The Western Balkans electricity sector is adjusting to a commercial shift as the EU’s Carbon Border Adjustment Mechanism (CBAM) starts affecting cross-border power trade. The mechanism is already changing price spreads, export revenues and the investment logic for renewables across Serbia, Montenegro, Bosnia and Herzegovina, North Macedonia, Albania and Kosovo. CBAM is applied to electricity imported into the EU from non-EU markets unless an exemption applies.
CBAM introduces a carbon cost on imported electricity, altering how value is captured in cross-border transactions. While EU-side buyers may continue importing electricity, the carbon-adjusted price reduces the realised value for exporters in the region. The impact is linked to systems that remain coal-heavy and to the role of EU interconnectors in generating export revenue.
EU-Western Balkans spreads move after CBAM’s January 2026 start
The first visible effect has been a widening gap between Western Balkan and neighbouring EU electricity prices. After the definitive phase began in January 2026, EU–Western Balkans price spreads increased sharply, with an average spread of around €30/MWh. Some interconnector spreads rose further.
The Italy–Montenegro spread reached around €44/MWh, while Hungary–Serbia stood around €34/MWh. Other cited spreads included Croatia–Serbia at €27/MWh, Romania–Serbia at €26/MWh, and Bulgaria–Serbia at €25/MWh. The wider gap reflects how carbon risk is priced into trade rather than a straightforward power-market arbitrage.
In a conventional market setting, lower-cost electricity in Serbia, Montenegro or Bosnia and Herzegovina would be expected to flow into higher-priced EU markets until congestion, capacity pricing or generation availability constrains exports. Under CBAM, the apparent arbitrage becomes a carbon-adjusted margin rather than a pure power spread. This changes how traders evaluate export windows and realised margins.
Exporters absorb most of the CBAM price shock
The commercial impact is concentrated on producers in the Western Balkans. The source data indicates that around 85–95% of the price shock is absorbed by exporting-side producers, particularly in Serbia, Montenegro and Bosnia and Herzegovina. As a result, CBAM does not only raise costs for EU importers; it depresses realised export values from the region.
This affects utilities and independent generators that depend on export windows to capture higher regional prices. Even where exports continue physically, realised revenue quality can deteriorate if net prices fall after carbon adjustments. The shift is therefore tied to both pricing outcomes and revenue capture.
Default emissions values drive obligations based on fossil intensity
The severity of the effect is linked to CBAM’s default-emissions methodology using country-specific default values. These defaults reflect emissions intensity of fossil-fuel electricity generation in the exporting country. For coal-heavy systems, this approach can increase obligations relative to low-carbon generation profiles.
The cited default values are 1.148 tCO₂/MWh for Bosnia and Herzegovina, 1.041 tCO₂/MWh for Serbia, 0.984 tCO₂/MWh for Kosovo, 0.979 tCO₂/MWh for Montenegro, and 0.887 tCO₂/MWh for North Macedonia. With an assumed EUA price of €70/tCO₂, this implies CBAM obligations of around €80/MWh for Bosnia and Herzegovina, €73/MWh for Serbia, €69/MWh for Kosovo and Montenegro, and €62/MWh for North Macedonia.
For Serbia, a default burden near €73/MWh can exceed the day-ahead spread that would otherwise make exports commercially attractive. Even when Serbian power appears cheaper than Hungarian, Romanian or Croatian power on screen, carbon-adjusted export value can be reduced once obligations are included. The exporter may still dispatch but with weaker margin capture under these conditions.
Grid-average default reforms would reduce obligations but not remove pressure
A reform proposal would change how default values are calculated by using overall grid emissions intensity rather than only fossil-fuel generation. The stated objective is to better reflect hydro, wind, solar and other low-carbon generation within national mixes. Under this approach, Serbia’s possible default value would fall from 1.041 tCO₂/MWh to 0.667 tCO₂/MWh.
This would reduce an indicative CBAM obligation from €73/MWh to €47/MWh. Montenegro would decline from 0.979 tCO₂/MWh to 0.414 tCO₂/MWh, cutting an indicative obligation from €69/MWh to €29/MWh. For Bosnia and Herzegovina, the source cites a reduction from “€80/MWhto €45/MWh”, alongside similar directional changes tied to revised defaults.
The reform would be commercially significant but still leaves obligations large enough to affect export incentives and producer revenues. For Montenegro, the difference is described as particularly relevant because hydro-heavy generation is poorly reflected by fossil-only defaults. Until methodology settlement results in bankable application, traders are expected to price uncertainty into contracts.
Exports persist early in 2026 while margins deteriorate
The early market picture shows exports remaining relatively high despite CBAM during January and February 2026. The source attributes this persistence to fundamentals such as temperature-related demand and favourable hydro conditions. This indicates that CBAM does not stop electricity trade immediately; it reprices it.
The data suggests that in tight market conditions EU buyers may continue importing Western Balkan electricity while price incidence shifts toward regional producers. Trade flows can therefore survive even as exporter margins deteriorate. This distinction matters when comparing scheduled volumes with realised revenue outcomes.
If exports continue but net prices fall, fiscal and corporate impacts can still be significant for utilities and governments. State-owned utilities may face weaker cash generation affecting maintenance funding and decarbonisation investment capacity. Private generators may see lower merchant revenues alongside less attractive refinancing conditions.
Full-year modelling points to lower EU exports and reduced export revenues
A full-year modelling comparison indicates a roughly 60% drop in annual exports from the Western Balkans to the EU under CBAM versus without it. Export revenues are projected at around 70% lower. Price spreads rise by around €20/MWh, aligning with early 2026 observations.
The modelling also describes net exports declining after lower EU exports are only partly offset by lower imports. The direction is described as consistent with CBAM reducing the value of Western Balkan electricity exports into the EU. This effect is highlighted as especially relevant in strong hydro years when surplus power would otherwise be positioned for EU sales.
Renewables face lower wholesale prices and higher revenue uncertainty
The renewable-investment consequence is tied to wholesale price reductions inside Western Balkan markets as producers absorb most of the burden. The source expects local wholesale prices to fall by about €15–20/MWh. That reduction lowers market value for renewable generation and increases revenue uncertainty for merchant renewables.
This creates a policy contradiction described through the interaction between decarbonisation incentives and depressed market outcomes for wind and solar projects unless support schemes adjust. For Serbia specifically, merchant wind or solar projects exposed to lower domestic prices, higher volatility and uncertain export value may struggle to attract capital on prior terms. Feed-in premium schemes may require higher support due to a larger gap between reference prices and wholesale market levels.
The source also points to corporate PPAs becoming more important with industrial buyers seeking documented low-carbon electricity tied to CBAM-related needs. It notes that such PPAs must be more sophisticated than traditional green-power contracts when generic wholesale prices are pressured lower by CBAM.
Banks assess projects using audit-ready proof linked to industrial supply contracts
A “power-plus-proof” approach is described as directly relevant for renewable bankability in Serbia under CBAM-distorted pricing conditions. A Serbian renewable project can become more bankable if it sells electricity not only as energy but as a compliance-grade supply product for heavy industry. The product requirements listed include settlement-meter data, SCADA production records, PPC and Grid Code evidence.
The same set of documentation items includes EMS schedule confirmation, GO registry documentation and PPA data-sharing clauses. In this framework, premiums are expected to attach to electricity that supports Serbian industrial exporters’ ability to defend EU market access through documented low-carbon attributes rather than generic MWh pricing alone.
Cumulation with market coupling depends on an EU ETS-equivalent carbon price by 2030
The market-coupling issue is addressed through exemption requirements rather than relying on coupling alone. Countries need an electricity exemption before acceding to the EU’s single day-ahead and intraday coupling frameworks. The key condition cited is introduction of a carbon price equivalent to the EU ETS by 2030, alongside other requirements.
No CBAM exemption would apply without equivalent carbon pricing, according to the stated logic in the source material. No straightforward market coupling would occur without that exemption condition being met first.
This links cross-border trading arrangements directly to domestic carbon-pricing readiness timelines.
Diligence focus shifts for lenders amid risks of falling merchant prices
The due-diligence agenda changes for banks and investors assessing renewable projects across Serbia and the region under CBAM effects on merchant markets. Lenders are described as needing assessment beyond resource yield, CAPEX strength, EPC capability, grid connection status, curtailment expectations and DSCR metrics alone.
The source lists additional questions including whether projects rely on merchant prices that may fall by €15–20/MWh. It also highlights whether projects have PPAs with industrial buyers valuing documented low-carbon electricity; whether they can produce audit-ready evidence; whether revenue models withstand higher volatility; and whether support schemes compensate for reduced wholesale prices.
These items are described as part of bankability checks under CBAM conditions.
Coal-heavy generators face lower realised export value; hydro-heavy systems need documentation too
The utilities impact described focuses on coal-heavy generators in Serbia, Bosnia and Herzegovina and Kosovo facing lower realised export value unless carbon pricing measures, exemptions or major decarbonisation steps are introduced.
Hydro-heavy systems such as Albania—and partially Montenegro during high-hydro periods—are noted as having stronger natural positioning but still requiring clear documentation and methodology reform.
The source places North Macedonia between these models with transition risk alongside room for solar-led repositioning.
It links these differences back to how defaults or methodologies capture emissions intensity relative to each system’s generation mix.
Cepam splits electricity into ordinary MWh versus carbon-defensible MWh for industry buyers
The effect on industrial buyers includes both risk and opportunity depending on domestic wholesale price movements tied to exporter absorption of carbon burdens.
If domestic wholesale prices fall because exporters absorb carbon costs externally through reduced export value mechanics, some industrial buyers could benefit from lower short-term electricity costs.
The source also states that export-oriented industry cannot rely on cheap undifferentiated electricity if EU customers require carbon evidence.
Heavy industry in Serbia will increasingly need PPAs or supply contracts providing low-carbon documentation rather than only lower prices.
In this sense, CBAM divides traded products into ordinary MWh versus carbon-defensible MWh based on proof requirements.
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