Carbon Border Adjustment Mechanism is about to turn from a regulatory acronym into a direct price signal that reshapes capital investment for South-East European power utilities and coal-fired thermal plants. From 2026, electricity imported into the European Union will carry a carbon cost that mirrors the EU emissions trading price. For non-EU countries in the Western Balkans and wider SEE region, this means every megawatt-hour of coal-based power exported into the EU effectively carries an embedded carbon bill. The choice for utilities and policymakers is stark: either allow that cost to accumulate as recurring operating expenditure borne in export corridors, or front-load large capital expenditure to decarbonise and protect market access.
The starting point is the emissions profile. The Western Balkans’ fossil-fuel combustion emits on the order of ninety million tonnes of CO₂ each year, with electricity and heat responsible for roughly two-thirds of that and lignite-fired electricity alone contributing around half. Serbia, Bosnia and Herzegovina, Montenegro and North Macedonia all export power to EU markets through interconnections with Hungary, Romania, Croatia, Greece and others. In practice, a large share of those exports is coal-based, reflecting generation fleets dominated by lignite baseload. At typical lignite plant intensities of roughly 0.8 to 0.9 tonnes of CO₂ per megawatt-hour, ten terawatt-hours of exported coal power embody on the order of eight to nine million tonnes of CO₂ each year.
Once CBAM is fully in force, that embedded carbon becomes a cost item. If you assume an effective carbon price in the range of sixty to ninety euros per tonne over the second half of this decade, the implied carbon bill on those eight to nine million tonnes sits between roughly five hundred and forty and eight hundred million euros per year. That cost is formally paid by EU importers buying CBAM certificates, but in practice it will be reflected in the price utilities can realise for exports and in the volume of power that remains competitive at the border. For SEE utilities, CBAM therefore behaves like a shadow tax on high-carbon exports, gradually eroding both margins and market share for coal-heavy systems.
The mechanism does not only apply to electricity. It initially covers emissions embedded in imports of iron and steel, cement, fertilisers, aluminium and hydrogen, with electricity as one of the key sectors. The transitional phase from late 2023 to the end of 2025 is essentially a data-gathering and capacity-building period. Exporters must report embedded emissions in their products and electricity, but do not yet pay. From 2026, annual declarations will be matched with CBAM certificate surrender, which is where the true cost begins. For SEE utilities this transitional period is an opportunity to build the monitoring, reporting and verification systems they will need to maintain exports on a credible basis; failure to do so risks defaulting to conservative, high emissions factors that push border costs even higher.
That leads to the first clear CBAM-driven CAPEX bucket: emissions data and compliance infrastructure. Utilities will need continuous stack monitoring, laboratory analysis capabilities, robust IT platforms and audit trails to calculate plant-level emissions factors. Coal-fired thermal plants that want to keep feeding exports will have to invest in metering and control systems capable of providing hourly data. At regional level, the cost of these monitoring and reporting upgrades is modest compared with generation investments, but it is still meaningful. A reasonable estimate for fully equipping the major Western Balkan power utilities and their thermal fleets with CBAM-compliant MRV systems would be in the order of one hundred to one hundred and fifty million euros through 2030. That is essentially the entry ticket: capital that has to be spent simply to measure emissions accurately and engage with the mechanism on favourable terms.
The second, much larger CAPEX layer is decarbonisation of the generation mix itself. Analysts of the region’s green transition estimate that achieving climate neutrality in line with EU objectives will require on the order of thirty billion US dollars of additional energy and climate investment across the Western Balkans by mid-century, with the power sector taking the largest share. If you focus only on the 2026–2030 period, a third of that investment, roughly nine to eleven billion euros, needs to be mobilised in the power system to bring emissions onto a trajectory compatible with EU expectations and CBAM realities. Regional decarbonisation targets for 2030 aim for a substantial reduction in greenhouse gases versus 1990 levels, and electricity from renewable sources should move toward or above half of total consumption in many systems. That does not happen without large new build.
South-East Europe has extensive technical potential in wind, solar and modernised hydropower. Aggregated across the Western Balkans alone, realistic renewable potential is frequently assessed at more than ninety gigawatts, while current deployment is only a fraction of that figure. If, between 2026 and 2030, the region were to add six to eight gigawatts of new wind and solar capacity largely focused on displacing coal and protecting export competitiveness, the required generation CAPEX is substantial but not out of reach. At today’s capital costs, a four-gigawatt utility-scale solar build-out at roughly one thousand euros per kilowatt would require four billion euros, while adding two to three gigawatts of onshore wind at around fourteen hundred euros per kilowatt adds another three to four billion euros. Together, this points to generation CAPEX of seven to eight billion euros. Add grid reinforcements, digitalisation, storage pilots and system-flexibility investments and the total for CBAM-motivated decarbonisation projects up to 2030 comfortably enters the nine to eleven billion euro range.
The economic comparison with doing nothing is instructive. If Western Balkan utilities continue to export roughly ten terawatt-hours of coal-heavy electricity per year into the EU, and those exports carry an effective CBAM carbon price in the sixty to ninety euro per tonne range, the annual carbon cost of those flows sits between approximately five hundred and forty and eight hundred million euros. Over a decade, that accumulates into a present-value burden that is of the same order as the capital required to build the renewable capacity needed to displace those exports with low-carbon megawatt-hours. What CBAM effectively does is pull forward the realisation that paying for carbon as OPEX is less efficient than investing once in low-carbon capacity and recovering that investment over twenty to thirty years.
The third CAPEX layer sits at the coal fleet and thermal plants. CBAM does not directly regulate what Serbia’s Nikola Tesla, Bosnia’s Tuzla, North Macedonia’s Bitola or Bulgaria’s Maritsa complexes do with their boilers, but it fundamentally alters the economics of exporting their output. At current emission factors, lignite-fired plants emitting close to one tonne of CO₂ per megawatt-hour see between sixty and ninety euros of CBAM cost attached to each exported megawatt-hour. Even if domestic wholesale prices remain below EU levels, the net realisation price after carbon becomes significantly less attractive. Utilities can respond in several ways: run coal fleets more for domestic supply and reduce exports; invest in efficiency improvements and partial fuel switches that modestly lower emissions intensity; or accelerate retirements and capacity replacement.
Efficiency and retrofit CAPEX can reduce emissions per unit, but usually at high cost. Comprehensive retrofits of large lignite units with upgraded boilers, turbines and flue gas treatment can cost several hundred million euros per plant. Even ambitious projects are unlikely to cut emissions intensity by more than fifteen to twenty percent relative to the original design without fundamentally changing fuel mix or introducing carbon capture. That may soften CBAM exposure, but it does not remove it. Given limited fiscal and corporate balance-sheet capacity, it is difficult to justify spending three or four hundred million euros on retrofits that still leave a thermal asset exposed to external carbon pricing, when the same money could finance several hundred megawatts of new renewables with near-zero marginal emissions.
This is why, in most SEE systems, the economically rational CBAM response is likely to be a mix of selective life-extension CAPEX for a shrinking set of coal units and aggressive investment in renewables, storage and flexible gas-fired generation to replace retiring capacity. Coal mines and thermal plants are likely to transition from expansionary CAPEX to managed-decline CAPEX: funds directed less at increasing production and more at maintaining safety, meeting environmental standards and preparing for closure and land rehabilitation. At the same time, new CAPEX will flow into combined-cycle gas plants that can provide mid-merit and peak support, into battery projects that smooth renewables variability, and into demand-side management infrastructure that reduces the need for coal-based backup.
A further, often overlooked, CBAM-related CAPEX category is social and just-transition spending around coal regions. If coal exports become less competitive because of CBAM and domestic carbon pricing, mines and plants will come under economic pressure even without explicit bans. International financial institutions are already financing repurposing programmes in coal regions, supporting worker retraining, mine closure and redevelopment of sites for new industries, often including renewable energy parks. These programmes involve hundreds of millions of euros in lending and grant resources in each heavily coal-dependent country. While this capital does not always flow directly through utility balance sheets, it critically shapes the political feasibility and timing of coal closures, thereby influencing how and when utility CAPEX can pivot fully to new assets.
The picture is more nuanced in EU-member SEE countries such as Bulgaria, Romania, Greece and Croatia, where electricity is already under the EU emissions trading system and CBAM does not directly apply to intra-EU power trade. Their decarbonisation CAPEX is driven primarily by ETS price trajectories, national energy-climate plans and internal policy commitments. Yet they are directly affected by CBAM in their role as entry points and trading hubs for Western Balkan electricity. As CBAM increases the cost of importing high-carbon electricity from neighbouring non-EU systems, cross-border flows and congestion patterns will shift, affecting interconnector revenues and the economics of export-oriented generation on both sides of the border. These countries also have an interest in seeing their neighbours decarbonise, to limit price volatility and maintain a stable regional market.
For SEE utilities and thermal power plant owners, the combined impact of CBAM and domestic energy transition agendas translates into a very concrete investment agenda for the period up to 2030. They need to allocate on the order of one hundred to one hundred and fifty million euros to build credible emissions monitoring and reporting systems, commit nine to eleven billion euros of generation and grid CAPEX to shift the balance toward renewables and flexibility, and direct several billion more into coal-fleet life extension, controlled retirement and social transition. The precise distribution will vary by country and utility, but the aggregate magnitude is clear. It is comparable to or larger than the cumulative CBAM carbon price that would otherwise be transferred to the EU as an external cost on high-carbon exports.
From an investor’s perspective, CBAM transforms decarbonisation for South-East European utilities from an abstract long-term challenge into a near-term cash-flow and competitiveness issue. Utilities that front-load CAPEX into renewables, grids, MRV systems and targeted coal rationalisation will see higher investment spending this decade, but they will preserve EU market access, strengthen their credit profiles and reduce exposure to volatile carbon costs. Those that delay will enjoy a short-lived benefit from cheap legacy assets but will increasingly face shrinking exports, hard-to-justify retrofit CAPEX and the risk of stranded coal capacity. In that sense, CBAM is less a new tax than a capital-allocation test: it rewards systems that convert looming carbon liabilities into productive investment and penalises those that try to ride high-carbon exports as long as possible. By 2030, the SEE power utilities that will be viewed as credible regional players will be the ones that treated CBAM not as an unwelcome compliance cost, but as a clear signal to accelerate a transition that was inevitable even without it.