Electricity producers, traders and banks in Southeast Europe are facing a widening gap between prices available on neighbouring EU exchanges and the revenue they can retain after carbon costs, transmission charges and delivery risks. The issue is affecting investment decisions for coal generation, renewable projects and cross-border power purchase agreements, with particular attention on Serbia and Montenegro.
The key commercial question is whether an exported megawatt-hour can generate a positive margin once the emissions treatment for that delivery is established. Higher destination prices in markets such as Hungary or Italy can improve revenue, but the transaction also depends on transmission capacity, balancing exposure and a defensible calculation of border carbon liability.
CBAM certificate pricing timeline and interaction with ETS
The European Commission’s official CBAM certificate price for electricity and other covered goods imported during the third quarter of 2026 is €82.32 per tonne of CO₂ equivalent. It rises from €75.28 in Q2 and €75.36 in Q1. The quarterly price applies to the relevant import period and is not the same as a daily EU allowance quotation.
Certificate purchases begin in February 2027, while the financial exposure relates to imports made during 2026. For traders, this separation means liabilities can be created before certificates are bought, so carbon provisions need to be retained or funded to avoid later payment requirements.
For lenders, the timing also affects how receivables, collateral and cash availability are assessed alongside conventional trading limits. Financing electricity purchases without accounting for associated carbon liability can understate working capital needs required to complete transactions.
The CBAM mechanism operates alongside the EU Emissions Trading System, which already prices emissions from covered power generation within the EU. Where fossil-fuel generation sets wholesale electricity prices, carbon costs can be reflected across market pricing, but pass-through depends on generation mix, fuel prices and which plant is marginal in each delivery period.
How carbon liabilities change export economics
A higher EU destination price does not automatically translate into higher exporter margins because carbon effects can work in opposite directions across SEE. Carbon can support wholesale prices available at an EU destination, while CBAM reduces margins on electricity imported from a third country. Exporters therefore need to calculate both effects rather than treating a wider exchange-price spread as unqualified benefit.
An illustrative transaction assumes electricity is bought in a non-EU market at €80/MWh, sold in the EU at €130/MWh, and incurs €10/MWh in capacity, balancing and other delivery costs. Before CBAM, this produces a €40/MWh margin.
At the Q3 certificate price, an applicable emissions factor of 0.40 tCO₂/MWh generates a gross carbon cost of €32.93/MWh, leaving €7.07/MWh. At 0.80 tCO₂/MWh, the carbon cost becomes €65.86/MWh, turning the transaction into a loss of €25.86/MWh.
The figures are sensitivity calculations rather than national default values or final compliance assessments. They assume no eligible deduction for carbon effectively paid in the country of origin, showing how a large exchange-price spread can disappear once emissions calculations are included.
Sensitivity break-even and trading schedule risk
The break-even condition under those assumptions indicates that the €40/MWh margin can support an emissions factor of only about 0.486 tCO₂/MWh at a carbon price of €82.32/tCO₂. Higher capacity charges or balancing costs reduce that tolerance further.
The calculation also highlights risk for annual-average trading strategies. A producer may expect a favourable average spread over a year but generate most exportable output during hours when destination prices are weak, requiring assessment against revenue from actual transactions rather than regional headline prices.
Early market evidence points to weaker cross-border activity already affecting trading volumes. The Energy Community Secretariat reports gross scheduled electricity exchanges between the Western Balkans and the EU fell from 8,828 GWh to 7,494 GWh in Q2 2026, about 15% year on year.
The first-half exchanges were around 19% lower as well. These figures represent gross flows in both directions rather than exports alone, and they should not be interpreted as proof that CBAM caused the entire decline because hydrology, generation availability and neighbouring EU prices also changed.
Physical flows versus commercial schedules
A distinction between physical movements and commercial schedules is increasingly important for market participants. Electricity can move through interconnected networks without every movement corresponding to a profitable separately contracted export.
A trading strategy therefore needs to follow scheduled transactions, customs treatment and contractual obligations rather than infer profitability from physical flow data alone. This approach becomes relevant when evaluating whether deliveries meet required emissions treatment rules.
Serbia’s domestic tax versus EU border attribution
Serbia illustrates partial carbon-price convergence because its national framework applies from 1 January 2026. A domestic emissions tax recorded by the World Bank is set at €4/tCO₂e on emissions above technology-based reference levels in covered sectors including electricity generation.
This structure differs from applying the EU carbon price to every tonne emitted under CBAM logic. As a result, the existence of a Serbian carbon tax does not establish equivalent carbon costs across borders.
A trader should not automatically subtract the headline €4 rate from the EU certificate price for every tonne attributed to an export unless eligible deductions reflect carbon costs effectively paid and supported by required evidence.
For Serbian utilities and independent suppliers, portfolio decisions depend on comparing domestic sales, regional non-EU sales and EU exports after delivery and carbon costs are accounted for alongside domestic supply obligations and operational constraints.
Montenegro’s allowance framework and route-specific eligibility
Montenegro has a different starting point due to its domestic emissions-credit framework. A published auction notice for 2024 allowances specified a minimum bid of €24/tCO₂, while that historical floor does not establish that every current exported megawatt-hour carries a deductible payment at that rate.
In July 2026, Montenegro published a proposed roadmap for implementing the EU ETS upon accession. For Montenegro’s electricity business linked to Italy, access to the interconnector provides export value potential but does not determine origin or emissions treatment of delivered electricity by itself.
A prudent assessment requires examining hydro availability, thermal generation, replacement purchases and contractual allocation separately because weak hydrology can increase delivery commitment costs even when original agreements were associated with renewable production.
The same logic applies when electricity is routed through Montenegro from another market: passing through a lower-emission system does not automatically change production origin of traded power. Routing, ownership and generation origin need documentation independently for CBAM purposes.
CBAM guidance for transit movements and renewable eligibility evidence
The Commission’s CBAM questions and answers distinguish electricity released for free circulation in the EU from qualifying transit movements. It also states that where third-country electricity passes through another third country before EU consumption, default treatment follows the production country.
Commercial rerouting therefore requires careful customs and origin assessment rather than relying on transit paths alone. Renewable producers may have more favourable physical emissions profiles but still need eligibility established for actual values under current electricity guidance.
The guidance requires a qualifying physical PPA or direct connection or evidence of no physical congestion along the route, emissions below 550 gCO₂/kWh, nominated capacity matched to production over periods no longer than one hour, and accredited verification supported by monthly evidence.
Lender modelling: intended versus downside CBAM treatment cases
The Energy Community Secretariat has identified practical difficulties for renewable producers seeking to demonstrate actual emissions. Its July assessment describes additional compliance costs and uncertainty affecting operations and projects.
The risk needs to be reflected in financial models before loans are approved by assessing at least two revenue cases: one where intended treatment is supported by acceptable evidence, and another where that treatment is unavailable. Differences can affect debt service requirements, distribution capacity needs and equity amounts.
A renewable certificate can support origin claims and corporate procurement requirements but should not replace complete CBAM delivery evidence because annual matching creates operational issues when wind or solar output does not align with contracted export hours.
PPA structures, replacement power exposure and storage economics
For shaped products supplied by traders, replacement costs for missing renewable production must be visible since replacement electricity may preserve commercial delivery while creating different emissions exposure. Contracts need to specify who funds replacement exposure and how it is reconciled with delivery obligations.
This matters for fixed-volume PPAs where fixed delivery profiles transfer production risk and replacement-power risk to parties responsible for shaping output. Those parties need adequate liquidity and clear methods for allocating eligible generation under CBAM requirements.
A pay-as-produced arrangement reduces some replacement obligations but leaves buyers exposed to volume and timing differences; contract suitability depends on producer operating profile, buyer flexibility and available capacity on intended routes.
Gvozd wind financing scale in Montenegro’s transition context
Financing of Gvozd illustrates capital already committed to Montenegro’s renewable transition. The European Bank for Reconstruction and Development describes financing of up to €82 million for acquisition, development, construction and commissioning of the 54.6 MW wind project, involving EPCG and Green Gvozd.
The example does not establish any specific CBAM export arrangement; it reflects why delivery economics matter for sizeable energy investments where eligibility evidence affects realised returns after carbon costs.
Batteries do not remove source emissions; negative-price hours add complexity
Storage can improve regional economics by reducing imbalance, shifting output into more valuable hours and limiting forced sales based on operating conditions including charging costs, discharge revenues, losses, degradation and available balancing income.
