The application of the EU Carbon Border Adjustment Mechanism to electricity imports from South-East Europe introduces a quantifiable financial and structural risk to the region’s power sector precisely at the point when large-scale capital deployment is required for decarbonisation and grid integration. In Serbia, electricity is not only a domestic utility service but a traded commodity underpinning regional balancing, liquidity, and investment returns. Any CBAM design that misprices the carbon content of exported electricity therefore propagates directly into power prices, investment cost of capital, and system adequacy.
From a quantitative starting point, Serbia’s installed electricity capacity stands at roughly 9.0 GW, with annual gross generation of approximately 34–35 TWh in hydrologically normal years. Lignite-fired thermal power plants account for about 60–65 percent of output, hydropower around 24–26 percent, with wind, gas, and other sources making up the remainder. In export-capable years, Serbia typically places 2.0–4.0 TWh of net electricity into regional markets, predominantly flowing toward Hungary, Romania, and Croatia via coupled or semi-coupled market arrangements. These exports are economically material: at a conservative wholesale price of €85–95/MWh, gross export revenues range between €170–360 million per year before congestion rents and balancing revenues.
Under CBAM, electricity imports into the EU are assigned a carbon price equivalent to the prevailing EU ETS allowance price. Using a forward-conservative ETS price range of €80–100 per tonne of CO₂, the carbon cost embedded in Serbian electricity depends entirely on the emissions factor applied. If default grid-average values are used, Serbia’s average intensity of roughly 0.55 tCO₂/MWh implies a CBAM charge of €44–55 per MWh. Applied to 3.0 TWh of exports, this equates to an annual CBAM exposure of €130–165 million, absorbing 40–55 percent of gross export value in average price conditions. At times of lower wholesale prices, CBAM would exceed the energy margin entirely, rendering exports economically irrational even when they are system-beneficial.
This is the central distortion risk: electricity is dispatched on a marginal basis, not on an annual-average emissions profile. In Serbia and the wider SEE region, the marginal export unit during large parts of the year is hydropower or wind, not lignite. During spring and early summer, hydro-dominated hours regularly account for 40–60 percent of export volumes. Applying an annual average emissions factor to those exports results in systematic over-taxation of low-carbon electricity, directly penalising the very generation assets EU policy aims to encourage.
The capital market implications are immediate. New wind and solar projects in Serbia are currently 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, increasingly required for grid compliance and merchant optimisation, adds €0.35–0.55 million per MWh of installed capacity. These projects rely on regional price convergence and export optionality to reach equity IRRs in the 8–12 percent range. If CBAM uncertainty reduces expected export prices by even €10–15/MWh, project IRRs compress by 150–250 basis points, pushing many developments below bankability thresholds unless compensated by higher support tariffs or state guarantees.
On the operating side, CBAM introduces a new category of OPEX linked to monitoring, reporting, and verification. For a mid-sized private wind portfolio of 300 MW producing roughly 900 GWh per year, the annual cost of CBAM-grade verification, including data management, third-party audit, and importer coordination, is estimated at €0.25–0.45 million per year, or €0.30–0.50/MWh. While modest relative to energy prices, this cost becomes material when layered onto balancing costs, grid fees, and curtailment risk. For state-owned utilities exporting thermal-heavy power, CBAM certificate purchase dominates OPEX, but for renewable producers the verification burden itself becomes a new fixed cost that must be absorbed in merchant pricing.
The verification pathway for green electricity is therefore decisive. Under CBAM rules, importers may declare actual emissions instead of default values, provided these are verified by an accredited independent verifier. For Serbian private producers, this requires installation-level carbon attribution, not grid-average assumptions. In practical terms, a wind, solar, or hydro producer must demonstrate three elements as an integrated chain.
First, metered generation data must be captured at high temporal resolution, typically hourly, with time stamps aligned to market dispatch intervals. This data must be auditable and reconciled with transmission system operator records, in Serbia’s case under Elektromreža Srbije. Second, the producer must document the emissions profile of the installation. For wind and solar this is effectively zero operational emissions, with lifecycle emissions excluded under CBAM electricity rules, but the verifier must still confirm technology type, commissioning date, and operational integrity. For hydropower, reservoir type and operational regime must be disclosed to exclude atypical methane-intensive profiles, even though most Serbian hydro assets fall within low-emission categories. Third, the verified data must be bundled into a declaration that can be relied upon by the EU importer when surrendering CBAM certificates.
This verification must be performed by a body accredited under ISO/IEC 17029 and ISO 14065-aligned schemes and recognised by EU authorities. In practice, Serbian producers today either engage EU-based verifiers directly or operate through structured cooperation with EU consultancies that rely on Serbian technical partners for data collection and site verification. The absence of a fully domestic CBAM-accredited verifier adds transaction cost and friction, particularly for smaller producers.
Looking forward, the quantitative outlook clarifies why timing matters. Serbia’s national energy and climate plans imply an increase in renewable generation sufficient to lift the renewable share of electricity production toward 40 percent by 2030, up from roughly 30 percent today. Achieving this requires incremental investment of €6–8 billion in generation, storage, and grid assets over the next five years. Under a delayed CBAM application to electricity, export revenues from low-carbon generation remain investable, supporting debt service and equity returns. Under immediate full CBAM with default emission factors, a material share of this pipeline becomes non-bankable, shifting the burden back to domestic consumers or public balance sheets.
From a system perspective, the EU also bears cost if CBAM is mis-timed. SEE exports provide flexible capacity during peak demand and drought-driven shortages. Removing or disincentivising these flows increases price volatility in neighbouring EU markets and raises the value of domestic fossil-based peaking capacity, counteracting decarbonisation objectives.
The policy implication is therefore not exemption but sequencing. A delay of CBAM application to electricity until 2028, combined with mandatory development of hourly emissions attribution, domestic carbon pricing alignment, and market coupling milestones, would reduce carbon leakage risk while preserving investment signals. For Serbia, this window enables the build-out of verifiable green electricity portfolios whose exports can demonstrably enter the EU market with near-zero CBAM liability, turning compliance from a cost into a competitive advantage.
Elevated by cbam.engineer