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 exports from Serbia, Montenegro and other SEE markets, the key issue is whether expected revenue remains sufficient after carbon expenditure and other trading costs are included. A positive difference between wholesale buying and selling prices does not automatically make a transaction profitable or financeable.
The assessment also needs to separate electricity imported into the EU as a covered CBAM good from electricity used 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 users is treated as an input under sector-specific rules.
Using a single carbon surcharge across both electricity trading and industrial production could misstate the financial exposure of trading facilities and industrial loans. The approach therefore requires different carbon-cost calculations depending on how electricity is used.
Separate carbon-cost modelling for imported electricity
Electricity has a distinct free-allocation treatment under the EU emissions trading framework. EU electricity generation receives no corresponding free allocation, so lenders should not apply an initial free-allocation percentage used for certain industrial products to imported electricity.
Instead, the calculation must follow the rules applicable to electricity imports and include any eligible deduction for a carbon price effectively paid in the country of production. This affects how lenders model net carbon costs in financing structures.
A hypothetical margin example illustrates the impact on trading economics. 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 were 0.5 tonnes of CO2 equivalent per MWh, applying the Q3 2026 CBAM certificate price of €82.32/tCO2e would create 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 after carbon costs are included.
The example is explicitly illustrative rather than a current quotation or an assessment of a specific SEE export route. It is intended to show why lenders should rely on the applicable emissions basis, actual commercial costs, and contractual allocation of the carbon obligation instead of using wholesale spreads alone.
Evidence requirements for generation-based claims
Where exporters rely on actual installation emissions, claimed treatment depends on meeting 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 relate to the generating installation, contractual relationships, electricity delivery, and supporting documentation. Banks need to verify that revenue models align with these requirements rather than relying only on a commercial description of electricity as renewable.
Depending on the 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 refer to the same delivery.
Complete documentation can reduce uncertainty in financing assessments but does not replace a separate regulatory check that evidence satisfies applicable requirements. For cross-border trade routes such as Montenegro–Italy interconnection, physical delivery capability does not automatically determine carbon treatment for a transaction.
Liquidity demands for traders and power market counterparties
Electricity traders can face multiple calls 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 therefore need to assess combined peak funding needs rather than rely only on annual net profitability. A trader may show a positive yearly result but still face short-term liquidity shortfalls if wholesale prices move against a hedge or if a counterparty delays payment.
Hedging can reduce selected risks without necessarily eliminating carbon-related exposure. Power derivatives may hedge 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 instead of assuming that a hedged portfolio has no remaining financing risk.
Credit insurance similarly requires case-specific assessment. The buyer’s solvency, contractual deductions, and disputes over emissions basis can affect whether receivables are recoverable; risk differs between physical sales with clearly defined carbon-cost clauses and fixed-net-price agreements dependent on uncertain emissions evidence.
Financing assumptions for renewables and battery storage
Long-term renewable project finance introduces additional considerations beyond an EU export contract underpinning projected revenue. Projects must manage generation variability along with balancing costs, curtailment risk, and delivery requirements tied to contracted supply.
If financial models include a carbon-related premium, the offtake agreement should specify how that premium is calculated and what happens if required evidence cannot be provided or contracted delivery conditions are not met. Battery storage likewise requires distinct commercial assessment because its value depends on charging sources, dispatch patterns, energy losses, and contractual arrangements.
Storage does not automatically establish that exported electricity qualifies for zero-carbon treatment under CBAM. Revenue from energy arbitrage must therefore be separated from any expected benefit linked to carbon treatment; each assumption requires its own supporting evidence and financial justification.
Status of electricity attribution rule changes
Proposed changes to electricity attribution rules remain part of a broader legislative process. They should not be built into lending assumptions as established benefits before final rules become applicable.
Long-term financing models may consider alternative regulatory outcomes, but base cases need to 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 into the EU, repayment assessments must connect the applicable carbon calculation with actual delivery routes, contractual cost allocation, hedging arrangements, and peak liquidity requirements. A projected advantage in carbon treatment cannot by itself support repayment when underlying evidence, delivery conditions or commercial margins remain uncertain.