EU carbon border rules are beginning to show up not only in industrial import bills, but also in the way electricity trade is structured across borders. With the Carbon Border Adjustment Mechanism entering its full charging phase in January 2026, carbon intensity has become a commercial variable for exporters that previously relied on price differentials and generation costs. For Serbia’s electricity sector, the shift is being felt through tighter export economics, altered contracting behaviour, and a recalibration of long-term capital plans.
CBAM charging turns electricity trade into a carbon-intensity test
Serbia has operated as a regional power hub, exporting electricity into Hungary, Romania and Croatia. In recent years, net exports have been in the range of 2–4 TWh per year, with Hungary taking around 6.1 TWh, Romania about 2.4 TWh, and Croatia about 1.5 TWh in 2023, based on trade data. The underlying generation mix has included coal-fired output alongside hydropower, enabling sales into the EU when market prices were favourable.
Under CBAM, buyers and traders must account for carbon costs alongside energy prices. For lignite-based Serbian power, this can translate into surcharges estimated at €70–110 per MWh, depending on the EU Emissions Trading System price and the assumed emission factor. In “normal” price conditions of €80–120 per MWh, large-scale coal-driven exports face reduced profitability once the CBAM-linked cost is incorporated.
From baseload volumes to selective cross-border supply
The practical effect is a change in procurement logic for EU-side counterparties. Instead of treating Serbian supply as a volume opportunity driven mainly by spot pricing, traders are expected to apply carbon-adjusted arbitrage: purchases proceed only if the bid price plus CBAM certificates still leaves a margin. This dynamic tends to favour shorter-term arrangements and more selective sourcing decisions.
As a result, Serbia is moving away from exporting baseload power at scale toward supplying flexibility-oriented volumes that can clear CBAM-linked cost barriers. Electricity that is low-carbon—particularly hydro-linked or renewable-based—faces little or no CBAM-linked cost pressure relative to higher-emitting generation. The shift also affects competitive positioning within the region as alternative suppliers with cleaner generation profiles become more attractive for EU-facing deals.
Estimated CBAM costs for Serbian electricity exports
Trade-pattern analysis using 2024-style flows indicates that Serbian-routed electricity exports into the EU implied roughly 9.18 TWh per year. That level of trade corresponds to an estimated €612.5 million in annual CBAM-related costs, or about €66.7 per MWh when expressed as carbon-adjusted cost. While these figures depend on underlying assumptions about emissions factors and certificate pricing, they illustrate that CBAM costs can function as a structural operating charge rather than a marginal adjustment.
The consequence for exporters is twofold: export volumes are compressed, especially during low- and medium-price periods; and export value becomes increasingly concentrated in cleaner and more flexible generation categories. Competitive pressure can intensify when neighbouring systems with predominantly renewable mixes—such as Albania—are able to offer EU buyers supply options with lower carbon-cost exposure.
CBAM squeezes EPS revenue buffers
For Elektroprivreda Srbije (EPS), the financial implications are direct because electricity exports have historically helped balance the utility’s books. Export revenues have supported domestic sales that carry lower margins and have contributed to covering fixed costs associated with an ageing coal fleet. When export economics deteriorate under CBAM-linked pricing effects, those balancing mechanisms weaken.
Reports indicate that even an export-price reduction of €10–15 per MWh—attributed to CBAM-related uncertainty and buyer risk-pricing—can erode EPS’s export-linked gross revenue and compress margins previously used to offset heavy capex needs and debt characteristics. The timing matters: electricity exports are charged at full CBAM rates from 1 January 2026 without an extended phase-in for the power sector.
Investment plans re-priced around stranded-asset risk
The most consequential impact is not limited to near-term profit-and-loss statements; it extends into project finance assumptions for new capacity and upgrades tied to export optionality into EU markets. If CBAM-driven price erosion of €10–15 per MWh is embedded in forecasts, internal rates of return can fall by about 1.5–2.5 percentage points. For capital-intensive coal-heavy projects, this can push expected returns toward or below bankability thresholds unless supported by explicit state guarantees, higher domestic tariffs, or dedicated decarbonisation grants.
This is reshaping how lenders and rating agencies evaluate risk as EU climate policy tightens: carbon-price risk, regulatory uncertainty and stranded-asset exposure are increasingly reflected in financing decisions. At the same time, projects aligned with renewables expansion, hydro-linked flexibility and grid modernisation are gaining favour because they can be positioned as lower-carbon power that better fits EU demand patterns under carbon-cost regimes.
Broader compliance implications across CBAM-covered industries
CBAM applies to imports of goods including cement, steel, aluminium, fertilisers and also covers electricity; hydrogen is part of the wider decarbonisation compliance landscape discussed under European Green Deal implementation pathways. For importers and exporters operating alongside the EU ETS framework, the central compliance requirement is that embedded emissions are accounted for when products enter the EU market during the charging phase starting January 2026 for definitive charges under the mechanism’s structure.
For EU producers already subject to ETS obligations, CBAM changes competitive dynamics by aligning import exposure with carbon-cost levels faced domestically. Across sectors such as cement and steel—where process emissions are material—and aluminium and fertilisers—where energy intensity drives emissions—trade compliance increasingly depends on robust emissions monitoring and reporting systems that can withstand buyer scrutiny and regulatory verification demands.
In practical terms for industry participants across Europe’s supply chains, the message from Serbia’s electricity case is transferable: once carbon intensity becomes a priced attribute at the border during full charging periods, contracting behaviour shifts toward lower-emitting supply options, investment models incorporate carbon-cost risk earlier in project appraisal cycles, and compliance capability becomes part of commercial competitiveness.