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, particularly in Serbia and Montenegro. Market participants are increasingly focused on whether an exported megawatt-hour can generate a positive margin once emissions treatment is established.
The European Commission’s official CBAM certificate price for electricity and other covered goods imported during Q3 2026 is €82.32 per tonne of CO₂ equivalent, up 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, the timetable separates the creation of a liability from its eventual cash settlement. Revenue from an electricity transaction can be collected well before certificates are purchased. If carbon provisions are not retained or funded, a trading book that appears profitable can still face a substantial later payment requirement.
Lenders face a related timing issue when assessing receivables, collateral and cash availability alongside conventional trading limits. Financing electricity purchases without accounting for associated carbon liabilities can understate working capital needs required to complete transactions. This affects how financing structures are evaluated against both market risk and compliance-related cash demands.
The CBAM mechanism operates alongside the EU Emissions Trading System, which already prices emissions from covered power generation inside the EU. When fossil-fuel generation sets wholesale electricity prices, carbon costs can be reflected in market pricing. Pass-through depends on factors including generation mix, fuel prices and which plant is marginal in each delivery period.
This creates uneven commercial outcomes across Southeast Europe. Carbon can support wholesale prices available in an EU destination while CBAM reduces margins on electricity imported from third countries. Exporters therefore need to calculate both effects rather than treating higher EU destination prices as an unqualified benefit.
CBAM price levels and margin sensitivity for cross-border trades
An illustrative transaction highlights how quickly exchange-price spreads can narrow once emissions calculations are included. The example 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 emissions factor of 0.40 tCO₂/MWh generates a gross carbon cost of €32.93/MWh, leaving €7.07/MWh after carbon charges. At 0.80 tCO₂/MWh, the carbon cost rises to €65.86/MWh and turns the transaction into a loss of €25.86/MWh. These figures are sensitivity calculations rather than national default values or final compliance assessments.
The sensitivity assumes no eligible deduction for carbon effectively paid in the country of origin. It is intended to show that a large exchange-price spread can disappear when emissions factors are applied at CBAM certificate prices. Under the same assumptions, the €40/MWh margin supports only about 0.486 tCO₂/MWh at a carbon price of €82.32/tCO₂.
Higher capacity charges or balancing costs reduce that tolerance further by lowering available margin headroom. The analysis also points to risks for strategies based on annual-average spreads. A producer may expect favourable average outcomes over a year while exporting most output during hours when destination prices are weak.
Cross-border scheduling data and Serbia’s partial carbon-price convergence
Early market evidence indicates weaker cross-border activity already underway. The Energy Community Secretariat reports that 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. First-half exchanges were around 19% lower.
The reported figures represent gross flows in both directions rather than exports alone. They should not be interpreted as proof that CBAM caused the entire decline because hydrology, generation availability and neighbouring EU prices also changed during the period under review. Reduced trading activity remains commercially relevant if it persists despite opportunities for price convergence.
The distinction between physical flows and commercial schedules is also highlighted as important for market participants. Electricity can move through interconnected networks without each movement corresponding to a separately contracted export with profitability implications. Trading strategies therefore need to follow scheduled transactions, customs treatment and contractual obligations rather than relying on physical flow data alone.
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 differs from applying the EU carbon price to every tonne emitted.
The presence of a Serbian carbon tax does not establish equivalent carbon costs across borders for CBAM purposes. Traders should not automatically subtract the headline €4 rate from the EU certificate price for each tonne attributed to an export because any deduction requires evidence reflecting eligible carbon costs effectively paid. For Serbian utilities and independent suppliers, this creates portfolio choices between domestic sales, regional non-EU sales and EU exports.
Those alternatives need comparison after delivery and carbon costs while including domestic supply obligations and operational constraints tied to each option. For coal-intensive producers, higher EU wholesale prices may still justify some exports but decisions become more sensitive to applicable emissions treatment and transmission capacity costs. Export revenue cannot be evaluated reliably using destination prices alone once these factors are included.
Montenegro’s emissions-credit framework and documentation requirements
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. That historical floor does not establish that every current exported megawatt-hour carries a deductible carbon payment at that rate.
In July 2026, Montenegro published a proposed roadmap for implementing the EU ETS upon accession. For Montenegro’s electricity business, links with Italy make destination pricing commercially significant while interconnector access does not determine origin or emissions treatment of delivered electricity by itself.
A separate assessment is described as needing hydro availability, thermal generation, replacement purchases and contractual allocation considered independently. During periods of weak hydrology, meeting delivery commitments can become more costly even when an agreement was associated with renewable production at inception.
The same logic applies when electricity is routed through Montenegro from another market because passing through a lower-emission system does not by itself change production origin of traded power. Routing, ownership and generation origin need documentation independently for commercial purposes tied to CBAM treatment.
The European Commission’s CBAM questions and answers distinguish electricity released for free circulation in the EU from qualifying transit movements. They also state that if third-country electricity passes through another third country before EU consumption, default treatment follows the production country rather than routing location alone.
Renewable eligibility evidence, financing risk cases and contract allocation
Renewable producers face eligibility requirements despite having more favourable physical emissions profiles compared with fossil generation scenarios discussed elsewhere in the guidance context. Current electricity guidance requires a qualifying physical PPA or direct connection or evidence showing no physical congestion along the route used for attribution purposes.
The guidance also specifies emissions below 550 gCO₂/kWh, nominated capacity matched to production over periods no longer than one hour, and accredited verification supported by monthly evidence. These requirements mean export structure becomes part of renewable project investment cases because technical performance alone does not guarantee achievement of assumed export pricing if contracts, nominations or evidence do not support intended emissions treatment.
The Energy Community Secretariat has identified practical difficulties for renewable producers seeking to demonstrate actual emissions through this process. Its July assessment describes additional compliance costs and uncertainty affecting operations and projects connected to demonstration requirements.
This risk is described as needing inclusion in financial models before loans are approved by lenders assessing at least two revenue cases: one where intended treatment is supported by acceptable evidence and another where that treatment is unavailable due to evidence constraints or other issues identified within compliance processes described earlier.
A renewable certificate can support origin claims and corporate procurement requirements but should not replace complete CBAM delivery evidence needed for compliance under guidance conditions described above. Annual matching also creates operational challenges because wind and solar output do not necessarily coincide with contracted export hours under shaped products or fixed-volume arrangements discussed later in this context.
For shaped products supplied by traders, replacement electricity costs for missing renewable production must be visible within commercial arrangements because replacement may preserve delivery while creating different emissions exposure than originally attributed output would have implied under intended treatment assumptions described earlier.
PPA structures, storage economics inputs and hourly modelling considerations
This issue is particularly relevant where developers offer fixed-volume PPAs with delivery profiles attractive to buyers but transferring production shaping risk to parties responsible for output shaping across contracted hours. Those parties require adequate liquidity and clear methods for allocating eligible generation used for CBAM-related attribution evidence requirements described earlier.
A pay-as-produced arrangement reduces some replacement obligations while leaving buyers exposed to volume and timing outcomes linked to actual production patterns rather than fixed schedules alone. The most suitable structure depends on producer operating profile, buyer flexibility and capacity available on intended routes used for attribution purposes under guidance conditions referenced earlier.
The financing of Gvozd illustrates capital committed toward Montenegro’s renewable transition based on European Bank for Reconstruction and Development descriptions of up to €82 million financing for acquisition, development, construction and commissioning of a 54.6 MW wind project. The project involves EPCG and Green Gvozd; it does not establish any specific CBAM export arrangement but it is used as an example showing why delivery economics matter for large energy investments under these compliance conditions.
Across the region, storage can improve delivery economics by reducing imbalance, shifting output into more valuable hours and limiting forced sales tied to operational constraints described elsewhere in this context. Its value should be calculated from operating conditions including charging costs, discharge revenues, losses, degradation rates and available balancing income used within balancing markets exposure considerations referenced earlier.
A storage investment does not erase emissions associated with its electricity source because charging inputs carry their own emission profile implications even if storage supports low-emission export products under contractual structures described earlier; therefore storage needs its own metering and allocation assessment tied to eligibility evidence requirements mentioned above.
Negative-price periods, contract cost allocation and hedging limits
Negative-price hours add another complication because higher carbon prices do not guarantee higher capture prices when wind or solar output is abundant during those periods of oversupply reflected through market pricing dynamics referenced here without additional figures beyond those already stated earlier in this context.
A project may benefit from carbon-supported evening prices while selling much of its production during low-price daytime hours when negative or low clearing prices occur relative to those evening periods referenced here as part of operational risk considerations discussed earlier without additional quantitative detail beyond those general statements.
Banks therefore use hourly revenue modelling rather than relying on baseload averages when assessing projects exposed to these timing effects described above; analysis should examine exportable production volumes tied to capacity availability, curtailment levels, imbalance exposure and any constraints on buyer acceptance of output across contracted hours relevant to CBAM attribution evidence needs mentioned earlier.
Contracts also need clear allocation of CBAM costs separating legal responsibility of an authorised declarant from commercial agreements determining who ultimately bears expenses linked to declarations required under CBAM processes described earlier; sellers may agree reimbursement without becoming responsible for making EU declarations themselves under those arrangements described here without additional procedural detail beyond cost allocation separation principles stated above.
Certain contract provisions are described as useful including evidence deadlines, rejected data handling processes, replacement purchases rules tied to missing volumes or timing mismatches described earlier when shaped products are supplied or fixed-volume PPAs fail their expected export hours assumptions due to actual production patterns against nominations used for eligibility evidence requirements mentioned above.
The provisions would also address carbon-price changes affecting later certificate cost settlement timing referenced earlier as well as later corrections; they should include workable dispute processes because measurable carbon liabilities depend on correct evidence submission outcomes under guidance conditions referenced earlier within this context.