Southeast European electricity markets were under significant price pressure for delivery on 13 October, with Serbia recording the highest day-ahead price among the regional exchanges covered. Serbia’s SEEPEX day-ahead baseload settled at €228.17/MWh, down €2.60 from the previous session. Hungary’s HUPX benchmark fell €11.90 to €223/MWh, while Montenegro’s BELEN closed at €206.40/MWh.
Greece and Bulgaria traded at around €224.60/MWh, indicating that high electricity prices remained widespread across the region despite declines in some markets. The largest single move was in Germany, where day-ahead electricity prices dropped €37 to €160.23/MWh. As a result, Hungary’s premium over Germany widened to €62.78/MWh, up €25.10.
Germany’s drop widens Hungary-Germany premium
The widening spread highlighted persistent barriers to electricity price convergence across Central and Southeastern Europe. Cross-border imports continued to support regional electricity supply even as prices separated between Germany and more expensive eastern European markets. The day-ahead pricing gap remained a key feature of the regional market snapshot for 13 October.
Demand rises while net imports fall
Physical balance forecasts pointed to tighter alignment between demand and supply across the region. Electricity consumption across Hungary and Southeast Europe was expected to increase by 858 MW to 31,194 MW on Tuesday, while net regional imports were projected to decline by 732 MW to 2,946 MW. The combination of higher demand and lower imports implied greater reliance on regional generation.
Regional production was forecast to rise from 26,659 MW to 28,249 MW, an increase of 1,590 MW. Wind output was expected to grow by 1,458 MW to 4,316 MW, partially offsetting a 978 MW decline in solar generation to 2,685 MW. The outlook suggested that stronger renewables could reduce import dependence without necessarily narrowing the regional price premium.
National import positions diverge across the region
Serbia remained among the most import-dependent markets in absolute terms, with forecast consumption of 3,728 MW. Domestic generation was expected at 2,699 MW, leaving net imports of approximately 1,029 MW. Hungary faced a larger deficit of 1,570 MW, while Bosnia and Herzegovina were expected to export 478 MW.
Montenegro shifted from near-balanced conditions on Monday to a small net export of 23 MW on Tuesday. Romania’s balance improved as forecast net imports fell from 1,190 MW to just 253 MW, with domestic generation rising to almost 6,000 MW. Bulgaria moved in the opposite direction by 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.
Cernavodă outage risk weighs on Romania’s outlook
Cernavodă nuclear plant availability remained a constraint for Romania. Both reactors are expected to stay unavailable until at least 21 October after exceptionally low Danube water levels. Nuclear generation is reported as absent from Romania’s electricity mix during this period. That leaves Romania more dependent on hydropower, wind, gas and imported electricity.
Differing exchange prices and volatile intraday spreads persist on 13 October [SEE electricity markets: Serbia records highest prices as Hungarian-German spread widens and regional import dependence persists]
Earnings across exchanges were uneven during the same delivery day. 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, while Greece increased by €6.50 to €224.57/MWh.
Intraday profiles also showed volatility 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 in hour eight and a low of €164.40/MWh; average off-peak prices exceeded average peak prices in both markets.
Bidding zones split within Italy; forward prices hold firm [SEE electricity markets: Serbia records highest prices as Hungarian-German spread widens and regional import dependence persists]
A separate split was visible within Italy’s market structure between bidding zones. The southern zone averaged just €148.20/MWh including one hour at zero, while northern Italy averaged about €224.60/MWh. The difference exceeded €76/MWh.
The forward curve showed limited evidence of a sustained near-term correction in Hungary. Hungarian week 43 baseload traded at €246/MWh and week 44 rose by €15.50 to €240/MWh; the November contract increased to €237/MWh with a €44/MWh premium versus the German November contract priced at €193/MWh. The German-Hungarian week 43 spread stood at €52.50/MWh.
Gas and carbon costs support higher forward electricity levels [SEE electricity markets: Serbia records highest prices as Hungarian-German spread widens and regional import dependence persists]
Austrian gas and EU carbon prices reinforced pressure on forward power values. The Austrian CEGH gas benchmark increased by €4.50 to €85.27/MWh, while EU carbon allowances rose by €1.40 to €88.34 per tonne on the same assessment basis.
The regional trading picture continued to reflect high spot levels alongside cross-border differences and hourly volatility across exchanges covered for 13 October . Forward premiums indicated expectations of tight conditions over coming weeks rather than treating recent spot declines as the start of a sustained correction . In the October 13 balance context, stronger regional generation reduced net imports but did not bring most exchange prices below the >€200/MWh range . Until additional flexible generation, energy storage and usable interconnection capacity reduce reliance on marginal thermal output and constrained cross-border supply , weather-driven improvements alone were not expected to remove the structural price premium .
