Electricity traders and power producers in South-Eastern Europe (SEE) face a financing calculation that goes beyond wholesale market spreads. For exports into the European Union, transaction profitability depends on procurement costs, transmission charges, the applicable carbon treatment and how commercial risks are allocated between counterparties.
For banks financing electricity exports from Serbia, Montenegro and other SEE markets, the key question is whether expected revenue remains sufficient after relevant carbon expenditure and other trading costs. A positive difference between wholesale buying and selling prices does not automatically make a transaction profitable or financeable.
The assessment needs to separate electricity imported into the EU as a covered CBAM good from electricity used as an input during the manufacture of another industrial product. Imported electricity can trigger a direct carbon obligation, while electricity consumed by steelmakers, aluminium producers and other industrial consumers is treated according to sectoral rules.
Applying a uniform carbon surcharge across both electricity trading and industrial production could misstate financial exposure for trading facilities and industrial loans. The approach therefore requires a carbon-cost calculation that matches the type of electricity use and the applicable regulatory framework.
Separate carbon-cost modelling for imported electricity
Under the EU emissions trading framework, electricity has a distinct free-allocation treatment. EU electricity generation receives no corresponding free allocation, so lenders should not model imported electricity using a general assumption based on an initial free-allocation percentage used for certain industrial products.
The carbon-cost calculation must follow the rules for electricity imports and include any eligible deduction tied to a carbon price effectively paid in the country of production. This means the financing assessment depends on how carbon costs are determined for imported power rather than on wholesale spread alone.
A hypothetical margin example shows how carbon charges can change outcomes. With sale proceeds of €100/MWh, procurement expenditure of €70/MWh and transmission and other specified trading costs of €8/MWh, the margin is €22/MWh before carbon expenditure.
If emissions intensity is 0.5 tonnes of CO₂ equivalent per MWh, applying the Q3 2026 CBAM certificate price of €82.32/tCO₂e produces a carbon cost of €41.16/MWh, before any eligible deduction for a carbon price already paid. Under those assumptions, the simplified trading margin becomes negative once carbon cost is included.
Evidentiary requirements for claimed emissions treatment
Where exporters rely on actual installation emissions, claimed treatment depends on meeting specific evidentiary conditions. A renewable generation label or guarantee of origin should not be treated by itself as proof that a shipment qualifies for the claimed emissions treatment.
The requirements cover the generating installation, contractual relationships, electricity delivery and supporting documentation. Banks need to verify that the revenue model aligns with these requirements rather than relying only on a commercial description of the electricity as renewable.
Depending on route and rules, supporting records may include metering data, production logs, delivery schedules and documents linking the generating installation to the quantity claimed as exported electricity. The sale contract, claimed volume and technical records must correspond to the same delivery.
Complete documentation can reduce uncertainty in financing assessments but does not replace a separate regulatory evaluation of whether evidence satisfies applicable requirements. For cross-border trade, physical delivery arrangements still need to be matched with carbon-treatment attribution.
Cross-border delivery routes do not determine CBAM treatment
The Montenegro–Italy interconnection provides a defined commercial route for cross-border trade. Even where physical delivery is possible through an interconnector, attribution of generation and allocation of costs must still be demonstrated.
The same principle applies at other SEE borders: interconnection establishes delivery capability but does not independently determine the carbon treatment of a transaction. Carbon-cost outcomes therefore depend on how generation is attributed and how costs are allocated under applicable rules.
Liquidity demands for traders financing cross-border power
Electricity traders can face overlapping demands on credit capacity at the same time. These include exchange collateral, bilateral security requirements, transmission capacity payments and carbon funding, which may compete for the same liquidity resources.
Banks need to assess combined peak funding requirements rather than rely only on annual net profitability. A trader may show a positive result over a year but still experience short-term liquidity shortfalls if wholesale prices move against a hedge or if counterparties delay payment.
Hedging can reduce selected risks without necessarily resolving carbon-related exposure. Power derivatives may protect against electricity-price movements while leaving emissions assessments, transmission availability and contractual deductions unresolved.
An emissions-price hedge can also create timing and basis differences relative to the applicable certificate price. Lenders are expected to examine net cash requirements under stressed conditions rather than assume that hedged portfolios have no remaining financing risk.
Insurance assessments depend on contractual emissions obligations
Credit insurance requires a similarly specific assessment tied to receivables risk under contracts. The buyer’s solvency, contractual deductions and disputes over emissions basis can affect whether receivables are recoverable.
A physical electricity sale with a clearly defined carbon-cost clause presents different risk from an agreement priced on fixed net terms that depends on uncertain emissions evidence. Insurance coverage must be evaluated against the actual contractual obligation and events covered by the policy.
Long-term renewable projects and storage require separate assumptions
Long-term renewable electricity project finance introduces additional considerations beyond export contracts supporting projected revenue. Projects also need to manage generation variability, balancing costs, curtailment and delivery requirements tied to export arrangements.
If financial models include a carbon-related premium, offtake agreements should specify the basis for that premium. They should also describe consequences if required evidence cannot be provided or if contracted delivery conditions are not met.
Battery storage requires its own commercial assessment distinct from exported-power carbon claims. Its value depends on charging sources, dispatch patterns, energy losses and contractual arrangements, and storage does not automatically establish that exported electricity qualifies for zero-carbon treatment under CBAM.
Revenue from energy arbitrage must be distinguished from any expected benefit associated with CBAM-related treatment of exported electricity. Each assumption requires its own supporting evidence and financial justification rather than being treated as interchangeable within models.
Electricity attribution rule changes remain pending legislative steps
Proposed changes to electricity attribution rules remain part of a wider legislative process. They should not be incorporated into lending assumptions as established benefits before final rules become applicable.
Long-term financing models can consider alternative regulatory outcomes while base cases reflect requirements already in force. This distinction is particularly relevant for electricity trading where wholesale spreads can change hourly and projected carbon-related advantages may depend on rules not yet applicable.
For banks financing SEE electricity exports, repayment assessments need to connect applicable carbon calculations with actual delivery routes, contractual cost allocation, hedging arrangements and peak liquidity requirements. A projected advantage in carbon treatment cannot support repayment by itself when underlying evidence, delivery conditions or commercial margins remain uncertain.