BELGRADE/SOFIA, Oct. 22, 2026 – Electricity traders operating between the Western Balkans and the European Union must account for carbon-border liabilities alongside wholesale price differentials, transmission constraints and balancing expenses. A profitable spread between regional power exchanges may narrow or disappear once the costs of delivering electricity and demonstrating eligible emissions are included.
Unlike steel and cement, electricity under the EU Carbon Border Adjustment Mechanism (CBAM) is assessed in megawatt-hours (MWh), with emissions expressed in tonnes of CO₂ equivalent per MWh (tCO₂e/MWh). The published CBAM certificate price for the third quarter of 2026 is €82.32/tCO₂e, announced on October 5. This represents a carbon price rather than a customs price for electricity; the corresponding cost per MWh depends on the applicable emissions calculation.
Under the current framework, importers generally rely on regulated default electricity emissions values unless they meet the cumulative requirements for using actual emissions. These conditions connect the generating installation and eligible power purchase agreement (PPA) with network and interconnection evidence, matching hourly generation and nominations, and independent verification.
Purchasing electricity from a country with a substantial renewable generation share does not, by itself, entitle an EU importer to claim zero embedded emissions.
Regional price spreads do not guarantee trading profits
A trader purchasing electricity in Serbia for delivery into Hungary or Romania, or sourcing power in Montenegro for delivery towards Italy, must assess more than the difference between wholesale market prices. Transmission rights, congestion auctions, curtailment, network losses, balancing deviations, settlement timing, credit support and customs obligations all influence the final trading margin.
Electricity may also pass through several markets with different trading arrangements and grid requirements, adding operational and contractual complexity to cross-border transactions.
An illustrative gross price spread of €35/MWh could appear commercially attractive. However, if transmission and balancing expenses total €8/MWh, and the applicable emissions calculation produces 0.4 tCO₂e/MWh, the modelled carbon exposure at €82.32/tCO₂e would be approximately €32.93/MWh.
The combined costs would exceed the original spread. This is a sensitivity example, not a quoted market spread or an established emissions factor for any particular country.
The opposite outcome is possible when a generator can substantiate a low actual-emissions value under the applicable legal requirements. Traceable renewable or other low-emission electricity could then offer a lower carbon component for EU delivery, potentially supporting additional commercial value. That benefit must be assessed against the contractual, monitoring and verification costs required to establish eligibility.
The claimed emissions must also correspond to the electricity allocated under the qualifying contract and the relevant physical delivery schedule.
Proposed EU reforms would change electricity accounting requirements
The European Commission’s December 2025 proposal, COM(2025)989, seeks to revise elements of the CBAM framework for imported electricity, including default emissions factors and the conditions for using actual emissions.
The proposal would permit certain intermediary PPAs where the contractual chain between the producer and importer can be verified. It would also remove one existing network-congestion condition while retaining stringent hourly nomination requirements and addressing the allocation of implicit interconnector capacity separately.
These provisions remain proposals rather than final legislation. Transactions conducted in 2026 must comply with the rules currently in force unless and until an adopted legal instrument changes the applicable requirements.
The Commission’s impact assessment found that approximately 3% of electricity declarations during the transitional period used actual values. That historical figure does not establish the proportion of imports eligible to use actual emissions under the stricter definitive-phase requirements.
Generation shortfalls can undermine emissions claims
Electricity traders must also manage portfolio risks arising from changes in generation availability. Hydropower shortages can require replacement purchases from thermal generators, affecting both transaction profitability and the emissions profile of the electricity supplied. Wind or solar generation shortfalls can similarly leave a long-term supply contract under-delivered.
Where a PPA’s pricing structure assumes eligibility for actual-emissions treatment, a failure to reconcile nominated electricity with the relevant generation and delivery records may trigger disputes between the importer, seller and intermediaries. Contractual provisions may need to establish responsibility for additional carbon costs and replacement-energy expenses.
Operational reconciliation is particularly important at hourly level. A trader may hold valid purchase and sale contracts but lack sufficient firm transmission capacity to deliver the nominated volume. Intraday adjustments, transmission system operator acceptance and imbalance settlement can differ from day-ahead nominations, particularly when renewable output deviates from forecasts.
For an actual-emissions claim, these changes must be assessed against the specific legal requirements. Financial settlement alone does not establish that the necessary physical-delivery conditions have been met, and a settlement invoice cannot substitute for the underlying operational records.
Carbon costs influence bids and electricity procurement contracts
The treatment of carbon costs can determine the maximum price an EU buyer is willing to pay for imported electricity. A purchaser modelling default emissions values may offer less than a buyer able to substantiate qualifying actual emissions, provided the latter’s calculation satisfies the applicable rules.
Any potential premium for low-carbon electricity must nevertheless account for legal due diligence, verifier fees and delivery risks. Contracts should allocate responsibility for metering, scheduling, legal review, verification and the costs of replacement electricity following forecasting errors or curtailment.
These expenses need to be incorporated into bid calculations from the beginning rather than treated as secondary costs after the wholesale transaction has been agreed.
Verified delivery data become part of the commercial offer
For investors and traders across Southeast Europe, the ability to document electricity delivery and emissions allocation is becoming an important component of cross-border transactions.
A defensible transaction requires an identified generating installation, an identifiable buyer and authorised CBAM declarant, an accepted cross-border schedule, verified hourly data and a controlled methodology for allocating delivered megawatt-hours.
Without the required contractual, operational and emissions evidence, a transaction may remain a conventional electricity trade with an uncertain carbon-border cost rather than a demonstrably eligible low-emissions supply arrangement.
