montenegro’s role in regional transit as well as domestic supply. Price differences and commercial schedules alone do not establish which network constraints were binding. Border-specific capacity and congestion data were insufficient to attribute the weekly spreads to individual transmission bottlenecks.
Intraday trading and investment developments
A change in trading infrastructure took effect on 20 October, when ADEX launched a common intraday continuous environment for Serbia, Hungary and Slovenia. BSP assumed operational responsibility, bringing the markets into a common M7 trading environment with more harmonised procedures and trade-limit management. Participants retain access to the individual markets for which they hold admission.
The common environment can simplify intraday position management across the three exchanges. Its immediate significance is operational; comparable weekly evidence does not establish increased liquidity or reduced balancing costs. Investment developments also advanced the region’s flexibility pipeline, although projects were at different stages.
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 construction commencement 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 recorded an ownership transaction disclosed on 21 October: Spark Terminal, developer of a 153 MW standalone battery project at Borzești, was transferred from RNV Infrastructure of Renovatio Group to SANY International. EY-Parthenon Romania advised on financial and tax due diligence.
The transaction announcement did not establish the project’s operating status, storage duration or a 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 are time-weighted delivery prices, not volume-weighted trading results.
The distance between Southeast European delivery prices and Germany’s benchmark widened, with Hungary’s premium exceeding €134/MWh. Montenegro also closed part of its price gap with Serbia. The choice of hedging market has become almost as consequential as the timing of electricity purchases.