From 2026, electricity imported into the European Union will include a carbon cost linked to the EU emissions trading price. For non-EU exporters in the Western Balkans and wider South-East Europe, coal-based power sent into the EU carries an embedded carbon bill. The mechanism creates a choice between absorbing that cost through recurring operating expenditure in export corridors or funding earlier capital spending to decarbonise and maintain market access.
The emissions starting point is fossil-fuel combustion in the Western Balkans, which releases on the order of 90 million tonnes of CO₂ per year. Electricity and heat account for roughly two-thirds of that total, while lignite-fired electricity contributes around half. Serbia, Bosnia and Herzegovina, Montenegro and North Macedonia export power to EU markets via interconnections with Hungary, Romania, Croatia, Greece and other systems.
A large share of those exports is coal-based, reflecting generation fleets dominated by lignite baseload. With typical lignite emission intensities of roughly 0.8 to 0.9 tonnes of CO₂ per megawatt-hour, ten terawatt-hours of exported coal power embody about 8 to 9 million tonnes of CO₂ each year. When CBAM is fully in force, that embedded carbon becomes a cost item for cross-border trade economics.
CBAM-linked carbon bills for coal-heavy electricity exports
If an effective carbon price of 60 to 90 euros per tonne applies over the second half of this decade, the implied annual carbon bill for 8 to 9 million tonnes ranges from roughly 540 million to 800 million euros. EU importers pay this through CBAM certificate surrender, but export pricing and border competitiveness determine how the cost shows up in practice. For South-East Europe utilities, CBAM therefore affects margins and market share for coal-heavy systems.
The CBAM scope extends beyond electricity. It initially covers emissions embedded in imports of iron and steel, cement, fertilisers, aluminium and hydrogen, with electricity among the key sectors. The transitional period runs from late 2023 to the end of 2025, when exporters report embedded emissions but do not yet pay.
From 2026, annual declarations are matched with CBAM certificate surrender, which marks when payment begins. For exporters in the region, the transition period supports building monitoring, reporting and verification systems needed to maintain credible export documentation. If reporting fails to align with conservative emissions factors, border costs can increase.
Monitoring, reporting and verification as an early CAPEX requirement
The first CBAM-driven capital spending bucket is emissions data and compliance infrastructure. Utilities need continuous stack monitoring, laboratory analysis capabilities, robust IT platforms and audit trails to calculate plant-level emissions factors. Coal-fired thermal plants seeking to keep exporting must invest in metering and control systems capable of producing hourly data.
At regional level, monitoring and reporting upgrades are described as modest compared with generation investments, but still meaningful for budgets. A reasonable estimate for fully equipping major Western Balkan power utilities and their thermal fleets with CBAM-compliant MRV systems is 100 million to 150 million euros through 2030. This spending is framed as an entry requirement for measuring emissions accurately and engaging with CBAM on favourable terms.
Decarbonising generation capacity under CBAM realities
A second CAPEX layer involves decarbonising the generation mix itself. Analysts estimate that climate neutrality aligned with EU objectives will require about 30 billion US dollars of additional energy and climate investment across the Western Balkans by mid-century, with power taking the largest share. For the 2026–2030 window alone, about one-third of that total—roughly 9 to 11 billion euros—needs to be mobilised in the power system.
The regional decarbonisation trajectory targets substantial greenhouse gas reductions versus 1990 levels by 2030. Electricity from renewables is expected to move toward or above half of total consumption in many systems. Meeting those targets requires large-scale new build rather than incremental changes alone.
The region has technical potential in wind, solar and modernised hydropower. Across the Western Balkans alone, realistic renewable potential is assessed at more than 90 gigawatts, while current deployment remains a fraction of that figure. Between 2026 and 2030, adding 6 to 8 gigawatts of wind and solar capacity focused on displacing coal would require generation CAPEX that remains within reach.
A four-gigawatt utility-scale solar build-out at roughly 1,000 euros per kilowatt implies about 4 billion euros. Adding two to three gigawatts of onshore wind at around 1,400 euros per kilowatt implies another 3 to 4 billion euros. Together these figures indicate generation CAPEX of roughly 7 to 8 billion euros.
If grid reinforcements, digitalisation measures, storage pilots and system flexibility investments are included, total CBAM-motivated decarbonisation projects up to 2030 fall comfortably within the 9 to 11 billion euro range. This aligns with the power-system investment needs described for bringing emissions onto a trajectory compatible with EU expectations.
Coal fleet exposure: retrofit limits and managed decline CAPEX
A third CAPEX layer concerns coal fleets and thermal plants even though CBAM does not directly regulate boiler operations. The mechanism changes export economics by attaching carbon costs to each exported megawatt-hour based on emission factors. Lignite-fired plants emitting close to one tonne of CO₂ per megawatt-hour face roughly 60 to 90 euros of CBAM cost per exported megawatt-hour at current factor assumptions.
If domestic wholesale prices remain below EU levels, net realisation after carbon becomes less attractive for exports. Utilities can respond by running coal fleets more for domestic supply while reducing exports; investing in efficiency improvements and partial fuel switches that lower emissions intensity; or accelerating retirements and capacity replacement. Each option affects how much output remains competitive under border-linked carbon costs.
The source material describes retrofit costs as typically high relative to expected emission reductions. Comprehensive retrofits involving 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 15% to 20% without changing fuel mix or introducing carbon capture.
This leaves thermal assets exposed even after upgrades when external carbon pricing applies through export flows. With limited fiscal space and corporate balance-sheet capacity, spending three or four hundred million euros on retrofits that still leave exposure is difficult compared with financing several hundred megawatts of new renewables with near-zero marginal emissions. In most South-East Europe systems described here, responses are expected to combine selective life-extension CAPEX for a shrinking set of coal units with aggressive investment in renewables, storage and flexible gas-fired generation replacing retiring capacity.
The shift is characterised as moving from expansionary CAPEX toward managed-decline CAPEX for coal mines and thermal plants. Funds would be directed less toward increasing production and more toward maintaining safety, meeting environmental standards and preparing for closure and land rehabilitation. At the same time new CAPEX would support combined-cycle gas plants providing mid-merit and peak support, battery projects smoothing renewables variability, and demand-side management infrastructure reducing reliance on coal-based backup.
Just-transition spending linked to coal regions
An additional CBAM-related CAPEX category involves social spending around coal regions under just-transition approaches. If coal exports become less competitive due to CBAM alongside domestic carbon pricing pressures can build even without explicit bans on production or trade. Mines and plants may face economic stress as competitiveness changes across export corridors.
The source material notes international financial institutions financing repurposing programmes in coal regions covering worker retraining, mine closure and redevelopment for new industries including renewable energy parks. These programmes involve hundreds of millions of euros in lending and grant resources in each heavily coal-dependent country. While capital does not always pass through utility balance sheets directly, it is described as shaping political feasibility and timing for coal closures.
Differing roles across EU-member SEE countries
The situation is described as more nuanced in EU-member states including Bulgaria, Romania, Greece and Croatia where electricity already falls under the EU emissions trading system. In those markets CBAM does not directly apply to intra-EU power trade because electricity trading within the EU is under ETS coverage rather than cross-border CBAM treatment. Decarbonisation CAPEX there is driven primarily by ETS price trajectories along with national energy-climate plans and internal policy commitments.
Borders still matter because these countries act as entry points and trading hubs for Western Balkan electricity flows into EU markets. As CBAM increases costs associated with importing high-carbon electricity from neighbouring non-EU systems, cross-border flows and congestion patterns can shift. That affects interconnector revenues as well as export-oriented generation economics on both sides of border interconnectors.
The source also notes an interest among these countries in seeing neighbours decarbonise to limit price volatility while maintaining a stable regional market structure across interconnections.
Total investment agenda up to 2030 for MRV plus generation change
Taken together with domestic energy transition agendas described here, utilities face a concrete investment agenda up to 2030 tied to both compliance systems and generation change. The material states that they need around 100 million to 150 million euros for credible emissions monitoring and reporting systems. It also cites commitments totalling roughly 9 to 11 billion euros for generation and grid CAPEX aimed at shifting toward renewables and flexibility.
A further several billion euros would be directed toward coal-fleet life extension measures alongside controlled retirement steps and social transition spending described as part of managing decline pathways. The distribution varies by country and utility owner but aggregate magnitude is presented as clear within this framework.
The scale is compared against cumulative external costs that would otherwise be transferred into EU markets through high-carbon exports under CBAM-linked pricing assumptions described earlier in the material.