Central and Southeast Europe’s day-ahead market weakened on 13 March 2026, reflecting a combination of stronger cross-border supply from the CORE region, stable weather conditions, and higher thermal output that compensated for softer renewables. For developers and grid stakeholders, the trading backdrop matters because it influences revenue expectations, dispatch patterns, and the urgency of transmission and balancing investments. The same session also highlighted how interconnector availability and regulatory changes can redirect flows—an operational reality that must be reflected in technical studies and procurement schedules.
Day-ahead price corrections across SEE exchanges
Spot prices fell across most trading venues compared with the previous day, with Hungary’s HUPX setting the tone for regional liquidity. The HUPX day-ahead price settled at €105.96/MWh, down €28.8/MWh day-on-day, while Romania’s OPCOM cleared at €93.93/MWh and Bulgaria’s IBEX at €92.28/MWh. Greece’s HENEX averaged €89.55/MWh, and Slovenia’s BSP together with Croatia’s CROPEX traded around €91.93/MWh.
Serbia’s SEEPEX averaged €102.08/MWh, maintaining a small premium linked to limited cross-border capacity alongside continued domestic thermal dispatch. At the extremes of the regional curve, Albania’s ALPEX recorded a minimum of €79.76/MWh, while Italy remained structurally higher at €146.58/MWh. The Italian premium continues to be associated with gas-linked generation and transmission constraints between Adriatic markets and the Italian peninsula.
Demand steadiness but import dependence drives system balance
System fundamentals were shaped by demand that eased slightly despite stable conditions. Electricity consumption across the Hungary + SEE region was forecast at approximately 32,917 MW, marginally below the previous day, while average temperatures held around 8.6°C. With weather-driven load growth limited, price pressure tilted further downward as supply responded.
Even with weaker demand, the region relied on imports from CORE: net power imports averaged -837 MW. Stronger inflows were particularly linked to the Austria and Slovakia interconnection corridor, delivering about 1,960 MW into the regional system. The Hungary–Germany price spread widened to €57.53/MWh, reinforcing incentives for cross-border movements from Western Europe into Central Europe.
Generation mix: hydro strength offsets weaker wind and lower solar
Regional generation totaled roughly 33,243 MW, with hydro and thermal resources dominating supply structure. Hydro production reached 8,502 MW supported by improved river flows across the Danube basin, while coal-fired generation remained significant at 6,984 MW. Gas plants supplied about 5,528 MW as marginal units during peak hours.
Renewables weakened on the day: wind output dropped sharply to 629 MW and solar production decreased to 4,526 MW amid cloudier conditions across Central Europe. Nuclear generation stayed stable at 5,702 MW across plants in Hungary, Romania and Bulgaria. Hydropower represented about 26% of total generation, while coal and gas combined accounted for around 39%, a mix that can influence how grid operators plan reactive support and flexibility needs for variable renewables.
Fuel signals for forward pricing: gas hub up, EUA slightly lower
Fuel markets sent mixed signals relevant to forward power pricing assumptions used in contracting and scheduling studies. The CEGH Austrian gas hub traded around €51.55/MWh after a daily increase of €1.7/MWh. EU carbon allowances for Dec-26 EUA remained near €70–75/t, slightly lower on the week.
These inputs fed into forward spreads: Hungarian forward contracts were quoted around €118/MWh for week 12 and €113/MWh for week 13. Coal futures on API2 were trading around $127–128/t for April-2026, supporting continued operation of coal-fired generation in Southeast Europe where carbon pricing remains lower than in the EU ETS zone.
Cross-border flows and regulatory shifts reshape where new capacity must fit
Commercial flow patterns over the past week pointed to persistent exports from Romania and Hungary toward Serbia and the Western Balkans, alongside electricity moving from Slovenia and Croatia toward Italy via Alpine interconnections. The Romania–Hungary corridor remained among the most active routes supporting balancing needs across Central and Eastern Europe.
Serbia continued importing power from Hungary and Bosnia and Herzegovina during periods of lower domestic renewable output—an operational dependency that affects how transmission upgrades are prioritized in planning cycles. In parallel, Serbia confirmed that electricity exports to the EU have effectively stopped since January 2026 because CBAM adds roughly €78/MWh to Serbian power exports, making them uncompetitive versus EU-generated electricity.
The same period also brought a planning constraint for renewable development: Serbia temporarily suspended new renewable connection approvals due to grid stability concerns after project applications exceeded system integration capacity. For engineering teams preparing grid impact assessments and connection studies, this kind of approval pause increases uncertainty around queue timing even when resource build-out targets remain unchanged.
Implications for wind, solar and BESS readiness in early spring
The near-term market outlook points to three drivers that can directly affect wind farms, solar portfolios and battery energy storage (BESS) dispatch strategies. First is sustained CORE-driven cross-border pressure as long as the Hungary–Germany spread stays above €50/MWh. Second is renewable variability in early spring: with wind output currently very low, any recovery could push additional downward pressure on day-ahead prices across Romania, Hungary and Bulgaria.
Third are structural regulatory factors increasingly shaping flow patterns; CBAM-related changes to Serbian exports may redirect electricity toward intra-Balkan routes rather than Western European markets during 2026. For developers preparing technical studies—such as grid connection assessments—and EPC preparation work for wind repowering or solar expansion, these dynamics reinforce why curtailment risk analysis and flexibility design need to be embedded early rather than treated as an operational afterthought.
Broader project implications follow from this snapshot: day-ahead prices shifted lower while import dependence remained high; hydro availability improved even as wind weakened; fuel costs moved unevenly; and regulatory actions in Serbia altered both export economics and renewable connection timing constraints. Together these factors underline how transmission infrastructure planning, interconnector capacity assumptions in system studies, procurement sequencing for grid upgrades or BESS integration readiness must align with real-time market behavior across SEE.