As the EU Carbon Border Adjustment Mechanism moves into its operational phase for covered imports, electricity trading in Southeast Europe is increasingly priced through a carbon lens rather than only through fuel, hydrology and demand. In the first quarter of 2026, carbon cost pass-through linked to the EU ETS began to alter how marginal pricing works across interconnected systems, affecting whether cross-border flows remain economically viable. The shift has immediate implications for importers and exporters, while also feeding back into bidding strategies and long-term contracting decisions.
EU ETS benchmark becomes a border reference for electricity
CBAM’s electricity-related cost formation is anchored to an EU ETS benchmark. In Q1 2026, the relevant carbon benchmark for electricity imports was set at a quarterly weighted average of €75.36 per tonne of CO₂, translating into per-megawatt-hour charges applied to imports from non-EU systems. For coal-heavy exporters in the Western Balkans, default emission factors produced CBAM costs between €70 and €86/MWh. By contrast, low-carbon systems such as Albania faced no additional CBAM cost due to a zero emission factor.
This linkage means that the carbon market signal is no longer confined to EU production. Instead, it becomes embedded directly into the economics of cross-border electricity transactions, effectively setting a regulatory component that traders must price alongside market fundamentals. The result is a new cost layer that can change the relative attractiveness of exporting electricity into EU markets.
Marginal pricing shifts from generation mix to border-adjusted costs
In conventional marginal pricing frameworks, electricity prices reflect the marginal generator required to meet demand. Across much of the EU, that marginal unit is often gas-fired during periods of moderate demand, while in parts of the Western Balkans marginal pricing has historically been influenced by coal and hydro depending on seasonal conditions. Under CBAM-linked pass-through, 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.
Market differentials show how this plays out in practice. In Q1 2026, EU markets including Hungary and Italy maintained prices in the €120–130/MWh range, reflecting gas prices combined with carbon costs embedded within the EU ETS. Western Balkan markets with strong hydro output recorded lower prices—Serbia averaged €94.7/MWh and Montenegro €85.8/MWh—conditions that would normally support exports toward higher-priced EU areas.
CBAM acts as an import price floor
The trade-off emerges when CBAM charges are added to those export economics. When CBAM costs of €70–80/MWh are applied to exports from lower-price systems, the effective cost of imported electricity can rise above EU domestic price levels. This removes the economic incentive to trade even when pre-CBAM spreads would have suggested convergence.
The mechanism functions as a price floor for imported electricity: it limits how far imports can undercut EU domestic generation when measured against carbon differentials. While this supports the policy objective of preventing carbon leakage, it also reshapes competitive dynamics in electricity markets by changing what “marginal” means for cross-border supply.
Default emission factors create distortions and uncertainty
Carbon pass-through is not uniform across exporters because it depends on default emission factors assigned at country level. These factors operate as proxies for carbon intensity but do not necessarily reflect actual generation mixes at the time of export. As a result, CBAM costs can diverge from real-time emissions performance—for example, a system with both hydro and coal may still face a high default factor that pushes border charges above true carbon intensity.
This approximation affects price signal efficiency by decoupling trading decisions from actual production costs. It also introduces uncertainty because changes in EU ETS prices feed directly into import costs; in Q1 2026, carbon prices showed notable volatility, declining sharply between mid-January and end-March amid discussions on potential reforms. For market participants, this volatility becomes an additional financial risk layered onto electricity pricing.
Day-ahead bids and forward contracts incorporate CBAM risk
The integration of carbon cost pass-through into cross-border pricing affects day-ahead bidding behaviour. Generators and traders must anticipate not only supply-demand balance and fuel costs but also how CBAM will influence cross-border trades into the EU. This has contributed to more cautious bidding strategies for exports, particularly where certificate-related uncertainty matters.
The uncertainty stems from expectations about the final cost of CBAM certificates and timing between trading decisions and surrender requirements. That lag creates an additional risk premium reflected in bids, making price formation less responsive to pure market fundamentals and more influenced by regulatory considerations.
Technology competitiveness tilts through imported carbon charges
Carbon pricing already shifts merit order within the EU toward lower-emission sources such as renewables and nuclear while penalising coal and, to a lesser extent, gas. CBAM extends this logic to imports by exporting part of the EU’s carbon price signal to neighbouring markets. However, default emission factors can amplify effects beyond actual emissions performance: systems with high default factors face significant penalties regardless of their current generation mix, while low-carbon systems gain a disproportionate advantage.
The contrast between Albania and Montenegro illustrates this effect on market access. Albania’s hydro-dominated system is assigned a zero emission factor, enabling exports without incurring CBAM costs. Montenegro’s coal-heavy structure faces CBAM costs of approximately €73–74/MWh; in Q1 2026 this translated into divergent outcomes as Albania increased exports while Montenegro saw exports decline despite favourable price spreads.
Implications extend beyond spot markets into investment signals
CBAM-linked electricity pricing also affects forward markets and long-term contracting through power purchase agreements and hedging strategies. When carbon costs become central components of pricing, contract structuring must incorporate projections of EU ETS prices, regulatory developments and potential changes in emission factor methodologies. This increases complexity for risk management because participants must account for a wider range of variables than before.
For investors across sectors covered by CBAM—including cement, steel, aluminium, fertilisers, electricity and hydrogen—the same logic applies where cross-border competitiveness depends on carbon pricing dynamics. Projects reliant on exports from coal-heavy systems face increased revenue uncertainty tied to how border charges evolve with EU ETS conditions. Conversely, low-carbon projects—particularly those associated with hydro and renewable generation—benefit from structural advantages where output can be exported without incurring additional CBAM costs.
Analytical synthesis: policy-driven price floors reshape trade-offs
Across Q1 2026 trading patterns, CBAM-linked carbon cost pass-through has become a central determinant of electricity price formation rather than a peripheral compliance add-on. By anchoring import costs to an EU ETS benchmark (€75.36 per tonne of CO₂) and applying default emission-factor-based charges (coal-heavy exporters facing €70–86/MWh; Albania at zero; Montenegro around €73–74/MWh), CBAM effectively sets a floor on what imported power can cost relative to EU domestic supply.
This reduces incentives for cross-border arbitrage when pre-CBAM spreads would otherwise support trade convergence and increases regulatory sensitivity in day-ahead bids and forward contracting decisions due to certificate-cost uncertainty and EU ETS volatility (mid-January through end-March). The resulting system is more complex and more policy-driven: it advances decarbonisation objectives while introducing transitional inefficiencies where relative prices across borders can lead to dispatch choices that prioritise regulatory-aligned outcomes over lowest-cost integration.