January 2026 showed a shift in South-East Europe’s electricity trading conditions compared with the crisis years of 2022–2024. Prices stayed elevated by historical standards, while tradable liquidity returned. Volumes increased and cross-border flows intensified, with professional trading activity expanding across organised exchanges and interconnector corridors. The region also moved away from emergency-style power allocation toward market-driven optimisation.
SEEPEX day-ahead volumes and price levels
The clearest signal came from the Serbian day-ahead market run by SEEPEX. In the first half of January, average daily traded volumes ranged from 12.9 GWh to 16.5 GWh, with multiple sessions clearing above 15 GWh. On a full-month basis, total January volumes were estimated at 420–450 GWh, higher than January 2025 when regulatory uncertainty and bilateral contracting reduced exchange participation.
Day-ahead prices reflected a return to market-led behaviour. Average levels moved between €66.9/MWh on high-hydro, mild-weather days and above €125/MWh during cold spells and tighter system conditions. Higher prices did not reduce traded volumes, as liquidity remained in place. Generators, traders and large consumers continued to expose positions to the market rather than relying solely on fixed bilateral cover.
Exportable systems and generation mix drive regional outcomes
Across the region, January’s strongest performers were linked to exportable baseload, flexible generation and cross-border access. Bulgaria and Romania accounted for much of the dominance described for the period. Their ability to combine stable supply with trading flexibility supported both exports and intraday optimisation.
Bulgaria entered winter with a structural position supported by Kozloduy. Nuclear output from the plant provided baseload of roughly 2 GW, while lignite units continued operating despite higher carbon costs. Wholesale prices were largely maintained within a €95–115/MWh band, supporting competitiveness as an exporter into Serbia, Greece and North Macedonia. Export volumes increased during hours when neighbouring systems faced tighter balances.
Romania’s position was supported by a diversified generation mix including nuclear, hydro, wind and gas. Day-ahead prices typically ranged between €90 and €120/MWh, supporting export activity and arbitrage versus higher-priced zones. Intraday ramps also contributed to trading relevance, particularly when wind output forecasts deviated from actual conditions.
Interconnector spreads and congestion rents across corridors
Cross-border capacity became a key value driver in January 2026. Interconnectors connecting Greece–Bulgaria, Romania–Hungary and Serbia–Hungary operated at high utilisation rates. Directional price spreads frequently exceeded €5–8/MWh. These spreads fed into congestion rents and trading margins for participants holding secured transmission rights.
The corridor economics supported trading strategies across multiple hubs in Southeast Europe. Professional trading houses with regional portfolios were among the most active participants described for the period. International firms including Axpo, MET Group, Statkraft, RWE Supply & Trading and Engie Trading operated across SEE alongside Central Europe and Italy.
Incumbent roles and monetisation of short-term flexibility
Eps, Serbian hydro operators, Croatian utility HEP, and Greece’s PPC were also cited as visible participants in January trading dynamics. EPS acted as a key seller during periods of favourable hydro conditions, while Serbian hydro operators provided intraday flexibility. In Croatia, HEP used hydro optimisation to stabilise domestic supply while selectively exporting surplus into neighbouring markets. Greece’s PPC operated as both buyer and seller as the system moved toward a more balanced profile supported by renewables.
Flexibility was highlighted as one of the most monetised attributes in January 2026. Hydro cascades, pumped storage and fast-responding assets captured value when intraday price spreads reached €20–40/MWh. The spreads were linked to differences between midday oversupply and evening peak demand. Although full 15-minute trading had not been uniformly implemented across SEE, price behaviour increasingly reflected shorter-interval logic that rewarded rapid-response assets over static baseload operation.
Evolving market structure after crisis-era constraints
The month also reflected an easing of crisis-era distortions described for 2022–2024. Emergency price caps, export restrictions and politically driven dispatch rules had largely receded by January 2026. Bilateral contracts coexisted with exchange trading again under a more pragmatic structure. Industrial consumers returned to day-ahead markets to manage marginal exposure, while generators used spot markets to monetise incremental output instead of locking all production into long-term deals.
SSEEPEX-level changes were also tied to higher throughput during the period. Improved throughput supported price discovery and reduced risk premiums embedded in bilateral contracts. Clearing days above 15 GWh placed SEEPEX among Europe’s more liquid secondary hubs described for the month. The exchange’s role expanded beyond Serbia toward wider Western Balkans participation.
Peak-hour exposure in import-dependent systems
The report also identified systems that underperformed relative to export-capable areas in January 2026. Import-dependent markets with limited flexibility—particularly North Macedonia and parts of Bosnia and Herzegovina
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