Wholesale Southeast European power prices increased during 19–25 October 2026, even as Germany’s weekly average fell sharply. Lower wind and nuclear output coincided with higher regional net imports, while prices and spreads moved in different directions across Balkan markets.
Weekly prices diverge across regional markets
The reporting period ran from Monday, 19 October, to Sunday, 25 October 2026, compared with 12–18 October. The weekly averages account for the extra delivery hour caused by Sunday’s clock change: the period covered 169 hours, against 168 hours the previous week.
Serbia’s SEEPEX averaged €263.79/MWh, up 6.4% from €247.89/MWh. Prices reached €300.22/MWh on 19 October and €317.08/MWh on 20 October, then dropped to €211.42/MWh on 21 October. They later recovered, closing the week at €261.92/MWh on Sunday.
The weekly benchmark masked substantial variation by delivery day. Suppliers buying replacement power and renewable generators correcting forecast errors therefore faced different conditions depending on when electricity was delivered.
Montenegro’s BELEN averaged €251.81/MWh, compared with €221.65/MWh a week earlier, a rise of 13.6%. Serbia’s premium over Montenegro narrowed to €11.98/MWh from €26.23/MWh. The higher price increased the potential value of available generation for Montenegrin generators, while raising replacement-power costs for suppliers and producers whose commitments exceeded their output.
The smaller spread also reduced the average gross price difference available to traders moving electricity towards Serbia. Serbia remained one of the region’s more expensive markets, but its premium over Montenegro narrowed during the week.
Hungary’s premium over Germany more than doubles
Hungary’s HUPX average rose 8.9%, from €246.87/MWh to €268.78/MWh. Serbia shifted from a €1.02/MWh premium over Hungary to a €4.99/MWh discount, highlighting how the relationship between the Serbian delivery market and a key regional hedging reference can change.
The gap between Hungary and Germany widened more sharply. The German-Luxembourg weekly average fell 26.4% to €134.35/MWh, while Hungary’s price increased. Hungary’s premium over Germany consequently grew to €134.43/MWh from €64.31/MWh.
For utilities, traders and lenders assessing procurement strategies, a hedge linked to a broader European price level leaves exposure to the difference between the reference contract and the market where electricity must be delivered. Lower German prices offered limited relief to southeastern buyers as trading relationships between neighbouring exchanges changed the economics of cross-border sourcing.
Greece recorded the largest percentage increase among the complete weekly market series assessed. HEnEx averaged €229.42/MWh, up from €186.57/MWh, or a 23% increase.
No negative prices appeared in 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; realised margins still depended on delivery intervals, border access and transaction costs.
Prices also rise in Romania and Bulgaria
Romania’s OPCOM averaged €258.48/MWh, an increase of 7.5%. Bulgaria’s IBEX rose 8.3% to €255.49/MWh.
In western markets, CROPEX in Croatia averaged €237.03/MWh, up 2.8%, while Slovenia’s BSP reached €231.56/MWh, an increase of 2%. Austria’s average rose 5.2% to €231.18/MWh. The northern Italian IPEX bidding zone increased 6.7% to €247.73/MWh.
Available weekday data also showed higher prices in Albania and North Macedonia. ALPEX averaged approximately €258.12/MWh during 19–23 October, compared with €215.56/MWh during 12–16 October, a rise of approximately 19.7%.
MEMO’s corresponding average increased 21.4%, from €219.72/MWh to €266.66/MWh. These figures cover weekdays only and therefore offer a narrower comparison than the full-week averages reported for other markets.
Lower wind and nuclear output coincide with higher imports
Operational data 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-to-Thursday period a week earlier.
Over the same matched periods, net imports rose 38.5% to approximately 3,691 MW, from 2,665 MW. 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 gain did not offset the combined decline in wind and nuclear generation. Gas-fired production rose 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. The operational comparison excludes Friday demand and renewable forecasts and covers reported production and consumption during the first four weekdays, rather than the full week.
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 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.
Bosnia and Herzegovina continued commercial exports towards Serbia while importing from Croatia. Montenegro’s connection with Italy also remained significant: reported weekday schedules showed average imports of approximately 275 MW from Italy, alongside exports to neighbouring markets.
The scheduled flows show Montenegro serving both domestic supply and regional transit. Price differences and commercial schedules alone do not identify which network constraints were binding, and border-specific capacity and congestion data were insufficient to attribute the weekly spreads to individual transmission bottlenecks.
Intraday trading arrangements change on 20 October
ADEX launched a common intraday continuous environment for Serbia, Hungary and Slovenia on 20 October. BSP took operational responsibility, bringing the three 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 change can simplify intraday position management across the three exchanges, but the immediate effect is operational: comparable weekly evidence does not yet establish that liquidity increased or balancing costs fell.
Flexibility and storage projects advance at different stages
In Serbia, talks 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. 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. The documents establish development relationships; project-level financing and investment decisions remain to follow.
Romania saw an ownership change involving a standalone battery project. An acquisition disclosed on 21 October transferred Spark Terminal, developer of the 153 MW 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 whether the project was operating, its storage duration or the 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 clearest commercial pressure described by the weekly data is the widening distance between southeastern delivery prices and Germany’s benchmark: Hungary’s premium exceeded €134/MWh, while Montenegro narrowed part of its price gap with Serbia. The choice of hedging market has therefore become almost as consequential as the timing of a purchase.