Analysis developed by Virtu.Energy
Electricity producers, traders and banks in Southeast Europe face a growing gap between the price available on neighbouring EU exchanges and the revenue they can retain after carbon costs, transmission charges and delivery risks. That gap is changing the investment case for coal generation, renewable projects and cross-border power purchase agreements, particularly in Serbia and Montenegro.
The central commercial question is increasingly whether an exported megawatt-hour can earn a positive margin after its emissions treatment has been established. A higher price in Hungary or Italy provides an opportunity, but the transaction also needs sufficient transmission capacity, manageable balancing exposure and a defensible calculation of its border carbon liability.
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, up from €75.28 in Q2 and €75.36 in Q1. The quarterly price applies to the relevant import period; it should not be confused with a daily EU allowance quotation. Certificate purchases begin in February 2027, although the financial exposure relates to imports made during 2026.
For traders, that timetable separates the creation of a liability from its eventual cash settlement. Revenue from an electricity transaction can be collected long before certificates are purchased. Unless the carbon provision is retained or adequately funded, a profitable-looking trading book can leave a substantial later payment requirement.
For lenders, the same timing creates a reason to examine receivables, collateral and cash availability alongside conventional trading limits. Financing the purchase of electricity without accounting for its associated carbon liability can understate the working capital needed to complete the transaction.
The mechanism operates alongside the EU Emissions Trading System, which already prices emissions from covered power generation inside the EU. When a fossil-fuel generator sets the wholesale electricity price, its carbon cost can be reflected in the price paid across the market. However, pass-through depends on the generation mix, fuel prices and the marginal plant in each delivery period.
This produces an uneven commercial relationship across SEE. Carbon can support the wholesale price available in an EU destination while CBAM reduces the margin on electricity imported from a third country. The exporter therefore needs to calculate both effects rather than treating a higher EU price as an unqualified benefit.
A simple illustrative transaction shows the scale of the difference. Assume electricity is purchased 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, the transaction 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 reaches €65.86/MWh, turning the transaction into a loss of €25.86/MWh.
These 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. Their purpose is to show that a substantial exchange-price spread can disappear once the emissions calculation is included.
The break-even condition follows directly. Under those assumptions, 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 exposes a risk in annual-average trading strategies. A producer may expect a favourable average spread over a year, yet generate most of its exportable output during hours when the destination price is weak. Carbon costs must be assessed against the revenue of the actual transaction, rather than a regional headline price.
Early market evidence suggests that cross-border activity has already weakened. 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, approximately 15% year on year. First-half exchanges were around 19% lower. These are gross flows in both directions, rather than a measure of exports alone.
The figures should not be interpreted as proof that CBAM caused the entire decline. Hydrology, generation availability and neighbouring EU prices also changed. Nevertheless, reduced trading activity creates a commercial concern when it persists despite opportunities for price convergence.
For market participants, the distinction between physical flows and commercial schedules becomes increasingly useful. Electricity can move through interconnected networks without every movement representing a profitable, separately contracted export. A trading strategy therefore needs to follow the scheduled transaction, customs treatment and contractual obligations rather than infer profitability from physical flow data alone.
Serbia illustrates the challenge of partial carbon-price convergence. Its national framework applies from 1 January 2026, with a domestic emissions tax recorded by the World Bank at €4/tCO₂e on emissions above technology-based reference levels in covered sectors, including electricity generation. That structure differs from applying the EU carbon price to every tonne emitted.
The commercial implication is that the existence of a Serbian carbon tax does not establish equivalent carbon costs across the border. Nor should a trader automatically subtract the headline €4 rate from the EU certificate price for every tonne attributed to an export. Any deduction needs to reflect the eligible carbon cost effectively paid and supported by the required evidence.
For Serbian utilities and independent suppliers, this creates a portfolio question. Domestic sales, regional non-EU sales and EU exports may offer different margins for the same generation portfolio. Those alternatives should be compared after delivery and carbon costs, with domestic supply obligations and operational constraints included.
For a coal-intensive producer, a high EU wholesale price may still justify some exports. But the decision becomes more sensitive to the applicable emissions treatment and the cost of transmission capacity. Export revenue can no longer be evaluated reliably through the destination price alone.
Montenegro has a different starting point because it already has a domestic emissions-credit framework. A published auction notice for 2024 allowances specified a minimum bid of €24/tCO₂. That historical floor is not evidence that every current exported megawatt-hour carries a deductible carbon payment at that rate. In July 2026, the government also published a proposed roadmap for implementing the EU ETS upon accession.
For Montenegro’s electricity business, the link with Italy makes the distinction commercially significant. A higher Italian price can provide export value, but access to the interconnector does not establish the origin or emissions treatment of the delivered electricity.
A prudent assessment would examine hydro availability, thermal generation, replacement purchases and contractual allocation separately. During periods of weak hydrology, the cost of meeting a delivery commitment can rise even when the original agreement was associated with renewable production.
The same logic applies to electricity routed through Montenegro from another market. Passing through a lower-emission electricity system does not, by itself, change the production origin of the traded power. Routing, ownership and generation origin need to be documented independently.
The Commission’s CBAM questions and answers distinguish electricity released for free circulation in the EU from qualifying transit movements. They also state that where third-country electricity passes through another third country before EU consumption, the relevant default treatment follows the production country. Commercial rerouting therefore requires careful customs and origin assessment.
Renewable producers face a more favourable physical emissions profile, but they still need to establish eligibility for actual values. The current electricity guidance requires a qualifying physical PPA, 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.
That makes the export structure part of the renewable project’s investment case. A wind farm can perform technically as expected while failing to achieve its assumed export price if the contracts, nominations and evidence do not support the intended emissions treatment.
The Energy Community Secretariat has explicitly identified practical difficulties for renewable producers and developers seeking to demonstrate actual emissions. Its July assessment describes additional compliance costs and uncertainty affecting operations and projects.
The resulting risk belongs in the financial model before a loan is approved. A lender should assess at least two revenue cases: the intended treatment supported by acceptable evidence, and a downside case in which that treatment is unavailable. The difference can affect debt service, distribution capacity and the amount of equity needed.
A renewable certificate can support origin claims and corporate procurement requirements, but it should not be valued as a substitute for the complete CBAM delivery evidence. Annual matching also leaves an operational problem: wind and solar generation do not necessarily coincide with contracted export hours.
For a trader providing a shaped product, the cost of replacing missing renewable production must be visible. Replacement electricity may preserve the commercial delivery while creating a different emissions exposure. The contract needs to identify who funds that exposure and how it is reconciled.
This is particularly relevant for developers offering fixed-volume PPAs. A fixed delivery profile may be attractive to the buyer, but it transfers production and replacement-power risk to the party responsible for shaping the output. That party needs adequate liquidity and a clear method for allocating eligible generation.
A pay-as-produced arrangement reduces some replacement obligations but leaves the buyer exposed to volume and timing. The most suitable structure depends on the producer’s operating profile, the buyer’s flexibility and the capacity available on the intended route.
The financing of Gvozd illustrates the scale of capital already committed to Montenegro’s renewable transition. The European Bank for Reconstruction and Development describes financing of up to €82 million for the acquisition, development, construction and commissioning of the 54.6 MW wind project involving EPCG and Green Gvozd. The example does not establish a particular CBAM export arrangement; it shows why delivery economics matter for sizeable energy investments.
Across the region, storage can improve that economics by reducing imbalance, shifting output into more valuable hours and limiting forced sales. But its value should be calculated from operating conditions: charging costs, discharge revenues, losses, degradation and available balancing income.
Charging a battery does not erase the emissions associated with its electricity source. A storage investment intended to support a low-emission export product therefore needs its own metering and allocation assessment. Commercial flexibility and emissions eligibility are related investment questions, but they require separate evidence.
Negative-price hours create another complication. A higher carbon price does not guarantee higher renewable capture prices when wind and solar output is abundant. A project may benefit from carbon-supported evening prices while selling much of its production during low-price daytime hours.
For banks, this makes hourly revenue modelling more useful than relying on a baseload average. The analysis should examine exportable production, capacity availability, curtailment, imbalance and any constraints on the buyer’s ability to accept output.
Contracts also need a clear allocation of CBAM costs. The authorised declarant’s legal responsibility should be distinguished from the commercial agreement determining who ultimately bears the expense. A seller can agree to reimburse costs without becoming the entity responsible for the EU declaration.
Useful provisions would address evidence deadlines, rejected data, replacement purchases, carbon-price changes and later corrections. They should also establish a workable dispute process. A broad promise to deliver “green electricity” leaves too much uncertainty for a transaction with measurable carbon and delivery liabilities.
Hedging requires similar precision. An EU allowance position can provide a financial hedge against movements in the underlying carbon market, but it cannot substitute for CBAM certificates or ensure acceptance of an emissions claim. Price risk and evidence risk remain separate.
Policy changes may eventually improve the position of renewable exporters. The Commission has proposed amendments to electricity emissions attribution alongside wider downstream and anti-circumvention measures. Those proposals should remain a sensitivity case until the applicable legislation is final.
Utilities, traders and investors therefore have an immediate operational task: establish the carbon-adjusted margin of each delivery route, assign responsibility for evidence and settlement, and test whether the economics survive lower spreads or rejected actual values.
The decisive advantage will belong to businesses that can turn a low-emission generating asset into a reliably delivered and verifiable commercial product. A neighbouring EU price may attract the trade, but the cash left after carbon, capacity and balancing costs determines whether the investment can repay its lenders.
Analysis developed by Virtu.Energy