The Carbon Border Adjustment Mechanism (CBAM) has emerged as a transformative force in Southeast Europe’s electricity markets, reshaping trading dynamics and establishing a pronounced divide between low-carbon and coal-based generation. As of the first quarter of 2026, the impacts of CBAM are becoming increasingly evident, highlighting significant disparities in competitiveness driven by carbon pricing and emissions intensity.
Central to this shift is the implementation of default emission factors that assign carbon costs to electricity imports into the European Union. These factors, expressed in tonnes of CO₂ per megawatt-hour, serve to approximate the carbon intensity of exporting countries’ electricity systems. The resulting cost differentials are stark: Albania, with its hydro-dominated energy mix, faced a CBAM cost of €0/MWh, while Serbia incurred around €78.45/MWh, Bosnia and Herzegovina approximately €86.5/MWh, and Montenegro about €73.8/MWh. Such disparities are not trivial; they fundamentally alter the economics of cross-border electricity trade.
This bifurcation creates a clear competitive advantage for low-carbon systems, particularly those reliant on hydropower. These systems can export electricity to EU markets without incurring additional carbon charges, positioning them favorably within a regulatory framework that penalizes high-emission generation. Conversely, coal-heavy systems face compounded challenges: they not only contend with higher emission intensities but also bear carbon costs that often negate any price advantages in cross-border transactions.
The contrasting experiences of Albania and Montenegro in Q1 2026 illustrate this divergence sharply. Both countries benefitted from strong hydro output leading to lower domestic prices; however, Albania significantly increased its exports due to its zero-emission factor, while Montenegro’s export capacity diminished despite favorable price spreads with Italy—where the differential reached approximately €43/MWh. The imposed CBAM costs rendered Montenegrin exports economically unviable, underscoring how regulatory frameworks can override traditional market signals.
The implications for coal-dependent nations like Serbia, Bosnia and Herzegovina, and Montenegro are profound. Historically reliant on thermal generation for both domestic supply and export capabilities, these countries now face an uncertain future as CBAM attaches costs reflective of carbon intensity rather than operational efficiency. This shift threatens the viability of existing assets while simultaneously introducing volatility into their long-term utilization strategies.
Moreover, this transformation extends beyond mere export volumes; it affects the entire economic lifecycle of coal-based generation. With constrained access to lucrative markets due to heightened carbon pricing, revenues are likely to decline while operational costs increase. This could lead to reduced capacity utilization and diminished cash flows over time as market participants reassess asset values based on a new competitive landscape dictated by carbon intensity.
Investment signals are also impacted by this structural divergence. While CBAM aims to incentivize decarbonization by making high-emission production less competitive, it simultaneously creates uneven advantages for low-carbon systems that attract investment in renewables such as hydro, wind, and solar power. In contrast, coal-heavy regions may find themselves facing complex disincentives without clear pathways for transitioning towards greener technologies.
This asymmetry may inadvertently stifle overall investment activity in renewable capacity as stakeholders adopt a cautious approach amid uncertainty regarding future carbon costs and regulatory changes. The result could be a transitional gap where existing coal-based assets suffer penalties without sufficient mobilization of replacement investments in renewables.
The regional integration process within the Western Balkans is further complicated by CBAM’s introduction of friction based on emissions intensity. Markets aligned with low-carbon generation tend to move closer to EU standards while those dependent on coal risk fragmentation into distinct sub-markets with varying levels of competitiveness and integration.
This shift is already influencing trade flows as market participants seek to minimize exposure to CBAM-related costs by favoring routes through low-carbon systems. Albania’s role as an emerging transit hub has expanded significantly due to these dynamics, whereas traditional routes through coal-heavy nations have become less appealing.
From a pricing perspective, low-carbon systems enjoy prices primarily driven by supply conditions such as hydrology and renewable output; meanwhile, coal-heavy markets face constraints that suppress their domestic prices without access to external monetization opportunities. This results in a widening revenue potential gap across different markets.
The interplay between CBAM and the EU Emissions Trading System (ETS) further exacerbates this divergence by linking CBAM costs directly to carbon prices. As seen in Q1 2026 with a carbon price of €75.36/tCO₂, any future increases in EU ETS allowances will disproportionately burden coal-exporting nations, widening existing competitiveness gaps.
The uniform application of default emission factors adds rigidity to this system; even if a coal-heavy country temporarily utilizes low-carbon resources during peak hydro output periods, it still incurs full CBAM costs based on historical emissions profiles rather than current production realities.
For policymakers navigating these challenges, reconciling decarbonization goals with regional market integration remains critical. Although CBAM serves as an effective tool for aligning carbon costs across borders, its current implementation highlights difficulties inherent in applying a one-size-fits-all approach across diverse energy systems within Southeast Europe.
Looking forward, unless significant adjustments occur within market designs or generation portfolios, the divide between low-carbon and coal-based systems is likely to intensify further. The evolving economics of electricity trade will increasingly favor those demonstrating lower emission intensities through renewable technologies or innovative solutions like carbon capture.
The developments observed in Q1 2026 affirm that competitiveness within Southeast Europe’s electricity sector is now intricately linked to regulatory frameworks governing emissions rather than merely resource availability or cost efficiencies alone—ushering in a new hierarchy that favors sustainable energy practices over traditional fossil fuel reliance.
