The European Union’s (EU) Carbon Border Adjustment Mechanism (CBAM) is reducing the value of electricity exports to the EU from the Western Balkans, adding pressure to coal generators’ cash flow and investment. Lower export earnings weaken a source of funds used to maintain power stations and the mines supplying them. Thermal generation has fallen in Serbia and Bosnia and Herzegovina, although market conditions, stronger hydropower output and coal supply problems also help explain the declines.
Coal output reflects market conditions and fuel constraints
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 of the year. That broader measure includes imports into the Western Balkans and transit-related trading.
Elektroprivreda Srbije (EPS) has identified one way CBAM is affecting regional markets in its first-half operating results. The company said the mechanism reduced regional exports to the EU, increasing electricity surpluses that were subsequently sold on regional exchanges and pushing wholesale prices lower. For coal operators, the commercial change is the amount left after an EU buyer accounts for carbon costs.
A power station may still be needed for domestic supply even when producing additional electricity for export is no longer profitable. In that case, fewer operating hours are available to recover maintenance spending, mine development costs and debt service. However, a reduction in generation does not by itself show that CBAM was the sole cause.
EPS’s 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 coal-only measure. EPS also reported that thermal units were in cold reserve for 8.2% of calendar time and that production reductions associated with operation at technical minimum amounted to 574.34 GWh.
The company also attributed weaker thermal production and increased procurement requirements to lower domestic coal output and poorer coal quality. The entire decline in thermal generation therefore cannot be assigned to CBAM. Reduced dispatch at a technically available plant can reflect a response to low prices, while lost production because a unit lacks sufficient or adequate-quality coal is an availability problem that may require replacement electricity purchases.
Bosnia and Herzegovina presents a similar but more complex picture. 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 to Croatia declined 38.5% to 946 GWh, and deliveries to all neighbouring systems fell 16.5% to 4.853 TWh. Receipts from neighbouring systems dropped faster, declining 32.8% to 2.742 TWh. As a result, the net outward commercial balance rose 22% to 2.111 TWh.
Bosnia and Herzegovina generated less thermal electricity while increasing its net commercial surplus, with stronger hydro production materially changing the balance between coal generation, imports and exports. Conditions also varied among plants: September thermal injections were only marginally below the previous year, while output at some individual facilities increased 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.
CBAM changes the export netback
The legal obligation under CBAM falls on the authorised declarant importing electricity into the EU. Its economic effects can nevertheless pass upstream to Western Balkan generators through lower purchase offers, revised contract terms and reduced demand. The relevant export calculation is: EU selling price minus CBAM liability, cross-border costs, balancing, losses and trading costs equals 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, the resulting 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 exposures before eligible deductions, not the production cost of an 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 effectively retain around €29/MWh.
A coal unit with avoidable operating costs above that level has little commercial reason to produce additional electricity specifically for export. If the EU selling price instead rises to €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.
Montenegro shows revenue pressure before an output decline
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 mechanism. The company remained profitable, generation was significantly above plan, hydrological conditions were favourable and Pljevlja thermal power plant continued to operate. The case shows how CBAM can affect utility earnings before changing physical output.
A generator can continue producing and exporting substantial volumes while earning less from 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 therefore depends on the export margin as well as the plant’s operating costs.
Redirected electricity adds competition in regional markets
Electricity that becomes less attractive to EU buyers can instead be sold in domestic or neighbouring markets, creating a secondary effect for regional coal generators. If Serbia, Bosnia and Herzegovina, Montenegro and North Macedonia have more electricity available domestically because some EU export opportunities are uneconomic, regional supply rises relative to demand. Wholesale prices can then decline.
CBAM can therefore weaken the economics of EU exports first, after which displaced electricity can put further downward pressure on prices within the Western Balkan market. Coal operating hours may be affected even at plants that never exported electricity directly. Renewable generation can face a similar issue if hydro, wind or solar electricity cannot meet the requirements for favourable CBAM treatment or cannot secure the necessary contractual and verification chain.
Such renewable electricity may also remain in regional markets, adding supply and reducing the residual demand available to coal generators. The resulting impact may be a gradual reduction in annual coal-plant utilisation rather than immediate closures. Coal plants 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, but they may operate fewer hours for commercial exports.
Lower utilisation raises financing concerns
A plant can remain indispensable for 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, the cost burden per generated megawatt-hour increases.
For example, if electricity production falls by one-third while fixed costs remain unchanged, fixed costs per MWh rise by 50%. This creates 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, but CBAM may weaken that model.
A thermal plant may still be needed to ensure reliable electricity supply even as export revenues used to help finance that capacity become less predictable. Investment assessments therefore need to distinguish domestic security-of-supply value—the imports avoided during periods of scarcity—from commercial export value, or the margin remaining after CBAM and cross-border costs. They also need to account for system flexibility value, including revenue from balancing, reserves, capacity availability or other services.
A historic export margin should no longer automatically be carried into 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 access to the EU increasingly carries an explicit carbon cost. Western Balkan coal-fired generation that previously served both domestic demand and profitable EU exports may increasingly operate mainly when required by the domestic system or when regional prices are exceptionally strong.
CBAM is unlikely to close Western Balkan coal plants overnight. Domestic electricity systems still require substantial thermal capacity, while hydrological conditions, weather, imports and network constraints can quickly increase the value of coal generation. The mechanism is changing the commercial role of these plants, with lower utilisation, fewer profitable export hours and weaker cash generation putting pressure on utilities that may still need coal capacity for security of supply.