The EU’s Carbon Border Adjustment Mechanism is moving carbon costs from the factory gate to cross-border commerce, with consequences that extend well beyond traditional “carbon leakage” concerns. As CBAM is built to operate alongside the EU Emissions Trading System, it is altering how electricity exports are priced into the EU market and how industrial buyers manage carbon exposure. For policy makers and companies across Central and South-East Europe, the practical challenge is no longer only domestic emissions compliance, but also trade-linked carbon accounting across multiple sectors.
CBAM is structurally tied to the EU ETS, which remains the core carbon pricing tool inside the European Union. The EU ETS covers around 10,000 installations and power plants and accounts for roughly 40% of total EU greenhouse gas emissions. Since it began in 2005, the carbon market has shifted from a low-price compliance instrument into a major structural cost driver for both power generation and heavy industry. That evolution matters because CBAM certificates are priced in line with EU ETS allowance prices.
EU ETS price signals now underpin CBAM-linked trade costs
Over the past decade, EU allowance prices have risen sharply, changing dispatch economics for fossil generation. After trading near €5–€10 per tonne in much of the early 2010s, EU Allowance prices exceeded €90 per tonne in 2023. During 2025–2026 they stabilized in a €60–€80 per tonne range. The resulting carbon cost component is already embedded in wholesale electricity pricing where EU generators must purchase allowances for every tonne of CO₂ emitted.
That linkage becomes decisive when electricity crosses borders into the EU market. CBAM is designed to extend carbon costs embedded in EU production to imports of carbon-intensive goods. Its initial coverage includes steel, cement, aluminium, fertilisers, hydrogen and electricity. Importers bringing these products into the EU are required to buy CBAM certificates corresponding to the carbon content of imported goods, aligned with the EU ETS allowance price.
Electricity becomes a CBAM-relevant trade variable for CSEE
Electricity represents a smaller share of CBAM’s initial sectoral scope than heavy industrial commodities, but it is particularly consequential for Central and South-East Europe’s power trade patterns. The region includes electricity exporters that are outside the EU ETS or only partially integrated with EU carbon pricing. In that context, electricity imports into the EU from neighbouring systems with more carbon-intensive generation portfolios can face CBAM cost adjustments.
The mechanism effectively embeds the EU carbon price into cross-border electricity trade by pricing the carbon content of imported electricity when it enters the EU internal market. This changes export competitiveness for systems with higher emissions intensity and can reshape regional flow directions over time. Historically, Western Balkan exports have often benefited from lignite’s lower direct fuel costs than gas-fired generation inside the EU, allowing coal-based electricity to enter European markets at lower marginal costs when carbon pricing was not reflected in import costs.
Lignite-heavy exporters face a new competitiveness test
Several Western Balkan systems remain dominated by lignite-fired generation, making them sensitive to any trade-linked carbon cost pass-through. In Serbia, coal-fired plants operated by Elektroprivreda Srbije still account for roughly 65%–70% of electricity production, primarily from lignite units at Nikola Tesla A/B and Kostolac power plants. Bosnia and Herzegovina shows a similarly coal-heavy profile, with lignite plants contributing about 60% of electricity output. These plants have often served as baseload suppliers capable of exporting during periods of demand.
Within the EU ETS framework, however, fossil generators already bear a direct allowance cost per tonne of CO₂ emitted. For lignite generation with emissions intensity exceeding 1 tonne of CO₂ per MWh, a carbon price around €70 per tonne translates into an additional cost of approximately €70/MWh. With CBAM applying an equivalent carbon price adjustment to imported electricity originating from non-EU jurisdictions when exported into the EU internal market, lignite-based exports lose much of their prior cost advantage. That shift can reduce the attractiveness of coal-based exports from non-EU countries into EU electricity markets.
Dispatch economics and wholesale prices may move with cross-border volumes
Changes in cross-border electricity competitiveness can feed through to wholesale price formation because European power prices are influenced by marginal generation costs. In systems where gas-fired plants often set marginal prices, carbon costs embedded through EU ETS allowances already represent a major part of power pricing. If CBAM reduces volumes of low-cost coal-based imports from neighbouring countries, marginal supply stacks in EU markets may shift toward higher-cost technologies more frequently.
The result could be modest upward pressure on wholesale prices during certain periods, particularly when supply is tight and marginal units are more likely to be higher-cost options. At the same time, CBAM-linked demand signals can accelerate renewable investment decisions in neighbouring countries seeking to preserve or regain export revenues by improving their generation’s carbon intensity profile.
Industrial exporters must manage electricity-linked carbon exposure
CBAM also creates incentives for industrial buyers because many sectors across Central and South-East Europe depend heavily on electricity as an input under narrow operating margins. Aluminium smelters, steel mills, fertiliser plants and chemical facilities often operate with limited room for cost increases driven by energy prices. Under CBAM, industrial exporters selling products into the EU market face carbon cost adjustments if their production processes rely on carbon-intensive electricity.
This pushes exporters toward securing low-carbon electricity supply through renewable power purchase agreements or direct investment in renewable generation assets. Across Europe, large industrial consumers increasingly use long-term renewable contracts that typically lock in electricity prices over 10–20 year periods while ensuring that consumed electricity originates from renewable sources. For Western Balkan exporters specifically, renewable procurement may become a strategic requirement tied to maintaining export competitiveness rather than a purely voluntary sustainability measure.
Market participants recalibrate assets and trading models
For generators operating coal-based assets outside the EU ETS boundary, CBAM introduces potential erosion of export revenues as trade-linked carbon adjustments reduce competitiveness in European markets. Long-term profitability for those assets may decline if export opportunities weaken under higher effective carbon costs applied at import time into the EU market. Conversely, renewable generators connected to European grids may find new export opportunities if their output can be verified as low-carbon and therefore exempt from CBAM adjustments.
Traders face additional transaction complexity because CBAM adds cost components linked to cross-border flows that require measurement and verification of electricity’s carbon content for pricing strategies. Asset managers and infrastructure investors are also reassessing portfolios as renewable assets, grid infrastructure and energy storage projects become increasingly attractive under a framework where both CBAM and EU ETS reinforce low-carbon generation advantages.
Renewables build pathways to restore export competitiveness
The direction of future power trade across CSEE may depend on whether exporters can reduce exported electricity’s carbon intensity enough to offset CBAM-linked adjustments. In years with high hydropower production or strong renewable output, Western Balkan countries have periodically acted as net exporters to European markets; Serbia’s exports have fluctuated based on hydrological conditions and thermal plant availability. If CBAM increases effective costs for carbon-intensive exports without corresponding decarbonisation gains elsewhere in exporting systems, flows could become structurally less competitive.
Renewable expansion provides one route to regain competitiveness because low-carbon generation avoids CBAM-related cost burdens when exported into the EU market. Serbia has wind projects such as Čibuk 1 (158 MW) and Kovačica (104 MW), alongside Kostolac Wind Farm (66 MW) and additional solar parks expanding its renewable base. More broadly across the region’s grid-connected systems, wind and solar deployment alongside nuclear capacity—such as Romania’s Cernavodă at about 1.4 GW and Bulgaria’s Kozloduy at roughly 2 GW—can support lower-carbon export profiles where verification requirements can be met.
Analytical synthesis: CBAM turns carbon pricing into a cross-border competitiveness mechanism
Taken together with the EU ETS allowance price trajectory—rising from near €5–€10 per tonne earlier this decade to above €90 per tonne in 2023 before stabilising at €60–€80 per tonne during 2025–2026—CBAM extends those cost signals into trade flows covering steel, cement, aluminium, fertilisers, hydrogen and electricity. For Central and South-East Europe’s power markets, this creates a structural shift: lignite-dominated exporters face reduced competitiveness when their exports enter the EU internal market under CBAM-linked adjustments tied to emissions intensity levels that can translate into tens of euros per megawatt-hour at higher allowance prices.
The compliance-driven logic also reaches industry procurement because exporters selling into the EU must account for production processes reliant on carbon-intensive electricity. As a result, decarbonisation choices—renewable PPAs or direct renewable investment—become intertwined with trade access and export economics alongside evolving dispatch impacts on wholesale price formation where marginal generation mix may shift toward higher-cost technologies during tight periods.