Electricity trading margins between the Western Balkans and EU markets increasingly depend on emissions calculations, certificate prices and the eligibility of actual-generation data.
ANALYSIS · 29 OCTOBER 2026
BELGRADE, 29 OCTOBER 2026 — Electricity exports from the Western Balkans to neighbouring EU markets face an additional cost variable under the definitive Carbon Border Adjustment Mechanism (CBAM). Wholesale price differences between interconnected markets may indicate an attractive trading opportunity, but the financial outcome can change substantially when the carbon liability associated with imported electricity is included.
The mechanism distinguishes between imports assessed using applicable default emissions values and transactions that satisfy the requirements for actual-emissions treatment. Where eligible actual data cannot be used, the emissions calculation must follow the applicable EU methodology. This distinction is particularly relevant in interconnected electricity systems, where power can move through several trading portfolios and across multiple borders before reaching an EU importer.
A contractual description of electricity as renewable does not automatically establish a zero-emissions value for CBAM purposes. The generating source, applicable calculation methodology and supporting evidence must satisfy the relevant regulatory conditions.
Default emissions and the cost of imported electricity
The potential financial exposure can be illustrated using a hypothetical import scenario. An electricity volume of 100,000 MWh, assigned 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.
Applying the official third-quarter 2026 CBAM certificate reference price of EUR 82.32 per tonne, the resulting gross carbon-price equivalent would reach approximately EUR 4.94 million. This calculation is a sensitivity example rather than a statutory charge applicable to a particular country, border or electricity transaction. It precedes applicable legal adjustments and the final certificate calculation.
At individual MWh level, the same assumptions produce gross carbon-price exposure of approximately EUR 49.39/MWh. A wholesale electricity price differential of EUR 20/MWh would therefore be insufficient to cover this illustrative carbon exposure, even before accounting for transmission charges, network losses, balancing requirements and trading costs.
The actual financial outcome depends on the legally applicable emissions factor, relevant phase-in adjustments and the circumstances of the authorised importer. The hypothetical factor of 0.60 tCO₂/MWh should not be interpreted as an official default for any Western Balkan country.
Wholesale arbitrage requires a carbon-adjusted calculation
The introduction of CBAM changes the basis on which electricity traders assess cross-border opportunities. Comparing day-ahead prices between two exchanges is no longer sufficient to establish the profitability of an export transaction.
A more complete assessment needs to incorporate the electricity purchase and sale prices, cross-border capacity costs, transmission losses, imbalance charges and expected CBAM treatment. Calculations should be performed at transaction level, taking account of the delivery hour, direction of electricity flows and identity of the importing entity.
Daily average prices can conceal substantial differences between individual trading periods. This is particularly relevant when renewable generation contributes to intraday price volatility and changes the relationship between available electricity, scheduled exports and realised market prices.
The distinction between actual and default emissions also affects commercial negotiations. A seller able to demonstrate eligible actual-generation emissions may seek a higher electricity price or negotiate a share of the associated carbon-cost savings. Conversely, uncertainty over the evidence or legal eligibility of an actual-emissions claim may lead an EU buyer to calculate its offer using a default assumption.
The commercial value of lower-emissions generation therefore depends not only on the physical characteristics of the generating installation but also on whether the relevant regulatory methodology allows those characteristics to be reflected in the import calculation.
Contract structures determine the allocation of carbon risk
CBAM exposure introduces additional requirements into electricity supply agreements between Western Balkan exporters and EU buyers. Contracts need to establish which party bears the financial consequences of the applicable emissions calculation.
One structure allows the seller to deliver electricity at an agreed price while leaving CBAM responsibility with the EU buyer. In that arrangement, the buyer can incorporate its anticipated carbon liability into the purchase price offered to the exporter.
Alternatively, a seller may agree to a delivered net price and assume part of the carbon-related exposure. This arrangement requires clear provisions covering changes in legislation, unsuccessful actual-emissions claims and revisions to the applicable emissions factor.
The contractual allocation becomes particularly important when electricity supply agreements extend over several years. Day-ahead electricity prices can change hourly, while long-term PPAs establish commercial commitments over much 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 consequently require different assumptions. Using a single quarterly certificate reference price or a temporary wholesale market spread as the basis for a multi-year revenue projection can produce an unreliable assessment of expected project income.
Regional generation profiles and default-factor exposure
The effects of CBAM may differ across Western Balkan electricity systems because their generation portfolios are not identical. Hydropower and renewable-intensive portfolios can have a physical emissions advantage compared with electricity produced predominantly from fossil fuels.
However, the commercial value of that advantage depends on the possibility of applying an eligible actual-emissions calculation or on the design of the applicable default factors. Where a country-level default is used, the emissions characteristics of an individual low-carbon installation may not be fully reflected in the carbon cost assigned to its exports.
This creates an incentive for electricity producers to establish reliable generation-data systems and for regional governments to support improvements in the regulatory framework governing electricity exports to the EU.
Renewable project developers also face a financial modelling challenge. Forecast revenues based on EU wholesale electricity prices alone may overstate the economic benefit of cross-border market access if the calculation excludes potential CBAM liabilities.
Project lenders need 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 regulatory outcomes.
For renewable generators, physically low-carbon electricity does not automatically translate into an equivalent financial advantage in EU trade. That advantage depends on the applicable emissions calculation and the availability of a defensible chain of supporting evidence.
The resulting change in trading economics extends beyond the electricity price differential between neighbouring markets. Congestion, hourly price volatility, balancing costs and transmission charges already influence cross-border electricity margins. The additional carbon exposure under CBAM means that the apparent profitability of an export can differ significantly from its net commercial value once the applicable emissions treatment is incorporated.
