January 2026 has highlighted significant challenges in the electricity markets of South-East Europe, particularly regarding cross-border capacity and congestion management. The month saw electricity prices surge not due to a lack of generation capacity but as a direct result of transmission constraints that hindered regional balancing during peak demand periods. This fragmentation of the market, which is intended to operate as an interconnected system, was exacerbated by binding transmission limitations.
During the coldest days of January, day-ahead electricity prices across key hubs such as Serbia, Hungary, Romania, and Bulgaria diverged sharply, often ranging between €115 and €135 per megawatt-hour (MWh). In contrast, neighboring markets could not export lower-priced electricity due to saturated interconnectors, leading to persistent price spreads of €20 to €40/MWh across borders that should theoretically allow for arbitrage within hours.
The primary constraints were observed along critical north-south and east-west corridors that link South-East Europe to Central Europe and within the Balkans. Interconnections such as those between Hungary and Serbia, Romania and Bulgaria, Bulgaria and Greece, and Croatia and Hungary frequently operated at or near full capacity during peak hours. Once these limits were reached, local marginal prices were determined by the costs associated with gas-fired or lignite generation instead of reflecting broader regional supply dynamics.
A quantitative analysis reveals the severity of these constraints: a single 1 GW constrained border during 6 to 8 peak winter hours can trap 6 to 8 GWh of higher-cost generation within a national system. With a price differential of €30/MWh, this translates into an implicit congestion rent of approximately €180,000 to €240,000 per day. Over several weeks in January, the economic impact from congestion-driven price fragmentation amounted to tens of millions of euros.
These congestion rents primarily benefited transmission system operators, underscoring the scarcity value of cross-border capacity. However, January’s events illustrated that current timelines for grid reinforcement are lagging behind the rapid emergence of price volatility. For market participants, these congestion revenues represent inefficiencies rather than solutions.
For traders operating in this environment, January exemplified a classic congestion market scenario. Those holding physical transmission rights or strategically positioned cross-border portfolios were able to capitalize on price spreads largely disconnected from energy fundamentals. Conversely, traders lacking firm capacity found themselves excluded from arbitrage opportunities despite prevailing price signals.
Generators faced asymmetric impacts due to congestion. Plants situated in import-constrained areas benefitted from elevated local prices even when cheaper alternatives existed just across borders. In contrast, generators in export-capable regions experienced price suppression when unable to access higher-priced neighboring markets fully. This uneven landscape distorted short-run dispatch efficiency and challenged the concept of a unified regional market.
The integration of renewable energy sources was notably affected as well. Surpluses from wind or hydro generation could not effectively lower prices in adjacent markets due to interconnectors being saturated with baseload and thermal flows. Thus, January demonstrated that renewable integration is increasingly limited by grid topology rather than generation availability; adding wind capacity does not alleviate regional winter prices if it cannot reach deficit zones during peak demand periods.
From the perspective of industrial buyers, congestion translated directly into elevated procurement costs. Large consumers located behind constrained borders faced local scarcity prices despite cheaper options available in neighboring markets. This situation reinforces a geographic competitiveness divide within South-East Europe where industrial cost structures are influenced not only by national policies or generation mixes but also by their specific locations within the transmission network.
The interplay between congestion and gas pricing proved critical during this period. Once interconnectors reached saturation points, gas-fired plants became the marginal price-setters in isolated zones. Each additional €10/MWh increase in gas prices correspondingly raised local electricity prices without relief from imports. Consequently, January illustrated how grid constraints can amplify fuel price shocks rather than merely transmit them.
Capacity allocation mechanisms also came under scrutiny during this time. While market coupling operated effectively as designed, it became evident that allocation efficiency could not compensate for insufficient capacity volume. Well-functioning auctions merely rationed scarcity rather than eliminating it altogether—a distinction that carries significant implications for regulators as it shifts focus from market design to infrastructure adequacy.
Looking ahead, January has reinforced the economic argument for targeted investments in grid infrastructure rather than generic enhancements. The most valuable investments would expand corridors that consistently face binding constraints during winter peaks—especially those connecting wind- and hydro-rich systems with demand-heavy industrial zones. Incremental increases in capacity of even 500 to 800 MW on critical borders could significantly alleviate winter price volatility by restoring arbitrage opportunities during stress periods.
This month also highlighted the necessity for regional coordination in grid development efforts. Unilateral national approaches risk perpetuating market fragmentation; the observed price behavior reflects systemic strain rather than isolated failures at the national level. Without coordinated planning among transmission system operators (TSOs) and regulators, South-East Europe may entrench a two-speed electricity market where price convergence occurs only under low-stress conditions.
In conclusion, January 2026 reframed cross-border capacity from a technical detail into a primary driver of electricity pricing within South-East Europe. Prices were not merely elevated; they were locationally distinct—shaped by which borders experienced congestion at any given time. As long as winter demand growth intersects with gas pricing pressures and insufficient interconnection capabilities, congestion will continue to influence pricing dynamics alongside generation costs.
