Electricity is covered by the European Union’s Carbon Border Adjustment Mechanism for imports into the EU from 1 January 2026. Electricity released for free circulation in the EU is subject to the definitive CBAM regime, with no 50-tonne exemption and no gradual protection linked to continuing allocation of free EU ETS allowances for industrial producers. For power imports, carbon-cost exposure begins immediately.
The financial settlement for CBAM obligations has been delayed, but the liability is not. Electricity imported during 2026 will be included in the first annual CBAM declaration due by 30 September 2027, when corresponding certificates must also be surrendered. Certificates are expected to become available through the EU’s common purchasing platform from February 2027.
The official certificate price was €75.36 per tonne of CO₂ for the first quarter of 2026 and €75.28 per tonne for the second. Using Western Balkan electricity default emission factors, gross carbon costs are estimated at €86.42/MWh for Bosnia and Herzegovina, €78.37/MWh for Serbia, €73.70/MWh for Montenegro, and €66.77/MWh for North Macedonia. Albania’s default value is zero due to its hydro-based generation system.
Default carbon costs compared with regional day-ahead spreads
The size of the default CBAM component relative to wholesale prices is central to how the rules affect trading economics. Serbia’s average day-ahead price in the second quarter was approximately €96.3/MWh, compared with €109.2/MWh in Hungary. On that basis, a conventional commercial spread was about €13/MWh, while the Serbian default-value CBAM component was more than €78/MWh.
The same comparison framework applies at other borders. Montenegro’s second-quarter day-ahead price averaged €93.6/MWh, versus €120.9/MWh in Italy, producing a spread of about €27.3/MWh, while Montenegro’s default-value carbon component was almost €73.7/MWh. North Macedonia averaged €91.6/MWh, slightly above Greece’s €90.2/MWh, leaving no positive wholesale spread before considering a default CBAM cost of almost €66.8/MWh.
An example of how generation structure affects default treatment appears in Albania. Albania’s day-ahead price was about €88.6/MWh, with only a modest discount versus Greece, but its zero default factor gives hydro-based exports an advantage that fossil-intensive systems do not share.
Serbia’s fiscal exposure and domestic emissions tax design
Serbia’s government modelling places the electricity component of its 2026 CBAM exposure at approximately €21.8mn under a baseline scenario using default values and assuming unchanged 2025 trade volumes. Full recognition of Serbia’s domestic carbon charge could reduce the electricity-related burden to around €20.7mn. A proposed EU methodology change that would reflect Serbia’s total national electricity mix could lower the estimate further to approximately €14.5mn, a reduction of about 30%.
The modelling figures are described as scenario calculations rather than forecasts, and Serbia’s fiscal analysis cautions that electricity trade may already have weakened due to regulatory uncertainty.
Serbia’s domestic response includes a greenhouse-gas emissions tax set at €4 per tonne of CO₂ equivalent above a technological minimum. The tax applies from 1 January 2026, with collection beginning in 2027. Producers can claim a tax credit equal to up to 20% of qualifying decarbonisation investment, capped at up to 80% of the relevant carbon-tax liability.
The domestic rate remains small compared with CBAM certificate prices above €75 per tonne. Any EU deduction depends on proof that the Serbian charge was effectively paid and can be linked to the electricity or installation concerned.
Generation mix drives country default factors and plant-level separation issues
The regional generation mix helps explain differences in default exposure across countries. In Serbia, coal generation fell by about 12% to 6.54 TWh, but Serbia remained the Western Balkans’ largest coal-based producer in the second quarter. Bosnia and Herzegovina generated around 2.35 TWh from coal, while North Macedonia produced approximately 0.67 TWh.
Montenegro’s output was about 0.52 TWh, driven heavily by the Pljevlja lignite power plant . Albania produced approximately
The same issue arises when low-carbon generation cannot be demonstrated as such under EU rules using admissible evidence chains. CBAM can therefore create two electricity categories within a single national market: electricity supported by admissible installation-level evidence and electricity valued using a country’s default emission factor.
Evidentiary requirements for actual emissions values and accredited verification timing
The alternative to country default factors is use of actual installation-level emissions, but this requires meeting multiple cumulative conditions under current rules for electricity. The authorised CBAM declarant must have an appropriate power-purchase agreement with the third-country generator, and physical and contractual delivery routes must meet applicable requirements.
Elections must also be firmly nominated against allocated interconnection capacity, with generation matched to import over periods no longer than one hour. The framework includes network and emissions-related conditions that can be difficult to demonstrate across multiple borders.
A guarantee of origin may support renewable provenance but does not replace PPA structure, scheduling, interconnection arrangements, hourly matching, or verification evidence required by CBAM. Actual values must be verified by an accredited CBAM verifier, with accreditation programmes only beginning to become operational during 2026.
The first accredited electricity verifiers are expected around end-2026 or early-2027, creating a timing challenge because 2026 generation data, nominations, meter readings, contractual allocations and cross-border evidence must be preserved before verification engagements are completed. The EU importer remains legally responsible for the declaration even if information is supplied by a producer, trader or external verifier.
PPA design effects on compliance gaps and financing risk signals
PPA structure can determine whether renewable attributes translate into admissible CBAM positions when output differs from contracted volumes. A baseload or shaped PPA can create a compliance gap if the renewable generator underproduces and replacement volume is sourced through intraday or balancing markets.
If replacement electricity cannot be traced to another qualifying low-carbon source, that portion may fall back to the national default factor under CBAM rules. A pay-as-produced PPA can preserve a clearer relationship between metered output and imported volume but shifts profile and balancing risk to buyers.
The Energy Community modelled a 130 MW onshore wind farm facing an opportunity cost of approximately €8.9mn over six months if it could not claim actual emissions and instead sold into a lower-priced non-EU market rather than against a Hungarian day-ahead benchmark.
Treatment depends on destination: transit versus release for free circulation in the EU
A key legal distinction concerns whether electricity is released for free circulation in the EU or enters under transit procedures before leaving again for consumption elsewhere outside the Union. CBAM applies when electricity is released for free circulation in the EU; electricity entering under transit and subsequently leaving for consumption in another third country is not treated in the same way.
A physical flow across borders does not automatically equate to a CBAM-liable import consumed within an EU member state or elsewhere inside the Union after transit routing. Traders, customs representatives and transmission operators must distinguish between physical border flows, commercial nominations, customs treatment and ultimate destination.
Borders show differences between scheduled nominations and physical flows
A shift at Serbia’s northern border shows how routing can change without implying that carbon liabilities disappear under CBAM rules. Scheduled Serbia-to-Hungary flows increased by approximately 111% year on year during the second quarter.
The increase does not indicate that Serbian electricity has escaped CBAM obligations or that carbon costs are commercially irrelevant because Hungary has also become an increasingly important transit and balancing hub for electricity moving towards Ukraine during this period.
Bosnia and Herzegovina illustrates divergence between commercial nominations and physical flows into Croatia during the second quarter: approximately 824 GWh physically crossed into Croatia while only about 282 GWh was commercially scheduled in that direction.
Countryspecific default factors: Bosnia highest; Montenegro tied to Pljevlja; Albania zero value linked to hydrology
Bosnia and Herzegovina has an estimated current electricity default factor of approximately 1.148 tonnes of CO₂ per MWh, producing gross CBAM value above €86/MWh at second-quarter certificate prices based on default treatment assumptions.
This can penalise individual low-carbon plants unless their output is separated through an admissible contractual and verification chain when national defaults are used instead of actual values supported by evidence acceptable under EU requirements.
Montenegro’s estimated default factor is approximately 0.979 tonnes of CO₂ per MWh, reflecting continued role of Pljevlja alongside hydro and wind production; under default treatment its carbon cost is almost three times the second-quarter wholesale spread between Montenegro and Italy.
The commercial value of power from hydropower plants including Piva and Perućica as well as wind production from Krnovo and Možura depends on whether output can be contractually separated from national averages with evidence acceptable to an EU importer and verifier.
Northern Macedonia-Greece trade shifts; Albania exports depend on water availability constraints
A trade shift affecting North Macedonia-Greece flows occurred during the quarter: scheduled exports from North Macedonia to Greece fell by approximately 78%, while flows in the opposite direction increased by around 70%. The change cannot be attributed solely to CBAM because it coincides with closely aligned day-ahead prices alongside a default carbon component above €66/MWh.
This leaves limited economic basis for exporting unidentified Macedonian system power southward unless renewable production can compete using verified actual values rather than ordinary national-mix electricity valued using defaults.
Albania’s zero default factor reflects its almost entirely hydro-based system, allowing exports to Greece to increase modestly despite a small underlying price spread versus Greece during this period.
Status changes within trading volumes during early definitive regime months
The first six months of definitive regime coverage indicate changes in regional trading patterns alongside other drivers including hydrology, plant availability, fuel prices, cross-border capacity and demand from Ukraine.
Scheduled Western Balkan imports from EU markets fell by around 14% year on year during the second quarter to approximately 4,271 GWh, while exports to the EU declined by 16% to about 3,223 GWh; overall this left the region as a net importer of roughly 1,048 GWh.
Total gross scheduled exchange with EU markets fell by about 15% during the quarter and by about 19% during first half of 2026 compared with earlier periods referenced in reporting context provided alongside these figures.
Pace increases on organised day-ahead exchanges within Western Balkans
Together with weaker gross exchange with EU markets, trading activity increased on organised day-ahead exchanges within Western Balkans markets during this period.
Total volumes rose by approximately 19% to 2.70 TWh across regional exchanges mentioned in reporting context: volumes increased by 52% on ALPEX, 49% on Montenegro’s MEPX, 31% on North Macedonia’s MEMO and 7% on Serbia’s SEEPEX.
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