The inclusion of electricity in the European Union’s Carbon Border Adjustment Mechanism marks a quiet but profound shift in how power systems at Europe’s periphery are judged, priced, and ultimately integrated. While much of the public CBAM debate has focused on steel, cement, aluminium, and fertilisers, electricity is the only CBAM-covered “product” that is not manufactured, shipped, or stored, but transmitted in real time across interconnected systems. This makes its treatment under CBAM uniquely consequential for Southeast Europe, where power trade has long functioned as both an economic stabiliser and a political bridge to the EU internal market.
For Southeast Europe, CBAM does not merely introduce a new cost. It exposes a structural mismatch between how the region’s power systems were built and how the European energy market is now being reorganised around carbon as a central economic variable. The result is a region that is formally interconnected with the EU, commercially dependent on electricity exports, yet institutionally unprepared for a regime in which carbon intensity directly determines market access.
Electricity as a traded commodity under carbon rules
Electricity occupies a special place in the CBAM framework. Unlike manufactured goods, its carbon content is inseparable from the generation mix of the exporting system at the moment of delivery. A megawatt-hour exported from a lignite-dominated system carries a radically different carbon footprint than the same unit exported from a hydro- or nuclear-based system, even if both flow across the same interconnector into the same EU market.
Under CBAM, this distinction becomes monetised. Electricity imports into the EU from non-EU countries are subject to a carbon charge reflecting their embedded emissions, unless those emissions are already priced domestically in a way recognised by the EU. In practice, this means that electricity exports from Southeast Europe are no longer assessed primarily on price, availability, or system balancing value, but on carbon intensity relative to EU ETS benchmarks.
This is where structural exposure begins. Southeast Europe’s electricity systems were historically designed to maximise domestic energy security and affordability, not to optimise carbon performance in a cross-border market. Large lignite baseload plants, long amortised and politically protected, remain the backbone of several national systems. Their output has traditionally supported export revenues, seasonal balancing, and regional price convergence. Under CBAM, that same output becomes a liability.
Coal dependence as a structural, not transitional, risk
In much of Southeast Europe, coal is not a marginal fuel but a system anchor. Serbia, Bosnia and Herzegovina, North Macedonia, and parts of Montenegro still rely heavily on lignite for baseload generation. These plants provide inertia, grid stability, and predictable volumes, but they also define the carbon intensity of the entire system.
Under CBAM, the carbon content of exported electricity is not diluted by political context or development status. A megawatt-hour produced by lignite carries the same emissions whether it comes from Germany in 2005 or Serbia in 2026. The economic consequence is that Southeast European electricity, when exported into the EU, faces an implicit carbon tariff that can easily exceed the wholesale power price itself during periods of high EU ETS prices.
This is not a short-term problem that disappears with incremental renewables additions. As long as coal remains the marginal or dominant generator during export hours, the system’s average carbon intensity stays high. CBAM therefore turns coal dependence from a domestic policy issue into an external trade penalty.
Crucially, this exposure is asymmetric. EU coal generators face the same carbon price, but they operate inside a market where carbon costs are already internalised, hedged, and embedded in long-term investment decisions. Southeast European utilities, by contrast, face carbon pricing only at the border, without the ability to recycle revenues domestically or use ETS instruments to manage risk.
Market integration without carbon integration
For more than a decade, the EU has encouraged Southeast Europe to integrate its electricity markets through the Energy Community framework. Market coupling, cross-border capacity allocation, and harmonised trading rules were promoted as pathways toward efficiency, competition, and investment. Electricity exports to Hungary, Romania, Croatia, Greece, and Italy became an important revenue source and a symbol of convergence.
CBAM fundamentally changes the economics of this integration. When electricity flows from a non-EU system into the EU internal market, it is no longer treated as just another traded commodity. It becomes a carbon-priced import. The result is a paradox: the more physically and commercially integrated Southeast Europe becomes with the EU power market, the more exposed it is to carbon-based trade penalties unless its climate policy converges at the same pace.
This creates a structural tension. Market coupling transmits EU price signals into Southeast Europe, but CBAM transmits EU climate costs outward. Without domestic carbon pricing, Southeast European exporters bear the full adjustment burden at the border, while EU buyers face little incentive to absorb higher-carbon imports when cleaner alternatives exist within the internal market.
Over time, this dynamic risks hollowing out cross-border power trade from the region, not because interconnections disappear, but because carbon-adjusted price differentials make Southeast European electricity uncompetitive except in extreme scarcity conditions.
The absence of domestic carbon pricing
Perhaps the most decisive source of structural exposure lies not in generation technology, but in policy architecture. Most Southeast European countries do not operate a comprehensive carbon pricing system comparable to the EU ETS. While emissions reporting frameworks exist and environmental taxes are discussed, there is no economy-wide carbon price that utilities can internalise, hedge, or plan around.
Under CBAM rules, the absence of recognised domestic carbon pricing means that the full carbon cost is imposed at the EU border. From an economic perspective, this is the worst possible configuration. Carbon revenues are collected by the EU rather than domestically. Utilities face higher export costs without any compensatory fiscal mechanism at home. Governments lose the ability to recycle carbon revenues into grid upgrades, renewable investment, or social mitigation.
By contrast, if Southeast European countries introduced credible carbon pricing aligned with EU benchmarks, CBAM liabilities on electricity exports could be partially or fully offset. The carbon cost would still exist, but it would be paid domestically, strengthening fiscal capacity and policy control. The failure to implement such systems therefore magnifies CBAM exposure far beyond the level implied by carbon intensity alone.
Revenue erosion and fiscal feedback loops
Electricity exports matter disproportionately for Southeast European utilities because domestic tariffs are often politically constrained. Export revenues cross-subsidise household prices, finance maintenance of ageing fleets, and support national budgets. CBAM directly undermines this model.
As carbon-adjusted export margins shrink, utilities face a choice between absorbing losses, reducing export volumes, or seeking domestic price increases. None of these options is politically or economically painless. Reduced exports weaken balance sheets. Absorbing losses delays investment and increases fiscal dependence. Domestic price increases risk social backlash.
This feedback loop is particularly dangerous because it coincides with the need for massive capital expenditure. Coal plants require refurbishment or replacement. Grids must be reinforced for renewables. Storage and flexibility assets are increasingly essential. CBAM arrives precisely when investment needs peak, but revenue certainty declines.
Why renewables alone are not a silver bullet
It is tempting to frame CBAM exposure as a simple argument for renewables. Lower carbon intensity means lower CBAM costs. In principle, this is correct. In practice, the transition path matters.
Southeast Europe’s renewables growth is uneven and often poorly integrated. Solar and wind additions reduce average emissions but do not necessarily reduce marginal emissions during export hours. If coal plants continue to set the marginal price or provide balancing power, exported electricity may still carry high embedded carbon even in systems with growing renewable capacity.
Moreover, without carbon pricing, renewables investment competes against artificially cheap coal generation domestically. This slows the pace of structural decarbonisation and prolongs CBAM exposure. In this sense, CBAM does not reward renewable capacity per se, but systemic decarbonisation that changes dispatch patterns, not just installed capacity statistics.
Electricity CBAM as an industrial signal
Beyond the power sector itself, electricity CBAM sends a broader signal to industry. Southeast European manufacturers exporting into the EU increasingly face CBAM charges on their products. If their electricity supply is carbon-intensive and increasingly expensive due to border adjustments, their cost base deteriorates from two directions at once.
This links electricity CBAM to industrial competitiveness. Energy-intensive industries cannot decarbonise supply chains if the power system remains structurally exposed. Conversely, without industrial demand for clean electricity, utilities lack anchor customers for investment in low-carbon generation. CBAM therefore reinforces the need for coordinated energy-industrial strategy, something Southeast Europe has historically struggled to implement.
Strategic choices and narrowing time windows
The structural exposure created by CBAM is not inevitable, but the window for painless adjustment is closing. Several strategic paths exist, each with different economic implications.
Introducing domestic carbon pricing aligned with the EU ETS is the most direct way to regain control over carbon costs. It does not eliminate exposure, but it transforms it from an external penalty into a domestic policy instrument. Revenues can be recycled, investment signals clarified, and CBAM liabilities reduced.
Accelerating coal phase-down is unavoidable, but sequencing matters. Abrupt closures without replacement capacity risk supply insecurity and political backlash. Gradual reduction combined with flexibility investments, storage, and cross-border balancing agreements can reduce both carbon intensity and system risk.
Finally, aligning electricity market reform with climate policy is essential. Market coupling without carbon convergence amplifies exposure. Climate alignment without market reform undermines efficiency. CBAM effectively forces both conversations to happen together.
CBAM as a stress test, not a punishment
Electricity under CBAM functions less as a punitive measure and more as a stress test of institutional readiness. Southeast Europe’s exposure is not primarily the result of geography or bad luck, but of delayed policy convergence. Coal-centric systems, absent carbon pricing, and partial market integration were sustainable in a pre-CBAM world. They are structurally fragile in a carbon-priced trade regime.
CBAM does not ask whether Southeast Europe wants to integrate into the EU energy market on climate terms. It assumes that outcome and prices the gap accordingly. The choice facing the region is therefore not whether to accept CBAM, but whether to internalise its logic domestically or continue paying the adjustment cost at the border.
In that sense, electricity CBAM is not the end of Southeast Europe’s export model. It is the end of exporting carbon risk without pricing it.
Elevated by clarion.engineer
