From 1 January 2026, electricity imported into the EU from non-EU neighbours entered the CBAM charging phase. EU importers now need authorised declarant status, must declare embedded emissions and surrender CBAM certificates priced off the EU ETS allowance price—calculated as a quarterly average in 2026 and moving to a weekly average from 2027. For electricity, there is no free-allocation adjustment, which makes the mechanism much more direct than in some industrial sectors. Any proven carbon price already paid in the exporting country can be deducted, but only if it is real, documented and recognised under the rules.
That changes the economics of Western Balkan power exports to the EU immediately. The legal obligation sits with the EU importer, but the commercial burden does not stay there. In practice, traders and counterparties reprice the cost back through lower bid prices for imported electricity, tighter spreads, shorter tenors and more selective sourcing. The Energy Community has been explicit that CBAM will affect arbitrage options, the amount and pattern of commercial exchanges, and the profitability of generation assets across the region and in neighbouring EU member states.
The scale is not marginal. Based on 2024 trade and system data, the Energy Community’s CBAM Readiness Tracker estimates that the annual CBAM exposure of EU electricity importers buying from the region could reach about €1.17bn. The country breakdown is especially revealing: Serbia €612.5m, North Macedonia about €200m, Montenegro about €190m, Bosnia and Herzegovina about €158m, Moldova about €6m, while Albania is assessed at zero CBAM-related cost because its electricity mix is overwhelmingly renewable. The estimated average CBAM cost per megawatt-hour is around €66.71/MWh for Serbia, €73.37/MWh for Bosnia and Herzegovina, €62.45/MWh for Montenegro, €59.71/MWh for North Macedonia and €33.14/MWh for Moldova.
Those numbers matter because they are large enough to wipe out a substantial part of the historical export margin from coal-heavy systems in normal market conditions. In a year when regional day-ahead prices are around €80–120/MWh, an added carbon border cost of €60–70/MWh is not a surcharge at the edges; it is a structural repricing of the product. It effectively turns part of the region’s legacy baseload export stack into a marginal or uneconomic flow for EU buyers unless the hour is extremely tight, the underlying supply is unusually cheap, or the exporter can demonstrate materially lower embedded emissions. This cost logic follows directly from the Commission’s certificate-pricing methodology and the Energy Community’s estimated per-MWh exposure.
This is why the trade pattern is likely to change before the physical generation mix changes. The first market response is not the disappearance of all flows from the Western Balkans into the EU. It is segmentation. Coal-linked baseload becomes harder to place. Low-carbon hours become more valuable. Hydro-rich, renewable-rich and mixed portfolios with lower emission intensity gain relative competitiveness. That is also why Albania is in a radically different position from coal-dependent exporters: under the tracker’s assessment, its exports are not carrying the same CBAM burden.
For traders, the practical consequence is a shift from simple regional arbitrage to carbon-adjusted arbitrage. The old model—buying on the Western Balkans side and selling into the EU when nominal spreads opened—now needs a carbon overlay embedded in every position. Import desks need emissions data, registry compliance, contractual protections and a view on whether the origin mix is actually bankable under CBAM. The European Commission’s implementation architecture is already live, with customs validation and authorisation checks integrated into border procedures, which means this is no longer a theoretical 2026 issue but an operational one.
That operational shift is also changing which trades are worth doing. Shorter-duration, hour-selective and flexibility-driven trades become more attractive than broad baseload structures when the carbon cost can swing effective import economics so sharply. The early regional market commentary from ADEX points in the same direction: more intraday activity, more algorithmic trading and a growing role for renewables in the intraday segment, while CBAM’s first local impacts are being seen in weaker liquidity on some power exchanges, a wider gap versus EU exchange prices and greater caution toward new green investments.
The regional exchange architecture is reinforcing that shift. ADEX says its overall traded volume rose from 49 TWh in 2023 to 66 TWh in 2025, with much of the growth driven by intraday rather than day-ahead activity. SEEPEX, meanwhile, is introducing negative prices from May 2026, cutting the day-ahead floor to -€500/MWh and the intraday floor to -€9,999/MWh. That is important because it pushes the Western Balkans further into the same market logic now visible across the EU: once solar and weather volatility deepen, the value migrates away from undifferentiated megawatt-hours and toward timing, balancing, storage, hydro flexibility and trading sophistication.
The result is that CBAM and market modernisation are landing at the same moment. On one side, carbon-heavy exports into the EU are being repriced upward. On the other, local exchanges are becoming more granular and more volatile, with intraday and negative-price capability increasing the premium on fast optimisation. That combination changes trader behaviour. Portfolios are likely to become more defensive on forward exports into the EU, more selective by hour, more reliant on intraday re-optimisation and more focused on origin-screened low-carbon volumes. This is partly a direct reading of the policy and market changes, and partly an inference from the way carbon cost and short-term price optionality interact.
There is another effect that matters for the region’s internal price formation. If EU off-take becomes harder for carbon-heavy generators, some electricity that would previously have cleared westward may remain inside the Western Balkans more often. In the short run, that can soften local prices in some hours and pressure domestic generators’ realised margins, especially if hydrology is good and renewable output rises. But this does not automatically mean cheaper systems overall. It can also mean sharper volatility: lower prices in oversupplied hours, higher prices when flexibility is scarce, and a bigger premium on reserve, balancing and hydro assets. The Energy Community itself warns that CBAM will affect commercial exchange patterns and neighbouring EU markets, not just exporting countries.
The timing on exemptions is crucial. The Energy Community says no contracting party currently qualifies for a CBAM exemption for electricity, even though Serbia, Moldova, North Macedonia and Montenegro are approaching a “point of no return” on the regulatory path toward EU market coupling. The mechanism does contain a route to a time-limited exemption for electricity, but it is conditional on market coupling, adoption of key EU electricity, renewables, environment and competition rules, a climate-neutrality roadmap, and meaningful progress on carbon pricing. Market coupling with the EU is now widely discussed as a 2028 to early-2029 event rather than something imminent in 2026 or 2027.
That timing means the market has to assume at least a multi-year period in which CBAM remains a real cross-border cost for Western Balkan electricity exports into the EU. This is especially significant for investment decisions. If developers cannot be confident that low-carbon generation will obtain either a credible exemption path or tradable value recognition in cross-border markets before 2028–2029, some projects may face slower final investment decisions even though, paradoxically, the long-run answer to CBAM is more renewables and more market integration. ADEX has already flagged increased caution toward new green investments as one of the first visible market effects.
There is also a methodological and system-operations issue that should not be ignored. ENTSO-E supports CBAM’s objective but has warned that the current framework still creates legal and methodological uncertainty for electricity, including how to compute embedded CO2 intensity and how to avoid imposing disproportionate burdens on TSOs for regulated system-stability actions such as reserve sharing, redispatch and countertrading. That matters for traders because uncertainty around what exactly is in scope tends to widen risk premia and reduce willingness to hold long-duration positions.
The most likely market trend through 2026–2027 is therefore not a collapse of all EU imports from the Western Balkans, but a strong reshaping of the flow profile. Carbon-heavy baseload exports should lose share. Weather-driven hydro and lower-carbon hours should retain access. Intraday trading should continue to grow faster than day-ahead as portfolios try to optimise around emissions-adjusted economics and renewable volatility. Exchange liquidity in some local markets may remain under pressure until participants get more comfortable with the new carbon cost architecture, but the more sophisticated hubs and the most connected exchanges should gain relative importance.
By 2028–2030, the market splits into two plausible paths. In the first, coupling progresses, domestic carbon-pricing frameworks deepen and renewable capacity continues to expand; in that case, a growing share of Western Balkan electricity can re-enter EU trade on a more competitive carbon basis, and cross-border trade shifts from coal arbitrage to flexibility, hydro, storage and renewable balancing value. In the second, market coupling slips, carbon pricing stays partial and coal-heavy systems remain dominant; in that case, EU imports from the region increasingly become occasional scarcity trades rather than a stable export channel, and the region’s price convergence with the EU slows materially. The Energy Community’s own tracker shows the reform vector moving in the right direction, but the calendar now matters almost as much as the direction.
The bigger conclusion is that CBAM has turned electricity from the Western Balkans into a screened product rather than a generic product. The EU will still import from the region, but not on the same basis as before. The relevant variables are no longer just border prices, transmission capacity and hydrology. They now include embedded emissions, certificate cost, proof of carbon paid, compliance readiness and the likelihood of eventual market coupling. That is why trader behaviour is changing first, even before generation fleets fully change. And that is why the next two years will be less about raw export volume and more about which parts of the Western Balkans’ power stack remain commercially credible once carbon is fully priced at the border.
Elevated by cbam.engineer
