CBAM’s knock-on effects in Southeast Europe: higher system costs and operational risk

While the early discussion around the Carbon Border Adjustment Mechanism (CBAM) in Southeast Europe has focused on pricing and competitiveness, the first quarter of 2026 highlights a more difficult challenge for grid operators: the mechanism is beginning to reshape how electricity systems are run. The emerging pattern—commercial decisions shifting while physical power flows remain governed by network physics—is translating into higher system costs, increased grid stress and elevated operational risk for transmission system operators (TSOs).

When schedules change but flows don’t

The core problem is a mismatch between market incentives and physical realities. As CBAM-related costs influence trading behaviour, market participants have reduced scheduled exchanges across some corridors and rerouted transactions to minimise carbon exposure. But electricity does not follow nominations. Physical flows are determined by network impedance, topology and where generation is located. Consequently, even when scheduled flows decline or shift, actual flows often continue along established pathways, diverging from what TSOs plan for.

More volatility for congestion management and balancing

This divergence makes day-to-day operation less predictable. Under normal conditions, TSOs use scheduled flows as a key input for system planning—supporting congestion management, reserve allocation and balancing strategies. When schedules no longer match real-time conditions, those tools become less effective, forcing operators to rely more heavily on real-time adjustments. That typically increases the need for ancillary services and raises the cost of maintaining system balance.

Financially, the shift is already visible in rising balancing costs—reflecting the expense of correcting deviations between supply and demand. TSOs may also need to procure additional reserves, particularly during periods of high renewable output or network congestion. These costs are recovered through network tariffs, meaning CBAM-induced distortions can ultimately be passed through to end consumers across both EU and non-EU markets.

Pressure on key corridors in the Western Balkans

The operational strain is especially apparent along major transmission routes. In Q1 2026, the south–north corridor through the Western Balkans—from Greece through Albania and Montenegro to Bosnia and Herzegovina and onward into EU markets—saw increased physical loading tied to strong hydro generation in Greece and Albania. At the same time, commercial flows along this route were altered by CBAM considerations, producing a gap between scheduled and actual usage.

The result is a corridor operating under higher stress, with greater risk of congestion and reduced flexibility when conditions change. The region’s vulnerability to disturbances is not theoretical: a blackout event in June 2024 was triggered by the simultaneous outage of key transmission lines in Montenegro and Albania. Although that incident was not linked directly to CBAM, it underscores how sensitive critical corridors can be—and how added uncertainty from schedule-flow divergence can make it harder for TSOs to anticipate stress points.

Capacity inefficiency as trade patterns shift

CBAM-related distortions also affect how effectively transmission capacity is used. Interconnectors are designed to support economically efficient trade using capacity allocated based on expected flows. When commercial schedules diverge from physical reality, capacity can be underutilised in some directions while overloaded in others. This reduces overall network effectiveness and can leave available capacity unused even as parts of the system experience congestion.

Generation mix changes add complexity

The operational picture is further complicated by generation patterns during Q1 2026. A surge in hydro output delivered large volumes of low-cost electricity into parts of the region—particularly the Western Balkans and Greece—improving supply security while reducing reliance on fossil fuels. But excess generation still must be transported to demand areas over long distances, often through constrained corridors.

When commercial incentives discourage certain routes under CBAM considerations, physical flows may concentrate elsewhere, increasing bottleneck risk. At the same time, coal generation fell by -16% across the region. Coal plants typically provide more stable output than variable renewables; as they are displaced by hydro and other renewables, variability rises further. Even though hydro can be more controllable than wind or solar, its output still depends on hydrological conditions that can change quickly—adding another layer of complexity for balancing operations when trade signals do not match physical behaviour.

A feedback loop for investment decisions

From an investment standpoint, these operational challenges create competing pressures. If flow patterns become less predictable and more concentrated on specific corridors, reinforcement or expansion of transmission networks may become more urgent—covering interconnectors, substations and control systems needed to manage new flow dynamics and maintain stability.

However, economic justification may be harder when CBAM discourages usage of particular corridors due to carbon-related costs. If those routes see weaker commercial utilisation, revenue streams that support infrastructure investment could weaken—creating a feedback loop where market distortions influence infrastructure utilisation and then shape future investment decisions.

Coordination needs rise—and regulatory clarity matters

Cross-border operations make coordination increasingly important. Divergent schedule signals complicate cross-border capacity calculation, congestion management and balancing strategies because TSOs must reconcile nominated market outcomes with real-time system behaviour. The article points to potential remedies such as enhanced data sharing, joint operational planning and regional coordination centres—but notes these require both investment and institutional alignment.

Regulatory clarity is also highlighted as a driver of observed divergence in Q1 2026: uncertainty about how transit flows through non-EU countries are treated under CBAM has been linked to traders altering schedules in ways that exacerbate inefficiencies. Clearer rules on transit treatment could reduce incentives for schedule changes that do not translate into corresponding physical flow benefits.

Carbon price volatility adds an extra operating variable

The interaction between CBAM expectations and the EU Emissions Trading System (EU ETS) introduces further operational risk because carbon prices fluctuate over time. Changes in cross-border trade costs can quickly influence trading behaviour—and therefore flow patterns—meaning TSOs must monitor not only physical grid variables but also developments in carbon markets as part of operational planning.

What happens next

Whether CBAM-induced distortions persist will depend on how market participants and policymakers respond. If current patterns continue unchecked, Southeast Europe could face sustained higher system costs alongside greater operational complexity. Conversely, measures that align commercial incentives with physical realities—such as improved market coupling, enhanced transparency and coordinated carbon pricing—could help mitigate these effects while supporting decarbonisation without undermining system stability or efficiency.

The takeaway from Q1 2026 is that CBAM’s impact reaches beyond electricity prices and trade volumes into core system operation: divergence between schedules and physical flows concentrates stress on key corridors while increasing the cost of managing the grid during balancing moments that become harder to predict—and harder to finance without broader coordination across technical planning and regulatory rules.