January 2026 confirmed that South-East Europe’s electricity markets have entered a structurally different phase from the crisis years of 2022–2024. Prices remained elevated by historical standards, but the defining change was the return of tradable liquidity. Volumes increased, cross-border flows intensified, and professional trading activity reasserted itself across organised exchanges and interconnector corridors. The region moved away from emergency-style power allocation and back toward market-driven optimisation.
The clearest signal came from the Serbian day-ahead market operated by SEEPEX. During the first half of January, average daily traded volumes consistently ranged between 12.9 GWh and 16.5 GWh, with several sessions clearing above 15 GWh. On a full-month basis, this implies total January volumes in the range of 420–450 GWh, representing a material increase versus January 2025, when regulatory uncertainty and bilateral contracting had depressed exchange participation.
Price behaviour underscored the return of genuine market dynamics. Day-ahead averages oscillated between €66.9/MWh on high-hydro, mild-weather days and peaks above €125/MWh during cold spells and tighter system conditions. Crucially, rising prices did not trigger a collapse in volume. Instead, liquidity held, indicating that generators, traders and large consumers were again willing to expose positions to the market rather than retreat into fixed bilateral cover.
At the regional level, January’s winners were not simply the cheapest markets, but those with exportable baseload, flexible generation and cross-border access. In this respect, Bulgaria and Romania clearly dominated.
Bulgaria entered the winter with one of the strongest structural positions in SEE. Nuclear output from Kozloduy provided a stable baseload of roughly 2 GW, while lignite plants continued operating despite higher carbon costs. This allowed Bulgaria to maintain wholesale prices largely within a €95–115/MWh band, making it consistently competitive as an exporter into Serbia, Greece and North Macedonia. Export volumes increased precisely during hours when neighbouring systems faced tighter balances, reinforcing Bulgaria’s role as a regional anchor.
Romania followed a similar pattern, supported by its diversified generation mix. Nuclear, hydro, wind and gas provided Romania with optionality that few SEE markets can match. Day-ahead prices typically ranged between €90 and €120/MWh, enabling both exports and profitable arbitrage against higher-priced zones. Romania’s flexibility during intraday ramps further increased its trading relevance, particularly during forecast deviations in wind output.
Cross-border capacity became one of the most valuable assets of January 2026. Interconnectors linking Greece–Bulgaria, Romania–Hungary and Serbia–Hungary operated at high utilisation rates, with directional price spreads frequently exceeding €5–8/MWh. These spreads translated directly into congestion rents and trading margins, rewarding participants with secured transmission rights and the operational capability to move power across borders at short notice.
This environment strongly favoured professional trading houses with regional portfolios. International players such as Axpo, MET Group, Statkraft, RWE Supply & Trading and Engie Trading were among the most active participants across SEE hubs. Their advantage lay in portfolio breadth rather than single-asset ownership, allowing them to optimise positions simultaneously across SEE, Central Europe and Italy.
Regional incumbents also played a visible role. EPS acted as a key seller during periods of favourable hydro conditions, while Serbian hydro operators provided valuable intraday flexibility. In Croatia, HEP used hydro optimisation to stabilise domestic supply while selectively exporting surplus into neighbouring markets. Greece’s PPC increasingly operated as both buyer and seller, reflecting Greece’s transition from a structurally import-dependent system toward a more balanced, renewables-supported trading profile.
Flexibility emerged as one of January’s most monetised attributes. Hydro cascades, pumped storage and fast-responding assets captured significant value as intraday price spreads frequently reached €20–40/MWh between midday oversupply and evening peak demand. Although full 15-minute trading has not yet been uniformly implemented across SEE, price behaviour increasingly reflected shorter-interval logic, rewarding assets capable of rapid response rather than static baseload operation.
From a market-structure perspective, January 2026 also highlighted the gradual unwinding of crisis-era distortions. Emergency price caps, export restrictions and politically driven dispatch rules that dominated 2022–2024 had largely receded. In their place, a more pragmatic coexistence of bilateral contracts and exchange trading re-emerged. Industrial consumers returned to day-ahead markets to manage marginal exposure, while generators increasingly used spot markets to monetise incremental output rather than locking everything into long-term deals.
Institutionally, SEEPEX itself benefited from this shift. Higher throughput improved price discovery and reduced risk premiums embedded in bilateral contracts. Clearing days above 15 GWh placed the exchange firmly among Europe’s more liquid secondary hubs, strengthening its role as a reference point not only for Serbia but for the wider Western Balkans.
The losers of January were also visible. Import-dependent systems with limited flexibility, particularly North Macedonia and parts of Bosnia and Herzegovina, remained exposed to peak-hour prices frequently exceeding €120/MWh. Their constrained ability to export during low-price hours or arbitrage intraday volatility translated into structurally higher procurement costs.
For industrial buyers, January 2026 did not signal a return to cheap electricity. It signalled something arguably more important: a market that can be traded, hedged and optimised again. Elevated prices persisted, but liquidity, transparency and cross-border access allowed buyers to construct layered procurement strategies instead of locking in full-year exposure at crisis-level risk premiums.
January 2026 therefore stands less as a turning point and more as confirmation of a new equilibrium in South-East Europe. Power remains expensive, but markets function. Winners are no longer defined solely by installed capacity, but by connectivity, flexibility and trading sophistication. Export-capable systems, diversified generation mixes and professional trading portfolios now shape outcomes across the region.
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