The European Union’s Carbon Border Adjustment Mechanism (CBAM) represents one of the most consequential structural reforms of the continent’s climate policy architecture since the creation of the EU Emissions Trading System (EU ETS). While CBAM is often described primarily as a trade policy instrument designed to prevent carbon leakage, its interaction with the EU ETS and its indirect effects on electricity markets are beginning to reshape the economics of power generation, cross-border electricity flows, and industrial energy procurement across Central and South-East Europe (CSEE).
The policy architecture underlying CBAM is inseparable from the EU ETS, which remains the central mechanism governing carbon pricing within the European Union. The EU ETS currently covers approximately 10,000 industrial installations and power plants, accounting for roughly 40 % of total EU greenhouse gas emissions. Since its introduction in 2005, the carbon market has evolved from a low-price compliance mechanism into a major structural cost component for European power generation and heavy industry.
Carbon prices under the EU ETS have increased dramatically over the past decade. After trading near €5–€10 per tonne during much of the early 2010s, EU Allowance (EUA) prices rose steadily to exceed €90 per tonne in 2023, before stabilizing in the €60–€80 per tonne range during 2025–2026. This transformation has profoundly altered the economics of fossil-fuel generation across the European power system.
CBAM is designed to extend the carbon cost embedded in EU production to imports of carbon-intensive goods. The mechanism initially applies to steel, cement, aluminum, fertilizers, hydrogen and electricity, sectors that collectively represent some of the most carbon-intensive segments of European industrial activity. Importers of these goods into the EU will be required to purchase CBAM certificates corresponding to the carbon content of the imported products, priced in line with the EU ETS allowance price.
Although electricity represents a smaller share of the initial CBAM coverage compared to heavy industrial commodities, its inclusion is particularly relevant for the power systems of Central and South-East Europe. The region contains multiple electricity exporting countries that are either outside the EU ETS or only partially integrated with the European carbon pricing framework.
Electricity imports into the EU from neighboring countries with carbon-intensive generation portfolios may therefore face a CBAM cost adjustment. The mechanism effectively embeds the EU carbon price into cross-border electricity trade, altering the price competitiveness of power exports originating from systems with higher emissions intensity.
This interaction between CBAM and EU ETS has important implications for regional electricity flows.
Countries such as Serbia, Bosnia and Herzegovina, and North Macedonia maintain electricity systems dominated by lignite-fired generation. In Serbia, coal-fired power plants operated by Elektroprivreda Srbije (EPS) still account for roughly 65 %–70 % of electricity production, primarily from lignite units at the Nikola Tesla A/B and Kostolac power plants. Bosnia and Herzegovina exhibits a similarly coal-heavy generation mix, with lignite plants contributing approximately 60 % of electricity output.
In contrast, EU member states such as Hungary, Romania, Bulgaria and Greece operate within the EU ETS framework, where power generators must purchase carbon allowances for every tonne of CO₂ emitted. For lignite generation with emissions intensity exceeding 1 tonne of CO₂ per MWh, a carbon price of €70 per tonne translates into an additional cost of approximately €70/MWh.
The introduction of CBAM effectively applies a comparable carbon price adjustment to imported electricity originating from non-EU jurisdictions when exported into the EU internal electricity market. This creates a structural shift in the economics of cross-border power flows.
Historically, electricity exports from Western Balkan countries have often been competitive in European markets because lignite generation has lower direct fuel costs than gas-fired plants. Without carbon pricing, coal-based electricity could enter neighboring EU markets at lower marginal costs.
CBAM fundamentally changes this equation.
Once the carbon content of imported electricity is priced in line with EU ETS allowances, lignite-based electricity exports lose much of their competitive advantage. This could reduce the attractiveness of coal-based exports from non-EU countries into EU electricity markets.
The consequences for regional electricity flows may therefore be significant.
In years with high hydropower production or strong renewable output, Western Balkan countries have traditionally exported electricity to neighboring EU systems. Serbia, Bosnia and Herzegovina, and Montenegro have all periodically acted as net exporters to the European market. Serbia’s electricity exports, for example, have fluctuated significantly depending on hydrological conditions and thermal plant availability.
However, if CBAM increases the effective cost of carbon-intensive electricity exports, these flows may become structurally less competitive.
This could gradually alter the direction of electricity trade across the CSEE region.
Instead of coal-dominated systems exporting electricity into EU markets, the region could experience greater flows of lower-carbon electricity originating from renewable-rich EU countries. Electricity produced from wind, solar, nuclear, or hydropower within the EU ETS system would not face CBAM adjustments and could therefore gain a relative advantage.
The implications for wholesale electricity price formation are equally important.
Wholesale power prices across Europe are strongly influenced by the marginal cost of generation technologies. In systems where gas-fired plants often set the marginal price, carbon costs embedded in EU ETS allowances already represent a major component of power prices.
If CBAM reduces the volume of low-cost coal-based electricity imports from neighboring countries, the marginal generation mix within EU markets may shift toward higher-cost generation technologies. This could slightly increase wholesale electricity prices in certain periods, particularly during tight supply conditions.
At the same time, the mechanism could accelerate renewable investment in neighboring countries seeking to maintain electricity export revenues.
Industrial consumers represent another key dimension of the CBAM transformation.
Many industrial sectors in Central and South-East Europe depend heavily on electricity as a production input. Aluminum smelters, steel mills, fertilizer plants, and chemical facilities often operate with extremely narrow operating margins that are highly sensitive to electricity costs.
Under CBAM, industrial exporters selling products into the EU market will face carbon cost adjustments if their production processes rely on carbon-intensive electricity.
This creates a strong incentive for industrial companies to secure low-carbon electricity supply through renewable power purchase agreements (PPAs) or direct investment in renewable generation assets.
Across Europe, large industrial consumers are increasingly entering long-term renewable electricity contracts to mitigate carbon exposure. These contracts typically lock in electricity prices over 10–20 year periods, providing price stability while ensuring that the electricity consumed by the industrial facility originates from renewable sources.
For industrial exporters in the Western Balkans, renewable electricity procurement could become a strategic necessity rather than a voluntary sustainability initiative.
The cost differential between carbon-intensive electricity and renewable electricity will increasingly determine the competitiveness of export-oriented industrial sectors.
Generators, traders, and asset managers must also adapt to this evolving policy environment.
For power generators operating coal-based assets in countries outside the EU ETS, CBAM introduces a potential erosion of export revenues. The long-term profitability of these assets may decline as carbon adjustments reduce their competitiveness in European electricity markets.
Conversely, renewable generators could benefit from rising demand for carbon-free electricity.
Wind and solar power plants located in countries connected to the European grid may find new export opportunities if their electricity can be verified as low-carbon and therefore exempt from CBAM adjustments.
Power traders will face new complexities as CBAM introduces additional cost components into cross-border electricity transactions. The carbon content of electricity flows may need to be measured, verified, and priced into trading strategies.
Asset managers and infrastructure investors are also recalibrating their portfolios in response to these regulatory shifts. Renewable energy assets, grid infrastructure, and energy storage projects may become increasingly attractive as CBAM and EU ETS reinforce the economic advantages of low-carbon generation.
Across Central and South-East Europe, the interaction between CBAM and EU ETS is therefore likely to accelerate structural transformation in electricity markets.
Carbon pricing will increasingly shape the direction of electricity trade, the competitiveness of industrial exports, and the investment strategies of energy companies.
The region’s future electricity system will be defined not only by the expansion of renewable generation, but also by the integration of carbon pricing mechanisms that reshape the economics of power production and consumption across national borders.
Carbon Pricing And Electricity Trade: Cross-Border Power Flows And Price Formation In Central And South-East Europe
The integration of carbon pricing mechanisms into European energy markets is transforming the economics of electricity trade across Central and South-East Europe (CSEE). The interaction between the EU Emissions Trading System (EU ETS) and the Carbon Border Adjustment Mechanism (CBAM) introduces a new layer of cost signals that directly influence cross-border power flows, generation dispatch decisions, and wholesale electricity price formation.
For more than two decades, electricity trade across the region has been shaped primarily by fuel costs, hydrological conditions, and transmission capacity constraints. Coal-dominated systems in the Western Balkans often exported electricity to neighboring EU countries, particularly during periods when lignite generation provided lower marginal costs than gas-fired generation within the EU.
The emergence of carbon pricing has fundamentally altered this dynamic.
Under the EU ETS, power plants located within EU member states must purchase carbon allowances corresponding to their emissions. At current carbon prices of approximately €60–€80 per tonne of CO₂, the cost impact on fossil-fuel generation is substantial.
A coal-fired power plant emitting 0.9–1.1 tonnes of CO₂ per MWh faces an additional carbon cost of roughly €55–€80/MWh, depending on the allowance price. Gas-fired plants, with emissions intensity closer to 0.35–0.45 tonnes of CO₂ per MWh, face carbon costs in the range of €20–€35/MWh.
These costs are embedded into the marginal cost of electricity generation within EU markets, directly influencing wholesale power prices.
Countries outside the EU ETS, however, historically did not face comparable carbon costs. Coal-based electricity produced in neighboring countries could therefore enter EU markets without the additional carbon price burden faced by EU generators.
The introduction of CBAM begins to close this gap.
CBAM extends the carbon pricing logic of the EU ETS to imported goods, including electricity. When electricity is imported from a country without equivalent carbon pricing, the importer may be required to purchase CBAM certificates reflecting the carbon content of the imported electricity.
This effectively embeds the EU carbon price into cross-border electricity trade.
For the electricity markets of Central and South-East Europe, this creates a structural shift in competitive dynamics.
Several countries in the Western Balkans remain heavily dependent on lignite generation. Serbia’s electricity system produces roughly 65 % of its electricity from lignite-fired power plants, primarily located at the Nikola Tesla A/B and Kostolac complexes. Bosnia and Herzegovina maintains a similar generation profile, with coal-based plants representing around 60 % of electricity production.
These plants historically served as low-cost baseload generators capable of exporting electricity to neighboring EU markets during periods of high demand.
Under CBAM, the carbon intensity of this electricity becomes a cost factor in cross-border trade.
For lignite-based generation with emissions intensity near 1 tonne of CO₂ per MWh, a carbon price of €70 per tonne translates into an additional €70/MWh cost adjustment. This erodes much of the cost advantage previously enjoyed by coal-based electricity exports.
As a result, the direction of electricity trade flows may gradually shift.
Instead of coal-dominated Western Balkan systems exporting electricity into EU markets, the region may increasingly import electricity from EU countries with lower carbon intensity generation portfolios.
Romania and Bulgaria, for example, operate electricity systems with significant nuclear and renewable generation capacity. Romania’s Cernavodă nuclear power plant, with installed capacity of approximately 1.4 GW, provides large volumes of low-carbon electricity. Bulgaria’s Kozloduy nuclear power plant, with capacity of roughly 2 GW, performs a similar role.
Electricity produced by nuclear plants carries essentially zero direct carbon emissions and therefore avoids EU ETS carbon costs.
Wind and solar generation are also expanding rapidly across the region. Romania alone has installed more than 3 GW of wind capacity, while Greece and Bulgaria have both accelerated solar deployment in recent years.
As these low-carbon generation sources expand, they could increasingly shape cross-border electricity flows across the CSEE region.
The impact on wholesale electricity price formation is complex.
On one hand, the reduction of coal-based imports into EU markets could slightly increase marginal generation costs during certain periods. If low-cost coal exports disappear from the supply stack, higher-cost gas or renewable generation may set the marginal price more frequently.
On the other hand, the mechanism also creates incentives for neighboring countries to decarbonize their generation portfolios.
If Western Balkan countries expand renewable generation capacity, their electricity exports could regain competitiveness by avoiding CBAM carbon adjustments.
Several large renewable projects are already under development in the region.
In Serbia, wind projects such as Čibuk 1 (158 MW) and Kovačica (104 MW) have already demonstrated the viability of large-scale wind generation. Additional projects including Kostolac Wind Farm (66 MW) and new solar parks are expanding the renewable generation base.
As renewable capacity increases, the carbon intensity of exported electricity may decline, reducing CBAM costs and restoring export competitiveness.
For electricity traders, these evolving dynamics create new arbitrage opportunities.
Carbon price differentials, renewable output variability, and transmission constraints will increasingly determine the profitability of cross-border trading strategies. Traders must integrate carbon cost modeling into their dispatch forecasts and price projections.
Asset managers and infrastructure investors are also reassessing the long-term value of generation assets.
Coal-based power plants may face declining export revenues as carbon pricing spreads across the region. Renewable generation assets, by contrast, may benefit from rising demand for carbon-free electricity.
Across Central and South-East Europe, the interaction between EU ETS and CBAM is therefore redefining the economic geography of electricity trade.
Power markets that once relied primarily on fuel cost advantages are increasingly governed by carbon cost structures. As the European energy transition accelerates, carbon pricing will become a central determinant of electricity flows, generation investment, and wholesale price formation throughout the region.
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