Electricity prices rose across Southeast Europe during 19–25 October as weaker wind and nuclear generation increased import requirements, even as prices fell sharply in Germany. The tightening of supply widened trading spreads and raised consumer supply costs across the Balkans. Hungary’s premium over Germany more than doubled to €134.43/MWh, while Montenegro’s weekly average rose 13.6% and Greece’s climbed 23%.
Serbia remained among the region’s most expensive markets, but its premium over Montenegro narrowed and it moved back to a discount against Hungary. The widening differences increased the importance of matching hedging contracts to delivery-market exposure. Lower prices in Germany offered limited relief to southeastern buyers, while changing price relationships between neighbouring exchanges affected the economics of cross-border sourcing.
The comparison covers Monday, 19 October, to Sunday, 25 October 2026, against 12–18 October. Weekly averages include the additional delivery hour created by Sunday’s clock change. The reporting period therefore covered 169 hours, compared with 168 hours a week earlier.
Prices and spreads across regional markets
Serbia’s wholesale electricity prices on SEEPEX averaged €263.79/MWh, up 6.4% from €247.89/MWh. Daily prices peaked at €300.22/MWh on 19 October and €317.08/MWh on 20 October, before dropping to €211.42/MWh on 21 October. They then recovered, closing the week at €261.92/MWh on Sunday.
The weekly benchmark masks substantial differences in exposure from one delivery day to another. Suppliers buying replacement electricity and renewable producers correcting forecast errors faced markedly different conditions depending on when power was delivered. Montenegro’s BELEN averaged €251.81/MWh, compared with €221.65/MWh the previous week.
As a result, 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 their 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 variable relationship between the Serbian delivery market and its principal regional hedging reference. Germany moved in the opposite direction: the German-Luxembourg weekly average fell 26.4% to €134.35/MWh.
With Hungarian prices rising as German prices declined, Hungary’s premium over Germany widened to €134.43/MWh from €64.31/MWh. The spread is relevant to utilities, traders and lenders evaluating electricity 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.
Southern and western market benchmarks
Greece recorded the largest percentage increase among the complete weekly market series assessed. HEnEx averaged €229.42/MWh, up from €186.57/MWh. The retrieved Greek series contained no negative prices, compared with 52 negative quarter-hours, equivalent to 13 hours, in 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. Realised margins still depended on delivery intervals, border access and transaction costs. Romania’s OPCOM averaged €258.48/MWh, a 7.5% increase, while Bulgaria’s IBEX rose 8.3% to €255.49/MWh.
Price increases were more limited further west. Croatia’s CROPEX averaged €237.03/MWh, up 2.8%, and Slovenia’s BSP reached €231.56/MWh, a 2% rise. Austria increased 5.2% to €231.18/MWh, while the northern Italian IPEX bidding zone climbed 6.7% to €247.73/MWh.
Available weekday data showed a substantial tightening in Albania and North Macedonia. ALPEX averaged approximately €258.12/MWh on 19–23 October, compared with €215.56/MWh on 12–16 October, an increase of approximately 19.7%. MEMO’s average for the same weekdays rose 21.4% to €266.66/MWh from €219.72/MWh; these comparisons exclude weekends and are narrower than the complete weekly averages reported for other markets.
Supply conditions and regional imports
Operational data indicate that weaker supply contributed more to the market tightening than demand growth. Reported regional consumption averaged 31,714 MW on 19–22 October, only 0.9% above the corresponding Monday-to-Thursday period a week earlier. Net imports nevertheless rose 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 increased 32.6% to 4,678 MW, but that rise did not offset the combined reduction in wind and nuclear generation. Gas-fired production grew 15.6% to approximately 5,480 MW, providing additional dispatchable supply.
Hydro output was broadly unchanged at approximately 3,951 MW, adding little further support in the matched figures. The operational comparison excludes Friday’s demand and renewable forecasts. It covers reported production and consumption over the first four weekdays, rather than full-week fundamentals.
Commercial flows across borders
Bulgaria’s export cushion remained weak. Commercial schedules for 19–23 October showed an average net import position of approximately 29 MW, against average net exports of 69 MW on 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 to export commercially towards Serbia while importing from Croatia. Montenegro’s connection with Italy also remained significant, with reported weekday schedules showing average imports of approximately 275 MW from Italy alongside exports to neighbouring markets.
Those flows show Montenegro’s role in regional transit as well as domestic supply. Price differences and commercial schedules alone do not identify which network constraints were binding. Border-specific capacity and congestion data were insufficient to attribute the weekly spreads to particular transmission bottlenecks.
Intraday trading changes
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 three markets into a shared M7 trading environment with more harmonised procedures and trade-limit management. Participants retain access to the individual markets for which they hold admission.
The shared environment can simplify intraday position management across the three exchanges. Its immediate significance is operational. Comparable weekly evidence does not yet establish that liquidity has increased or balancing costs have fallen.
Investment and project developments
In Serbia, discussions with JICA on 22 October focused on accelerating procedures for the Bistrica pumped-storage project. The project’s environmental and social impact assessment is being finalised for submission in December, and most technical issues were described as resolved. No financial close or start of construction was 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; project-level financing and investment decisions are still to follow.
Romania also recorded an ownership transaction. An acquisition disclosed on 21 October 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.
Market data and procurement exposure
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 distance between southeastern delivery prices and Germany’s benchmark.
With Hungary’s premium over Germany exceeding €134/MWh and Montenegro narrowing part of its discount to Serbia, the choice of hedging market has become almost as consequential as the timing of a purchase.
