CBAM Reshapes Serbia’s Electricity Exports and Regional Power Trade

Serbia’s electricity trade with the European Union is facing a major structural change as the EU Carbon Border Adjustment Mechanism (CBAM) begins applying to power imports, creating new compliance obligations and changing the economics of cross-border electricity transactions across the Western Balkans.

Since 1 January 2026, electricity released for free circulation in the EU has been included in the definitive CBAM regime. Unlike steel, aluminium, cement and fertiliser imports, electricity does not benefit from the 50-tonne exemption or the gradual protection provided by the continued allocation of free EU ETS allowances to European industrial producers. This means carbon-cost exposure begins immediately for electricity entering the EU market.

Electricity imported during 2026 will be reported in the first annual CBAM declaration, which must be submitted by 30 September 2027, when the related CBAM certificates must also be surrendered. Certificates will become available through the EU common purchasing platform from February 2027. The delayed payment process provides additional time for utilities and traders to manage cash flows, but it does not remove the future liability created by imports during 2026.

Carbon costs create new pressure on regional electricity exports

The official CBAM certificate price reached €75.36 per tonne of CO₂ in the first quarter of 2026 and €75.28 per tonne in the second quarter. Applying the second-quarter price to the electricity default emission factors used for Western Balkan countries produces significant potential carbon costs.

Under current default values, the gross CBAM exposure reaches:

• Bosnia and Herzegovina: €86.42/MWh
• Serbia: €78.37/MWh
• Montenegro: €73.70/MWh
• North Macedonia: €66.77/MWh
• Albania: €0/MWh due to its predominantly hydro-based generation system

These calculations represent default-value scenarios rather than final invoices. The costs apply where importers cannot demonstrate eligible actual emissions or prove that an accepted carbon price has already been paid in the exporting country.

The impact becomes clearer when compared with regional wholesale electricity prices. Serbia recorded an average day-ahead price of approximately €96.3/MWh during the second quarter, while Hungary averaged €109.2/MWh, creating a wholesale price difference of about €13/MWh. The Serbian default CBAM component of €78.37/MWh is therefore more than six times larger than the normal cross-border price spread. This significantly changes the economics of electricity arbitrage. Exporters must either absorb the carbon cost, accept lower net revenues or qualify for substantially lower actual emissions values.

Serbia estimates multi-million euro electricity exposure

Serbia’s preliminary fiscal modelling estimates that the electricity-related CBAM exposure for 2026 could reach approximately €21.8 million under a baseline scenario using default values and unchanged 2025 trade volumes. The estimated burden could decline to around €20.7 million if Serbia receives full recognition of its domestic carbon charge. A proposed EU methodology change, which would calculate default emissions based on Serbia’s entire electricity mix rather than primarily fossil generation, could reduce the estimated exposure further to approximately €14.5 million, representing a decrease of about 30%.

These figures are scenario calculations rather than final forecasts. Serbia’s fiscal analysis also notes that electricity trading patterns may already have changed due to regulatory uncertainty surrounding CBAM. Serbia introduced a domestic greenhouse gas emissions tax of €4 per tonne of CO₂ equivalent above the defined technological minimum from 1 January 2026, with collection beginning in 2027. Electricity producers may receive a tax credit covering up to 20% of eligible decarbonisation investments, limited to 80% of the related carbon-tax liability.

The mechanism allows Serbia to retain part of the carbon-related revenue domestically and direct support towards generation investments. However, the domestic rate remains significantly below the CBAM certificate price above €75 per tonne, and recognition by EU authorities will depend on evidence that the Serbian charge was paid and linked to the relevant electricity or installation.

Generation structure determines CBAM exposure

Regional differences in CBAM exposure largely reflect electricity generation structures. Serbia remained the Western Balkans’ largest coal-based electricity producer during the second quarter, although coal generation declined by approximately 12% to 6.54 TWh. Bosnia and Herzegovina produced around 2.35 TWh from coal, while North Macedonia generated approximately 0.67 TWh from coal sources.

Montenegro produced about 0.52 TWh, with output heavily influenced by the Pljevlja lignite power plant, alongside hydro and wind generation. Albania generated approximately 0.90 TWh, almost entirely from hydropower. The regional default hierarchy therefore follows underlying generation patterns, although national averages do not reflect differences between individual plants.

A megawatt-hour produced by a Serbian wind farm has a different emissions profile from electricity generated at a lignite facility, but both can initially face the same national default factor if renewable origin and delivery documentation cannot be demonstrated under CBAM rules. This creates two categories of electricity within the same national market: power supported by admissible installation-level evidence and power assessed using national default emissions values.

Western Balkan electricity flows adjust under new rules

During the first six months of the definitive CBAM regime, regional electricity trade patterns showed signs of change. Scheduled Western Balkan imports from EU markets declined by approximately 14% year on year in the second quarter, reaching about 4,271 GWh, while exports to EU markets decreased by 16% to approximately 3,223 GWh. The region recorded a net import position of around 1,048 GWh.

Gross scheduled electricity exchanges with EU markets fell by approximately 15% during the quarter and by around 19% during the first half of 2026. At the same time, trading volumes on organised regional day-ahead exchanges increased by approximately 19% to 2.70 TWh. Volumes grew by:

• 52% on ALPEX
• 49% on Montenegro’s MEPX
• 31% on North Macedonia’s MEMO
• 7% on Serbia’s SEEPEX

The combination of lower EU exchange volumes and stronger regional exchange activity indicates that more electricity is being cleared within Western Balkan markets as exporting carbon-intensive electricity to the EU becomes more challenging.

Serbia-Hungary flows reflect regional transit role

Scheduled electricity flows from Serbia to Hungary increased by approximately 111% year on year during the second quarter. The increase does not indicate that Serbian electricity has avoided CBAM costs. Hungary has become an increasingly important transit and balancing hub for electricity flows towards Ukraine, with available Hungary-to-Ukraine auction capacity rising significantly during the period.

As a result, some Serbian exports may reflect wider regional routing rather than final electricity consumption within the EU. The distinction is important because CBAM applies when electricity is released for free circulation in the EU. Electricity entering the EU under transit arrangements and later leaving for consumption in another third country is treated differently. Physical border flows must therefore be distinguished from commercial nominations, customs procedures and final destinations.

Regional markets face different commercial challenges

Bosnia and Herzegovina illustrates the difference between physical and commercial electricity flows. During the second quarter, approximately 824 GWh physically crossed from Bosnia and Herzegovina into Croatia, while only about 282 GWh was commercially scheduled in that direction.

Scheduled exports declined while physical flows increased. CBAM can influence commercial arrangements, but electricity flows through interconnected grids cannot be redirected instantly. Differences between scheduled and physical flows may increase requirements for redispatch, countertrading and additional system security measures. Bosnia and Herzegovina currently has the highest electricity default factor in the region at approximately 1.148 tonnes of CO₂ per MWh, producing a gross CBAM value above €86/MWh at second-quarter certificate prices.

Montenegro faces a similar challenge. Its default factor of approximately 0.979 tonnes of CO₂ per MWh reflects the continued role of the Pljevlja lignite plant, despite the country’s hydro and wind resources. The commercial value of electricity from the Piva and Perućica hydropower plants and wind farms such as Krnovo and Možura will increasingly depend on whether their production can be separated from the national average and supported with acceptable evidence.

North Macedonia recorded a sharp shift in electricity trade with Greece. Scheduled exports from North Macedonia to Greece declined by approximately 78%, while flows in the opposite direction increased by around 70%. With day-ahead prices closely aligned and a default CBAM cost above €66/MWh, unidentified national-mix electricity faces significant commercial pressure.

Albania benefited from its hydro-based electricity system, with a zero default factor allowing exports to Greece to increase modestly despite limited price differences. However, export capacity remains dependent on hydrological conditions and available grid capacity.

Renewable projects require stronger compliance structures

Using actual installation-level emissions instead of national default values requires more than renewable certification. Under current CBAM rules, the authorised declarant must have an appropriate power purchase agreement with the third-country generator, a compliant physical and contractual delivery route, firm nomination against allocated interconnection capacity, and matching between generation and imports over periods of no longer than one hour.

Guarantees of origin can confirm renewable attributes but do not replace requirements related to PPAs, scheduling, interconnection, hourly matching and verification. Actual emissions values must also be verified by an accredited CBAM verifier. Accreditation programmes began becoming operational during 2026, with the first accredited electricity verifiers expected around the end of 2026 or early 2027.

Because verification will occur after the first reporting period, companies must preserve generation data, meter readings, contractual allocations and cross-border documentation from 2026 onwards. The EU importer remains legally responsible for the CBAM declaration even when information is provided by producers, traders or external verifiers.

CBAM compliance becomes a financing factor for renewable projects

The structure of power purchase agreements is becoming increasingly important for renewable energy projects. Baseload or shaped PPAs may create compliance risks if renewable generators underproduce and replacement electricity is sourced from balancing markets without a qualifying low-carbon origin. Pay-as-produced agreements can provide a clearer connection between metered generation and imported electricity but transfer balancing risks to buyers.

The Energy Community modelled a 130 MW onshore wind farm that could face an opportunity cost of approximately €8.9 million over six months if it cannot demonstrate actual emissions and must sell into a lower-priced non-EU market instead of the Hungarian day-ahead market.

The loss would not result from emissions produced by the wind farm, but from the inability to establish an admissible CBAM position. This creates a new consideration for renewable investments in Serbia, Montenegro, Bosnia and Herzegovina and North Macedonia. Investors and lenders will need to evaluate EU buyers, compliant PPAs, hourly metering, nomination structures, verifier availability and audit documentation.

EU considers changes to electricity CBAM methodology

The European Commission has proposed amendments to the electricity framework, including changes to default emission calculations. The proposed methodology would calculate national default factors using the weighted average emissions intensity of the entire electricity mix rather than primarily fossil generation. It would also allow intermediaries within the PPA chain where the connection between generator and importer remains verifiable, clarify physical PPA requirements and remove the condition requiring proof that no physical network congestion existed between the generator and the EU system.

The Commission has proposed applying revised default and actual-value rules to electricity imported from 1 January 2026, although the changes remain under negotiation and are not yet binding legislation.

For Serbia, the whole-mix methodology would be particularly significant because it would recognise lower-carbon generation sources within the national electricity factor. It would not eliminate the impact of lignite generation, but it could reduce the current default penalty and improve the economics of some cross-border electricity transactions.

A longer-term pathway could involve closer electricity-market integration with the EU. The CBAM Regulation allows limited treatment for third-country electricity systems integrated with the Union through market coupling, provided demanding conditions are met, including regulatory alignment and progress towards carbon pricing equivalent to the EU ETS.

Serbia’s future position in regional electricity trade will depend not only on installed generation capacity but also on compliance infrastructure, including hourly measurement, delivery structures, PPA design, cross-border nominations, verifier availability and documentation capable of meeting EU customs requirements.

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