During the coldest periods of January 2026, day-ahead prices at key hubs in South-East Europe separated sharply. While Serbia, Hungary, Romania and Bulgaria often cleared in the €115–135/MWh range, neighbouring markets could not export enough lower-priced power when interconnectors were saturated. The gap between adjacent markets persisted as price spreads of €20–40/MWh, and sometimes higher.
Decoupling across hubs as interconnectors reached saturation
The price divergence was linked to cross-border transfer limits rather than aggregate generation shortages. Neighbouring systems with different supply-demand balances were unable to move sufficient electricity across borders during peak conditions. As a result, arbitrage that would normally narrow differences within hours did not work when transmission capacity was fully used.
The constraint affected both north-south and east-west corridors connecting South-East Europe with Central Europe and within the Balkans. Interconnections including Hungary–Serbia, Romania–Bulgaria, Bulgaria–Greece and Croatia–Hungary repeatedly operated at or near full capacity during peak hours. Once those limits were reached, marginal pricing became locally determined.
Locally set marginal prices tied to gas and lignite costs
After interconnector limits were hit, prices in constrained areas reverted to the cost of gas-fired or lignite generation rather than reflecting regional supply conditions. This contributed to persistent fragmentation across borders that are part of an interconnected system. The pattern was observed during winter peak periods when demand and balancing needs intensified.
A quantitative example highlighted the scale of the effect: a single 1 GW constrained border during 6–8 peak hours per day can restrict transfers equivalent to 6–8 GWh. With a price differential of €30/MWh, this implies €180,000–240,000 per day in implicit congestion rent and consumer cost transfer. When repeated across several borders over multiple weeks in January, the congestion-driven fragmentation reached tens of millions of euros.
Congestion rents and market access under stress
Congestion rents accrued primarily to transmission system operators due to the scarcity value of cross-border capacity. Although such revenues are often earmarked for grid investment, January indicated that reinforcement timelines can lag behind the pace of emerging price volatility. In market terms, congestion income reflected scarcity rather than resolving underlying inefficiency.
For traders, January functioned as a congestion market where outcomes depended on access to constrained borders. Participants with physical transmission rights or well-positioned cross-border portfolios captured spreads that were largely independent of energy fundamentals. Traders without firm capacity were structurally excluded from arbitrage even when price signals suggested opportunities.
Asymmetric impacts for generators, renewables and industrial buyers
Generators faced uneven outcomes depending on their location relative to import-constrained and export-capable zones. Plants in import-constrained areas benefited from higher local prices even when cheaper electricity was available just across the border. Conversely, generators in export-capable zones experienced price suppression when they could not fully access higher-priced neighbouring markets.
Renewables, including wind and hydro, were also affected by saturated interconnectors. Surpluses in one system could not reliably dampen prices in adjacent markets because transfers were already constrained by baseload and thermal flows. The effect described for January was that renewable integration was limited more by grid topology than by generation availability.
Industrial buyers saw congestion translate into higher procurement costs behind constrained borders. Large consumers located where interconnectors were saturated paid local scarcity prices even when neighbouring markets were materially cheaper. The resulting pattern reinforced a geographic competitiveness divide within South-East Europe based on asset location within the transmission network.
Gas price shocks amplified by saturated interconnectors
The interaction between congestion and fuel pricing was described as decisive once interconnectors saturated. In isolated zones, gas-fired plants became marginal price-setters, linking local electricity prices closely to gas costs. Each additional €10/MWh increase in gas prices translated almost mechanically into higher local electricity prices without relief from imports.
Auction-based allocation could not offset insufficient capacity volume
Auction-based allocation mechanisms under scrutiny during January peaks
Toward targeted corridor expansion and coordinated planning
The outlook described for January emphasized targeted grid investment rather than generic reinforcement. The highest value was linked to expanding corridors that repeatedly bind during winter peaks, particularly connections between wind- and hydro-rich systems and demand-heavy industrial zones. Incremental capacity increases of 500–800 MW on critical borders were cited as capable of reducing winter price volatility by restoring arbitrage during stress hours.
The same period also highlighted the role of regional coordination for grid development planning. Unilateral national approaches were described as risking continued fragmentation across the region. Without coordinated planning across transmission system operators and regulators, South-East Europe risked entrenching a two-speed electricity market where price convergence occurs only under low-stress conditions.
Cross-border capacity treated as a first-order driver of winter pricing
The overall framing attributed January’s outcome to cross-border capacity limits becoming a primary driver of locational pricing in South-East Europe. Electricity prices were described as not only high but also locationally high depending on which borders were congested and at what times during winter demand peaks. The persistence of congestion was tied to the intersection of winter demand growth, gas marginal pricing and renewable seasonality with insufficient interconnection capacity.
The period was characterized as consistent with system operation under existing design parameters rather than a market malfunction. The question raised within the source material concerned whether winter congestion would remain a recurring determinant or whether cross-border capacity expansion would become as central to energy policy as renewable deployment.