The implementation of the Carbon Border Adjustment Mechanism (CBAM) is set to significantly influence capital investment decisions for power utilities and coal-fired thermal plants in Southeast Europe. Starting in 2026, electricity imported into the European Union will incur a carbon cost that aligns with the EU emissions trading price. This regulatory shift poses a critical challenge for non-EU countries in the Western Balkans, where each megawatt-hour of coal-based power exported to the EU will carry an embedded carbon cost. Utilities and policymakers face a pivotal decision: absorb these costs as ongoing operational expenditures or invest upfront in decarbonization to secure market access.
The emissions profile of the Western Balkans reveals a stark reality, with fossil fuel combustion generating approximately ninety million tonnes of CO₂ annually. Electricity and heat production account for about two-thirds of this total, with lignite-fired electricity contributing nearly half. Countries like Serbia, Bosnia and Herzegovina, Montenegro, and North Macedonia export significant amounts of coal-based power to EU markets via interconnections with Hungary, Romania, Croatia, and Greece. The carbon intensity of these lignite plants, estimated at 0.8 to 0.9 tonnes of CO₂ per megawatt-hour, means that ten terawatt-hours of coal power exported translates to an annual emission of eight to nine million tonnes of CO₂.
Once CBAM is fully operational, this embedded carbon will become a direct cost for utilities. Assuming a carbon price between sixty and ninety euros per tonne during the latter half of this decade, the annual carbon bill for those emissions could range from approximately five hundred forty to eight hundred million euros. Although EU importers will formally pay for CBAM certificates, the financial burden will ultimately impact the prices utilities can charge for exports and their competitiveness in the market. Consequently, CBAM acts as a shadow tax on high-carbon exports, progressively diminishing profit margins and market share for coal-dependent systems.
The scope of CBAM extends beyond electricity; it initially encompasses emissions from imports of iron and steel, cement, fertilizers, aluminum, and hydrogen. The transitional phase from late 2023 until the end of 2025 serves as an opportunity for exporters to establish necessary reporting frameworks without incurring costs. However, beginning in 2026, compliance will require annual declarations paired with CBAM certificate surrender, marking the onset of significant financial implications. For Southeast European utilities, this period is crucial for developing monitoring and verification systems essential for maintaining competitive exports; failure to do so may lead to conservative emissions estimates that inflate border costs.
A primary capital expenditure (CAPEX) requirement driven by CBAM is the establishment of emissions data compliance infrastructure. Utilities must invest in continuous emissions monitoring systems and robust IT platforms to accurately calculate plant-level emissions factors. While the cost of these upgrades is relatively modest compared to generation investments—estimated at one hundred to one hundred fifty million euros through 2030—it represents a necessary initial investment to engage effectively with CBAM.
The larger CAPEX requirement pertains to decarbonizing the generation mix itself. Analysts predict that achieving climate neutrality aligned with EU targets will necessitate around thirty billion US dollars in energy and climate investments across the Western Balkans by mid-century, with a substantial portion allocated to the power sector. For the period from 2026 to 2030 alone, approximately nine to eleven billion euros must be mobilized within the power system to align emissions trajectories with EU expectations and CBAM stipulations. Regional decarbonization goals aim for significant reductions in greenhouse gases compared to 1990 levels while increasing renewable energy’s share in total consumption.
Southeast Europe possesses considerable potential for wind, solar, and modernized hydropower generation. Realistic assessments indicate over ninety gigawatts of renewable potential across the Western Balkans; however, current deployment remains minimal. If six to eight gigawatts of new wind and solar capacity are added between 2026 and 2030—primarily aimed at displacing coal—the required generation CAPEX could reach seven to eight billion euros when factoring in grid reinforcements and other investments necessary for decarbonization projects.
Inaction presents its own economic challenges. Should Western Balkan utilities continue exporting around ten terawatt-hours of coal-heavy electricity annually into the EU under an effective CBAM price range of sixty to ninety euros per tonne, they would face an annual carbon cost between five hundred forty and eight hundred million euros. Over ten years, this burden equates closely to the capital needed for renewable capacity that could replace those high-carbon exports with low-carbon alternatives.
Regarding existing coal fleets, CBAM alters their export economics without directly regulating operations at plants such as Serbia’s Nikola Tesla or Bulgaria’s Maritsa complexes. With current emission factors leading to significant CBAM costs per exported megawatt-hour, utilities may need to reconsider their export strategies—either focusing on domestic supply or investing in efficiency improvements that lower emissions intensity.
While efficiency upgrades can reduce emissions per unit produced, they often entail high costs without fundamentally altering fuel mixes or incorporating carbon capture technologies. With limited fiscal resources available for extensive retrofits that still expose thermal assets to external carbon pricing pressures, many utilities may find it more viable to finance new renewable projects instead.
Consequently, a rational response among Southeast European utilities is likely a combination of selective life-extension CAPEX for certain coal units alongside aggressive investments in renewables and flexible gas-fired generation as replacements for retiring capacity. As coal mines transition from expansionary CAPEX towards managed decline—focused on safety and environmental compliance—new investments will flow into technologies that support renewable integration and flexibility within energy systems.
Additionally, social transition spending related to coal regions must not be overlooked as CBAM impacts competitiveness. Economic pressures on mines and plants due to reduced export viability may prompt international financial institutions to support repurposing programs aimed at workforce retraining and site redevelopment for new industries like renewable energy parks.
In EU-member countries such as Bulgaria and Romania—where electricity already falls under the EU emissions trading system—their decarbonization CAPEX is primarily influenced by ETS price trajectories rather than CBAM directly impacting intra-EU trade dynamics. However, these nations remain affected by shifts in cross-border flows due to increased costs associated with importing high-carbon electricity from neighboring non-EU systems.
For Southeast European utilities facing both CBAM implications and domestic energy transition agendas up until 2030, a clear investment strategy emerges: allocate one hundred to one hundred fifty million euros towards credible emissions monitoring systems; commit nine to eleven billion euros towards generation CAPEX focused on renewables; direct additional funds into coal fleet management; and address social transition needs within coal-dependent regions.
From an investment standpoint, CBAM reframes decarbonization challenges into immediate cash-flow considerations for Southeast European utilities. By prioritizing CAPEX into renewables and supporting infrastructure now rather than delaying action based on legacy assets’ short-term benefits, utilities can enhance their market access while mitigating exposure to volatile carbon costs moving forward.
