Southeast European electricity markets stayed under price pressure for delivery on 13 October, with Serbia recording the highest day-ahead price among the regional markets covered. The gap between Hungary and Germany widened, reflecting continued barriers to electricity price convergence across Central and Southeastern Europe. Several exchanges still traded around the mid-€220s per megawatt-hour.
Serbia’s SEEPEX day-ahead baseload price reached €228.17/MWh, down €2.60 from the previous session. Hungary’s HUPX benchmark fell €11.90 to €223/MWh. Montenegro’s BELEN settled at €206.40/MWh, while Greece and Bulgaria traded at around €224.60/MWh.
Germany saw the largest day-ahead move, with prices down €37 to €160.23/MWh. That decline widened Hungary’s premium over Germany to €62.78/MWh, up €25.10. Cross-border imports continued to support regional supply as prices remained separated between Germany and more expensive eastern European markets.
Demand-supply balance and generation outlook
Electricity consumption across Hungary and Southeast Europe was forecast to rise by 858 MW to 31,194 MW on Tuesday. Net regional imports were expected to decline by 732 MW to 2,946 MW. The combination of higher demand and lower imports pointed to a larger role for regional generation, without bringing Southeast European prices closer to German levels.
Regional electricity production was projected to increase from 26,659 MW to 28,249 MW, a gain of 1,590 MW. Wind generation was forecast to rise by 1,458 MW to 4,316 MW, partly offsetting a 978 MW decline in solar output to 2,685 MW. The figures indicated that stronger renewables could reduce import dependence without necessarily removing the regional price premium.
National balances and generation availability
Serbia remained among the most import-dependent markets in absolute terms, with consumption forecast at 3,728 MW versus domestic generation of 2,699 MW. That left 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 shifted from near balance on Monday to a small net export of 23 MW on Tuesday. Romania’s forecast net imports fell 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 remained exposed to generation risks tied to hydrology and nuclear availability. Both reactors at the Cernavodă nuclear power plant were expected to remain unavailable until at least 21 October following exceptionally low Danube water levels. With nuclear generation absent from the reported Romanian electricity mix, the country relied more on hydropower, wind, gas and imported electricity.
Exchange price moves and intraday volatility
Price changes across exchanges were uneven on the day-ahead curve. Romania’s OPCOM benchmark declined to €218.37/MWh, while Croatia and Slovenia fell to €214.46/MWh and €212.83/MWh respectively. North Macedonia’s MEMO rose €17.40 to €215.84/MWh as Greece gained €6.50 to €224.57/MWh.
Intraday profiles also fluctuated sharply in both Serbia and Hungary. Serbia’s hourly SEEPEX price reached €320/MWh during hour eight after a minimum of €165/MWh in hour two. Hungary recorded a peak of €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 differences between morning and evening supply conditions versus midday trading periods. Italy showed additional internal fragmentation between zones: the southern bidding zone averaged just €148.20/MWh including one hour at zero, while northern Italy averaged approximately €224.60/MWh.
Forward power and carbon-linked fuel costs
Forward electricity pricing provided limited evidence of a sustained near-term correction. Hungarian week 43 baseload traded at €246/MWh before week 44 rose €15.50 to €240/MWh. The November Hungarian contract increased to €237/MWh and held a €44/MWh premium over the equivalent German November contract priced at €193/MWh.
The German-Hungarian week 43 spread stood at €52.50/MWh as fuel and carbon costs moved higher alongside forward power levels. The Austrian CEGH gas benchmark increased €4.50 to €85.27/MWh while EU carbon allowances rose €1.40 to €88.34 per tonne.
The combination of higher gas and emissions costs supported expensive thermal generation when renewable output and imports could not fully cover regional demand conditions reflected in forward premiums for coming weeks.
The October 13 balance highlighted a structural pattern in Southeast European electricity trading: stronger regional generation reduced net imports while prices remained above €200/MWh across most exchanges covered in the reporting set.