Electricity traders moving power between the Western Balkans and the European Union need to factor in carbon-border liabilities alongside wholesale price differentials, transmission constraints and balancing expenses. The margin between regional power exchanges can narrow or disappear when delivery costs and eligible emissions documentation are included.
Under the EU Carbon Border Adjustment Mechanism (CBAM), electricity is assessed in megawatt-hours (MWh), while emissions are expressed as 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. The figure is a carbon price for CBAM purposes, and the cost per MWh depends on the emissions calculation applied to the transaction.
Importers generally use regulated default electricity emissions values unless they meet cumulative requirements to use actual emissions. Those conditions link the generating installation and an eligible power purchase agreement (PPA) with network and interconnection evidence. They also require matching hourly generation and nominations, together with independent verification.
Buying electricity from a country with a substantial renewable generation share does not automatically allow an EU importer to claim zero embedded emissions. Trading outcomes depend on how emissions are calculated under the CBAM framework rather than on the presence of renewables alone.
Transmission, balancing and settlement factors in cross-border trades
A trader purchasing electricity in Serbia for delivery into Hungary or Romania, or sourcing power in Montenegro for delivery toward Italy, must evaluate more than wholesale price differences. Transmission rights, congestion auctions, curtailment, network losses, balancing deviations, settlement timing, credit support and customs obligations all affect the final trading margin.
Cross-border electricity can also move through multiple markets with different trading arrangements and grid requirements. That structure increases operational and contractual complexity for transactions spanning several systems.
An illustrative gross spread of €35/MWh may appear commercially attractive. If transmission and balancing expenses total €8/MWh, and the applicable emissions calculation produces 0.4 tCO2e/MWh, carbon exposure based on €82.32/tCO2e would be about €32.93/MWh. In that scenario, combined costs exceed the original spread.
The same sensitivity framing notes that the example is not a quoted market spread and does not represent an established emissions factor for any specific country. A different outcome can occur when a generator substantiates a low actual-emissions value under applicable legal requirements.
Actual-emissions eligibility depends on contract-linked delivery evidence
When low actual-emissions values can be supported, traceable renewable or other low-emission electricity may carry a lower carbon component for EU delivery. Any additional commercial value must be assessed against contractual monitoring and verification costs needed to establish eligibility.
The emissions claimed must correspond to the electricity allocated under the qualifying contract and to the relevant physical delivery schedule. For actual-emissions treatment, eligibility depends on aligning documentation with what was physically delivered rather than relying on settlement outcomes alone.
Generation availability can also affect whether emissions claims remain supportable. Hydropower shortages may require replacement purchases from thermal generators, changing both profitability and the emissions profile of supplied electricity. Wind or solar shortfalls can similarly leave a long-term supply contract under-delivered.
EU proposals to revise CBAM electricity accounting
The European Commission’s December 2025 proposal COM(2025)989 aims to revise elements of CBAM for imported electricity. The proposal includes changes to default emissions factors and conditions for using actual emissions.
The draft would allow certain intermediary PPAs where the contractual chain between producer and importer can be verified. It also proposes removing one network-congestion condition while keeping stringent hourly nomination requirements, and it addresses allocation of implicit interconnector capacity separately.
The Commission’s impact assessment reported that about 3% of electricity declarations during the transitional period used actual values. That figure does not indicate what share of imports could qualify to use actual emissions under stricter definitive-phase requirements.
Hourly reconciliation and how carbon costs enter procurement decisions
Operational reconciliation is especially important at hourly level because traders may have contracts but lack sufficient firm transmission capacity to deliver nominated volumes. Intraday adjustments, transmission system operator acceptance and imbalance settlement can differ from day-ahead nominations when renewable output deviates from forecasts.
For an actual-emissions claim, those changes must be assessed against specific legal requirements. Financial settlement alone does not establish that physical-delivery conditions were met, and a settlement invoice cannot replace underlying operational records.
The treatment of carbon costs can determine the maximum price an EU buyer is willing to pay for imported electricity. A buyer modelling default emissions may offer less than a buyer able to substantiate qualifying actual emissions if that calculation meets applicable rules.
Any premium for low-carbon electricity must still reflect legal due diligence, verifier fees and delivery risks. Contracts should allocate responsibility for metering, scheduling, legal review, verification and costs of replacement electricity following forecasting errors or curtailment.
These expenses need to be included in bid calculations from the beginning rather than treated as secondary costs after agreeing wholesale terms. Verified delivery data then become part of what is presented in commercial offers for cross-border transactions across Southeast Europe.
A defensible transaction requires an identified generating installation, an identifiable buyer and an authorised CBAM declarant, along with an accepted cross-border schedule and verified hourly data. It also requires a controlled methodology for allocating delivered megawatt-hours under qualifying arrangements.
Without required contractual, operational and emissions evidence, a transaction may remain a conventional electricity trade with uncertain carbon-border cost rather than a demonstrably eligible low-emissions supply arrangement.