The EU Carbon Border Adjustment Mechanism (CBAM) applied to electricity imports from South-East Europe creates a financial and structural risk for the region’s power sector at a time when decarbonisation and grid integration require large-scale investment. In Serbia, electricity is both a domestic utility service and a traded commodity used in regional balancing, liquidity and investment returns. CBAM designs that assign incorrect carbon content to exported electricity can affect power prices, the cost of capital for investment and system adequacy.
Serbia’s installed electricity capacity is roughly 9.0 GW, with annual gross generation of about 34–35 TWh in hydrologically normal years. Lignite-fired thermal power plants account for roughly 60–65% of output, while hydropower provides around 24–26%. Wind, gas and other sources make up the remainder of generation.
In export-capable years, Serbia typically sends 2.0–4.0 TWh of net electricity into regional markets. Flows are described as predominantly directed toward Hungary, Romania and Croatia, using coupled or semi-coupled market arrangements. At a conservative wholesale price of €85–95/MWh, gross export revenues are estimated at €170–360 million per year, before congestion rents and balancing revenues.
CBAM carbon pricing applied to electricity volumes
Under CBAM rules for electricity, EU imports are assigned a carbon price equivalent to the prevailing EU ETS allowance price. A forward-conservative ETS range of €80–100 per tonne of CO₂ is used to estimate the carbon cost embedded in Serbian electricity. The resulting charge depends on the emissions factor applied to the exported power.
If default grid-average values are used, Serbia’s average intensity is stated at roughly 0.55 tCO₂/MWh. That implies a CBAM charge of €44–55 per MWh. Applied to 3.0 TWh of exports, the annual CBAM exposure is estimated at €130–165 million, equivalent to absorbing about 40–55% of gross export value under average price conditions.
The exposure can increase relative to energy margins when wholesale prices fall. The text states that in such periods CBAM charges could exceed the energy margin entirely, making exports economically irrational even when they are system-beneficial. This depends on how carbon costs are calculated against market prices.
Marginal dispatch versus annual-average emissions factors
The material distortion risk described relates to how electricity is dispatched compared with how emissions factors are applied. Electricity is dispatched on a marginal basis rather than according to an annual-average emissions profile. In Serbia and the wider SEE region, the marginal export unit during large parts of the year is described as hydropower or wind rather than lignite.
The source reports that during spring and early summer hydro-dominated hours account for roughly 40–60% of export volumes. Applying an annual average emissions factor to those exports is described as leading to systematic over-taxation of low-carbon electricity. This would directly penalise generation assets that EU policy aims to encourage.
Investment impacts for wind, solar and storage projects
The capital market implications are presented alongside these CBAM cost estimates. New wind and solar projects in Serbia are described as being developed at indicative CAPEX levels of €1.1–1.4 million per MW for wind and €0.55–0.75 million per MW for utility-scale solar, excluding grid reinforcement. Battery storage adds an estimated €0.35–0.55 million per MWh of installed capacity.
The projects are described as relying on regional price convergence and export optionality to reach equity IRRs in the 8–12% range. If CBAM uncertainty reduces expected export prices by even €10–15/MWh, project IRRs compress by 150–250 basis points. The text states that this could push developments below bankability thresholds unless offset by higher support tariffs or state guarantees.
Operational costs tied to monitoring, reporting and verification
The operating side includes additional OPEX linked to monitoring, reporting and verification under CBAM requirements. For a mid-sized private wind portfolio of 300 MW, producing roughly 900 GWh per year, annual CBAM-grade verification costs are estimated at €0.25–0.45 million per year. This is also expressed as about €0.30–0.50/MWh.
The source notes that while verification costs may be modest relative to energy prices, they can become material when combined with balancing costs, grid fees and curtailment risk. For state-owned utilities exporting thermal-heavy power, certificate purchase is described as dominating OPEX. For renewable producers, the verification burden is described as a fixed cost that must be absorbed into merchant pricing.
Verification pathway for actual emissions declarations
The verification pathway for green electricity is presented as central under CBAM rules allowing actual emissions declarations instead of default values. Importers may declare actual emissions provided these are verified by an accredited independent verifier. For Serbian private producers, this requires installation-level carbon attribution rather than grid-average assumptions.
The text describes an integrated chain of evidence needed from producers such as wind, solar or hydro operators. First, metered generation data must be captured at high temporal resolution, typically hourly, with time stamps aligned to market dispatch intervals. The data must be auditable and reconciled with transmission system operator records under Elektromreža SrbijeElektromreža Srbije.
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