Southeast European electricity markets remained under significant price pressure for delivery on 13 October, with Serbia recording the highest day-ahead price among the regional markets covered, while a widening premium between Hungary and Germany highlighted persistent constraints on electricity price convergence across Central and Southeastern Europe.
Serbia’s SEEPEX day-ahead baseload price reached €228.17/MWh, down €2.60 from the previous session, while Hungary’s HUPX benchmark declined €11.90 to €223/MWh. Montenegro’s BELEN settled at €206.40/MWh, maintaining a substantial discount to Serbia and Hungary. Greece and Bulgaria traded around €224.60/MWh, confirming that relatively expensive electricity remains a regional characteristic despite softer prices in several markets.
The most consequential movement came from Germany, where day-ahead electricity fell €37 to €160.23/MWh, widening Hungary’s premium over Germany to €62.78/MWh, an increase of €25.10. The divergence reflects continuing price separation between Germany’s electricity market and more expensive eastern markets, even as substantial cross-border imports support regional supply.
The underlying physical balance illustrates the tension. Electricity consumption across Hungary and Southeast Europe was forecast to increase by 858 MW to 31,194 MW on Tuesday, while net regional imports were expected to decline by 732 MW to 2,946 MW. The simultaneous increase in demand and reduction in imports indicates a greater contribution from regional generation, but not enough price relief to bring Southeast European benchmarks closer to German levels.
The forecast generation balance provides some relief. Regional production was projected to increase from 26,659 MW to 28,249 MW, a gain of 1,590 MW, sufficient to accommodate higher demand while reducing net imports. Wind output was forecast to rise by 1,458 MW to 4,316 MW, partly offsetting a 978 MW reduction in solar generation to 2,685 MW. The figures suggest that stronger renewable output can reduce dependence on imported electricity without necessarily eliminating the regional price premium.
Serbia remained among the most import-dependent markets in absolute terms. Its electricity consumption was forecast at 3,728 MW, against domestic generation of 2,699 MW, leaving net imports of approximately 1,029 MW. Hungary faced a larger deficit of 1,570 MW, while Bosnia and Herzegovina was expected to export 478 MW. Montenegro moved from a near-balanced position on Monday to a small net export of 23 MW on Tuesday.
Romania’s position improved considerably, with forecast net imports falling from 1,190 MW to just 253 MW, as domestic generation increased to almost 6,000 MW. Bulgaria moved in the opposite direction, switching from a marginal net export of 9 MW to imports of 277 MW, while Greece’s export surplus contracted from 585 MW to 168 MW.
Romania nevertheless remains exposed to significant generation risks. Both reactors at the Cernavoda nuclear plant are expected to remain unavailable until at least 21 October, following exceptionally low Danube water levels. Nuclear output remains absent from the reported Romanian generation mix, leaving the country more dependent on hydroelectric, wind, gas and imported power. Further hydrological deterioration or weaker renewable production could quickly reverse the improvement in Romania’s electricity balance.
Price movements across individual exchanges were uneven. Romania’s OPCOM benchmark declined to €218.37/MWh, while Croatia and Slovenia fell to €214.46/MWh and €212.83/MWh respectively. By contrast, North Macedonia’s MEMO rose €17.40 to €215.84/MWh and Greece gained €6.50 to €224.57/MWh. These opposing movements underline the importance of national generation availability, cross-border schedules and hourly demand patterns rather than a single regional supply indicator.
Intraday price profiles also remained volatile. Serbia’s hourly SEEPEX price reached €320/MWh during hour eight, compared with a minimum of €165/MWh in hour two. Hungary similarly reached €284.30/MWh during hour eight, with its lowest hourly price at €164.40/MWh. In both markets, average off-peak prices exceeded average peak prices, reflecting the importance of morning and evening supply conditions relative to the midday trading period.
Italy demonstrated another form of market fragmentation. The southern bidding zone averaged only €148.20/MWh, including an hour at zero, while northern Italy averaged approximately €224.60/MWh. The difference of more than €76/MWh illustrates the extent to which internal network conditions and renewable generation patterns can separate prices within a single national electricity market.
Forward electricity markets offered little indication of a sustained near-term price correction. Hungarian week 43 baseload traded at €246/MWh, while week 44 increased €15.50 to €240/MWh. The November Hungarian contract rose to €237/MWh, maintaining a €44/MWh premium over the equivalent German November contract at €193/MWh. The German-Hungarian week 43 spread stood at €52.50/MWh.
Fuel and carbon markets reinforced the forward-price pressure. The Austrian CEGH gas benchmark increased €4.50 to €85.27/MWh, while EU carbon allowances rose €1.40 to €88.34 per tonne. Higher gas and emissions costs continue to support expensive thermal generation, particularly when renewable output and imports cannot fully cover regional demand.
For electricity traders, industrial consumers and renewable energy investors, the principal risk remains the combination of high absolute prices, substantial cross-border differences and volatile hourly spreads. Forward premiums indicate that the market continues to price in tight conditions through the coming weeks, rather than treating the latest spot-price declines as the start of a sustained correction.
The October 13 balance illustrates the central contradiction in Southeast European electricity trading: stronger regional generation can reduce imports substantially, yet prices may remain above €200/MWh across most exchanges. Until additional flexible generation, storage and usable interconnection capacity reduce that dependence on marginal thermal production and constrained cross-border supply, short-term weather improvements are unlikely to remove the region’s structural price premium.
