The European Union’s Carbon Border Adjustment Mechanism (CBAM) is reducing the value of Western Balkan electricity exports, putting pressure on utility cash flow and investment. In Serbia and Bosnia and Herzegovina, thermal generation has declined, while utilities report lower export revenues and stronger competition for buyers within the region. Operating data point to a mix of commercial pressure, higher hydropower output and coal supply problems, rather than a uniform drop in generation 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. Combined electricity trade in both directions declined by approximately 19% in the first half, a broader measure that also includes imports into the Western Balkans and transit-related trading. For coal operators, the key commercial change is the revenue left after an EU buyer accounts for carbon costs.
A plant may still be required to meet domestic demand but lose the opportunity to produce additional electricity profitably for export. That can leave fewer operating hours in which to recover maintenance expenditure, mine development costs and debt service. The reduced value of cross-border electricity sales therefore affects both trading income and the financing of generation assets and supplying mines.
Generation declines reflect market and fuel constraints
Elektroprivreda Srbije (EPS) has identified CBAM’s effect in its first-half operating results. EPS said the mechanism reduced regional exports to the EU, leaving larger electricity surpluses to be sold on regional exchanges and pushing wholesale prices lower. The company’s thermal generation fell approximately 12% to 9.423 TWh, from 10.712 TWh in the first half of 2025, while hydropower production rose 9% to 5.307 TWh.
The thermal total includes combined heat and power production, so it is not an exact coal-only measure. EPS also reported that thermal units were in cold reserve for 8.2% of calendar time and that reductions linked to operation at technical minimum amounted to 574.34 GWh. The company attributed weaker thermal generation and higher procurement requirements in part to lower domestic coal output and poorer coal quality, meaning the entire decline cannot be assigned to CBAM.
The distinction has commercial implications for plant operations. Lower dispatch at a technically available station may reflect a response to weak prices, while lost production because a unit lacks enough coal or coal of adequate quality is an availability problem that may require the utility to buy replacement electricity. Both factors are present in the region, but they affect operations differently.
Bosnia and Herzegovina also recorded a decline in thermal generation alongside stronger hydropower output. Thermal electricity injected into the country’s transmission grid fell 12.9% to 4.931 TWh in January-September 2026, while hydro injections rose 27.3% to 3.926 TWh. Total generation injections increased 2.6% to 9.849 TWh.
Declared commercial deliveries from Bosnia and Herzegovina to Croatia dropped 38.5% to 946 GWh. Deliveries to all neighbouring systems declined 16.5% to 4.853 TWh, while receipts fell more sharply, by 32.8% to 2.742 TWh. As a result, the net outward commercial balance increased 22% to 2.111 TWh.
The country generated less thermal electricity while recording a larger net commercial surplus, with stronger hydro production materially changing the balance between coal generation, imports and exports. Conditions also varied between plants: September thermal injections were only marginally below the previous year, while output at some individual facilities rose strongly. At Ugljevik, production interruptions have been linked to insufficient coal, difficulties accessing mining areas and equipment constraints, rather than weaker EU export demand alone.
Carbon costs reduce the export netback
The legal CBAM obligation applies to the authorised declarant importing electricity into the EU. Its economic effect can nevertheless pass upstream to Western Balkan generators through lower purchase offers, changed contract terms and reduced demand. The relevant export calculation is: EU selling price – CBAM liability – cross-border costs – balancing – losses – trading costs = 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. Based on published electricity default factors, the implied gross carbon burden is 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 are indicative default-based CBAM exposures 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, around €29/MWh remains for the generator.
A coal unit with avoidable operating costs above that level has little commercial incentive to generate additional electricity specifically for export. If the EU selling price instead reaches €180/MWh, the remaining revenue increases substantially and exports can again become commercially attractive. CBAM does not necessarily stop electricity exports; it changes which hours remain profitable for them.
Utility revenues face pressure before generation necessarily falls
Elektroprivreda Crne Gore (EPCG) estimated that CBAM reduced the value of its first-quarter electricity sales by approximately €13 million, compared with the revenue those sales could have generated without the carbon mechanism. The company nevertheless remained profitable, generation was significantly above plan, hydrological conditions were favourable and Pljevlja thermal power plant continued operating. The case shows that CBAM can first affect utility earnings rather than physical output.
A generator can continue 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. Revenue effects and generation effects therefore need not appear at the same time.
Regional supply adds competition for coal generation
Electricity that is no longer attractive to EU buyers can instead be directed to domestic or neighbouring markets. 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 weaken the economics of EU exports first, after which displaced electricity may put additional downward pressure on prices within the Western Balkans.
This effect can reduce coal operating hours even at plants that never export electricity directly. Renewable generation may face a similar issue: if hydro, wind or solar power cannot meet the requirements for favourable CBAM treatment, or cannot secure the necessary contractual and verification chain, it may also remain in regional markets. Additional renewable supply further reduces the residual demand available to coal generators.
Fewer profitable operating hours could increase financing pressure
The main structural consequence may be a gradual reduction in annual utilisation rather than the immediate closure of coal-fired plants. Coal stations remain important to 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, operate fewer hours specifically for commercial exports.
A plant can remain essential to system security while becoming harder to finance. Coal mines, maintenance programmes, environmental upgrades, staffing and debt service involve substantial fixed costs; if annual production falls while most fixed expenditure remains unchanged, fixed costs per generated megawatt-hour rise. For example, a one-third decline in electricity production with fixed costs unchanged increases fixed costs per MWh by 50%.
This presents a significant challenge for utilities including EPS, EPBiH, ERS and EPCG. Historically, electricity exports provided Western Balkan utilities with additional cash to help finance domestic generation fleets, mines, overhauls and investment. CBAM could weaken that model: thermal capacity may still be needed for reliable supply even as export revenues that helped finance it become less predictable.
Future investment assessments need to distinguish three value streams. The first is domestic security-of-supply value: what a coal plant saves the system by avoiding imports during periods of scarcity. The second is commercial export value, meaning the margin remaining after CBAM and all cross-border costs; the third is system flexibility value, including revenue from balancing, reserves, capacity availability or other services.
A historic export margin should no longer automatically be included in a coal mine expansion, power plant rehabilitation or life-extension model. The relevant question is how many profitable operating hours a plant can realistically achieve in a market where EU access increasingly carries an explicit carbon cost. Coal-fired generation that once served both domestic demand and profitable EU exports may increasingly operate mainly when the domestic system needs it or regional prices are exceptionally strong.
Western Balkan electricity systems still require substantial thermal capacity, and hydrological conditions, weather, imports and network constraints can quickly increase the value of coal generation. At the same time, CBAM is changing the commercial role of those plants, bringing the prospect of lower utilisation, fewer profitable export hours and weaker cash generation. Utilities may continue to need coal capacity for security of supply while losing some of the export business that helped finance the mines and power stations.