Southeast European electricity prices increased during 19–25 October, even as German power prices fell sharply, highlighting a growing divergence between Central European and Balkan markets. Weaker wind and nuclear generation increased the region’s reliance on imports, widening price spreads and raising electricity procurement costs across Southeast Europe.
Hungary’s premium over Germany more than doubled to €134.43/MWh, while Montenegro’s weekly average increased by 13.6% and Greece’s rose 23%. Serbia remained one of the region’s most expensive markets, although its premium over Montenegro narrowed and it moved from a small premium to a discount against Hungary.
The widening price differences are increasingly important for market participants managing hedging and physical delivery exposure. Lower German prices provided limited relief for Southeast European buyers, while changing relationships between neighboring exchanges altered the economics of cross-border electricity sourcing.
The comparison covers Monday, October 19, through Sunday, October 25, 2026, against the previous week of October 12–18. Because the reporting period included the additional hour created by the seasonal clock change, it contained 169 delivery hours, compared with 168 hours in the previous week.
Serbia’s SEEPEX averaged €263.79/MWh, up 6.4% from €247.89/MWh. Prices reached €300.22/MWh on October 19 and €317.08/MWh on October 20 before dropping to €211.42/MWh on October 21. The market subsequently recovered, closing the week at €261.92/MWh on Sunday.
The weekly average therefore masks significant daily volatility. Suppliers purchasing replacement electricity and renewable generators managing forecast deviations could face substantially different costs depending on the delivery day.
Montenegro’s BELEN averaged €251.81/MWh, compared with €221.65/MWh a week earlier. As a result, Serbia’s average premium over Montenegro narrowed to €11.98/MWh, from €26.23/MWh in the previous period.
For Montenegrin generators, the higher prices increased the potential value of available production. At the same time, suppliers and generators with delivery obligations exceeding their own output faced higher replacement costs. The narrower Serbia-Montenegro spread also reduced the average gross price differential available to traders moving electricity toward Serbia.
Hungary’s HUPX average increased 8.9% to €268.78/MWh, from €246.87/MWh. Serbia consequently shifted from a €1.02/MWh premium over Hungary to a €4.99/MWh discount, illustrating how quickly the relationship between the two regional markets can change.
The contrast with Germany was much more pronounced. The German-Luxembourg weekly average fell 26.4% to €134.35/MWh, while Hungary moved higher. Hungary’s premium over Germany consequently widened to €134.43/MWh, compared with €64.31/MWh a week earlier.
This divergence has direct implications for utilities, traders and lenders assessing procurement and hedging strategies. A hedge linked to a broader European reference price can still leave substantial exposure to the spread between the hedging market and the location where electricity is ultimately delivered.
Greece recorded the largest percentage increase among the complete weekly market series assessed. HEnEx averaged €229.42/MWh, up from €186.57/MWh in the previous week.
Negative prices disappeared from the retrieved Greek series, compared with 52 negative quarter-hours, equivalent to 13 hours, during the previous week. Zero-price intervals remained. Hungary’s premium over Greece consequently narrowed to €39.36/MWh from €60.29/MWh, reducing the average incentive for northbound electricity flows, although actual trading margins continued to depend on hourly prices, transmission availability and transaction costs.
Romania’s OPCOM average increased 7.5% to €258.48/MWh, while Bulgaria’s IBEX rose 8.3% to €255.49/MWh.
Price increases were more moderate farther west. Croatia’s CROPEX averaged €237.03/MWh, up 2.8%, while 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.
Available weekday data also showed substantial tightening in Albania and North Macedonia. ALPEX averaged approximately €258.12/MWh during October 19–23, compared with €215.56/MWh during October 12–16, an increase of about 19.7%.
The corresponding MEMO average increased 21.4% to €266.66/MWh, from €219.72/MWh. These figures exclude weekends and therefore provide a narrower comparison than the full-week averages available for the other markets.
Operational data suggest that weaker electricity supply played a larger role than demand growth in tightening the regional market.
Reported regional consumption averaged 31,714 MW from October 19–22, only 0.9% above the corresponding Monday-to-Thursday period a week earlier. Despite the limited demand increase, net imports climbed 38.5% to approximately 3,691 MW, compared with 2,665 MW previously.
During the same period, reported wind generation fell 46% to 2,675 MW, while nuclear output declined 9.1% to 2,742 MW. Solar generation increased 32.6% to 4,678 MW, but the additional solar output was insufficient to offset the combined reduction in wind and nuclear production.
Gas-fired generation increased 15.6% to approximately 5,480 MW, providing additional dispatchable supply. Hydropower output remained broadly stable at around 3,951 MW and therefore provided little additional support in the matched-period comparison.
The operational comparison covers only the first four weekdays and excludes Friday demand and renewable forecasts. It should therefore be viewed as an indication of the early-week supply picture rather than a complete assessment of weekly fundamentals.
Bulgaria’s export position also weakened. Commercial schedules for October 19–23 showed an average net import position of approximately 29 MW, compared with average net exports of 69 MW during October 12–16.
Greece continued supplying Bulgaria throughout the working week, while Turkey maintained scheduled exports into Bulgaria of 100 MW per weekday.
Bosnia and Herzegovina also provided less surplus electricity. Reported weekday net exports fell to approximately 145 MW from 307 MW, reducing another source of regional supply. Bosnia and Herzegovina continued commercial exports toward Serbia while importing electricity from Croatia.
Montenegro’s connection with Italy remained an important element of regional power flows. Reported weekday schedules indicated average imports from Italy of approximately 275 MW, alongside exports toward neighboring markets, underlining Montenegro’s role as both a domestic market and regional transit route.
However, price differences and commercial schedules alone do not establish which transmission constraints were binding. Available border-specific capacity and congestion data are insufficient to attribute the weekly spreads to individual network bottlenecks.
Trading infrastructure also saw a significant change during the period. On October 20, ADEX launched a common intraday continuous trading environment for Serbia, Hungary and Slovenia.
BSP assumed operational responsibility, bringing the three markets into a common M7 trading environment with more harmonized procedures and trade-limit management. Participants continue to access the individual markets for which they are admitted.
The development should simplify intraday position management across the three markets, although there is not yet enough comparable weekly evidence to conclude that it has materially increased liquidity or reduced balancing costs.
The region’s flexibility pipeline also continued to advance, although projects remain at different stages of development.
In Serbia, discussions with JICA on October 22 focused on accelerating procedures for the Bistrica pumped-storage project. The environmental and social impact assessment is being finalized for submission in December, with most technical issues reportedly resolved. Financial close and construction commencement have not yet been announced.
In Montenegro, EPCG signed four cooperation agreements on October 20 involving EBRD, Rudnik uglja Pljevlja, Qair, Akuo Energy and Mantel Capture. The initiatives cover renewable generation, battery storage, district heating, thermal storage and potential carbon capture at the Pljevlja site.
The EBRD framework includes solar generation and storage at the former mining complex. The agreements establish development partnerships, while project-level financing and final investment decisions remain outstanding.
Romania also recorded an important energy-storage transaction. An acquisition announced on October 21 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 disclose a transaction price or establish the project’s operating status or storage duration.
Several important data gaps remain in assessing the region. Comparable full-week exchange volumes, intraday prices, balancing costs, imbalance settlements and reservoir inventories are not consistently available. In addition, day-ahead averages represent time-weighted delivery prices rather than volume-weighted trading results.
The clearest commercial signal from the week was the widening gap between Southeast European delivery prices and Germany’s benchmark. With Hungary’s premium over Germany exceeding €134/MWh and Montenegro moving closer to Serbia, the choice of hedging reference has become increasingly important.
For utilities, traders and large consumers, the week demonstrated that where electricity is hedged can be nearly as important as when it is purchased. Persistent regional price separation means that exposure to Central European benchmarks does not necessarily protect against the much higher prices prevailing in Southeast European delivery markets.
