The European Union’s Carbon Border Adjustment Mechanism (CBAM) is affecting electricity trade patterns across Southeast Europe by linking carbon costs to electricity imports from non-EU countries. The impact is most visible in Serbia, which is the largest electricity producer in Southeast Europe outside the EU and a key transit and balancing hub between EU and non-EU power systems.
Serbia’s power system combines generation scale, a mix of asset types, central geography, and dense interconnection with neighbouring markets. Total annual electricity generation fluctuates around 35–38 TWh, exceeding output from other Western Balkan countries, including Croatia and Bosnia and Herzegovina individually. The size of the system matters for CBAM because carbon pricing affects regional dispatch choices, congestion patterns, and investment decisions across interconnected grids.
Generation mix and role of Elektroprivreda Srbije
Elektroprivreda Srbije operates a generation fleet dominated by lignite-fired thermal plants supported by hydropower assets. Hydropower resources are located on the Danube, Drina, Lim, and Morava river systems. Lignite accounts for roughly 65–70 percent of installed capacity and a similar share of generation in normal hydrological years.
Average emissions intensity for Serbian baseload lignite units is typically in the range of 0.9–1.05 tCO2/MWh. This places Serbia among the more carbon-intensive power producers on the European continent. Under earlier market conditions without an explicit carbon price applied at the border, Serbian lignite-based electricity remained cost-competitive across borders even when EU wholesale prices tightened.
Export corridors and how CBAM changes trade economics
For more than a decade, Serbia’s generation structure supported exports and price stabilisation across the region. Serbian flows into Bosnia and Herzegovina, Montenegro, North Macedonia, Hungary, Romania, and occasionally Croatia have been part of routine Southeast European market operations. During peak demand periods and hydrological shortfalls, neighbouring markets received electricity from Serbia.
CBAM changes how those cross-border flows clear into EU markets by imposing a carbon cost equivalent to the EU Emissions Trading System (EU ETS). With EU ETS prices averaging €75–90 per tonne of CO2 during 2025 and forward curves indicating €90–120 per tonne by 2030, the implied carbon surcharge on Serbian lignite-based electricity exported to the EU reaches €70–110 per MWh. The added cost pushes lignite-based exports out of merit order in most trading hours.
The decline in competitiveness affects export utilisation into EU Member States including Hungary, Romania, and Croatia. Even during high-demand periods, Serbian exports increasingly clear when hydropower or other low-carbon generation sets marginal prices. By contrast, lignite-based volumes face competition from EU-based generation that already internalises carbon costs and from renewable sources with near-zero marginal emissions.
Serbia as balancing and transit hub under regional price shifts
Serbia’s role under CBAM does not disappear; it shifts toward balancing and transit functions. Instead of relying primarily on low-cost baseload exports, Serbia influences price formation through internal dispatch decisions and cross-border flows across multiple neighbouring systems. This position is reinforced by Serbia’s grid topology and its central location within the Energy Community network connecting Adriatic, Danube, and Pannonian power corridors.
CBAM also affects how Serbia interacts with non-EU neighbours. Bosnia and Herzegovina and Montenegro—smaller systems with higher hydrological volatility—may depend more on Serbian imports when their own carbon-intensive generation becomes uneconomic or constrained. In those circumstances, Serbia can move from exporter to net importer of electricity from the EU while exporting power eastward or southward to non-EU markets.
This pattern can increase congestion risks and require additional transmission system coordination. It also links regional dispatch outcomes more tightly to carbon-related price signals affecting EU-bound flows. The resulting operational demands extend beyond direct bilateral exchanges.
Domestic price exposure and investment implications for lignite
Serbia faces dual pressures on system costs under CBAM-linked pricing dynamics. Export revenues to the EU can decline for electricity produced by lignite units that previously monetised surplus generation. At the same time, higher regional prices driven by carbon costs can raise domestic wholesale benchmarks.
Wholesale prices in Serbia historically hovered in the €50–70/MWh range but are increasingly exposed to EU price signals above €80–100/MWh during tight system conditions. Dry hydrological years are particularly relevant because thermal generation tends to set marginal prices. These conditions affect revenue expectations for existing assets.
Lignite investment incentives are influenced by reduced long-term revenue certainty under CBAM conditions, especially if domestic carbon policy aligns with EU standards. Serbia’s lignite fleet represents several gigawatts of installed capacity with residual technical life extending into the 2040s. Under high carbon price scenarios, capacity factors for these plants decline sharply, raising questions about stranded asset risk and balance-sheet stress for EPS.
Low-carbon build-out: hydropower limits, wind/solar costs
The same policy environment strengthens the case for low-carbon capacity additions in Serbia. Hydropower remains a cornerstone but expansion potential is limited by environmental constraints and hydrological risk. Wind and solar are entering a phase of rapid scale-up within Serbia’s market context.
Utility-scale solar projects in Serbia are reported to achieve levelised costs below €50/MWh. Onshore wind projects in favourable locations approach €45–55/MWh, even before accounting for any carbon-related advantages. Installed capacity costs are cited at €600–900/kW for solar and €900–1,200/kW for wind.
The economics are described as more bankable when projects are paired with long-term offtake arrangements. These figures relate to technology cost levels rather than specific project approvals or permits within the text provided. They also connect to how future generation mix could offset declining lignite competitiveness under sustained carbon pricing.
Flexibility needs: storage timelines and regulatory alignment
The need for grid flexibility increases as variable renewables expand across the region. Serbia’s large hydropower reservoirs provide short-term balancing capability, but fast-response assets become more important with higher shares of intermittent generation. Battery energy storage systems are currently deployed at pilot scale in Serbia.
Batteries are expected to become economically viable as costs fall toward €200–250/kWh installed by the late 2020s. Such storage would support arbitrage opportunities between EU and non-EU market price spreads under volatility linked to CBAM-driven repricing. The text frames this as tied to Serbia’s hub position rather than a standalone technology deployment plan.
Regulatory alignment remains a key factor because Serbia is not yet part of the EU ETS while discussions on carbon pricing mechanisms intensify. A domestic carbon tax or an ETS-like system at a lower introductory price could allow partial internalisation of carbon costs. Revenues could be recycled into grid upgrades, renewable subsidies, and social transition measures.
If no alignment occurs domestically, exporters would face CBAM charges at the EU border without capturing fiscal upside in Serbia. In that case, carbon-related rent would be directed to EU treasuries rather than being retained through domestic policy instruments described in the text provided.
Outlook toward 2030 under sustained EU carbon prices
The energy outlook described anticipates sustained high carbon prices alongside tighter EU emission caps and accelerated electrification of industry and transport through 2030. Under these conditions, Serbia’s system is positioned at the intersection of decarbonisation pressures and regional market integration efforts. Forecast scenarios suggest that by 2030 Serbia could remain a net exporter in energy terms if low-carbon generation expands quickly enough.
The same scenarios indicate that continued net export status depends on offsetting declining lignite competitiveness through generation mix changes rather than relying on legacy dispatch economics alone. Otherwise, peak-period imports could increase as structural exposure to EU price volatility rises without full benefits from market integration described in the text provided.
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