The introduction of the Carbon Border Adjustment Mechanism (CBAM) is rapidly transforming the strategic landscape for industrial electricity procurement across Central and South-East Europe. While CBAM is frequently discussed as a trade measure targeting the carbon intensity of imported commodities, its deeper impact lies in the way it reshapes electricity sourcing strategies for export-oriented industrial sectors.
For heavy industries that sell into the European Union market, the carbon content of their production processes will increasingly determine competitiveness. Electricity consumption is one of the most significant contributors to the embedded emissions of many industrial products, particularly in sectors such as aluminum, steel, chemicals, fertilizers and cement.
The EU ETS already imposes a carbon price on industrial installations located within EU member states. With carbon allowances trading around €60–€80 per tonne of CO₂ during 2025–2026, European industrial producers face significant compliance costs linked to their emissions intensity.
CBAM extends this carbon cost structure to imports. Companies exporting carbon-intensive products into the EU will be required to declare the embedded emissions of their goods and purchase CBAM certificates priced in line with EU ETS allowances.
This framework fundamentally changes the economic incentives surrounding electricity sourcing.
Industrial producers located outside the EU ETS — including those in Serbia, Bosnia and Herzegovina, Montenegro, North Macedonia and parts of Turkey — historically benefited from electricity systems dominated by lignite generation without explicit carbon pricing. While these systems provided relatively low-cost electricity, they also carried high carbon intensity.
Serbia’s electricity mix illustrates the scale of the challenge. Coal-fired plants operated by Elektroprivreda Srbije (EPS) generate roughly 65 %–70 % of national electricity output, with most capacity concentrated at the Nikola Tesla A/B complex near Obrenovac and the Kostolac power plants. Lignite combustion at these facilities typically produces around 1 tonne of CO₂ per MWh, placing them among the most carbon-intensive generation assets in Europe.
For industrial facilities consuming electricity from such carbon-intensive grids, the embedded emissions associated with their production processes can be significant.
Under CBAM, exporters selling electricity-intensive products into the EU market may face additional carbon costs corresponding to the emissions embedded in their production. If these emissions originate from coal-based electricity consumption, the effective carbon cost could approach the EU ETS benchmark.
At a carbon price of €70 per tonne, electricity produced from lignite with emissions intensity of 1 tonne CO₂/MWh carries an implicit carbon cost of €70/MWh. For electricity-intensive industrial operations consuming hundreds of gigawatt-hours annually, this translates into substantial cost exposure.
The strategic response emerging across the region is a shift toward renewable electricity sourcing.
Large industrial consumers are increasingly pursuing long-term renewable power purchase agreements (PPAs) to reduce their carbon exposure. These contracts typically involve a renewable energy producer selling electricity to an industrial buyer under fixed or indexed price terms over 10–20 year durations.
PPAs provide several advantages in the CBAM environment.
First, they allow industrial companies to secure electricity from low-carbon generation sources such as wind, solar or hydropower. Because these sources produce negligible direct emissions, the embedded carbon intensity of electricity consumption declines substantially.
Second, long-term renewable contracts provide price stability in electricity markets characterized by increasing volatility. Since the energy crisis of 2021–2022, wholesale electricity prices across Europe have demonstrated significant variability. Renewable PPAs allow industrial consumers to hedge this volatility.
Third, renewable electricity procurement enhances ESG positioning and regulatory compliance, which increasingly influences access to capital and supply-chain partnerships.
The aluminum sector provides a clear example of these dynamics.
Primary aluminum production requires enormous electricity consumption, often exceeding 14–15 MWh per tonne of aluminum produced. At electricity prices of €70–€100/MWh, energy costs alone can represent a large share of total production costs.
If this electricity is produced from coal, the associated carbon intensity can significantly increase the embedded emissions of aluminum exports. Under CBAM, this carbon intensity could translate directly into financial liabilities.
As a result, aluminum producers are increasingly prioritizing access to low-carbon electricity.
Similar dynamics apply to steel production.
Electric arc furnace (EAF) steelmaking relies heavily on electricity rather than coal-based blast furnaces. While EAF technology reduces direct emissions, the carbon intensity of electricity used in the process remains a critical determinant of the overall emissions footprint.
Steel producers exporting into the EU therefore face growing incentives to secure renewable electricity supply.
In Central and South-East Europe, the expansion of renewable generation is creating new opportunities for industrial electricity procurement.
Wind capacity in the region has grown steadily over the past decade. Serbia currently hosts more than 500 MW of installed wind capacity, including projects such as Čibuk 1 (158 MW) and Kovačica (104 MW). Additional wind projects are under development, including new capacity expected to emerge from Serbia’s renewable energy auction framework.
Solar power is expanding even more rapidly.
Across South-East Europe, several gigawatts of photovoltaic capacity are currently in development pipelines. Declining technology costs have made solar generation increasingly competitive even without extensive subsidy frameworks.
For industrial consumers, these renewable projects provide a growing pool of potential electricity suppliers.
In addition to bilateral PPAs, companies are also exploring Guarantees of Origin (GO) mechanisms, which certify that electricity consumed originates from renewable generation sources. While GOs do not physically deliver renewable electricity to a specific facility, they allow companies to attribute renewable generation to their electricity consumption for compliance and reporting purposes.
In the CBAM environment, the credibility and verification of renewable electricity sourcing becomes increasingly important.
Exporters may need to demonstrate the carbon intensity of their electricity consumption to EU authorities. This requires robust measurement, reporting and verification frameworks capable of documenting the emissions characteristics of electricity supply.
Energy traders and aggregators are beginning to play a larger role in this process.
Companies capable of structuring renewable electricity portfolios, managing price risk and facilitating cross-border power contracts are becoming key intermediaries between renewable producers and industrial consumers.
For Central and South-East Europe, the implications extend beyond individual industrial facilities.
The region’s industrial competitiveness increasingly depends on the availability of large volumes of low-carbon electricity. Countries capable of expanding renewable generation capacity while maintaining competitive electricity prices will be better positioned to attract and retain energy-intensive industries.
Conversely, countries that remain dependent on carbon-intensive electricity generation may face increasing challenges in maintaining export competitiveness under CBAM.
The transition toward renewable electricity procurement therefore represents not only an environmental objective but also an industrial strategy.
Industrial companies that successfully integrate renewable electricity into their production processes will reduce their exposure to carbon pricing mechanisms while strengthening their position within European supply chains.
In the emerging CBAM landscape, electricity sourcing decisions are becoming a central determinant of industrial competitiveness across Central and South-East Europe.
Carbon markets, power trading and portfolio strategy: Implications of CBAM for generators, traders and energy asset managers
The emergence of the Carbon Border Adjustment Mechanism (CBAM) alongside the EU Emissions Trading System (EU ETS) is reshaping the strategic environment for power generators, electricity traders and energy infrastructure investors across Europe. While the immediate focus of CBAM lies in regulating carbon leakage in industrial trade, the mechanism introduces structural changes that ripple through electricity markets, asset valuations and trading strategies.
For power generators, the most immediate implication lies in the changing competitiveness of carbon-intensive generation assets.
Across Europe, coal-fired power plants already operate under the cost structure imposed by the EU ETS. At carbon allowance prices of €60–€80 per tonne, coal plants emitting roughly 1 tonne CO₂ per MWh face carbon compliance costs approaching €70/MWh.
This cost burden has already reduced the competitiveness of coal generation relative to gas, nuclear and renewable sources.
However, the CBAM mechanism extends similar carbon pricing logic to electricity imports originating outside the EU ETS framework.
For generators located in neighboring countries — particularly in the Western Balkans — this introduces a new strategic challenge. Coal-based electricity exports may face carbon adjustments when entering EU markets, reducing their competitiveness.
Serbia’s electricity system illustrates the magnitude of the issue. Coal-fired generation operated by Elektroprivreda Srbije accounts for roughly 65 %–70 % of national electricity output, with installed lignite capacity exceeding 4 GW.
These plants historically supplied electricity not only to the domestic market but also to neighboring countries during periods of surplus generation.
If CBAM introduces carbon adjustments equivalent to EU ETS prices, the effective marginal cost of exporting lignite-based electricity could increase by €60–€80/MWh depending on carbon price levels.
Such cost increases would significantly reduce export margins.
For power generators operating carbon-intensive assets, the strategic response may involve accelerating investment in lower-carbon generation technologies.
Wind, solar and hydropower assets become more attractive in a carbon-priced electricity system. These technologies produce negligible direct emissions and therefore avoid both EU ETS carbon costs and CBAM adjustments.
Across Europe, renewable generation has already become the dominant form of new power capacity investment.
The European Union installed more than 70 GW of new renewable capacity in 2023, with solar power accounting for the majority of new installations. Wind capacity expansion is also accelerating as supply chain constraints gradually ease.
In Central and South-East Europe, renewable deployment remains uneven but is gaining momentum.
Serbia’s renewable energy auctions, for example, have already allocated more than 1 GW of new wind and solar capacity through competitive bidding processes. Similar programs are emerging across neighboring countries as governments seek to align with EU climate policy frameworks.
For energy traders, CBAM introduces new dimensions of complexity into cross-border electricity trading strategies.
Electricity traders operate in markets where profit opportunities often arise from price differentials between neighboring countries. Transmission interconnectors allow electricity to flow from lower-price markets to higher-price markets, generating arbitrage opportunities.
Carbon pricing mechanisms influence these price differentials by altering the marginal cost structure of generation assets.
When CBAM adjustments are applied to electricity imports from carbon-intensive systems, the effective price of imported electricity increases. Traders must therefore incorporate carbon cost modeling into their price forecasts and dispatch strategies.
This requires sophisticated analysis of carbon intensity, fuel price dynamics, renewable generation patterns and transmission constraints.
Electricity traders operating across the Central and South-East European region already navigate complex market conditions characterized by varying regulatory frameworks, generation mixes and hydrological conditions.
The addition of CBAM further increases the importance of carbon analytics within power trading operations.
For energy asset managers and infrastructure investors, the interaction between CBAM and EU ETS has important implications for portfolio valuation.
Carbon pricing fundamentally alters the long-term profitability of power generation assets. Coal-fired power plants face declining economic viability as carbon costs increase, while renewable assets benefit from structural demand for carbon-free electricity.
Institutional investors managing energy infrastructure portfolios are increasingly incorporating carbon pricing scenarios into asset valuation models.
For coal-based generation assets, projected carbon costs can significantly reduce future cash flows. In contrast, renewable assets benefit from rising electricity demand for low-carbon power and from policy frameworks supporting decarbonization.
Energy storage assets also gain importance in this environment.
As renewable generation expands, electricity markets experience greater variability in supply. Energy storage technologies such as battery storage and pumped-hydro systems help stabilize electricity systems by absorbing excess generation during periods of high renewable output and releasing electricity during peak demand periods.
Large storage projects across Europe are increasingly attracting investment.
In the Western Balkans, the planned pumped-storage hydropower plant Bistrica, with potential capacity exceeding 600 MW, illustrates the scale of infrastructure needed to support renewable integration.
For asset managers evaluating long-term energy infrastructure investments, projects that enhance system flexibility may become as valuable as generation assets themselves.
Across the European energy landscape, the interaction between CBAM and EU ETS therefore represents more than a regulatory adjustment.
It signals the consolidation of carbon pricing as the central economic driver shaping electricity markets, investment strategies and energy infrastructure development.
Generators, traders and asset managers who successfully adapt their portfolios and strategies to this carbon-priced environment will be positioned to capture value from the transformation of Europe’s energy system.
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