Renewable energy financing models need to separate electricity sales revenue from additional income that depends on Carbon Border Adjustment Mechanism (CBAM) eligibility. A project can meet generation targets and contractual availability requirements while still not receive a CBAM-related premium due to gaps in nominations, emissions evidence, or verification.
For lenders, this separation affects revenue forecasts, debt sizing, and debt service coverage ratio (DSCR) calculations. While electricity output, market prices, curtailment, offtaker creditworthiness, and operating availability remain central, conditional CBAM-linked payments create an additional revenue risk.
Eligibility for actual emissions values in imported electricity
Under the current framework, imported electricity generally uses a default-values route unless installation-specific actual emissions values requirements are met. The conditions include a qualifying physical power purchase agreement (PPA), applicable network conditions, and a generating installation below 550 g CO₂/kWh fossil-fuel-origin emissions.
Eligibility also requires firm nominations matched with production over periods of no more than one hour. Independent verification must be supported by at least monthly interim evidence.
CBAM-related cash flows extend beyond the generation period. For electricity imported in 2026, sales of CBAM certificates are scheduled to begin on 1 February 2027.
The first annual CBAM declaration and certificate surrender deadline is set for 30 September 2027. From 2027, certificate pricing moves to weekly auction-price averaging, and quarterly certificate-holding requirements become part of treasury planning.
Modelling CBAM-linked income alongside contracted electricity revenue
The potential for CBAM-related revenue can depend on contractual arrangements, the share of nominations matched to production, the completeness of supporting data, verification findings, and the importer’s status. This income is therefore distinct from the underlying electricity revenue and needs separate modelling in financing cases.
Investment committees are expected to use consistent assumptions across financial models and technical due-diligence reports. If a model assumes that 85% of electricity volumes qualify for the relevant treatment, operational records must show the project can achieve a representative eligible share at that level.
A mismatch between assumed qualification ratios and verifiable operating performance affects valuation and cannot be treated only as a compliance issue. Where the electricity offtaker is a steel or aluminium producer, lenders must also establish the commercial basis for any additional payment.
Under current CBAM treatment for metal goods, purchased renewable electricity may not directly reduce the buyer’s CBAM certificate liability. The premium may instead relate to energy-price hedging, customer requirements, corporate decarbonisation objectives, or preparation for future regulatory developments.
Monitoring eligible shares and documentation to protect DSCR
Lenders are advised to compare financial models with a monthly operating dashboard rather than relying solely on an annual assurance cycle. A declining eligible share, recurring documentation exceptions, or heavy dependence on a single intermediary can signal emerging problems before they appear in DSCR.
Debt sizing should be based on cash flows available under the selected stress scenario. Revenue assumptions that depend on unproven regulatory interpretations, incomplete evidence, or operational performance not yet demonstrated should remain optional upside rather than required debt service support.
Status of EU electricity reform proposal COM(2025) 989
The financing model should distinguish current rules from potential changes under COM(2025) 989, which is described as a separate reform proposal that would materially alter electricity treatment under CBAM. The proposal includes changes to electricity default value methodology and parts of the conditions governing actual values.
It would also broaden physical PPAs to include intermediaries and modify the applicable congestion and nomination framework. The Council adopted its negotiating position on 12 June 2026, followed by the European Parliament’s position on 15 September 2026.
The proposal remains under interinstitutional negotiation and has not become enacted legislation. Its potential effects should be assessed separately from current-law pricing and should not be included in financing assumptions as if changes were already applicable.
For renewable energy lenders, the key financing distinction remains between contracted electricity revenue secured under the commercial contract and additional CBAM-linked value dependent on eligibility, measurable performance, and availability of supporting evidence when cash flow is needed to service debt.