CBAM is often assessed through the lens of import costs, competitiveness, and compliance burdens. In Southeast Europe, however, the first quarter of 2026 has highlighted a less visible channel: how carbon-related trading incentives can spill into day-to-day electricity system operation. The result is a growing gap between what markets schedule and what networks physically carry, with consequences for balancing, congestion management, and overall operating expenditure.
From carbon-linked incentives to schedule–flow divergence
The early impact of the Carbon Border Adjustment Mechanism in the region has been widely discussed in terms of pricing and trade flows. Yet the medium-term operational picture is becoming clearer as commercial behaviour changes in response to CBAM-related costs. Market participants have reduced scheduled exchanges across certain corridors and rerouted transactions to minimise carbon exposure.
Electricity flows, though, are constrained by network physics rather than trading intent. Physical transmission patterns follow the grid’s impedance, topology, and generation distribution, meaning actual flows can continue along established pathways even when nominated schedules shift. This creates a more volatile operating environment for transmission system operators as scheduled inputs become less reliable for planning.
Why TSOs face higher balancing costs and tighter real-time control
Transmission system operators typically use scheduled flows as a key input for congestion management, reserve allocation, and balancing strategies. When schedules no longer align with actual flows, these tools lose effectiveness and operators must rely more heavily on real-time adjustments. That shift increases the need for ancillary services and raises the cost of maintaining system balance.
Balancing costs are expected to rise as unpredictability increases. TSOs may need to procure additional reserves to manage unexpected flows, particularly during periods of high renewable output or network congestion. These expenses are recovered through network tariffs, spreading CBAM-induced operational impacts to end consumers across both EU and non-EU markets.
Western Balkans corridor under pressure as hydro surges meet altered trade
Grid stress is particularly evident along a south–north transmission axis through the Western Balkans. In Q1 2026, physical loading increased along the route from Greece through Albania and Montenegro to Bosnia and Herzegovina and onward into EU markets. Strong hydro generation in Greece and Albania contributed to higher physical loading at the same time that CBAM considerations altered commercial flows.
The combination produced divergence between scheduled and actual usage on a corridor that is already critical for regional electricity movement. Operating under higher stress increases the risk of congestion and reduces operational flexibility. The situation also adds uncertainty around where system strain may concentrate during periods of disruption.
Operational risk amplified by past vulnerability and new uncertainty
The Southeast European grid has demonstrated sensitivity to disturbances in critical corridors. A blackout event in June 2024 was triggered by the simultaneous outage of key transmission lines in Montenegro and Albania. While that incident was not directly linked to CBAM, it underscores how quickly disruptions can propagate when key links fail.
With commercial schedules diverging from physical flows, TSOs face additional difficulty anticipating stress points. The mismatch makes it harder to manage potential disturbances because real-time conditions may deviate from what scheduling-based planning assumes. This elevates operational risk even if underlying physical vulnerabilities remain unchanged.
Transmission capacity inefficiency and feedback into investment decisions
Beyond balancing challenges, CBAM-linked trading adjustments can affect how efficiently transmission capacity is used. Interconnectors are designed to support economically efficient trade with 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 inefficiency reduces overall network effectiveness and can leave available capacity unused even as parts of the system experience congestion. It also complicates infrastructure investment economics: reinforcement and expansion may be needed when flow patterns become less predictable and more concentrated on certain corridors, but revenue streams supporting those investments could weaken if specific routes are underutilised due to CBAM-related costs.
Generation shifts increase complexity for system balancing
The operational challenge is compounded by generation patterns during Q1 2026. A surge in hydro output introduced large volumes of low-cost electricity into the system, particularly across the Western Balkans and Greece. While this improved supply security and reduced reliance on fossil fuels, it created new constraints for moving surplus generation toward demand areas over long distances.
When commercial incentives discourage certain routes, physical flows may concentrate elsewhere, increasing bottleneck risk through constrained corridors. At the same time, coal generation fell by −16% across the region, removing a source of relatively stable output that had supported predictability in system operation.
Regulatory clarity remains central as carbon-market dynamics feed into operations
Operational outcomes are also shaped by regulatory uncertainty around transit treatment under CBAM. Uncertainty regarding how electricity passing through non-EU countries is treated has been identified as a driver of observed divergence in Q1 2026. Clearer rules could reduce incentives for traders to alter schedules in ways that exacerbate inefficiencies between nominations and physical flows.
There is also an interaction between CBAM implementation effects and the EU Emissions Trading System through carbon price fluctuations. As carbon prices move, cross-border trade costs change accordingly, influencing trading behaviour and therefore flow patterns with immediate operational implications. TSOs therefore need to monitor not only physical grid variables but also developments in carbon markets when integrating inputs into operational planning.
Analytical synthesis: CBAM’s footprint extends from compliance into grid management
The evidence from Q1 2026 indicates that CBAM’s effects extend beyond market pricing and trade volumes into fundamental electricity system operation. Distorted commercial incentives have contributed to reduced or rerouted scheduled exchanges while physical flows continue along established pathways governed by network physics. This schedule–flow mismatch increases volatility for TSOs, pushes them toward greater real-time intervention, raises balancing requirements through additional reserve procurement, and concentrates stress on key corridors such as the south–north Western Balkans axis.
If these patterns persist, the region faces sustained higher system costs and elevated operational complexity driven by balancing needs, congestion risk, capacity inefficiency, and generation variability alongside altered trading behaviour. Mitigation would depend on aligning commercial incentives more closely with physical realities through improved market coupling approaches, enhanced transparency measures, coordinated carbon pricing actions, and clearer transit-related rules under CBAM—while ensuring that operational planning accounts for carbon-market dynamics affecting cross-border trade costs.