The introduction of the Carbon Border Adjustment Mechanism has done more than alter trading behaviour or reshape price spreads across Southeast Europe. It has begun to redraw the competitive map of the region’s electricity systems, creating a clear structural divide between low-carbon and coal-based generation portfolios. This divergence is not theoretical or gradual—it is immediate, quantifiable, and embedded directly into the economics of cross-border trade. The first quarter of 2026 offers the earliest measurable evidence that CBAM is functioning as a powerful differentiator of competitiveness, with implications that extend far beyond short-term market volatility.
At the core of this divergence lies the application of default emission factors, which determine the carbon cost applied to electricity imports into the European Union. These factors, expressed in tonnes of CO₂ per megawatt-hour, are intended to approximate the carbon intensity of exporting systems. In practice, they create a simplified and, in some cases, blunt representation of complex generation mixes. The resulting cost differentials are substantial. In Q1 2026, Albania faced a CBAM cost of €0/MWh, reflecting its hydro-dominated system, while Serbia incurred approximately €78.45/MWh, Bosnia and Herzegovina €86.5/MWh, and Montenegro around €73.8/MWh. These figures are not marginal adjustments; they are of a magnitude that can completely redefine the economics of cross-border trade.
The immediate effect is a bifurcation of regional competitiveness. Low-carbon systems—particularly those dominated by hydro—gain a structural advantage that extends beyond their already low marginal generation costs. They are able to export electricity into EU markets without incurring additional carbon charges, effectively positioning them as preferred suppliers in a CBAM-regulated environment. Coal-heavy systems, by contrast, face a dual penalty: higher emission intensity and the imposition of a carbon cost that often exceeds the underlying price differential between markets. This dynamic transforms what was once a relatively level playing field into a stratified market where access to cross-border trade is determined as much by carbon intensity as by production cost.
The contrast between Albania and Montenegro illustrates this divergence in stark terms. Both systems benefited from strong hydro output in Q1 2026, contributing to lower domestic prices. However, their export performance diverged significantly. Albania increased its exports across multiple borders, leveraging both its surplus generation and its zero emission factor. Montenegro, despite facing favourable price spreads—most notably with Italy, where the differential reached approximately €43/MWh—saw a decline in exports. The explanation lies in the CBAM cost applied to Montenegrin electricity, which effectively absorbed the price advantage and rendered exports economically unattractive. This outcome underscores the extent to which CBAM can override traditional market signals.
The implications for coal-dependent systems are profound. Serbia, Bosnia and Herzegovina, and Montenegro have historically relied on their thermal generation fleets to provide both domestic supply and export capacity. These assets, often fully depreciated and capable of producing electricity at relatively low operating costs, formed the backbone of regional trade. CBAM challenges this model by attaching a cost that reflects carbon intensity rather than operational efficiency. In doing so, it reduces the competitiveness of existing assets and introduces uncertainty into their future utilisation.
This shift is not merely a matter of reduced export volumes. It affects the entire economic lifecycle of coal-based generation. Revenues decline as access to higher-priced markets is constrained, while costs increase due to the need to account for carbon pricing in cross-border transactions. Over time, this could lead to lower capacity utilisation, reduced cash flow, and a reassessment of asset value. For utilities and investors, the question is no longer whether these assets can compete on cost alone, but whether they can remain viable in a market where carbon intensity is a primary determinant of competitiveness.
The divergence also extends to investment signals. In theory, CBAM is designed to incentivise decarbonisation by making carbon-intensive production less competitive. In practice, the signals it sends are uneven. Low-carbon systems receive a clear and immediate advantage, reinforcing the attractiveness of investments in hydro, wind, and solar generation. Coal-heavy systems, however, face a more complex set of incentives. While CBAM increases the cost of carbon-intensive generation, it does not necessarily provide a clear pathway for transition, particularly in regions where access to capital, regulatory frameworks, and grid infrastructure may be less developed.
This asymmetry can lead to unintended consequences. Rather than accelerating investment in new renewable capacity, the structural disadvantage imposed on coal-based systems may result in reduced overall investment, as market participants adopt a wait-and-see approach. The uncertainty surrounding future carbon costs, regulatory adjustments, and market integration can deter long-term commitments, particularly for large-scale projects that require stable revenue expectations. In this sense, CBAM may create a transitional gap where existing assets are penalised, but replacement investments are not yet fully mobilised.
Another dimension of this divergence is its impact on regional market integration. The Western Balkans have long been in the process of aligning their energy markets with those of the European Union, with cross-border trade serving as a key mechanism for integration. CBAM introduces a friction into this process by creating differential treatment based on carbon intensity. Markets that are structurally aligned with low-carbon generation are effectively drawn closer to the EU, while those reliant on coal are pushed further away. This divergence risks fragmenting the region into distinct sub-markets with differing levels of integration and competitiveness.
The effect is particularly evident in the reconfiguration of trade flows. As traders seek to minimise exposure to CBAM costs, they increasingly favour routes and sources that offer lower emission intensity. This has led to a shift towards “CBAM-efficient” corridors, where electricity can be sourced or routed through low-carbon systems. Albania’s role as a transit and export hub has expanded as a result, while traditional transit routes through coal-heavy systems have become less attractive. The net effect is a redistribution of trade activity that reflects carbon intensity as much as geography or infrastructure.
From a pricing perspective, the divergence introduces a new layer of complexity. Prices in low-carbon systems are influenced primarily by supply conditions, particularly hydrology and renewable output. Prices in coal-heavy systems, while still affected by these factors, are increasingly constrained by their limited ability to export and arbitrage. This can lead to situations where low-carbon systems enjoy both low domestic prices and access to higher-priced export markets, while coal-based systems experience suppressed domestic prices without the ability to monetise them externally. The result is a widening gap in revenue potential across different markets.
The interaction between CBAM and the EU ETS further amplifies this divergence. Because CBAM costs are directly linked to carbon prices, any increase in EU ETS allowances will disproportionately affect coal-heavy exporters. In Q1 2026, the carbon price of €75.36/tCO₂ already imposed significant costs. Should prices rise further—as many long-term projections suggest—the gap between low-carbon and high-carbon systems will widen accordingly. This introduces a dynamic element to competitiveness, where relative positions can shift with movements in the carbon market.
The use of default emission factors adds another layer of rigidity to the system. These factors are applied uniformly at the country level, without accounting for variations in generation mix over time. As a result, even if a coal-heavy system temporarily relies on low-carbon generation—such as during periods of high hydro output—it still faces the same CBAM cost. This disconnect between actual emissions and applied costs can discourage efficient dispatch and distort investment decisions. Systems may be penalised for emissions they are not currently producing, while others benefit from structural classifications that may not fully reflect their operational reality.
For policymakers, the challenge is to reconcile the objectives of decarbonisation and market integration. CBAM is a powerful tool for aligning carbon costs across borders, but its current implementation highlights the difficulty of applying a uniform mechanism to diverse energy systems. Adjustments that allow for more granular recognition of actual emissions—such as plant-level reporting or certification of low-carbon generation—could mitigate some of the distortions observed. At the same time, efforts to align carbon pricing frameworks across the Western Balkans with the EU ETS could reduce the asymmetry that currently drives divergence.
Looking ahead, the structural divide between low-carbon and coal-based systems is likely to deepen unless significant changes occur in either market design or generation portfolios. The economics of electricity trade will increasingly favour systems that can demonstrate low emission intensity, whether through renewable generation, nuclear capacity, or carbon capture technologies. Coal-based systems will need to adapt, either by reducing their carbon footprint or by focusing on domestic markets where CBAM does not apply.
The first quarter of 2026 has made one point unmistakably clear: competitiveness in Southeast Europe’s electricity markets is no longer determined solely by cost efficiency or resource availability. It is now fundamentally linked to carbon intensity and the regulatory frameworks that govern it. CBAM has introduced a new hierarchy into the market, one that rewards low-carbon systems and penalises high-emission ones in a direct and measurable way.
This transformation is still in its early stages, and its long-term trajectory will depend on a range of factors, including carbon price developments, regulatory refinements, and investment responses. What is already evident, however, is that the region’s electricity markets are entering a new phase—one defined not just by the integration of physical infrastructure, but by the alignment of carbon economics. In this emerging landscape, the distinction between low-carbon and coal-based systems will continue to shape trade flows, price formation, and investment decisions, establishing a new competitive order across Southeast Europe.
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