The European Union’s Carbon Border Adjustment Mechanism (CBAM) is reducing the value of cross-border electricity sales from the Western Balkans, affecting cash flow and funds used for maintaining power stations and coal mines. In Serbia and Bosnia and Herzegovina, lower thermal generation is occurring alongside weaker export revenues and intensified competition for regional buyers. Utilities also report that changes in generation are not uniform across the region.
Operational data cited by utilities do not indicate that CBAM alone is driving a single direction in output. Commercial pressure, stronger hydropower production, and coal supply problems are also contributing to the reported shifts. The Energy Community Secretariat recorded a 16% decline in scheduled electricity exports from the Western Balkans to the EU, to 3.223 TWh in the second quarter of 2026.
Across the first half of 2026, combined electricity trade in both directions fell by approximately 19%. The broader measure includes imports into the Western Balkans and transit-related trading. Against that backdrop, utilities describe how market conditions are influencing dispatch decisions and fuel availability.
Generation changes tied to market pressure and fuel constraints
Elektroprivreda Srbije (EPS) said CBAM has affected regional market outcomes by reducing exports to the EU. In its first-half operating results, EPS reported that more electricity surpluses were redirected to regional exchanges, contributing to lower wholesale prices. The company linked output changes to both commercial signals and fuel-related factors.
EPS thermal generation fell by approximately 12% to 9.423 TWh in the first half of 2026, compared with 10.712 TWh in the same period of 2025. Hydro production rose by 9% to 5.307 TWh. EPS noted that its thermal figure includes combined heat and power generation, so it does not isolate coal-fired output.
The company reported thermal units in cold reserve for 8.2% of calendar time. It also cited 574.34 GWh of production reductions associated with operation at technical minimum. EPS said weaker thermal output and increased procurement requirements were linked to lower domestic coal production and poorer coal quality, meaning the full thermal decline cannot be attributed to CBAM.
Bosnia and Herzegovina shows a different pattern in aggregate injections. Thermal electricity injected into the Bosnian transmission grid fell by 12.9% to 4.931 TWh in January-September 2026, while hydro injections rose by 27.3% to 3.926 TWh. Total generation injections increased by 2.6% to 9.849 TWh.
Bosnia’s declared commercial deliveries to Croatia decreased by 38.5% to 946 GWh. Deliveries to all neighbouring systems declined by 16.5% to 4.853 TWh, while receipts fell faster, by 32.8% to 2.742 TWh. The resulting net outward commercial balance rose by 22% to 2.111 TWh.
The utility data also show variation at plant level. September thermal injections were only marginally below the previous year, while production at some individual facilities increased strongly. At Ugljevik, production interruptions were linked to insufficient coal, difficulties accessing mining areas, and equipment constraints, which cannot reasonably be classified as a direct result of weaker EU export demand.
CBAM liability affects export net revenue calculations
The legal obligation under CBAM lies with the authorised declarant importing electricity into the EU. Even so, its economic effect can pass upstream through lower purchase offers, revised contract terms, and reduced demand for electricity exports from the Western Balkans.
The exporter-oriented calculation described in utility analysis increasingly follows: EU selling price minus CBAM liability minus cross-border costs minus balancing minus losses minus trading costs equals 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, implied gross carbon burden is estimated at 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 described as indicative default-based estimates of CBAM exposure before eligible deductions rather than production costs for specific generating units.
The impact on export margins can be significant under illustrative pricing assumptions provided in utility analysis. If Serbian electricity sells into an EU market at an illustrative €120/MWh, gross CBAM exposure of around €85.70/MWh leaves €34.30/MWh, before transmission capacity charges, balancing costs, losses, and other commercial costs.
If additional costs total about €5/MWh, the generator would be left with around €29/MWh. A coal unit with avoidable operating costs above that level would have limited commercial incentive to produce additional electricity specifically for that export window.
The same framework indicates that exports can remain commercially attractive at higher EU prices because remaining revenue increases after carbon charges and cross-border costs are accounted for. At an EU selling price of €180/MWh, remaining revenue rises substantially according to the example provided.
Earnings pressure reported before changes in output; Montenegro case
EPCG estimated that CBAM reduced the value of its first-quarter electricity sales by approximately €13 million. The company reported that it remained profitable during the period despite that estimated revenue reduction.
EPCG said generation was significantly above plan and hydrological conditions were favourable during the quarter it cited. It also stated that Pljevlja thermal power plant continued operating throughout the period referenced in its estimate.
The experience described indicates that CBAM can affect earnings before any immediate shift in physical output becomes visible in utility reporting. Under those conditions, a generator may continue producing and exporting substantial volumes while receiving less revenue for each unit exported.
A stronger incentive to reduce loading, delay starts, or hold capacity in reserve would emerge when netback falls below a plant’s avoidable operating costs, according to EPCG’s described mechanism for decision-making thresholds.
Easier redirection of exports can depress regional prices; renewables affected too
If electricity becomes less attractive for EU buyers under revised economics, it can be redirected toward domestic or neighbouring markets within the Western Balkans region described in utility analysis.
The analysis links this redirection to potential downward pressure on wholesale prices when more supply is available domestically because some EU export opportunities become uneconomic for exporters based on their netback calculations.
This is presented as a two-stage effect: CBAM first weakens EU export economics; displaced volumes then depress prices within regional markets where coal generators operate alongside other supply sources.
The same dynamic can extend beyond coal-fired generation if hydro, wind or solar output cannot meet requirements for favourable CBAM treatment or cannot secure contractual and verification chains needed for those benefits under CBAM rules as described in utility analysis.
Tighter financing risk as utilisation declines; fixed-cost burden rises
The structural consequence highlighted is described as a gradual decline in annual utilisation rather than immediate closure of coal-fired plants across the region.
Thermal capacity remains important for security of supply across much of the Western Balkans during winter peaks, dry hydrological periods, and times when electricity imports are limited according to utility reporting referenced here.
A plant may remain necessary for system security while becoming harder to finance if it operates fewer hours for commercial reasons tied to export economics or regional price levels.
The financing challenge is linked to fixed costs including coal mining operations, maintenance programmes, environmental upgrades, staffing expenses, and debt service obligations described as substantial fixed expenditures relative to output volumes.
An example provided states that if annual electricity production falls by one third while fixed costs remain unchanged, fixed costs per megawatt-hour would rise by 50%. Utilities named as facing this type of challenge include EPS (Serbia), EPBiH (Bosnia and Herzegovina), ERS (Kosovo), and EPCG (Montenegro).
Differentiating domestic security value from export margin and flexibility services
The investment framework described distinguishes between multiple value streams historically supported by export revenues used for domestic fleets, mines, overhauls, and investment programmes in Western Balkan utilities.
A thermal plant may still be needed for reliable domestic supply even if export revenue used previously to finance capacity becomes less predictable under CBAM-influenced netback economics described here.
The analysis sets out three value streams for future investment assessments: domestic security-of-supply value tied to avoiding imports during scarcity periods; commercial export value defined as margin left after CBAM charges and all cross-border costs; and system flexibility value including revenue from balancing markets, reserves provision, capacity availability or other services.
A historic export margin should no longer be automatically carried into decisions on coal mine expansion or power plant rehabilitation or life-extension models under conditions where EU access increasingly carries an explicit carbon cost as described in this investment approach.
No immediate closures expected; operating role shifts toward domestic needs or strong regional prices
The mechanism described here is unlikely to close Western Balkan coal plants overnight because domestic systems still require substantial thermal capacity under varying conditions including hydrology, weather patterns affecting demand and generation mix, import availability constraints, and network limitations.
The reporting also describes a change in how these plants operate commercially: generation previously serving both domestic demand and profitable EU exports may increasingly run mainly when required by domestic system needs or when regional prices are exceptionally strong.
This shift would correspond with lower utilisation levels, fewer profitable export hours where netback remains positive under CBAM-adjusted calculations, and weaker cash generation from exports relative to earlier periods described here.