Hungary’s electricity price premium over Germany more than doubled to €134.43/MWh during 19–25 October 2026 as weaker wind and nuclear generation increased import needs across Southeast Europe. Regional power prices rose despite a sharp decline in Germany, widening trading spreads and increasing the cost of supplying consumers across the Balkans. Montenegro’s weekly price climbed 13.6%, while 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. Cheaper German electricity offered limited relief to southeastern buyers because delivery-market prices moved differently. The divergence increased the importance of matching hedging contracts with exposure in the market where power is delivered, while changing spreads between neighbouring exchanges altered cross-border sourcing economics.
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 therefore contained 169 hours, compared with 168 hours in the preceding week.
Serbia, Montenegro and Hungary
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. They subsequently recovered to end Sunday at €261.92/MWh.
Those daily movements show the exposure that a weekly benchmark can conceal. Suppliers buying replacement electricity and renewable producers correcting forecast errors faced substantially different prices depending on the delivery day. Montenegro’s BELEN averaged €251.81/MWh, against €221.65/MWh a week earlier, narrowing Serbia’s premium over Montenegro to €11.98/MWh from €26.23/MWh.
The higher Montenegrin price increased the potential value of output available to generators, but raised replacement-power costs for suppliers and producers whose delivery commitments exceeded generation. It also reduced the average gross price difference available to traders moving electricity towards Serbia. Hungary’s HUPX, meanwhile, rose 8.9% to €268.78/MWh from €246.87/MWh.
Serbia moved from a €1.02/MWh premium over Hungary to a €4.99/MWh discount. The reversal illustrates how the Serbian delivery market can move relative to its principal regional hedging reference. Germany diverged much more sharply: the German-Luxembourg weekly average fell 26.4% to €134.35/MWh, widening Hungary’s premium to €134.43/MWh from €64.31/MWh.
Prices across regional exchanges
The wider German-Hungarian spread matters to utilities, traders and lenders assessing procurement strategies. A hedge against a broader European price level does not remove exposure to the difference between the reference contract and the delivery market. Greece recorded the largest percentage increase among the complete weekly market series assessed, with HEnEx averaging €229.42/MWh, up from €186.57/MWh.
Negative prices disappeared from the retrieved Greek series, 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; actual margins still depended on delivery intervals, border access and transaction costs.
Romania’s OPCOM averaged €258.48/MWh, up 7.5%, and Bulgaria’s IBEX increased 8.3% to €255.49/MWh. Further west, Croatia’s CROPEX rose 2.8% to €237.03/MWh and Slovenia’s BSP gained 2% to €231.56/MWh. Austria increased 5.2% to €231.18/MWh, while the northern Italian IPEX bidding zone rose 6.7% to €247.73/MWh.
Available weekday data also showed substantial increases in Albania and North Macedonia. ALPEX averaged approximately €258.12/MWh during 19–23 October, against €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; both comparisons exclude weekends and are therefore narrower than the complete weekly averages for other markets.
Weaker supply increases imports
Reported operational data indicate that weaker supply contributed more to the tightening than demand growth. 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 and nuclear production declined 9.1% to 2,742 MW. Solar output rose 32.6% to 4,678 MW, but did not offset the combined reduction in wind and nuclear generation. Gas-fired production increased 15.6% to approximately 5,480 MW, providing additional dispatchable supply.
Hydro output was broadly unchanged at approximately 3,951 MW, offering little additional support in the matched figures. The operational comparisons exclude Friday’s demand and renewable forecasts. They describe reported production and consumption over the first four weekdays, not the full week’s fundamentals.
Commercial flows and regional supply
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 maintained scheduled exports into Bulgaria of 100 MW 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. Reported weekday schedules for Montenegro indicated average imports from Italy of approximately 275 MW alongside exports towards neighbouring markets, reflecting its role in regional transit as well as domestic supply.
Price differences and commercial schedules do not, on their own, identify binding network constraints. The available border-specific capacity and congestion data were insufficient to attribute the weekly spreads to individual transmission bottlenecks. The observed commercial flows therefore cannot establish which constraints determined particular price differences.
Intraday trading and flexibility projects
A trading infrastructure change took effect on 20 October, when ADEX launched its common intraday continuous environment for Serbia, Hungary and Slovenia. BSP assumed operational responsibility, bringing the 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 arrangement can simplify intraday position management across the three exchanges. Its immediate significance is operational, as comparable weekly evidence does not yet establish increased liquidity or lower balancing costs. Separately, investment developments advanced the region’s flexibility pipeline, although the 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, with most technical issues described as resolved. Neither financial close nor the 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; the documents establish development relationships, while project-level financing and investment decisions remain outstanding.
Romanian battery transaction and data gaps
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 or storage duration, or disclose a transaction price.
Comparable full-week exchange volumes, intraday prices, balancing costs, imbalance settlements and reservoir inventories remain gaps in the regional assessment. Day-ahead averages are time-weighted delivery prices rather than volume-weighted trading results. The widening distance between southeastern delivery prices and Germany’s benchmark remains the clearest commercial pressure in the figures.
Hungary’s premium over Germany exceeded €134/MWh, while Montenegro closed part of its discount to Serbia. Those changes made the choice of hedging market nearly as consequential as the timing of a purchase. They also left buyers exposed to differences between reference prices and the markets where electricity had to be delivered.