Electricity prices across southeastern Europe rose sharply for delivery on 15 October, with Hungary and Serbia trading above €250/MWh. The move followed a reversal in Romania’s electricity balance alongside stronger regional demand and lower forecast wind generation. Cross-border trading spreads widened as day-ahead prices diverged between central and eastern markets and Greece.
Day-ahead price moves across HUPX, SEEPEX, OPCOM and IBEX
The HUPX day-ahead baseload price increased by €28.9/MWh to €252.81/MWh. Serbia’s SEEPEX gained €18.1/MWh to €252.74/MWh, leaving the two markets almost aligned. Romania’s OPCOM advanced by €26.8/MWh to €248.44/MWh, while Bulgaria’s IBEX rose by €18.8/MWh to €233.29/MWh.
Albania recorded the largest daily jump, with ALPEX up €113.6/MWh to €249.56/MWh. Montenegro’s BELEN increased by €14/MWh to €223.17/MWh, while North Macedonia reached €222.30/MWh on the day.
Romania reverses from net exports to net imports
Romania recorded a major shift in its regional trading position, moving from a scheduled net export of 749 MW on 14 October to net imports of 629 MW on 15 October. The change amounted to a 1,378 MW reversal in its daily average electricity balance. Romanian electricity consumption rose from 5,724 MW to 6,096 MW, while forecast domestic generation fell from 6,473 MW to 5,467 MW.
The higher demand alongside reduced domestic output increased Romania’s reliance on power arriving through neighbouring systems, particularly Bulgaria. Scheduled commercial flows from Bulgaria into Romania increased to approximately 1,278 MW from 657 MW the previous day. At the same time, Romanian exports towards Hungary fell from 1,213 MW to 121 MW.
The flow pattern changed supply available to central European markets and supported a closer price relationship between Romania and Hungary. Across Hungary and the wider SEE region, net electricity imports rose by 565 MW to 2,267 MW against forecast consumption of 32,017 MW, up 749 MW day on day.
Imports from Austria and Slovakia towards Hungary and Slovenia increased to 2,661 MW, up by 890 MW. The figures reflected continued dependence on northern and western supply corridors for the region’s cross-border balances.
Serbia’s deficit persists as generation rises
Serbia continued operating with a substantial electricity deficit even as higher domestic generation reduced its scheduled import requirement. Forecast consumption increased to 3,975 MW from 3,820 MW the previous day. Domestic generation rose from 2,628 MW to 2,948 MW, cutting net imports from 1,192 MW to 1,027 MW.
Commercial schedules showed Serbia importing about 370 MW from Bulgaria, 354 MW from North Macedonia and 293 MW from Bosnia and Herzegovina. Imports also included approximately 214 MW from Romania and around 183 MW from Montenegro. Serbia was simultaneously scheduled to export 476 MW towards Hungary.
SEEPEX remained among the highest prices in the region despite stronger domestic output. The market reached an hourly maximum of €368.6/MWh at hour 20 versus a minimum of €189.9/MWh at hour 14. The resulting intraday spread of nearly €179/MWh reflected the value of flexible generation and demand response alongside battery storage for shifting supply between lower-priced daytime periods and evening demand peaks.
Montenegro keeps a discount versus Serbia and Hungary
Montenegro maintained smaller net exports as both domestic consumption and generation declined. Average demand fell from 420 MW to 362 MW while generation decreased from 456 MW to 378 MW. The system ended with scheduled net exports of approximately 16 MW compared with 36 MW previously.
BELEN’s baseload price of €223.17/MWh represented an approximate discount of €29.57/MWh versus Serbia and €29.64/MWh versus Hungary. Scheduled flows indicated average imports of about 192 MW from Italy alongside exports of around 183 MW towards Serbia.
The relationship between daily average prices and scheduled flow directions highlighted that cross-border profitability cannot be inferred from baseload spreads alone. Hourly price differences, allocated transmission capacity, contracted delivery positions and congestion charges remained decisive factors for traders active between Montenegro, Italy and Serbia.
Greece remains cheaper as renewable availability depresses daytime prices
Greece stayed the region’s principal low-price market with its HENEX day-ahead baseload averaging €160.54/MWh while rising by €21.6/MWh versus the previous session. The Hungarian premium over Greece widened to €92.28/MWh as the Hungarian-German spread increased to €65.51/MWh compared with approximately €44.9/MWh a day earlier.
German baseload prices rose more moderately to €187.30/MWh, reinforcing divergence between Germany and higher-priced southeastern markets. Greek electricity prices reached zero during hour 14 before recovering to an evening maximum of €296.5/MWh; the Greek peak-period average was €97.3/MWh versus an off-peak average of €223.7/MWh.
Greece was scheduled to export approximately 1,700 MW on a net basis including substantial flows towards Bulgaria and North Macedonia. Bulgaria moved from a net import position of 74 MW into exports of 717 MW, supported by an increase in forecast generation.
Solar output rises while wind falls; forward spreads remain elevated
Regional renewable forecasts showed changes in generation mix with average solar production forecast at 5,932 MW, up by 2,631 MW. Wind generation was expected to fall by 1,571 MW to 5,114 MW. The combined renewable increase provided only a partial offset relative to changes in demand and other generation sources.
The shift explained why stronger solar availability did not prevent broad increases in day-ahead baseload prices across the region. Higher midday renewable production could depress hourly quotations without materially reducing evening scarcity or demand for dispatchable capacity.
The forward market continued pricing regional risk premiums with a significant Hungarian premium over Germany for multiple contracts. The Hungarian week 43 contract rose to €270/MWh compared with €201.50/MWh for the corresponding German contract, producing a forward premium of €68.50/MWh.
Hungary’s November baseload contract stood at €242.50/MWh against Germany at €195/MWh; the Hungarian calendar-year 2027 baseload contract was quoted at €168.50/MWh versus Germany’s €145.50/MWh.
EUA carbon allowances were quoted at approximately €87.14 per tonne, slightly lower on the day, while November coal futures declined to €148 per tonne. The modest easing in carbon and coal indicators did not prevent pronounced increases in regional electricity spot prices as physical balances and transmission conditions remained immediate drivers.
Batteries expand as spot spreads highlight flexibility needs
The sharp hourly price differences reinforced interest in flexible electricity assets including batteries that can combine wholesale arbitrage with balancing and ancillary services across changing price periods within days.
Romania was cited as one of the more active regional markets for storage plans: Helleniq Energy planned at least 500 MW of battery storage over the next three years. R.Power was progressing a standalone battery project of 100 MW/200 MWh at Studina alongside its larger Scornicesti development.
The source also noted that wide spot spreads do not automatically translate into bankable storage revenues because investors must account for round-trip efficiency, battery degradation, network charges, imbalance settlement and trading restrictions alongside risks that additional capacity compresses spreads used in investment assumptions.
The trading pattern on 15 October pointed to strong price convergence between Serbia and Hungary alongside large north-south spreads and rapidly changing import requirements across regional systems.