The introduction of the Carbon Border Adjustment Mechanism at the start of 2026 has not only altered cross-border trade flows in Southeast Europe but has also begun to reshape the deeper architecture of electricity price formation. What had previously been a system driven primarily by fuel costs, hydrology, and demand cycles is now increasingly influenced by a fourth variable: carbon cost pass-through embedded directly into cross-border transactions. The first quarter of 2026 provides a clear early-stage view of how this mechanism is interacting with regional power markets, and more importantly, how it is redefining marginal pricing logic across interconnected systems.
At the centre of this transformation is the linkage between CBAM and the EU Emissions Trading System. In Q1 2026, the relevant carbon benchmark for electricity imports was set at a quarterly weighted average of €75.36 per tonne of CO₂, effectively anchoring the cost of imported electricity to the EU’s carbon market. This linkage is not theoretical; it is directly translated into per-megawatt-hour costs applied to imports from non-EU systems. For coal-heavy exporters in the Western Balkans, default emission factors resulted in CBAM costs ranging between €70 and €86/MWh, while low-carbon systems such as Albania faced no additional cost due to a zero emission factor.
This cost layer fundamentally alters the structure of price formation in interconnected markets. In a conventional marginal pricing framework, the price of electricity in a given market is determined by the marginal generator—the last unit required to meet demand. In much of the EU, this marginal unit is often gas-fired generation, particularly during periods of moderate demand. In the Western Balkans, by contrast, marginal pricing has historically been influenced by coal and hydro, depending on seasonal conditions. CBAM introduces a new dimension: the marginal cost of imported electricity is no longer defined solely by the exporting system’s generation mix but by the carbon-adjusted cost imposed at the border.
The implications become evident when examining price differentials between markets. In Q1 2026, EU markets such as Hungary and Italy maintained price levels in the range of €120–130/MWh, reflecting a combination of gas prices and carbon costs embedded within the EU ETS. At the same time, Western Balkan markets, benefiting from strong hydro output, recorded significantly lower prices, with Serbia averaging €94.7/MWh and Montenegro €85.8/MWh. Under traditional market conditions, these lower-cost systems would have exported electricity to the EU, contributing to price convergence. However, when CBAM costs of €70–80/MWh are added to these exports, the effective cost of imported electricity rises to levels that often exceed EU domestic prices, eliminating the economic incentive to trade.
This dynamic illustrates a key shift in marginal pricing logic. The marginal cost of supply in EU markets is no longer influenced by the actual cost of generation in neighbouring systems but by the carbon-adjusted cost imposed on imports. In effect, CBAM acts as a price floor for imported electricity, ensuring that it cannot undercut EU domestic generation by more than the carbon differential. This mechanism supports the policy objective of preventing carbon leakage but does so by reshaping the competitive landscape of electricity markets.
The pass-through of carbon costs is not uniform across all systems. It is determined by default emission factors assigned at the country level, which serve as proxies for the carbon intensity of exported electricity. These factors introduce a degree of approximation into the pricing mechanism, as they do not necessarily reflect the actual generation mix at the time of export. For example, a country with a mixed generation portfolio that includes both hydro and coal may still face a high default emission factor, resulting in CBAM costs that exceed the true carbon intensity of the exported electricity. This creates a distortion in price signals, as the cost applied at the border does not align perfectly with the underlying emissions.
From a market perspective, this distortion has several consequences. First, it reduces the efficiency of price signals by decoupling them from actual production costs. Traders and utilities must base their decisions not on the marginal cost of generation but on a regulatory construct that may not reflect real-time conditions. Second, it introduces uncertainty into price formation, as changes in EU ETS prices directly affect the cost of imports. In Q1 2026, carbon prices exhibited notable volatility, declining sharply between mid-January and the end of March amid discussions on potential reforms. This volatility feeds directly into electricity prices, adding a layer of financial risk that market participants must manage.
The integration of carbon cost pass-through into electricity pricing also affects bidding behaviour in day-ahead markets. Generators and traders must now anticipate not only the supply-demand balance and fuel costs but also the impact of CBAM on cross-border trades. In practice, this has led to more cautious bidding strategies, particularly for exports into the EU. The uncertainty surrounding the final cost of CBAM certificates—combined with the lag between trading decisions and the actual surrender of certificates—creates an additional risk premium that is reflected in bids. As a result, price formation becomes less responsive to pure market fundamentals and more influenced by regulatory considerations.
Another important dimension of carbon cost pass-through is its impact on the relative competitiveness of different generation technologies. Within the EU, carbon pricing has already shifted the merit order in favour of lower-emission sources such as renewables and nuclear, while penalising coal and, to a lesser extent, gas. CBAM extends this logic to imports, effectively exporting the EU’s carbon price signal to neighbouring markets. However, the use of default emission factors amplifies this effect in ways that may not fully align with actual emissions. Systems with high default factors face significant cost penalties, regardless of their current generation mix, while low-carbon systems gain a disproportionate advantage.
This dynamic is particularly evident in the contrast between Albania and Montenegro. Albania’s electricity system, dominated by hydro, is assigned a zero emission factor, allowing it to export electricity into the EU without incurring CBAM costs. Montenegro, by contrast, with a substantial share of coal generation, faces CBAM costs of approximately €73–74/MWh. In Q1 2026, this difference translated into divergent trading outcomes. Albania increased its exports, benefiting from both low generation costs and the absence of carbon charges, while Montenegro saw a decline in exports despite favourable price spreads. The implication is clear: carbon cost pass-through is not merely an adjustment mechanism but a determinant of market access.
The influence of CBAM on price formation also extends to forward markets and long-term contracting. Power purchase agreements and hedging strategies rely on expectations of future price dynamics, including the relationship between different markets. When carbon costs become a central component of pricing, these expectations must incorporate projections of EU ETS prices, regulatory developments, and potential changes in emission factor methodologies. This increases the complexity of contract structuring and risk management, as participants must account for a wider range of variables.
For investors, the integration of carbon cost pass-through into electricity markets has significant implications. Projects that depend on cross-border exports—particularly those in coal-heavy systems—face increased revenue uncertainty, as their competitiveness is contingent on carbon pricing dynamics. Conversely, low-carbon projects, especially in hydro and renewable generation, benefit from a structural advantage, as their output can be exported without incurring additional costs. This creates a divergence in investment signals, favouring certain technologies and locations over others.
At the system level, the incorporation of carbon costs into price formation contributes to the broader objective of decarbonisation but may also introduce transitional inefficiencies. By altering the relative prices of electricity across borders, CBAM affects the allocation of generation and the utilisation of transmission capacity. In some cases, this may lead to suboptimal dispatch decisions, where higher-cost domestic generation is used instead of lower-cost imports due to carbon adjustments. While this outcome aligns with climate policy objectives, it raises questions about the trade-off between efficiency and decarbonisation.
Looking forward, the evolution of carbon cost pass-through will depend on several factors. The trajectory of EU ETS prices will remain a key driver, as higher carbon prices increase the cost of imports and reinforce the effects observed in Q1 2026. Regulatory refinements to CBAM, particularly in the treatment of emission factors and the recognition of actual generation characteristics, could mitigate some of the distortions currently observed. Additionally, the potential introduction of carbon pricing mechanisms within the Western Balkans could reduce the asymmetry between EU and non-EU markets, aligning price signals and restoring some degree of integration.
The first quarter of 2026 demonstrates that carbon cost pass-through is no longer a peripheral consideration in electricity markets; it is a central determinant of price formation. By embedding carbon costs directly into cross-border transactions, CBAM has extended the reach of the EU ETS beyond its borders, reshaping the economics of trade and the structure of pricing across Southeast Europe. The resulting system is more complex, more policy-driven, and more closely tied to carbon market dynamics than ever before. For market participants, understanding and navigating this new landscape will be essential as the region moves deeper into the CBAM era.
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