Western Balkan coal-fired power generators are facing growing pressure on cash flow and investment as the European Union’s Carbon Border Adjustment Mechanism (CBAM) reduces the value of electricity exports, weakening an important source of revenue used to maintain power plants and the mines that supply them.
Thermal generation has declined in Serbia and Bosnia and Herzegovina, while utilities are reporting lower export revenues and stronger competition for buyers within the region. However, the available operating data point to a combination of commercial pressure, stronger hydropower output and coal-supply constraints rather than a uniform decline in coal 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 of the year, although that broader measure also includes imports into the Western Balkans and transit-related activity.
For coal generators, the main commercial change is the value left after EU buyers account for carbon costs. A power plant may remain essential for domestic electricity security while losing the ability to generate additional output profitably for export. That reduces the number of operating hours available to recover maintenance expenditure, mine-development costs and debt-service obligations.
The impact is particularly important because lower export profitability does not necessarily mean lower generation at every plant. Output can fall because market prices make additional generation uneconomic, but it can also decline because generators lack sufficient coal or face technical constraints.
Serbia’s Elektroprivreda Srbije (EPS) has identified CBAM as one factor affecting its export business. The company said the mechanism reduced regional exports to EU markets, increasing electricity surpluses that were subsequently sold on regional exchanges and contributing to lower wholesale prices.
EPS’s thermal generation fell approximately 12% to 9.423 TWh in the first half of 2026, from 10.712 TWh a year earlier. Hydropower production, by contrast, increased 9% to 5.307 TWh. The thermal figure includes combined heat and power generation and should therefore not be interpreted as a pure measure of coal-fired output.
EPS also reported thermal units in cold reserve for 8.2% of calendar time, while production reductions associated with operation at technical minimum reached 574.34 GWh.
At the same time, the company linked weaker thermal production and higher electricity procurement requirements to lower domestic coal output and poorer coal quality. The entire decline in thermal generation therefore cannot be attributed to CBAM.
The distinction is commercially significant. Reduced dispatch at a technically available plant can represent a rational response to weak prices. Lost production caused by insufficient or poor-quality coal is an availability problem that can force a utility to purchase replacement electricity.
Bosnia and Herzegovina presents a similarly 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 increased 27.3% to 3.926 TWh. Total generation injections nevertheless rose 2.6% to 9.849 TWh.
Commercial deliveries to Croatia declined 38.5% to 946 GWh, while deliveries to all neighbouring systems fell 16.5% to 4.853 TWh. Receipts declined even faster, falling 32.8% to 2.742 TWh.
As a result, Bosnia and Herzegovina’s net outward commercial electricity balance increased 22% to 2.111 TWh.
This demonstrates why the regional market cannot be analysed through coal output alone. Stronger hydropower production can materially alter the relationship between thermal generation, imports and exports, even as coal-fired output declines.
The operating picture also differs between individual plants. September thermal injections were only marginally below the previous year, while production at some facilities increased significantly.
At Ugljevik, however, production interruptions have been associated with insufficient coal, difficulties accessing mining areas and equipment constraints. Such disruptions cannot reasonably be classified as a direct consequence of weaker EU export demand.
The central commercial issue created by CBAM is the changing value of the export netback. The legal obligation to pay CBAM falls on the authorised declarant importing electricity into the EU, but the economic impact can move upstream to Western Balkan generators through lower purchase offers, revised contract terms and weaker demand.
For exporters, the relevant calculation is increasingly:
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 was €82.32 per tonne of CO₂, compared with €75.28/tCO₂ in the second quarter.
Using published electricity default factors, this corresponds to indicative gross carbon exposure of approximately €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 figures before eligible deductions and should not be interpreted as the actual production cost or final CBAM liability of an individual generating unit.
Nevertheless, the potential effect on export margins is significant.
If Serbian electricity were sold into an EU market at an illustrative €120/MWh, a gross CBAM exposure of approximately €85.70/MWh would leave €34.30/MWh before transmission capacity, balancing, losses and other trading costs.
If those additional costs amounted to €5/MWh, the remaining margin would fall to around €29/MWh.
A coal-fired unit with avoidable operating costs above that level would have little commercial incentive to generate additional electricity specifically for that export market.
At an EU selling price of €180/MWh, however, the remaining revenue would be substantially higher and exports could again become attractive.
CBAM therefore does not necessarily eliminate electricity exports. Instead, it changes which hours remain commercially viable for export.
Montenegro illustrates another important aspect of the transition. Elektroprivreda Crne Gore 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.
At the same time, EPCG remained profitable, generation was significantly above plan, hydrological conditions were favourable and the Pljevlja thermal power plant continued operating.
The example shows that CBAM can initially affect utility revenues rather than physical output. A generator can continue producing and exporting substantial volumes while receiving less value for the same electricity.
Only when the export netback falls below a plant’s avoidable operating costs does the incentive become stronger to reduce loading, delay starts or keep capacity in reserve.
The electricity that becomes less attractive for EU buyers does not simply disappear. It can be redirected towards domestic and neighbouring markets, creating a second layer of pressure for regional coal generators.
If Serbia, Bosnia and Herzegovina, Montenegro and North Macedonia have more electricity available domestically because some EU export opportunities become uneconomic, regional supply can increase relative to demand. Wholesale prices may then weaken.
The resulting effect can be described in two stages: CBAM first weakens the economics of EU exports, while displaced electricity can subsequently put pressure on prices within the Western Balkan market itself.
This can reduce coal operating hours even at plants that have little or no direct exposure to EU exports.
The same dynamic can affect renewable generation. Hydro, wind and solar output that does not meet the requirements for favourable CBAM treatment or cannot secure the necessary contractual and verification arrangements may remain within regional markets, adding further supply and reducing residual demand for coal generation.
The strongest structural consequence of CBAM may therefore not be the immediate closure of coal-fired plants. It could instead be a gradual reduction in their annual utilisation.
Coal plants remain important for security of supply across much of the Western Balkans, particularly during winter peaks, periods of weak hydrology and times when electricity imports are limited.
However, they may increasingly operate fewer hours purely for commercial export purposes.
That distinction is crucial because power plants and coal mines carry substantial fixed costs. Maintenance, environmental upgrades, staffing, mine development and debt service do not necessarily decline in line with electricity production.
If annual output falls by one-third while fixed costs remain unchanged, fixed costs per generated MWh increase by 50%.
This creates a growing challenge for utilities including EPS, EPBiH, ERS and EPCG.
Historically, electricity exports provided Western Balkan utilities with an additional source of cash that helped finance domestic generation fleets, coal mines, overhauls and new investment. CBAM weakens the reliability of that revenue stream.
A thermal plant may remain necessary to guarantee domestic electricity supply while the export revenues that previously helped finance the same capacity become more uncertain.
Future investment decisions therefore need to distinguish between three different sources of value.
The first is domestic security-of-supply value — the value created by avoiding imports during periods of scarcity.
The second is commercial export value — the margin remaining after CBAM and all associated cross-border costs.
The third is system flexibility value — potential revenues from balancing, reserves, capacity availability and other ancillary services.
Historical export margins should therefore no longer automatically be incorporated into coal mine expansions, power-plant rehabilitation projects or life-extension plans.
The more relevant question is how many profitable operating hours a plant can realistically achieve in a market where access to EU buyers increasingly carries an explicit carbon cost.
CBAM is unlikely to shut down Western Balkan coal plants overnight. Domestic electricity systems still require substantial thermal capacity, while hydrological conditions, weather, imports and transmission constraints can rapidly increase the value of coal generation.
But the mechanism is changing the commercial role of coal-fired generation.
Plants that previously operated to serve both domestic demand and profitable EU exports may increasingly run primarily when required for domestic security of supply or when regional prices are sufficiently high to justify their operation.
The result could be lower utilisation, fewer profitable export hours and weaker cash generation.
The strategic challenge for Western Balkan utilities is therefore becoming increasingly clear. They 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 emerging CBAM pressure is consequently about more than electricity trade. It raises a broader question over whether Western Balkan utilities can continue financing large thermal systems whose domestic strategic importance remains high even as their external commercial value gradually declines.
