January 2026 made one structural reality unmistakably clear across South-East Europe: electricity prices did not diverge because markets lack generation in aggregate, but because cross-border capacity and congestion management failed precisely when regional balancing was most needed. The winter price spikes observed across SEE were not only a function of fuel costs and demand; they were amplified, and in some cases created, by binding transmission constraints that fragmented what is nominally an interconnected market.
During the coldest January periods, day-ahead prices across key SEE hubs decoupled sharply. While Serbia, Hungary, Romania and Bulgaria frequently cleared in the €115–135/MWh range, neighbouring markets with different supply-demand balances could not export sufficient lower-priced electricity due to saturated interconnectors. The result was persistent price spreads of €20–40/MWh, and at times more, across borders that in theory should arbitrage within hours.
The core constraint lay on north–south and east–west corridors linking SEE to Central Europe and the Balkans internally. Interconnections between Hungary–Serbia, Romania–Bulgaria, Bulgaria–Greece and Croatia–Hungary repeatedly operated at or near full capacity during peak hours. Once these limits were reached, marginal prices became locally determined, reverting to the cost of gas-fired or lignite generation rather than reflecting regional supply.
From a quantitative perspective, the issue is not subtle. A single 1 GW constrained border during 6–8 winter peak hours per day can trap 6–8 GWh of higher-cost generation inside a national system. At a price differential of €30/MWh, that translates into €180,000–240,000 per day of implicit congestion rent and consumer cost transfer. Multiplied across several borders and multiple weeks in January, congestion-driven price fragmentation reached tens of millions of euros in economic impact.
Congestion rents accrued primarily to transmission system operators, reflecting the scarcity value of cross-border capacity. While these revenues are often earmarked for grid investment, January demonstrated that current reinforcement timelines lag far behind the speed at which price volatility is emerging. From a market participant’s perspective, congestion income is a symptom of inefficiency, not a solution to it.
For traders, January was a textbook congestion market. Those with physical transmission rights or well-positioned cross-border portfolios captured spreads that were largely independent of energy fundamentals. The value was not in predicting demand or fuel prices, but in securing access to constrained borders. Traders without firm capacity found themselves structurally excluded from arbitrage, regardless of price signals.
For generators, congestion created asymmetric outcomes. Plants located in import-constrained zones benefited from higher local prices even when cheaper electricity existed just across the border. Conversely, generators in export-capable zones faced price suppression when they could not fully access higher-priced neighbouring markets. This uneven geography of price formation distorted short-run dispatch efficiency and undermined the premise of a single regional market.
Renewables were particularly affected. Wind or hydro surpluses in one system could not reliably dampen prices in adjacent markets because interconnectors were already saturated by baseload and thermal flows. January thus demonstrated that renewable integration is now constrained more by grid topology than by generation availability. Adding wind capacity in one country does not reduce regional winter prices if it cannot physically reach deficit zones during peak hours.
From an industrial buyer perspective, congestion translated directly into higher procurement costs. Large consumers located behind constrained borders paid local scarcity prices even when neighbouring markets were materially cheaper. This reinforces a geographic competitiveness divide within SEE, where industrial cost structures depend not only on national policy or generation mix, but on the precise electrical location of assets within the transmission network.
The interaction between congestion and gas pricing was decisive. Once interconnectors saturated, gas-fired plants became the marginal price-setters within isolated zones. Every additional €10/MWh in gas prices translated almost mechanically into higher electricity prices locally, with no relief from imports. January therefore illustrated how grid constraints magnify fuel price shocks rather than merely transmit them.
Capacity allocation mechanisms also came under implicit scrutiny. While market coupling functioned as designed, January showed that allocation efficiency cannot compensate for insufficient capacity volume. Well-functioning auctions simply rationed scarcity; they did not eliminate it. This distinction matters for regulators, because it shifts the problem from market design to infrastructure adequacy.
Looking forward, January strengthens the economic case for targeted grid investment rather than generic reinforcement. The highest value lies in expanding corridors that repeatedly bind during winter peaks, particularly those linking wind- and hydro-rich systems with demand-heavy industrial zones. Incremental capacity increases of even 500–800 MW on critical borders can materially reduce winter price volatility by restoring arbitrage during stress hours.
January also underscores the strategic importance of regional coordination. Unilateral national approaches to grid development risk perpetuating fragmentation. The price behaviour observed during the month reflects a regional system under strain, not isolated national failures. Without coordinated planning across TSOs and regulators, SEE risks entrenching a two-speed electricity market where price convergence exists only in low-stress conditions.
The broader conclusion is that January 2026 reframed cross-border capacity from a technical detail into a first-order price driver. Electricity prices in SEE were not merely high; they were locationally high, shaped by which borders were congested and when. As long as winter demand growth, gas marginal pricing and renewable seasonality intersect with insufficient interconnection, congestion will continue to set prices as much as generation costs do.
January did not reveal a market malfunction. It revealed a system operating exactly as built. The question for South-East Europe is whether it continues to accept winter congestion as a recurring price determinant, or whether cross-border capacity expansion becomes as central to energy policy as renewable deployment itself.
By virtu.energy
