Day-ahead electricity prices across Central and Southeast Europe fell sharply on 13 March 2026, driven primarily by stronger cross-border imports from the CORE region, stable temperatures, and increased thermal generation offsetting weaker renewable output. The regional price structure continued to track developments on the Hungarian HUPX benchmark, which remained the primary liquidity hub for power trading in the wider SEE market.
Spot prices declined across most exchanges compared with the previous trading day. Hungary’s HUPX day-ahead price settled at €105.96/MWh, representing a drop of €28.8/MWh day-on-day, while neighboring markets showed similar downward corrections. Romania’s OPCOM cleared at €93.93/MWh, Bulgaria’s IBEX at €92.28/MWh, Greece’s HENEX at €89.55/MWh, and Slovenia’s BSP and Croatia’s CROPEX both around €91.93/MWh. The Serbian SEEPEX price averaged €102.08/MWh, maintaining a small premium to surrounding markets due to limited cross-border capacity and continued domestic thermal dispatch.
The regional price minimum was observed in Albania’s ALPEX market at €79.76/MWh, while the highest spot levels remained in the Italian market at €146.58/MWh, reflecting the persistent structural price premium in Italy due to gas-linked generation and transmission constraints between the Adriatic markets and the Italian peninsula.
Demand and system balance
Electricity consumption across the Hungary + SEE region was forecast at approximately 32,917 MW, slightly lower than the previous day. Average temperatures remained stable at around 8.6°C, limiting weather-driven demand increases and contributing to softer power prices.
Despite weaker demand, the region continued to rely on imports from the CORE European market. Net power imports averaged -837 MW, reflecting stronger inflows particularly from the Austria and Slovakia interconnection corridor, which delivered about 1,960 MW of power into the regional system.
The Hungary–Germany price spread widened to €57.53/MWh, incentivising cross-border flows from Western Europe into Central Europe and reinforcing downward pressure on regional day-ahead prices.
Generation mix
Regional electricity generation totaled roughly 33,243 MW, with the supply structure dominated by hydro and thermal plants. Hydro production accounted for 8,502 MW, supported by improved river flows across the Danube basin. Coal-fired generation remained significant at 6,984 MW, while gas plants supplied about 5,528 MW as marginal units during peak hours.
Renewable output weakened compared with the previous day. Wind generation dropped sharply to 629 MW, while solar production decreased to 4,526 MW, partly due to cloudier conditions across Central Europe. Nuclear output remained stable at 5,702 MW, mainly from plants in Hungary, Romania and Bulgaria.
Hydropower therefore represented the largest single component of the regional generation mix at approximately 26%, followed by coal and gas combined with around 39% of total output.
Fuel and carbon markets
Fuel markets presented mixed signals for forward power pricing. The CEGH Austrian gas hub traded around €51.55/MWh, showing a daily increase of €1.7/MWh, while EU carbon allowances (Dec-26 EUA) remained near €70–75/t, slightly lower on the week.
Forward power spreads reflected this structure. Hungarian forward contracts were quoted around €118/MWh for week 12 and €113/MWh for week 13, indicating expectations of continued tightness in the regional market despite the day-ahead correction.
Coal futures on the API2 benchmark were trading around $127–128/t for April-2026, supporting the continued operation of coal-fired generation across Southeast Europe where carbon pricing remains lower than in the EU ETS zone.
Cross-border flows
Commercial flows over the past week show persistent export patterns from Romania and Hungary toward Serbia and the Western Balkans, while electricity also moved from Slovenia and Croatia toward Italy through the Alpine interconnections.
The Romania-Hungary corridor remained one of the most active cross-border routes, supporting balancing flows across Central and Eastern Europe. Meanwhile Serbia continued importing power from Hungary and Bosnia and Herzegovina, highlighting the region’s structural reliance on neighboring generation during periods of lower domestic renewable output.
Market news impacting power fundamentals
Several regional developments also shaped trading sentiment. Serbia confirmed that electricity exports to the EU have effectively stopped since January 2026 because the EU’s CBAM carbon charge adds roughly €78/MWh to Serbian power exports, making them uncompetitive compared with EU-generated electricity.
At the same time, Serbia temporarily suspended new renewable connection approvals, citing grid stability concerns after a surge in project applications exceeding the system’s integration capacity. This decision may delay the addition of new renewable capacity in the near term, potentially supporting regional power prices if demand rises later in the year.
Elsewhere in the region, Slovenia added about 230 MW of solar capacity in 2025, bringing its total installed solar fleet to roughly 1,650 MW, although growth slowed compared with earlier years as support schemes changed.
Short-term outlook
For the coming trading sessions, electricity prices across SEE will continue to be influenced by three dominant drivers.
First, cross-border flows from the CORE market are likely to remain strong as long as the Hungary-Germany spread stays above €50/MWh, maintaining pressure on Central European prices.
Second, renewable variability remains high in early spring. With wind output currently very low, any recovery in wind generation could trigger additional downward pressure on day-ahead markets across Romania, Hungary and Bulgaria.
Third, structural regulatory factors are increasingly shaping regional electricity flows. The CBAM-related collapse of Serbian power exports to the EU may redirect electricity toward intra-Balkan trading routes rather than Western European markets, gradually reshaping the SEE power flow map during 2026.
In the near term, traders expect the €90–110/MWh corridor to remain the central trading range for most Southeast European day-ahead markets, with volatility primarily driven by renewable output and cross-border capacity availability.