In the Western Balkans, the EU’s carbon border charge is reducing the value of cross-border electricity sales, putting pressure on coal generators’ cash flow and investment. Export earnings have helped utilities maintain power stations and the mines that supply them. Lower thermal generation in Serbia and Bosnia and Herzegovina has coincided with weaker export revenues and tougher competition for buyers within the region.
The operating data, however, point to a mix of commercial pressure, higher hydropower production and coal-supply problems, rather than a uniform output decline caused by CBAM alone. The Energy Community Secretariat reported that scheduled electricity exports from the Western Balkans to the EU fell 16% to 3.223 TWh in the second quarter of 2026. Electricity trade in both directions declined by approximately 19% in the first half, a broader measure that includes imports into the Western Balkans and transit-related trading.
For coal operators, the key commercial change is the revenue remaining after an EU buyer accounts for carbon costs. A power station may still be needed to supply domestic demand, but may no longer be able to generate additional electricity profitably for export. Fewer viable operating hours mean less opportunity to recover maintenance spending, mine development costs and debt service.
Market pressure and fuel constraints weigh on thermal output
Elektroprivreda Srbije identified this mechanism in its first-half operating results. EPS said CBAM had reduced regional exports to the EU, leaving larger electricity surpluses to be sold on regional exchanges and pushing wholesale prices lower. Its thermal generation fell approximately 12% to 9.423 TWh, from 10.712 TWh in the first half of 2025, while hydro production rose 9% to 5.307 TWh.
The thermal total includes combined heat and power production, so it is not an exact measure of coal-only generation. EPS also reported that thermal units were in cold reserve for 8.2% of calendar time, and that 574.34 GWh of production reductions were associated with operation at technical minimum. The company attributed weaker thermal output and higher procurement requirements in part to lower domestic coal production and poorer coal quality, meaning the full decline cannot be ascribed to CBAM.
The distinction has commercial consequences. Reduced dispatch at a technically available plant may be a rational response to low prices. If generation is lost because a unit lacks enough coal or the fuel is of inadequate quality, that is an availability problem and may force the utility to buy replacement electricity.
Bosnia and Herzegovina shows a similar but more complex pattern. Thermal electricity injected into the country’s transmission grid fell 12.9% to 4.931 TWh in January-September 2026, while hydro injections climbed 27.3% to 3.926 TWh. Total generation injections increased 2.6% to 9.849 TWh.
Declared commercial deliveries to Croatia dropped 38.5% to 946 GWh. Deliveries to all neighbouring systems declined 16.5% to 4.853 TWh, but receipts fell faster, by 32.8% to 2.742 TWh. As a result, the net outward commercial balance grew 22% to 2.111 TWh.
Bosnia and Herzegovina therefore produced less thermal electricity while increasing its net commercial surplus, with stronger hydro output materially shifting the balance between coal generation, imports and exports. Plant-level performance was not uniform: September thermal injections were only marginally below the previous year, while production at some individual facilities increased sharply. At Ugljevik, production interruptions have been linked to insufficient coal, difficulties accessing mining areas and equipment constraints, rather than directly to weaker EU export demand.
CBAM changes the economics of export sales
The legal obligation under CBAM rests with the authorised declarant importing electricity into the EU. Its economic effect can nevertheless reach Western Balkan generators through lower purchase offers, revised contract terms and weaker demand. The relevant calculation for exporters is the EU selling price minus CBAM liability, cross-border costs, balancing, losses and trading costs: the result is the export netback.
The European Commission’s published CBAM certificate price for third-quarter 2026 imports is €82.32 per tonne of CO₂, compared with €75.28/tCO₂ in the second quarter. Using published electricity default factors, this implies indicative gross carbon burdens of around €94.50/MWh for Bosnia and Herzegovina, €85.70/MWh for Serbia, €80.59/MWh for Montenegro and €73.02/MWh for North Macedonia. These default-based figures are indicative exposure before eligible deductions, not the production cost of any individual generating unit.
The effect on an export margin can be substantial. At an illustrative EU selling price of €120/MWh, Serbian electricity facing gross CBAM exposure of around €85.70/MWh would leave €34.30/MWh before transmission capacity, balancing, losses and other commercial costs. If those additional costs total €5/MWh, the generator would be left with around €29/MWh.
A coal unit with avoidable operating costs above that level would have little commercial reason to generate extra electricity specifically for export. If the EU selling price rose to €180/MWh, the remaining revenue would increase substantially and exports could again become commercially attractive. CBAM does not necessarily stop electricity exports; it changes which hours remain profitable for them.
Montenegro’s revenue impact precedes any output decline
Elektroprivreda Crne Gore illustrates how the effects can first appear in revenue rather than generation. EPCG estimated that CBAM reduced the value of its first-quarter electricity sales by approximately €13 million compared with what those sales could have earned without the carbon mechanism. The company remained profitable, generation was significantly above plan, hydrological conditions were favourable and Pljevlja thermal power plant continued to operate.
A generator can therefore keep producing and exporting substantial volumes while receiving less for the same electricity. A stronger incentive to reduce loading, delay starts or keep capacity in reserve emerges only when the netback falls below a plant’s avoidable operating costs. The effect on utility earnings can thus precede any reduction in physical output.
Displaced exports intensify competition in regional markets
Electricity that is no longer attractive to EU buyers is redirected to domestic or neighbouring markets rather than disappearing. If Serbia, Bosnia and Herzegovina, Montenegro and North Macedonia have more power available domestically because some EU export opportunities are uneconomic, regional supply rises relative to demand and wholesale prices can fall. CBAM can therefore first weaken the economics of EU exports, then depress prices within the Western Balkan market as displaced electricity is sold regionally.
This secondary effect can reduce coal operating hours even at plants that never exported electricity directly. Renewable generation can also be affected: if hydro, wind or solar electricity cannot meet the requirements for favourable CBAM treatment, or cannot secure the necessary contractual and verification chain, it may remain in regional markets. That additional renewable supply further reduces residual demand for coal generators.
Fewer profitable hours create a financing challenge
The main structural consequence may not be the immediate closure of coal-fired power stations, but a gradual decline in their annual utilisation. Coal plants remain important for security of supply across much of the Western Balkans, particularly during winter peaks, dry hydrological periods and times when electricity imports are limited. They may, however, run fewer hours purely to serve commercial export demand.
A plant can remain indispensable to system security while becoming harder to finance. Coal mines, maintenance programmes, environmental upgrades, staffing and debt service carry substantial fixed costs. If annual production falls while most fixed expenditure remains unchanged, the cost burden per generated megawatt-hour rises; a one-third reduction in output with fixed costs unchanged would increase fixed costs per MWh by 50%.
This presents a major challenge for utilities including EPS, EPBiH, ERS and EPCG. Historically, electricity exports provided Western Balkan utilities with additional cash to help fund domestic generation fleets, mines, overhauls and investment. CBAM may weaken that model, leaving thermal plants needed for reliable supply but making the export revenue used to help finance them less predictable.
Future investment assessments need to distinguish three value streams: domestic security-of-supply value, or the imports a coal plant helps the system avoid during shortages; commercial export value, or the margin left after CBAM and all cross-border costs; and system flexibility value, including revenue from balancing, reserves, capacity availability or other services. Historic export margins should no longer automatically be built into coal mine expansion, power plant rehabilitation or life-extension models.
The more relevant question is how many profitable operating hours a plant can realistically achieve in a market where access to the EU increasingly carries an explicit carbon cost. CBAM is unlikely to close Western Balkan coal plants overnight: domestic systems still require substantial thermal capacity, and hydrological conditions, weather, imports and network constraints can quickly raise the value of coal generation. But plants that once served domestic demand and profitable EU exports may increasingly run mainly when the domestic system needs them or regional prices are exceptionally strong.
That shift means lower utilisation, fewer profitable export hours and weaker cash generation. Western Balkan utilities may continue to need coal capacity for security of supply while losing part of the export business that helped finance the same mines and power stations. The pressure is therefore not limited to electricity trade: it also concerns the ability to finance large thermal systems whose domestic strategic importance remains high as their external commercial value declines.
