The European Union’s Carbon Border Adjustment Mechanism (CBAM) is reshaping electricity pricing and cross-border trading across Southeast Europe, widening the gap between wholesale power prices and the carbon-adjusted cost of electricity exported from the Western Balkans into the EU.
The impact on electricity could emerge more quickly than in sectors such as steel and aluminium. While these industries benefit from transitional arrangements linked to the gradual phase-out of free EU carbon allowances, electricity imports receive no equivalent free-allocation relief, exposing carbon-intensive exports to additional costs from the beginning of 2026.
The latest published CBAM certificate price reached €82.32 per tonne of CO₂ for the third quarter, up from €75.28 in the preceding quarter. This increases the indicative carbon cost of electricity exported from countries subject to high default emissions factors.
Applying the latest certificate price to existing national default factors produces an estimated gross CBAM exposure of approximately €85.70/MWh for Serbian electricity, €80.59/MWh for Montenegro and €94.50/MWh for Bosnia and Herzegovina. North Macedonia faces an indicative cost of €73.01/MWh, while Albania’s zero default factor results in no carbon charge under the default calculation.
These figures are illustrative estimates based on the third-quarter certificate price, rather than final charges for October deliveries. The fourth-quarter certificate price will be established in January 2027, while actual liabilities may also reflect eligible deductions for carbon prices paid in the country of origin.
Nevertheless, the estimates show how CBAM costs can exceed conventional wholesale electricity trading margins.
On Oct. 9, Serbia’s SEEPEX day-ahead electricity price climbed to €239.96/MWh, an increase of almost 34% from the previous session, while Hungary’s HUPX benchmark reached €269.43/MWh. The resulting spread of €29.47/MWh remained substantially below Serbia’s indicative carbon exposure calculated using the national default factor.
A trader importing Serbian electricity into Hungary would therefore face difficulty covering the indicative carbon cost from that daily average wholesale price difference alone, even before accounting for cross-border transmission capacity, losses, balancing and other trading expenses.
Montenegro’s BELEN benchmark reached €223.39/MWh on the same day, while wholesale electricity prices in several Italian bidding zones stood at approximately €230-235/MWh. This also indicates a relatively narrow potential price differential for electricity delivered through the Montenegro-Italy interconnection.
Daily average price differences do not represent executable trading margins, and hourly fluctuations can create individual trading opportunities. However, the broader commercial implication is becoming clearer: a lower wholesale electricity price outside the EU no longer guarantees a competitive delivered price inside the EU.
The Energy Community Secretariat has already identified changes in regional electricity flows. Gross commercial exchanges between the Western Balkans and neighbouring EU markets declined by approximately 19% year on year in the first half of 2026, although hydrological conditions, generation availability and changing import requirements also contributed to the decline.
The regional market is increasingly dividing into two commercial segments: domestic and regional electricity trading, where EU CBAM import charges do not directly apply, and exports into EU markets, where carbon-adjusted costs increasingly influence whether transactions remain commercially viable.
For Serbia’s EPS, Montenegro’s EPCG and electricity producers across Bosnia and Herzegovina, the new environment places greater emphasis on generation technology, electricity origin and the ability to demonstrate actual embedded emissions.
This distinction is particularly important for renewable-energy developers. A Serbian wind farm producing low-carbon electricity does not automatically qualify for more favourable CBAM treatment when its output is exported to Hungary. Unless the EU importer satisfies the applicable requirements for using actual embedded emissions, the electricity may remain subject to Serbia’s national default emissions value.
The existing framework requires qualifying physical power purchase agreements, evidence identifying the generating installation, compliant cross-border capacity nominations, hourly matching between generation and nominated deliveries, and evidence concerning grid connection or the absence of congestion. Supporting documentation must also undergo assessment by an accredited verifier.
Guarantees of Origin alone are insufficient to replace the physical and contractual evidence required under the applicable CBAM methodology.
For project developers and lenders, the implications are significant. A wind or solar project may generate electricity at a competitive cost while remaining uncertain about the additional revenue it can obtain from direct sales into EU markets.
This uncertainty affects projected revenues, long-term power purchase agreements, financing assumptions and the investment case for new renewable capacity across the Western Balkans.
The impact also extends to industrial manufacturers, although the regulatory treatment differs between sectors. Under the current CBAM framework, indirect emissions from purchased electricity are included in the liability calculations for cement and fertilisers, but are not generally included for iron, steel and aluminium, where the current obligations focus on direct embedded emissions.
Consequently, sourcing renewable electricity does not automatically reduce the current CBAM certificate liability of a Serbian steel or aluminium exporter. It can, however, lower operating costs, improve corporate emissions performance and strengthen commercial relationships with European manufacturers seeking lower-carbon materials.
For cement and fertiliser producers, qualifying lower-emission electricity can directly affect the carbon intensity used in CBAM calculations, subject to the applicable calculation methodology and verification requirements.
The European Commission has proposed changes to the electricity CBAM methodology that could reduce the disadvantage faced by renewable generators in countries whose default emissions factors reflect carbon-intensive thermal generation. If adopted, such changes could improve the economics of hydropower, wind and solar exports from Serbia, Montenegro and Bosnia and Herzegovina.
However, the proposed changes have not yet been fully adopted, leaving investors exposed to uncertainty over the final regulatory treatment.
For banks financing renewable-energy projects, electricity-intensive manufacturers and cross-border trading businesses, CBAM has become an additional source of revenue, margin and regulatory risk.
New project assessments increasingly need to distinguish conventional wholesale electricity revenues from income that depends on verified, CBAM-compliant physical export arrangements. Existing loans may also require reassessment where earlier financial models assumed uninterrupted access to EU wholesale price premiums.
The first CBAM certificates covering electricity imports during 2026 will be available for purchase from February 2027, with annual declarations and certificate surrender due by Sept. 30, 2027.
For Southeast Europe, the central challenge is that electricity markets remain physically interconnected while their commercial economics are becoming increasingly differentiated by carbon treatment.
A megawatt-hour generated in Serbia or Montenegro can still reach a European buyer through the interconnected transmission network. However, whether that electricity can be sold profitably will increasingly depend on its carbon classification, the evidence supporting the transaction and the applicable CBAM rules, rather than simply on the wholesale price difference between the two sides of the border.
