Electricity traders and power producers in South-Eastern Europe (SEE) face a financing calculation that extends beyond wholesale market spreads. For exports into the European Union, the profitability of a transaction depends on procurement costs, transmission charges, the applicable carbon treatment and the allocation of commercial risks between counterparties.
For banks financing electricity exports from Serbia, Montenegro and other SEE markets, the central question is whether the expected revenue remains sufficient after the relevant carbon expenditure and other trading costs are included. A positive difference between wholesale buying and selling prices does not necessarily translate into a profitable or financeable transaction.
The assessment must distinguish electricity imported into the EU as a covered CBAM good from electricity consumed during the manufacture of another industrial product. Imported electricity can trigger a direct carbon obligation, while electricity used by steelmakers, aluminium producers and other industrial consumers is an input whose cost and emissions treatment depend on the applicable sectoral rules.
Applying a uniform carbon surcharge across electricity trading and industrial production could therefore misrepresent the financial exposure of both trading facilities and industrial loans.
Electricity imports require a separate carbon-cost calculation
Electricity has a distinct free-allocation treatment under the EU emissions trading framework. EU electricity generation receives no corresponding free allocation, meaning lenders should not model imported electricity using a general assumption based on the initial free-allocation percentage applied to certain industrial products.
The calculation must instead follow the applicable rules for electricity imports and account for any eligible deduction relating to a carbon price effectively paid in the country of production.
A hypothetical transaction illustrates the effect on trading margins. With sale proceeds of €100/MWh, procurement expenditure of €70/MWh and transmission and other specified trading costs of €8/MWh, the transaction generates a margin of €22/MWh before carbon expenditure.
If the applicable emissions intensity were 0.5 tonnes of CO₂ equivalent per MWh, applying the Q3 2026 CBAM certificate price of €82.32/tCO₂e would produce a carbon cost of €41.16/MWh, before any eligible deduction for a carbon price already paid.
Under those assumptions, the simplified trading margin would become negative after the carbon cost was included.
The calculation is illustrative. It is not a current exchange quotation, a national emissions factor or an assessment of a specific SEE electricity export route. It demonstrates why lenders must use the applicable emissions basis, actual commercial costs and contractual allocation of the carbon obligation rather than relying on the wholesale price spread alone.
Generation evidence and cross-border delivery records
Where an exporter relies on actual installation emissions, the claimed treatment depends on satisfying the relevant evidentiary conditions. A renewable generation label or guarantee of origin should not, by itself, be treated as proof that a shipment qualifies for the claimed emissions treatment.
The applicable requirements concern the generating installation, contractual relationships, electricity delivery and supporting documentation. Banks need to establish that the revenue model is consistent with those requirements rather than based solely on a commercial description of the electricity as renewable.
Depending on the applicable 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 the financing assessment, but it does not replace the separate regulatory assessment of whether the evidence meets the applicable requirements.
The Montenegro–Italy electricity interconnection provides a defined commercial route for cross-border trade, while the attribution of generation and allocation of costs still need to be demonstrated. The same principle applies to other SEE borders: physical interconnection establishes the possibility of delivery, but does not independently determine the carbon treatment of a transaction.
Trading facilities face overlapping liquidity requirements
Electricity traders can face several demands on credit capacity at the same time. Exchange collateral, bilateral security requirements, transmission capacity payments and carbon funding may compete for the same liquidity resources.
Banks therefore need to assess the combined peak funding requirement rather than rely exclusively on annual net profitability. A trader may have a positive result across the year but still experience a short-term liquidity shortfall if wholesale prices move against a hedge or a counterparty delays payment.
Hedging reduces selected risks but does not necessarily resolve the carbon-related exposure. Power derivatives can protect against electricity-price movements while leaving emissions assessments, transmission availability and contractual deductions unresolved.
An emissions-price hedge can also introduce timing and basis differences relative to the applicable certificate price. Lenders should examine the net cash requirement under stressed conditions rather than assume that a portfolio described as hedged has no remaining financing risk.
Credit insurance requires a similarly specific assessment. The buyer’s solvency, contractual deductions and disputes over the emissions basis can all affect the recoverability of a receivable. A physical electricity sale with a clearly defined carbon-cost clause presents a different risk from a fixed-net-price agreement that depends on uncertain emissions evidence.
Insurance coverage must be assessed against the actual contractual obligation and the events covered by the policy.
Renewable projects and storage require distinct revenue assumptions
Long-term renewable electricity project finance introduces additional considerations. An EU export contract may underpin projected revenue, but the project must also manage generation variability, balancing costs, curtailment and delivery requirements.
Where a financial model includes a carbon-related premium, the offtake agreement should specify the basis for that premium and the consequences if the required evidence cannot be provided or the contracted delivery conditions are not met.
Battery storage also requires a separate commercial assessment. Its value depends on charging sources, dispatch patterns, energy losses and contractual arrangements. Storage does not automatically establish that electricity qualifies for zero-carbon treatment under CBAM.
Revenue from energy arbitrage must therefore be distinguished from any expected benefit associated with the carbon treatment of exported electricity. Each assumption requires its own supporting evidence and financial justification.
Electricity attribution proposals remain subject to the legislative process
Proposed changes to electricity attribution rules remain part of a wider legislative process and should not be incorporated into lending assumptions as established benefits before the final rules become applicable.
Long-term financing models can assess alternative regulatory outcomes, but their base cases need to reflect requirements already in force. This distinction is particularly important for electricity trading, where wholesale spreads can change hourly and projected carbon-related advantages may depend on rules that have not yet become applicable.
For banks financing SEE electricity exports, repayment assessments must connect the applicable carbon calculation with the actual delivery route, contractual cost allocation, hedging arrangements and peak liquidity requirements. A projected advantage in the carbon treatment of electricity cannot independently support repayment where the underlying evidence, delivery conditions or commercial margins remain uncertain.
