Bosnia and Herzegovina is facing growing pressure to address the carbon intensity of its electricity exports as the EU’s Carbon Border Adjustment Mechanism (CBAM) reshapes cross-border power trading and investment decisions. The International Monetary Fund’s 2026 assessment estimates that goods currently covered by CBAM represent approximately 11% of the country’s exports. Without offsetting domestic policy measures, the IMF projects that real GDP could be 0.4%–0.7% lower by 2035.
The exposure extends beyond individual electricity transactions. Carbon-related costs can affect export margins, the competitiveness of energy-intensive industries and the financial case for new generation and grid infrastructure. With industrial production closely connected to European customers, maintaining access to EU markets is an important part of Bosnia and Herzegovina’s economic outlook.
Electricity faces a different CBAM timetable
Electricity imports into the EU face a distinct adjustment framework compared with industrial products such as steel and aluminium. Industrial CBAM obligations are linked to the gradual withdrawal of EU ETS free allowances, whereas imported electricity does not benefit from an equivalent general industrial free-allocation adjustment.
As a result, the emissions intensity of generation and the price differential between EU and regional electricity markets are central to export economics. The IMF has identified early evidence that traders have redirected some electricity towards non-EU destinations to avoid the carbon-related cost associated with EU sales.
That approach offers only limited flexibility. Serbia and other neighbouring markets may absorb additional electricity when demand and prices are favourable, but their capacity to replace EU demand is not unlimited. If several exporters simultaneously redirect coal-intensive generation, regional supply could increase, weakening local prices and placing additional pressure on available transmission capacity.
Low-carbon generators face a different commercial obstacle. Their physical emissions performance may be favourable, but electricity sold through intermediary traders can lose the contractual and physical traceability needed to demonstrate that advantage under EU requirements.
National electricity factors and renewable generation
Bosnia and Herzegovina has a generation mix that combines coal-fired power with substantial hydropower capacity. The electricity default emissions factor may reflect a national methodology rather than the specific emissions profile of an individual generating station associated with an export transaction.
The IMF highlighted the potential distortion created when a comparatively high default factor is applied to renewable electricity. Better monitoring, emissions measurement and independent verification could help distinguish lower-carbon generation from the national average.
Proposed EU amendments to electricity emissions calculations could also change how imported power is assessed. However, these changes remain proposals and should not be treated as legislation already in force.
For hydropower operators, the commercial opportunity depends on more than the emissions performance of the generating asset. Investment in metering, contractual arrangements and verification systems may be necessary to substantiate the electricity’s characteristics in transactions with EU buyers.
Investment requirements extend across generation and networks
Coal-fired units face a different set of decisions. Improvements in operational reliability and efficiency may preserve domestic supply value, but they do not remove the longer-term challenge of carbon-intensive generation competing in export markets. Policymakers must also consider replacement capacity and the implications of a transition for mining employment and affected communities.
Transmission infrastructure is another part of the competitiveness equation. Network upgrades can improve access to higher-priced electricity markets, but their economic value is reduced when carbon-adjusted export margins are insufficient to support profitable sales. Generation investment, grid development and emissions verification therefore need to be assessed as connected elements of the same electricity strategy.
The IMF’s assessment points towards targeted investment rather than a uniform approach across technologies. Hydropower, coal, wind and solar projects have different operating characteristics, commercial risks and requirements for demonstrating their emissions performance.
Carbon exposure enters project finance decisions
Banks and other lenders need to distinguish between the risks attached to individual assets. A coal-fired plant may remain important for domestic electricity security even as its ability to compete in EU export markets deteriorates. Hydropower facilities can offer low operating emissions but remain exposed to hydrological conditions and permitting constraints.
Wind and solar projects may achieve competitive generation costs, yet their ability to secure recognised carbon treatment in EU electricity sales can depend on power purchase agreements, cross-border scheduling and the evidence connecting generation to delivered electricity. A single national emissions figure cannot capture these differences.
The financing implications extend to contractual design and project preparation. Producers seeking to supply EU buyers need commercial arrangements that support the required physical delivery and emissions evidence. Without those arrangements, the potential value of low-carbon generation may not be fully reflected in the price received by the exporter.
Domestic reform and industrial competitiveness
The policy response extends beyond the introduction of a national carbon tax. Bosnia and Herzegovina faces a broader requirement to develop credible investment plans covering more efficient generation, renewable capacity, network upgrades and reliable emissions data.
The country also needs a legal and commercial framework that enables electricity producers to establish qualifying delivery arrangements with EU buyers where feasible. Progress must account for domestic electricity prices, coal mine economics, employment considerations and the country’s regional regulatory divisions, all of which make power-sector reform politically sensitive.
The IMF’s projected 0.4%–0.7% GDP reduction by 2035 represents a scenario illustrating the potential consequences of limited policy adjustment, rather than a predetermined economic outcome. Reducing emissions, improving the recognition of verifiable low-carbon electricity and preserving access to European industrial markets could change that trajectory.
The immediate competitiveness challenge is therefore not limited to the carbon cost attributed to electricity exports. It also concerns the ability to finance generation and transmission assets, establish commercially viable cross-border supply arrangements and provide emissions evidence that EU buyers and importers can substantiate.
