The Eurelectric response to the draft EU Implementing Regulation on carbon price paid in a third country under CBAM should be read in Southeast Europe as a direct warning for regional electricity trade. The document is technical, but its market consequence is simple: once CBAM’s financial phase starts, electricity moving from non-EU SEE markets into the EU will no longer be priced only on power spreads, transmission capacity and balancing risk. It will also be priced on whether the exporting country’s carbon costs, emissions factors and documentation are recognised by the EU.
For SEE, this is not a marginal issue. Serbia, Montenegro, Bosnia and Herzegovina, North Macedonia, Albania and Kosovo sit around EU electricity borders and trade into or through EU markets such as Croatia, Hungary, Romania, Bulgaria, Greece and Italy. These flows are increasingly shaped by hydrology, coal availability, solar output, wind production, interconnector capacity and regional price spreads. CBAM adds a new layer: carbon-price uncertainty.
The first SEE implication is that annual CBAM reference prices are bad for trading liquidity. Eurelectric argues for a monthly CBAM reference price because electricity is traded continuously, not once a year. This matters directly for Serbia, Montenegro and Bosnia and Herzegovina. Traders need to know carbon exposure before they buy cross-border capacity, nominate flows or price forward deliveries. If the final CBAM deduction is only clear much later, non-EU SEE exports will carry a wider risk premium.
The second implication is that SEE countries need carbon-pricing systems designed to be EU-recognisable, not merely domestic. A Serbian, Bosnian or Montenegrin carbon levy that cannot be clearly deducted under CBAM would raise producer costs without reducing EU border exposure. That would be the worst outcome: domestic industry and electricity producers would pay more, while EU importers would still treat their electricity as carbon-risky. Carbon-pricing reform in SEE therefore has to be built around CBAM deduction rules from the start.
The third implication is that default emissions factors may become one of the most important commercial variables in SEE power trade. Countries with coal-heavy electricity systems will face higher CBAM exposure unless they can prove lower actual emissions for specific imports. Serbia, Bosnia and Herzegovina, North Macedonia and Kosovo are most exposed. Montenegro and Albania have a better structural position because of hydro, but even they face volatility in dry years when imports rise or thermal generation becomes more important.
The fourth implication is that CBAM will separate SEE electricity into two price categories: documented low-carbon electricity and undocumented or carbon-intensive electricity. Hydro-backed, renewable-backed or plant-specific low-emission electricity with credible evidence will command better treatment. Coal-heavy or unclear electricity will trade at a discount once EU buyers and traders price the CBAM risk. This directly affects EPCG, EPS, Elektroprivreda BiH, ESM, KOSTT-related flows, regional traders and industrial offtakers.
The fifth implication is that SEE exporters will need plant-level evidence, not only national averages. A Serbian renewable producer, Montenegrin hydro generator or Bosnian low-carbon exporter should be able to prove generation source, metered output, emissions factor and contractual allocation. Without this, EU counterparties may fall back on default factors, which could be commercially punitive. The value of documentation will rise alongside the value of the electricity itself.
The sixth implication is that netting rules matter for the Balkans more than for many other regions. SEE is not only an export source; it is a transit and balancing corridor. Serbia can import at one hour and export at another. Montenegro can swing between hydro exports and import dependence. Bosnia and Albania can shift positions depending on hydrology. Without workable CBAM netting for imports and exports, the EU could overstate the carbon exposure of flows that are actually part of regional balancing rather than final EU consumption.
The seventh implication is that CBAM may weaken the economics of coal-based exports. Serbia, Bosnia and Herzegovina, North Macedonia and Kosovo cannot assume that electricity exports into EU markets will remain attractive under the same logic as before. Carbon adjustment will gradually eat into margins unless these systems decarbonise, introduce recognised carbon pricing or redirect electricity to domestic and non-EU demand. This will also affect the valuation of coal assets, long-term generation planning and the economics of refurbishment.
The eighth implication is that Montenegro’s hydro profile becomes more valuable, but only if documented. EPCG’s hydro fleet can be a CBAM advantage in wet years, especially if electricity exports can be clearly linked to low-emission generation. But hydro advantage is not automatic. Dry-year import exposure, system balancing, cross-border flows and unclear contractual tracing can weaken the claim. Montenegro needs a formal electricity-carbon documentation system around hydro, solar and future wind output.
The ninth implication is that Serbia needs a CBAM electricity strategy tied to EPS, EMS, SEEPEX and industrial offtakers. Serbia’s challenge is larger because the country combines coal-heavy generation, a growing renewable pipeline, industrial export exposure and regional transit importance. A credible Serbian strategy would include official emissions factors, recognised carbon-price methodology, renewable electricity documentation, rules for low-carbon PPAs, and trading guidance for exports into Hungary, Romania, Croatia and Bulgaria.
The tenth implication is that SEE renewable PPAs become more valuable. A renewable PPA will no longer be only a hedge against power prices. It becomes a carbon-evidence instrument. Serbian and Montenegrin industrial exporters selling to the EU will increasingly need documented electricity to support embedded-emissions reporting. That creates a direct commercial bridge between RES developers, industrial buyers, CBAM reporting, bankability and export competitiveness.
The eleventh implication is that regional power exchanges and TSOs need to prepare. SEEPEX, BELEN, CROPEX, HUPX-linked trading routes, IBEX, OPCOM and regional balancing platforms will all be affected by how CBAM risk is priced into flows. TSOs such as EMS, CGES, NOSBiH, MEPSO and OST will need clearer data coordination, especially where cross-border electricity flows are complex. The more transparent the emissions and carbon-price data, the lower the market-risk premium.
The twelfth implication is that banks will start pricing CBAM exposure into power-sector finance. Coal-heavy generators, merchant exporters and industrial offtakers without clean electricity procurement will face higher transition risk. Renewable assets with documented offtake and CBAM-relevant electricity evidence will become more bankable. Storage and hybrid renewable projects can gain additional value because they help shape low-carbon electricity into more usable industrial supply.
The thirteenth implication is that SEE governments should avoid symbolic carbon instruments. A poorly designed carbon fee may satisfy domestic politics but fail under CBAM deduction rules. The right approach is a CBAM-recognisable carbon-price framework with clear publication frequency, official conversion rules, eligible instruments, transparent treatment of free allocation or subsidies, and documentation that EU importers can actually use.
The fourteenth implication is that electricity trade with the EU will become more administrative, but also more strategic. Traders will need to model not only price spreads but also carbon-adjusted margins. A Serbian exporter selling into Hungary, a Montenegrin seller into Italy or a Bosnian exporter into Croatia will need to understand the CBAM-adjusted delivered price. This could reduce opportunistic trading and favour larger, better-documented counterparties.
The fifteenth implication is that SEE’s energy transition becomes an export-market issue. Decarbonising power systems is no longer only about EU accession, climate policy or air quality. It is about preserving market access for electricity and industrial goods. Coal-heavy electricity will weaken both direct power exports and the competitiveness of factories using that electricity. Low-carbon electricity with credible documentation will support both power trading and manufacturing exports.
For SEE, the practical roadmap is clear. Countries need official monthly or at least regularly updated carbon-price and emissions-factor publication. They need plant-level generation evidence for hydro, wind, solar and low-carbon assets. They need recognised rules for renewable electricity claims and industrial PPAs. They need guidance on import-export treatment and netting. They need carbon-pricing laws designed for CBAM deduction, not only domestic revenue collection. They need utilities, TSOs, power exchanges and exporters to produce data that EU counterparties can trust.
The main commercial divide in SEE electricity will no longer be simply between cheap and expensive power. It will be between CBAM-documented electricity and CBAM-uncertain electricity. Serbia, Montenegro and the wider Western Balkans can still trade into the EU power system, but the margin will increasingly belong to the producer, trader or industrial buyer that can prove the carbon position before the transaction is priced.
Elevated by CBAM.Clarion.Engineer
