Electricity exports from Southeast Europe to the European Union face a more demanding profitability calculation as the Carbon Border Adjustment Mechanism (CBAM) introduces a carbon cost into cross-border power transactions. Price differences between regional electricity exchanges and EU destination markets may no longer translate into positive trading margins once carbon liabilities, transmission capacity and balancing expenses are included.
The commercial implications extend across Serbia, Montenegro, Bosnia and Herzegovina, North Macedonia and Albania, where electricity exports involve different generation technologies, contractual arrangements and delivery routes. Traders and utilities must determine the applicable emissions treatment for individual transactions rather than assuming that a portfolio with a high renewable share automatically qualifies every exported megawatt-hour for actual-emissions treatment.
Electricity CBAM costs and the impact on trading spreads
Under the applicable implementing rules, electricity has a zero free-allocation adjustment. The phase-in assumptions used for industrial goods therefore cannot be applied to electricity imports. Depending on the relevant emissions factor and any eligible deduction for carbon prices paid, the CBAM carbon component can account for a substantial share of an electricity trade’s gross price spread.
At an illustrative carbon price of €82.32/tCO₂e, an emissions factor of 0.4 tCO₂e/MWh results in a gross carbon component of €32.93/MWh. At 0.8 tCO₂e/MWh, the corresponding amount rises to €65.86/MWh. These calculations are sensitivities rather than official country-specific default values or assessments of any particular generating installation.
The difference becomes commercially significant when measured against the underlying electricity price spread. In a transaction where the EU selling price is €30/MWh above the purchase price in the source market, applying the first illustrative carbon component would turn the spread negative even before transmission and balancing costs are deducted.
For a transaction covering 100,000 MWh, the difference between the two illustrative emissions factors amounts to approximately €3.29 million in gross carbon costs. The calculation demonstrates the financial significance of the emissions assumption used for a cross-border electricity transaction.
Actual emissions require evidence of generation and delivery
Imported electricity can be assessed using actual emissions only when the applicable CBAM conditions are fulfilled. The European Commission’s August 2026 electricity guidance addresses requirements involving a qualifying power purchase agreement (PPA), identification of the generating installation, network conditions, an emissions threshold, and the relationship between electricity production and firm nomination within the required hourly period.
Where these conditions are not satisfied, default values remain the general route for determining the emissions treatment. Exporters and importers therefore need to establish which methodology applies before calculating the carbon-adjusted value of a transaction.
Commercial contracts and generation records must substantiate the emissions claim made by the EU declarant. A renewable energy certificate alone does not demonstrate that a specific imported megawatt-hour satisfies all the requirements for actual-emissions treatment under CBAM.
Contractual allocation and evidence of physical delivery consequently have direct financial implications. The ability to establish the applicable emissions treatment can affect whether an apparent price advantage remains commercially viable after the importer’s carbon obligation is included.
Carbon exposure enters electricity project financing
The same calculations affect the financial structure of renewable electricity projects targeting EU buyers. Wind and solar developers may pursue cross-border sales where destination-market prices exceed those available in their domestic markets, but the revenue available to service debt depends on the amount retained after route costs, balancing obligations and the agreed allocation of CBAM exposure.
Where a project’s financial model assumes that actual emissions will qualify under CBAM, the relevant delivery route and supporting evidence need to be substantiated before the expected price premium is relied upon to support debt service.
This makes the documentation of generation and delivery arrangements relevant not only to trading operations but also to project revenue assumptions. The commercial value of an EU sales contract depends on the carbon treatment that can be demonstrated for the electricity delivered under its terms.
Seasonal generation and congestion affect export revenues
Electricity exports from Southeast Europe also remain exposed to changes in generation availability and cross-border transmission conditions. Montenegro’s exports towards Italy and Serbian exports into neighbouring EU markets are affected by seasonal generation patterns and congestion, which can influence the achievable margin on individual deliveries.
Hydropower availability varies with weather conditions, while wind and solar generation may coincide with hours when electricity prices are low. As a result, annual average prices can overstate potential export revenues when production is concentrated in periods with narrow or negative price spreads.
The combination of variable generation, transmission constraints and CBAM liabilities makes route-specific and time-sensitive revenue calculations important. A favourable annual price differential does not necessarily indicate that electricity can be exported profitably during the hours when generation is available.
Proposed EU rule changes remain separate from current obligations
Potential changes to electricity-related CBAM requirements form part of the ongoing European Parliament and Council negotiations on downstream measures and anti-circumvention provisions. These discussions include electricity provisions that could affect the practical conditions governing qualifying exports.
However, the provisions under negotiation must be distinguished from the rules currently applicable. Proposed simplifications cannot be treated as an existing exemption or as a guaranteed increase in export revenues.
For electricity traders, utilities and project developers, the immediate commercial requirement remains to calculate the margin for each delivery route using the applicable emissions treatment, transmission capacity and balancing costs. Exporters able to substantiate their emissions treatment may be better positioned to preserve sales that would otherwise face greater exposure to default values.
The relevant commercial measure is the margin remaining on each delivered megawatt-hour after the EU importer’s CBAM carbon obligation has been accounted for.
