January 2026 has underscored significant challenges in the electricity markets of South-East Europe (SEE), revealing that the divergence in electricity prices was not solely due to a lack of generation capacity. Instead, these price fluctuations were exacerbated by inadequate cross-border capacity and congestion management, particularly during peak winter demand periods. The observed price spikes were influenced by both fuel costs and the inability to balance regional supply effectively, leading to fragmented market conditions.
During the coldest days of January, day-ahead electricity prices across major SEE hubs experienced notable decoupling. Markets in Serbia, Hungary, Romania, and Bulgaria typically registered prices between €115 and €135 per megawatt-hour (MWh). However, neighboring markets struggled to export lower-priced electricity due to saturated interconnectors, resulting in persistent price spreads of €20 to €40/MWh across borders that are generally expected to equilibrate within hours.
The primary constraints affecting these markets were identified along key north-south and east-west corridors linking SEE with Central Europe and the Balkans. Interconnections among Hungary-Serbia, Romania-Bulgaria, Bulgaria-Greece, and Croatia-Hungary frequently reached full capacity during peak hours. As these limits were approached, local marginal prices were determined by gas-fired or lignite generation costs rather than reflecting broader regional supply dynamics.
Quantitatively, a single constrained border of 1 gigawatt (GW) during 6 to 8 peak winter hours daily could retain 6 to 8 gigawatt-hours (GWh) of higher-cost generation within a national market. With price differentials averaging €30/MWh, this situation resulted in an implicit congestion rent ranging from €180,000 to €240,000 per day. Over several borders and weeks in January, this congestion-induced price fragmentation resulted in economic impacts reaching tens of millions of euros.
The revenue from congestion predominantly benefitted transmission system operators, highlighting the scarcity value of cross-border capacity. While these funds are often allocated for grid improvements, it became evident that the pace of infrastructure reinforcement is lagging behind rising price volatility. For market participants, congestion revenues reflect inefficiencies rather than solutions.
Traders faced a scenario characterized as a textbook congestion market throughout January. Those possessing physical transmission rights or strategically positioned cross-border portfolios capitalized on price spreads largely disconnected from energy fundamentals. Conversely, traders lacking firm capacity found themselves systematically excluded from arbitrage opportunities despite existing price signals.
Generators also experienced asymmetric outcomes due to congestion effects. Facilities situated in import-constrained areas benefited from elevated local prices even when cheaper alternatives were available nearby. In contrast, plants located in export-capable regions encountered price suppression when they could not fully access higher-priced neighboring markets. This disparity distorted short-run dispatch efficiency and challenged the notion of a unified regional market.
Renewable energy sources were notably impacted as well. Surpluses from wind or hydro generation could not effectively lower prices in adjacent markets due to saturated interconnectors dominated by baseload thermal flows. This situation illustrated that renewable integration is increasingly limited by grid topology rather than generation availability; adding wind capacity does not alleviate regional winter pricing if it cannot reach deficit zones during critical hours.
From the perspective of industrial buyers, congestion directly translated into elevated procurement costs. Large consumers situated behind constrained borders faced local scarcity pricing even when neighboring markets offered significantly cheaper alternatives. This scenario emphasizes a geographic competitiveness divide within SEE where industrial cost structures are influenced not only by national policy but also by specific locations within the transmission network.
The interplay between grid congestion and gas pricing was particularly significant during this period. Once interconnectors became saturated, gas-fired plants emerged as the marginal price-setters within isolated zones; each additional €10/MWh increase in gas prices led almost automatically to higher local electricity rates without relief from imports. Thus, January showcased how grid constraints can amplify fuel price shocks rather than merely transmit them.
Capacity allocation mechanisms faced scrutiny as well; while market coupling operated effectively as intended, it became clear that allocation efficiency alone cannot address insufficient capacity volume. Well-functioning auctions merely rationed scarcity without eliminating it altogether—a critical distinction for regulators that shifts focus from market design issues to infrastructure adequacy concerns.
Looking ahead, January’s events bolster the case for targeted investments in grid infrastructure rather than broad reinforcement efforts. The most significant value lies in enhancing corridors that frequently experience strain during winter peaks—especially those linking renewable-rich areas with industrial demand centers. Incremental increases in capacity on critical borders could substantially mitigate winter price volatility by restoring effective arbitrage during high-stress periods.
This month also highlights the necessity for enhanced regional coordination; unilateral national approaches to grid development risk perpetuating fragmentation within the market structure. The observed pricing behavior reflects systemic pressures rather than isolated failures at national levels. Without collaborative planning among transmission system operators and regulators across SEE, there is a risk of entrenching a two-speed electricity market where convergence occurs only under low-stress scenarios.
In summary, January 2026 has reframed cross-border capacity as a crucial factor influencing electricity pricing dynamics within SEE. The region’s electricity prices were not just elevated; they exhibited locational dependencies shaped by congested borders at critical times. As demand growth continues alongside gas marginal pricing and seasonal renewable variability intersecting with limited interconnections persist, congestion will remain a significant determinant of pricing alongside generation costs.
