Industrial groups selling into the European Union are increasingly treating electricity as a regulated input, not just an operating cost. Under the Carbon Border Adjustment Mechanism, carbon embedded in production can translate into additional obligations tied to EU allowance benchmarks, pushing developers and operators to align power procurement with measurable low-carbon attributes.
For engineering teams supporting CAPEX planning and EPC preparation, the shift is already changing how feasibility studies are framed: grid carbon intensity, contract structuring, and evidence packages for measurement, reporting and verification are becoming core deliverables alongside generation volumes and delivery profiles. The result is a faster convergence between power-market analytics and industrial project execution readiness across sectors including aluminum, steel, chemicals, fertilizers and cement.
From EU ETS compliance to CBAM-linked electricity exposure
The EU Emissions Trading System establishes a carbon price for industrial installations inside EU member states, with allowance trading around €60–€80 per tonne of CO₂ during 2025–2026. That pricing logic is now extended to imports through CBAM, requiring exporters to declare embedded emissions of goods entering the EU market and purchase CBAM certificates priced in line with EU ETS allowances.
For industrial producers outside the EU ETS—such as those in Serbia, Bosnia and Herzegovina, Montenegro, North Macedonia and parts of Turkey—the operational challenge is that electricity supply has historically been dominated by lignite generation without explicit carbon pricing. While this has supported relatively low-cost power domestically, it also creates high carbon intensity that can follow products into EU-bound trade.
Serbia’s system illustrates the engineering scale of the issue. Coal-fired generation operated by Elektroprivreda Srbije accounts for roughly 65%–70% of national 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.
Electricity procurement becomes a design input for export competitiveness
When industrial facilities draw power from carbon-intensive grids, embedded emissions associated with production processes can become material for CBAM exposure. If electricity used in manufacturing originates from coal-based supply, effective carbon costs can approach the EU ETS benchmark depending on allowance levels applied through CBAM certificates.
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 operations consuming hundreds of gigawatt-hours annually, this becomes a substantial planning variable rather than a marginal accounting line item.
This dynamic is reshaping how industrial buyers evaluate procurement frameworks and how developers structure delivery risk for long-duration contracts. It also changes how engineering studies quantify total emissions footprints—linking production schedules and load profiles to verified electricity attributes rather than relying on historical grid averages alone.
Long-term renewable PPAs and origin instruments move into project scope
A key response across the region is a shift toward renewable electricity sourcing supported by long-term renewable power purchase agreements. Large industrial consumers are increasingly pursuing PPAs where a renewable producer sells electricity to an industrial buyer under fixed or indexed price terms over 10–20 year durations.
From an engineering procurement perspective, PPAs provide three operational advantages in a CBAM environment: access to wind, solar or hydropower with negligible direct emissions; price stability in markets marked by volatility after the 2021–2022 energy crisis; and improved ESG positioning that can influence access to capital and supply-chain partnerships. These benefits directly affect CAPEX planning assumptions because they reduce uncertainty around future carbon-linked cost exposure.
In parallel with bilateral PPAs, companies are exploring Guarantees of Origin mechanisms that certify electricity consumed originates from renewable generation sources. Although GOs do not physically deliver renewable electricity to a specific facility, they enable attribution of renewable generation for compliance and reporting purposes—an important distinction when engineering teams prepare documentation requirements for exporters facing EU authorities.
Sector pressure: aluminum load intensity and EAF steelmaking footprints
The aluminum sector demonstrates why procurement decisions are moving upstream into technical study workstreams. 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 that electricity is coal-based, associated carbon intensity can increase embedded emissions of aluminum exports in ways that may translate directly into financial liabilities under CBAM. As a result, aluminum producers are prioritizing access to low-carbon electricity as part of their competitiveness strategy rather than treating it as an optional sustainability measure.
Steel provides a parallel case where process electrification changes what matters most for overall emissions. Electric arc furnace steelmaking relies heavily on electricity rather than coal-based blast furnaces; while EAF technology reduces direct emissions, the carbon intensity of electricity used remains a critical determinant of emissions footprints. Steel producers exporting into the EU therefore face growing incentives to secure renewable electricity supply.
Renewable build-out in CSEE expands supplier options for industrial buyers
Engineering feasibility work is also being influenced by the availability of new renewable capacity in Central and South-East Europe. Wind capacity has grown steadily over the past decade in Serbia, which hosts more than 500 MW of installed wind capacity including Čibuk 1 at 158 MW and Kovačica at 104 MW. Additional wind projects are under development through Serbia’s renewable energy auction framework expected to add further capacity.
Solar deployment is expanding even faster across South-East Europe. Several gigawatts of photovoltaic capacity are currently in development pipelines, supported by declining technology costs that have made solar increasingly competitive even without extensive subsidy frameworks. For industrial consumers evaluating procurement options, this creates a broader pool of potential suppliers for PPAs and origin-based attribution strategies.
However, CBAM raises the bar on credibility and verification. Exporters may need to demonstrate the carbon intensity characteristics of their electricity consumption to EU authorities using robust measurement, reporting and verification frameworks capable of documenting emissions characteristics linked to supply arrangements.
Carbon analytics reshape trading strategies and asset valuation
The CBAM effect extends beyond industrial buyers into generators, traders and energy asset managers through changes in market economics for cross-border flows. Coal-fired power plants already operate under EU ETS cost structures; at allowance prices of €60–€80 per tonne, plants emitting roughly 1 tonne CO₂ per MWh face carbon compliance costs approaching €70/MWh. This has reduced coal generation competitiveness relative to gas, nuclear and renewables within Europe.
CBAM extends similar carbon pricing logic to electricity imports originating outside the EU ETS framework. For generators in neighboring countries—particularly in Western Balkans markets—coal-based exports may face carbon adjustments when entering EU markets, reducing competitiveness through increased effective marginal costs tied to allowance-referenced benchmarks.
Serbia again provides scale: coal-fired generation operated by Elektroprivreda Srbije supplies roughly 65%–70% of national output with installed lignite capacity exceeding 4 GW. Historically these plants have supplied not only domestic demand but also neighboring markets during surplus periods; under CBAM-linked adjustments equivalent to EU ETS prices, effective marginal export costs could increase by €60–€80/MWh depending on carbon price levels.
Portfolio strategy shifts toward renewables and flexibility infrastructure
For power generators operating carbon-intensive assets, one strategic response is accelerating investment in lower-carbon technologies such as wind, solar and hydropower whose negligible direct emissions avoid both EU ETS carbon costs and CBAM adjustments. Across Europe renewables have already become dominant for new capacity investment; the European Union installed more than 70 GW of new renewable capacity in 2023 with solar accounting for most new installations while wind expansion accelerates as supply chain constraints ease.
Traders face added complexity because profit opportunities often arise from price differentials between neighboring countries enabled by transmission interconnectors that allow arbitrage flows from lower-price markets to higher-price markets. When CBAM adjustments apply to imports from carbon-intensive systems, effective imported electricity prices increase; traders must incorporate carbon cost modeling into price forecasts and dispatch strategies using analysis spanning carbon intensity inputs, fuel price dynamics, renewable patterns and transmission constraints.
For energy asset managers evaluating long-term infrastructure portfolios, interaction between CBAM and EU ETS affects valuation through altered long-term profitability assumptions. Coal-based generation cash flows can be reduced by projected carbon costs while renewable assets benefit from structural demand for carbon-free electricity; institutional investors increasingly incorporate scenario-based carbon pricing into asset valuation models.
Bistrica pumped storage highlights engineering needs for system flexibility
As renewable generation expands across regional grids, variability increases supply-side balancing requirements. Energy storage technologies such as battery storage and pumped-hydro systems help stabilize systems by absorbing excess generation during high-output periods and releasing electricity during peak demand periods—an operational requirement that becomes more visible during grid integration studies.
Large storage projects across Europe are attracting investment as flexibility becomes part of system value propositions rather than only an ancillary service concept. In the Western Balkans specifically, the planned pumped-storage hydropower plant Bistrica is cited with potential capacity exceeding 600 MW as an example of infrastructure scale needed to support renewable integration.
Broader project implications for developers and contractors
Across Central and South-East Europe, CBAM-linked electricity procurement decisions are becoming central determinants of industrial competitiveness alongside traditional considerations such as delivery reliability and contract pricing terms. Developers preparing engineering studies now need to treat measurement reporting capabilities—alongside contract structures—as part of execution readiness because exporters may need evidence packages demonstrating verified low-carbon attributes for EU authorities.
The broader industry implication is that portfolio strategies spanning generators, traders and infrastructure investors must incorporate carbon pricing scenarios alongside market modeling assumptions about dispatch economics and cross-border transmission constraints. For industrial stakeholders across aluminum production requiring 14–15 MWh per tonne ranges or EAF steelmaking dependent on electricity carbon intensity, procurement frameworks backed by long-duration PPAs over 10–20 years or credible Guarantees of Origin pathways are increasingly shaping investment planning priorities rather than remaining peripheral ESG initiatives.