The Western Balkans electricity sector is moving into a new commercial reality faster than most utilities, traders and policymakers expected. CBAM is no longer a future compliance mechanism sitting somewhere beyond market operations. It is already changing price spreads, cross-border trading incentives, export revenues and the investment logic for renewables across Serbia, Montenegro, Bosnia and Herzegovina, North Macedonia, Albania and Kosovo.
The central issue is simple but disruptive. CBAM places a carbon cost on electricity imported into the EU from non-EU markets unless an exemption applies. For the Western Balkans, where several systems remain coal-heavy and where EU interconnectors have historically offered important export revenue, the mechanism changes who captures value in cross-border trade. The EU-side buyer may continue to import electricity, but the carbon-adjusted price weakens the realised value for the regional exporter.
The first visible effect is the widening gap between Western Balkan and neighbouring EU electricity prices. After the start of CBAM’s definitive phase in January 2026, EU–Western Balkan price spreads increased sharply, with an average spread of around €30/MWh and some interconnector spreads moving even higher. The Italy–Montenegro spread reached around €44/MWh, while Hungary–Serbia stood around €34/MWh, Croatia–Serbia around €27/MWh, Romania–Serbia around €26/MWh, and Bulgaria–Serbia around €25/MWh.
At first glance, larger spreads should make Western Balkan exports more attractive. In a normal power-market setting, cheaper electricity in Serbia, Montenegro or Bosnia and Herzegovina would flow into higher-priced EU markets until congestion, capacity prices or generation availability limited the trade. CBAM changes that logic. The widened spread is not simply an opportunity; it is the market’s way of pricing carbon risk. The apparent arbitrage therefore becomes a carbon-adjusted margin, not a pure power spread.
That is the commercial shock. Most of the CBAM price burden is absorbed by Western Balkan producers, especially in Serbia, Montenegro and Bosnia and Herzegovina, where around 85–95% of the price shock falls on the exporting side. This means CBAM does not merely raise the cost for EU importers; it depresses the realised value of electricity exports from the region. For utilities and independent producers that rely on export windows to capture higher regional prices, this is a direct hit to revenue quality.
The default-emissions methodology is the reason the effect is so severe. Current CBAM treatment is based on country-specific default values that reflect the emissions intensity of fossil-fuel electricity generation in the exporting country. That matters enormously for coal-heavy systems. The current default values stand at 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. At an assumed EUA price of €70/tCO₂, this implies a CBAM obligation 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, this is especially important. A CBAM default burden of around €73/MWh is not a marginal adjustment. It can be larger than the day-ahead spread that makes an export commercially attractive. Even if Serbian power is cheaper than Hungarian, Romanian or Croatian power on the screen, the carbon-adjusted export value may be heavily reduced once the CBAM obligation is included. This creates a new floor under EU import prices and a new ceiling over Serbian export revenues. In practical terms, the Serbian exporter may still dispatch, but it does so with weaker margin capture.
The proposed reform of default values would soften this burden but not remove it. A reform proposal would calculate default values based on the overall grid emissions intensity of the exporting country, rather than only fossil-fuel generation. This would better reflect hydro, wind, solar and other low-carbon generation in the national mix. Under that approach, Serbia’s possible default value would fall from 1.041 tCO₂/MWh to 0.667 tCO₂/MWh, reducing the indicative CBAM obligation from €73/MWh to €47/MWh. Montenegro would fall from 0.979 tCO₂/MWh to 0.414 tCO₂/MWh, cutting the obligation from €69/MWh to €29/MWh. Bosnia and Herzegovina would fall from €80/MWhto €45/MWh.
That reform would be commercially significant, but it would not eliminate the competitive problem. Even a Serbian CBAM burden of €47/MWh remains large enough to reshape exports, depress producer revenues and reduce the market value of renewable generation. For Montenegro, the difference is particularly striking because the country’s hydro-heavy profile is poorly reflected by a fossil-only default methodology. A grid-average approach would better capture the system’s low-carbon component and could preserve more of the value of the Montenegro–Italy interconnector. But until the methodology is settled and applied in a bankable way, traders will price uncertainty.
The early market evidence is more nuanced than a simple collapse in trade. Exports to the EU remained relatively high in January and February 2026, despite CBAM, probably because of strong fundamentals such as temperature-related demand and favourable hydro conditions. This is important. CBAM does not stop electricity trade immediately. It reprices it. In tight market conditions, EU buyers may still import Western Balkan electricity, but the price incidence shifts heavily toward regional producers. Trade flows can survive while exporter margins deteriorate.
That distinction matters for utilities and governments. A policymaker looking only at physical or scheduled exports may conclude that CBAM has not yet disrupted trade. A finance director looking at realised export revenues will see a different picture. If exports continue but net prices fall, the fiscal and corporate impact can still be severe. State-owned utilities may face weaker cash generation, reduced ability to fund maintenance and lower capacity to invest in decarbonisation. Private generators may face lower merchant revenues and less attractive refinancing conditions.
Full-year modelling points to a more severe structural outcome. A comparison of regional market behaviour with and without CBAM suggests a roughly 60% drop in annual exports from the Western Balkans to the EU and around 70% lower export revenues. Price spreads rise by around €20/MWh, broadly consistent with early 2026 market observations, while net exports decline after lower EU exports are only partly offset by lower imports. The direction is clear: CBAM materially reduces the value of Western Balkan electricity exports, especially in strong hydro years when the region would otherwise be well placed to sell surplus power into the EU.
The renewable-investment consequence is one of the most important points. CBAM can reduce wholesale prices inside Western Balkan markets because the majority of the burden is absorbed by regional producers. The expected €15–20/MWh reduction in local wholesale prices lowers the market value of renewable generation and increases revenue uncertainty for merchant renewables. This is a serious policy contradiction. CBAM is designed to encourage decarbonisation, but if it depresses regional wholesale prices and export revenues, it can weaken the economic case for new wind and solar investment unless support schemes are adjusted.
For Serbia, this means renewable bankability will need a different structure. A merchant wind or solar project exposed to lower domestic prices, higher volatility and uncertain export value may struggle to attract capital on the same terms as before. Feed-in premium schemes may require higher support because the gap between the reference price and the wholesale market price increases. Corporate PPAs may become more important, especially with industrial buyers that value documented low-carbon electricity for CBAM-related reasons. But those PPAs will need to be more sophisticated than traditional green-power contracts.
This is where the power-plus-proof concept becomes directly relevant. 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. That product must include settlement-meter data, SCADA production records, PPC and Grid Code evidence, EMS schedule confirmation, GO registry documentation and PPA data-sharing clauses. In a market where generic wholesale prices are pressured lower by CBAM, the premium will sit with electricity that can help Serbian industrial exporters defend their EU market access.
The market-coupling issue is equally important. Market coupling alone does not automatically remove CBAM. Countries need to secure an electricity exemption before acceding to the EU’s single day-ahead and intraday coupling frameworks. The key condition is the introduction of a carbon price equivalent to the EU ETS by 2030, alongside other requirements. The logic is hard but clear: no CBAM exemption without equivalent carbon pricing, and no straightforward market coupling without the exemption.
This is politically difficult for the Western Balkans. Introducing an EU ETS-equivalent carbon price into coal-heavy power systems would raise domestic generation costs and could push up electricity prices for households and industry unless carefully phased. Yet delaying carbon pricing exposes exporters to CBAM, reduces export revenues, and may block deeper electricity-market integration with the EU. Serbia, Montenegro, Bosnia and Herzegovina and North Macedonia therefore face a difficult trade-off: either internalise carbon costs domestically and prepare for exemption and coupling, or allow CBAM to impose carbon costs externally through reduced export value.
There may be room for transitional design. The requirement for equivalent carbon pricing does not necessarily mean a sudden full pass-through of an EU ETS-level cost to every domestic consumer from day one. A phased framework with a visible EUA-linked reference price, transitional free allocation, partial verified-emissions coverage or gradual exposure mechanism could create a bridge. The objective would be to demonstrate credible convergence with EU carbon pricing while avoiding a sudden shock to domestic power prices and industrial competitiveness.
For banks and investors, the analysis changes the due-diligence agenda. Renewable projects in Serbia and the region can no longer be assessed only by resource yield, CAPEX, EPC strength, grid connection, curtailment and DSCR. Lenders must also ask whether the project is positioned for a CBAM-distorted market. Does it rely on merchant prices that may fall by €15–20/MWh? Does it have a PPA with an industrial buyer that values documented low-carbon electricity? Can it produce audit-ready evidence? Does the revenue model survive higher volatility and lower export market values? Does the support scheme compensate for reduced wholesale prices? These questions are now part of bankability.
For utilities, the message is more urgent. Coal-heavy generators in Serbia, Bosnia and Herzegovina and Kosovo will face lower realised export value unless carbon pricing, exemptions or major decarbonisation measures are introduced. Hydro-heavy systems such as Albania, and partially Montenegro in high-hydro periods, have a stronger natural position, but even they require clear documentation and methodology reform to capture value. North Macedonia sits between these models, with transition risk but also room for solar-led repositioning.
For industrial electricity buyers, the CBAM effect creates both risk and opportunity. If domestic wholesale prices fall because exporters absorb the carbon burden, some industrial buyers may benefit from lower electricity costs in the short term. But export-oriented industry cannot rely on cheap undifferentiated electricity if EU customers demand carbon evidence. Heavy industry in Serbia will increasingly need PPAs or supply contracts that provide low-carbon documentation, not just lower prices. In that sense, CBAM splits the electricity market into two products: ordinary MWh and carbon-defensible MWh.
The region should therefore accelerate carbon-pricing preparation in the power sector, not because higher costs are attractive, but because unmanaged external carbon pricing is already reducing export value. Renewable support schemes should also be recalibrated because lower market values and higher volatility increase the required support for new RES projects. Domestic CBAM-style mechanisms for electricity imports may also become part of the policy debate if governments want to avoid carbon leakage and mirror EU treatment more closely.
For Serbia, the strongest conclusion is that CBAM is no longer only a risk to electricity exporters. It is becoming a structural test of the country’s energy transition model. If Serbia delays carbon pricing and market-coupling alignment, it risks losing export revenues and weakening renewable investment incentives. If it introduces carbon pricing too abruptly, it risks domestic price pressure and industrial cost shocks. The workable path is a phased carbon-pricing strategy, stronger renewable support, bankable industrial PPAs, documentation-ready green electricity products and serious preparation for EU market coupling.
The Western Balkans entered 2026 expecting CBAM to be a compliance challenge. The early evidence shows something larger. CBAM is already a price-formation mechanism, an export-revenue shock, a renewable-bankability risk and a market-coupling condition. It is changing the economics of power trade before the region has completed the institutional reforms needed to manage it. Serbia and its neighbours still have room to shape the outcome, but the direction is visible: electricity will no longer be valued only by megawatt-hours. It will be valued by carbon cost, market access and proof.
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