Carbon pricing is moving from the balance sheet to the dispatch stack across Central and South-East Europe, as the EU’s Carbon Border Adjustment Mechanism starts to change how electricity exports are valued. For utilities, industrial buyers and investors, the practical effect is that cross-border power flows are increasingly judged not only on fuel and hydrology, but also on embedded emissions. That shift is now feeding directly into renewable procurement strategies, engineering study priorities, and the timing of grid and storage investment.
At the center of the new planning environment is the EU Emissions Trading System, which covers roughly 10,000 industrial installations and power plants and accounts for about 40% of EU greenhouse gas emissions. Since its launch in 2005, the carbon market has evolved from a low-price compliance tool into a structural cost driver for both power generation and heavy industry. Over the past decade, allowance prices moved from around €5–€10 per tonne to above €90 per tonne in 2023, before settling in the €60–€80 per tonne band during 2025–2026.
From carbon allowances to border adjustments: what changes for electricity
CBAM is intended to extend carbon costs embedded in EU production to imports of carbon-intensive goods. Its initial coverage includes steel, cement, aluminum, fertilizers, hydrogen and electricity, with importers required to purchase CBAM certificates aligned with the carbon content of imported products and priced in line with EU ETS allowance values. While electricity is a smaller share of CBAM’s starting scope than heavy commodities, it becomes strategically significant for CSEE because several neighboring exporters sit outside full EU carbon pricing coverage.
When electricity is imported into the EU from jurisdictions with higher-emissions generation portfolios, CBAM can introduce a cost adjustment that effectively embeds EU carbon pricing into cross-border trade. That changes relative competitiveness between exporters whose systems rely on lignite and those whose generation mix is lower-carbon. The operational implication for market participants is that trading models must increasingly treat carbon cost as a variable in cross-border pricing rather than as an internal-only EU factor.
Western Balkans lignite exposure meets EU marginal pricing
Countries such as Serbia, Bosnia and Herzegovina and North Macedonia remain dominated by lignite-fired generation. Serbia’s coal-based fleet operated by Elektroprivreda Srbije still produces about 65%–70% of electricity output, mainly from lignite units at Nikola Tesla A/B and Kostolac. Bosnia and Herzegovina shows a similar pattern, with lignite plants contributing around 60% of electricity production.
Within the EU ETS framework, power generators must buy allowances for every tonne of CO₂ emitted. For lignite generation with emissions intensity above 1 tonne of CO₂ per MWh, a carbon price near €70 per tonne implies an additional cost of roughly €70/MWh. As CBAM begins to apply comparable adjustments to imported electricity exported into the EU internal market from non-EU systems, coal-based exports lose part of their historical price advantage versus gas-fired marginal producers inside the EU.
Dispatch outcomes and wholesale price formation could shift
Wholesale power prices across Europe are heavily influenced by marginal generation costs, particularly in periods when gas-fired units set price levels. With EU ETS costs already embedded in fossil dispatch economics, CBAM’s effect on import volumes can indirectly alter which technologies become marginal more often. If low-cost coal-based imports from neighboring systems decline, marginal supply stacks inside EU markets may shift toward higher-cost generation technologies during certain hours.
The result could be modest upward pressure on wholesale prices in specific periods, especially under tight supply conditions where marginal units are more frequently binding. At the same time, CBAM can accelerate renewable investment decisions in neighboring countries seeking to preserve export revenues by reducing the carbon intensity of exported electricity. For developers and asset managers, this means that early-stage resource assessments increasingly need to be paired with emissions accounting assumptions that affect bankability of long-term export-oriented revenue models.
Industrial procurement becomes a carbon-risk engineering problem
Beyond power trading economics, CBAM changes incentives for industrial exporters across Central and South-East Europe because many sectors depend on electricity with narrow operating margins. Aluminum smelters, steel mills, fertilizer plants and chemical facilities are particularly sensitive to electricity price volatility. Under CBAM-linked conditions for products sold into the EU market, industrial exporters can face carbon cost adjustments if their production processes rely on carbon-intensive electricity.
This creates a stronger business case for securing low-carbon electricity through renewable power purchase agreements or direct investment in renewable generation assets. Across Europe, large industrial consumers are increasingly signing long-term renewable contracts that typically lock prices over 10–20 year periods while ensuring that consumed electricity is sourced from renewables. For Western Balkan exporters targeting EU demand, renewable procurement may move from voluntary sustainability positioning toward a strategic necessity tied to competitiveness.
Renewables pipeline signals where engineering studies may concentrate
The shift toward low-carbon export competitiveness is already visible in project pipelines where wind and solar capacity additions can reduce the carbon intensity profile of outgoing power. In Serbia, wind projects including Čibuk 1 (158 MW) and Kovačica (104 MW) have demonstrated large-scale wind viability. Additional developments such as Kostolac Wind Farm (66 MW) and new solar parks are expanding the renewable base.
As renewable penetration rises in export-oriented systems, developers expect lower CBAM-related costs through reduced emissions intensity of exported electricity. For engineering teams preparing EPC packages or grid interconnection scopes, this reinforces the need to align feasibility studies with transmission constraints and deliverability timelines rather than treating generation build as an isolated workstream. It also increases attention on verification approaches that can support claims of low-carbon electricity attributes relevant to cross-border transactions.
Grid modernization and storage planning gain urgency
While CBAM itself does not specify technical buildouts like transmission upgrades or battery energy storage systems, its market signal affects how quickly developers must make projects execution-ready under evolving dispatch economics. Traders already face new complexities because cross-border transactions may require measurement and verification of carbon content alongside conventional price drivers such as renewable output variability and transmission constraints. That operational reality tends to raise requirements for grid modernization planning so that renewable output can be delivered reliably when it matters for export pricing.
For investors evaluating portfolio resilience under carbon-linked trade conditions, battery energy storage systems can become more valuable as they help manage variability and support firming strategies that improve delivery certainty into constrained networks. Asset managers recalibrating long-term value may therefore place greater emphasis on projects combining renewables with enabling infrastructure—grid reinforcement where needed and storage where it supports dispatchability—alongside robust EPC preparation for interconnection readiness.
Broader implications for developers across CSEE
The interaction between CBAM and the EU ETS is likely to accelerate structural transformation in regional electricity markets by changing how carbon costs shape trade direction, industrial competitiveness and investment strategies. Carbon pricing increasingly influences not just domestic dispatch within EU jurisdictions but also cross-border flow economics when imported electricity enters the EU internal market context. For project sponsors preparing feasibility studies through EPC execution planning—especially those targeting export-linked revenues—the planning focus is shifting toward low-carbon generation portfolios supported by verifiable procurement frameworks.
In parallel, utilities and network operators face a clearer mandate to modernize transmission capacity planning so that renewable growth aligns with deliverability under tighter market constraints. Across Central and South-East Europe’s industrial base—where aluminum smelting, steelmaking, fertilizer production and chemicals depend on stable power inputs—the commercial value of long-term renewable contracting strengthens as carbon exposure becomes embedded in competitiveness calculations tied to EU market access.