Independent power producers (IPPs) that negotiate renewable electricity contracts may receive a premium for deliveries supported by emissions evidence. In parallel, those contracts can include indemnities that create liabilities larger than the additional revenue. When an installation-specific actual emissions claim does not meet the required standard, the resulting fallback carbon exposure can exceed the premium earned on eligible megawatt-hours.
The risk profile depends on how payments and indemnity coverage are structured. The producer may be paid only for megawatt-hours accepted under eligibility conditions, while the indemnity can cover a broader volume or a larger share of the buyer’s incremental CBAM liability. Contract terms such as weak liability caps, limited cure mechanisms and unclear causation tests can amplify the gap between incremental revenue and potential damages.
Current CBAM electricity rules set conditions for actual emissions claims
Under the current EU Carbon Border Adjustment Mechanism (CBAM) framework, default emissions values apply to imported electricity unless all conditions for installation-specific actual emissions are satisfied. The conditions include a qualifying physical power purchase agreement (PPA), the relevant network condition, and a generating installation below a threshold of 550 g CO2/kWh from fossil-fuel origin. Firm nominations must be matched with production in periods of no more than one hour.
Verification is also required, supported by at least monthly interim evidence. If an actual-emissions claim cannot meet the applicable requirements, contractual consequences may extend beyond losing the premium tied to eligible electricity deliveries. Depending on the agreed indemnity, claims may be linked to the buyer’s additional carbon costs.
Commercial review therefore needs to separate revenue tied to qualifying megawatt-hours from the quantity and financial exposure covered by indemnity provisions. Liability clauses should define how a contractual breach relates to demonstrable buyer loss and what portion is recoverable. The structure of these relationships is central to determining whether downside aligns with expected premium-backed cash flows.
Contract design links title, scheduling, evidence and fallback settlement
Contract structures require mapping of title transfer, payment flows and emissions evidence as distinct elements, followed by consistency checks. A deal can be legally coherent yet fail operationally if the entity responsible for electricity scheduling, import operations or data custody differs from what is assumed in the PPA. This mismatch can affect whether eligibility conditions for actual emissions are met.
For projects supplying industrial steel or aluminium customers, allocation of contractual benefits needs specific attention. Different agreements may address renewable attributes, CBAM evidence and electricity availability. The same megawatt-hour or financial benefit should not be promised more than once under incompatible contractual obligations and remedies.
Where multiple generating installations operate under one framework, each plant should have its own controlled schedule and allocation limits. Portfolio flexibility may support procurement, but substitutions must trigger a defined review process. This is intended to prevent replacement electricity from being automatically attributed to the original generating installation without reassessment.
Lenders evaluate indemnity scope, security and damages calculation
Project-finance assessments should examine maximum indemnity exposure alongside available security, insurance exclusions and claim timing. These factors determine whether contractual liabilities can be absorbed within the project’s financial structure. Lenders also need to consider how quickly claims could crystallize relative to cash flow assumptions.
Lenders and counterparties should distinguish verified buyer losses from theoretical avoided-cost calculations that did not materialise as actual expenses. The damages calculation method in contracts should identify relevant loss categories, specify evidence requirements and define limits on recovery. These elements affect whether indemnity payments reflect measurable CBAM-related impacts.
Contract managers should approve arrangements only when parties’ roles, title transfers, cash flows, data rights and fallback settlement formulas can be reconciled without relying on informal assumptions. This includes confirming that fallback settlement mechanics correspond to how eligibility failures would be treated under CBAM requirements.
EU reform proposal on electricity treatment remains under negotiation
A separate reform proposal identified as COM(2025) 989 would change electricity treatment under CBAM. It includes adjustments to default value methodology and parts of the conditions governing actual emissions values. The proposal would broaden how physical PPAs involving intermediaries are treated and would modify congestion and nomination framework elements.
The Council adopted its negotiating position on 12 June 2026, followed by the European Parliament’s position on 15 September 2026. The proposal remains subject to interinstitutional negotiation and is not enacted legislation for current pricing or project-finance assumptions. The European Commission published definitive-period sector guidance on 14 August 2026 covering electricity as well as iron and steel and aluminium.
The Commission updated general CBAM questions and answers on 15 October 2026. These materials explain implementation but do not replace binding regulations and implementing acts. For an IPP considering a premium-backed PPA, bankability depends on whether downside linked to that premium is clearly defined, appropriately capped and recoverable within project financing arrangements.