As the energy market evolves, January 2023 has highlighted the emerging significance of the Carbon Border Adjustment Mechanism (CBAM) in shaping electricity imports in Southeast Europe (SEE). Beginning in 2026, electricity entering the European Union will be subject to stringent emissions reporting requirements. This regulatory shift is poised to create a new layer of complexity and cost for traders and industrial buyers, particularly those engaged with non-EU exporters.
During January, Bulgaria emerged as a key player by exporting over 400 GWh of electricity to Romania, primarily generated from nuclear and hydro sources. These exports are characterized by low emissions, which could minimize CBAM exposure if appropriately certified. Conversely, electricity flows from non-EU countries in the Western Balkans may face significant emissions penalties during peak demand periods. This is due to a potential classification based on average system emissions rather than the actual marginal generation source.
In particular, Serbia and Bosnia and Herzegovina exported electricity to EU markets even when their domestic generation relied heavily on fossil fuels like coal and gas. Without precise emissions tracking or alignment with Guarantees of Origin, these exports risk being assessed under CBAM using default emission factors that could reach between 400 and 700 kg CO₂/MWh. Given current carbon pricing levels under the EU Emissions Trading System (ETS), this could lead to additional costs ranging from €30 to €70 per MWh on top of existing wholesale prices.
Montenegro’s situation further complicates matters. Although its energy system is predominantly hydro-based, without full integration into EU-recognized certification frameworks, its exports might be classified as carbon-intensive. The price volatility observed on the Montenegrin Power Exchange (MEPX) has not yet fully reflected these risks, but market behaviors indicate that traders are becoming increasingly aware.
For industrial consumers, these developments present an asymmetric risk profile. Purchasing electricity during peak hours—when prices can soar above €200/MWh—may inadvertently involve hidden carbon costs not directly factored into spot prices. This creates a scenario where short-term procurement decisions could translate into long-term compliance liabilities as CBAM regulations take effect.
Traders will also need to navigate a new basis risk introduced by CBAM. A trade that appears profitable based on price differentials could turn unprofitable once emissions costs are accounted for, particularly for those sourcing from mixed or fossil-heavy systems without certified low-carbon attributes. This cumulative risk may not be immediately apparent but could have significant financial implications over time.
The dynamics observed in January suggest that EU-integrated systems with nuclear and hydro resources will maintain a competitive edge moving forward. Countries like Bulgaria and Romania can offer both energy supply and compliance certainty. In contrast, Western Balkan nations may find themselves facing higher carbon premiums despite exporting surplus power. This shift is likely to favor long-term contracts that include explicit emissions attribution while discouraging spot-market trading strategies.
The overarching market implication is clear: CBAM will not necessarily reduce price volatility but will instead reprice it based on carbon risk factors. High-price hours are expected to coincide with high-carbon-risk periods unless backed by certified low-carbon sources. January’s trading patterns provide an early indication of this future landscape where proving the origin of electricity will become essential for market participants.
