Carbon Border Adjustment Mechanism (CBAM) compliance adds an extra cost variable to electricity exports from the Western Balkans into neighbouring EU markets. The impact depends on how carbon liability is calculated for imported power, even where wholesale price differences between interconnected systems suggest potential trading opportunities. The mechanism’s treatment can change the financial outcome once emissions-related charges are included.
CBAM distinguishes between imports assessed using applicable default emissions values and transactions that meet requirements for actual-emissions treatment. Where eligible actual data cannot be used, the emissions calculation follows the applicable EU methodology. The distinction is particularly relevant in interconnected electricity systems where power can move through multiple trading portfolios and across several borders before reaching an EU importer.
A contractual description of electricity as renewable does not by itself create a zero-emissions value for CBAM purposes. The generating source, the applicable calculation methodology, and supporting evidence must satisfy the relevant regulatory conditions.
Default emissions calculations and certificate reference pricing
A hypothetical import scenario illustrates potential exposure under CBAM. An electricity volume of 100,000 MWh with an illustrative embedded-emissions factor of 0.60 tonnes of CO2 per MWh would correspond to total embedded emissions of 60,000 tonnes of CO2.
Using the official third-quarter 2026 CBAM certificate reference price of EUR 82.32 per tonne, the gross carbon-price equivalent would reach approximately EUR 4.94 million. The figure is presented as a sensitivity example rather than a statutory charge for a specific country, border, or electricity transaction. It also precedes applicable legal adjustments and the final certificate calculation.
On a per-MWh basis, the same assumptions yield gross carbon-price exposure of approximately EUR 49.39/MWh. Under those assumptions, a wholesale electricity price differential of EUR 20/MWh would be insufficient to cover the illustrative carbon exposure. This remains true even before considering transmission charges, network losses, balancing requirements, and trading costs.
The final financial outcome depends on the legally applicable emissions factor, relevant phase-in adjustments, and the circumstances of the authorised importer. The illustrative factor of 0.60 tCO2/MWh is not described as an official default for any Western Balkan country.
Transaction-level assessment for cross-border trading
The CBAM framework changes how electricity traders evaluate cross-border opportunities. Comparing day-ahead prices between two exchanges alone is no longer sufficient to establish whether an export transaction is profitable when carbon liability is considered.
A full assessment needs to include electricity purchase and sale prices, cross-border capacity costs, transmission losses, imbalance charges, and expected CBAM treatment. Calculations should be carried out at transaction level, using details such as delivery hour, direction of electricity flows, and the identity of the importing entity.
Daily average prices can mask differences across individual trading periods. This is relevant when renewable generation contributes to intraday price volatility and affects how available electricity aligns with scheduled exports and realised market prices.
The split between actual and default emissions also influences commercial negotiations between counterparties. A seller able to demonstrate eligible actual-generation emissions may seek a higher electricity price or negotiate participation in carbon-cost savings. If evidence or legal eligibility for an actual-emissions claim is uncertain, an EU buyer may base its offer on a default assumption.
Contract terms for allocating carbon risk
CBAM introduces additional requirements into electricity supply agreements between Western Balkan exporters and EU buyers. Contracts need to specify which party bears the financial consequences arising from the applicable emissions calculation.
One contractual approach allows the seller to deliver electricity at an agreed price while leaving CBAM responsibility with the EU buyer. In that case, the buyer can incorporate its anticipated carbon liability into the purchase price offered to the exporter.
An alternative approach sets a delivered net price with the seller assuming part of the carbon-related exposure. That structure requires clear provisions covering changes in legislation, unsuccessful actual-emissions claims, and revisions to the applicable emissions factor.
The allocation becomes more significant in agreements extending over several years. Day-ahead electricity prices can change hourly, while long-term PPAs set commercial commitments over longer periods. CBAM legislation and associated calculation requirements may also evolve during the contract term.
A short-term trading calculation and a long-term project-finance forecast therefore rely on different assumptions. Using a single quarterly certificate reference price or a temporary wholesale market spread as inputs for multi-year revenue projections can produce an unreliable assessment of expected project income.
Regional generation profiles and modelling assumptions
The effects of CBAM may differ across Western Balkan electricity systems because generation portfolios are not identical. Hydropower and renewable-intensive portfolios can have a physical emissions advantage compared with electricity produced predominantly from fossil fuels.
The commercial value of that advantage depends on whether an eligible actual-emissions calculation can be applied or on how default factors are designed. Where a country-level default is used, emissions characteristics of individual low-carbon installations may not be fully reflected in the carbon cost assigned to exports.
This creates incentives for electricity producers to establish reliable generation-data systems and for regional governments to support improvements in regulatory frameworks governing exports to the EU. Renewable project developers also face modelling challenges when forecasting revenues based only on EU wholesale electricity prices without accounting for potential CBAM liabilities.
Project lenders are expected to assess expected offtake revenue after applicable carbon costs using the current regulatory framework and conservative default-emissions assumptions. Scenarios involving proposed legislative changes should be assessed separately rather than treated as established outcomes.
For renewable generators, physically low-carbon electricity does not automatically translate into an equivalent financial advantage in EU trade under CBAM rules. The advantage depends on the applicable emissions calculation and whether there is a defensible chain of supporting evidence.
The change in trading economics extends beyond differences in electricity prices between neighbouring markets. Congestion, hourly price volatility, balancing costs, and transmission charges already affect cross-border margins, while additional carbon exposure under CBAM can make apparent export profitability differ from net commercial value once emissions treatment is applied.