Revised changes to the EU Carbon Border Adjustment Mechanism would adjust how electricity imports are linked to emissions data when power is traded and physically mixed across interconnected markets. The focus is on the evidentiary chain needed to connect a specific generator with electricity imported into the EU. The rules are relevant for wind, solar and hydropower projects in Serbia, North Macedonia, Montenegro and other Western Balkan markets.
Under the current framework, importers generally rely on national default emission factors unless they meet cumulative conditions to use actual emissions. Those conditions aim to establish a relationship between production and import, but they do not align with how European electricity trading operates. Electricity can be sold through intermediaries rather than directly to an EU importer.
A wind farm in Serbia, a solar plant in North Macedonia or a hydropower facility in Montenegro may sell electricity via an intermediary. The electricity may cross multiple bidding-zone borders, while transmission capacity can be allocated through market coupling instead of a separately nominated cross-border contract. Physical flows also follow network conditions rather than the contractual path agreed between buyer and seller.
Default factors and CBAM charges for coal-dependent systems
In that setting, renewable electricity can take on the default emissions of the exporting country’s broader power system. This outcome is described as particularly damaging for coal-dependent markets. Serbia’s default factor is 1.041 tonnes of CO₂ per MWh, producing an indicative CBAM liability of about €78.37/MWh.
The calculation uses a Q2 2026 certificate price of €75.28/tCO₂. Bosnia and Herzegovina’s default factor is 1.148 tonnes of CO₂ per MWh, generating a charge of about €86.42/MWh. These costs can apply even when the electricity is contractually associated with a renewable plant.
The charges apply unless the importer can meet the conditions for reporting actual emissions. For project developers, this can affect confidence that an EU-facing power-purchase agreement will deliver the expected price premium. It also introduces uncertainty around how CBAM treatment will apply to long-term offtake arrangements.
Proposed recognition of physical PPAs with intermediaries
The proposed revision would recognise physical PPAs that involve intermediaries if a verifiable contractual chain links the generator, intermediary and EU importer. The change is tied to how regional utilities and independent renewable producers use licensed traders for balancing, scheduling and market access. It aims to address situations where direct contracting with an EU importer is not used.
The revision would not treat financial or virtual PPAs as evidence of physical electricity delivery. The contract would still need to be connected to actual generation and cross-border supply during the relevant period. Hourly metering, nomination records, production data and contractual allocation would remain central to demonstrating that covered electricity was generated and delivered.
Guarantees of origin may support documentation but are not described as an automatic substitute for the full CBAM evidence chain. Producers and traders would still need to connect the commercial agreement with measurable production, the applicable delivery period and the electricity presented for import into the EU. The evidentiary requirements are therefore expected to remain detailed at hourly resolution.
Changes to congestion tests and capacity nomination requirements
The proposal would remove requirements tied to proving either a direct grid connection to the EU or the absence of physical congestion along the entire transmission route. The congestion condition has been described as problematic because renewable generators cannot control the operational state of multiple interconnectors at delivery time. This limitation affects how generators can demonstrate compliance under existing tests.
Another amendment would limit firm capacity-nomination requirements to borders where capacity is allocated explicitly. Where market coupling allocates electricity together with transmission capacity, traders would no longer be expected to provide separate nominations that the market design does not produce. The changes are aimed at aligning documentation expectations with market operations.
Implications for wind, solar and hydropower project structuring
The revisions are described as making actual emissions technically usable rather than only available in principle within CBAM calculations. They are also intended to improve economic differentiation between coal-fired exports and electricity supplied under a traceable renewable contract. That distinction is relevant for project finance decisions tied to long-term revenue stability.
Western Balkan renewable developments are increasingly structured around long-term PPAs intended to stabilise revenue and support debt repayment when buyers are inside the EU. Uncertainty over CBAM treatment can reduce bankable offtake prices, shorten contract tenors or require wider risk premiums. A 100 MW wind farm operating at a 35% capacity factor would produce around 307 GWh annually.
A CBAM-risk discount of €10/MWh would reduce potential annual revenue by approximately €3.1 million for such a project. For a renewable project exposed to a default cost exceeding €70/MWh, nominal liability could be larger than operating margin and debt-service capacity. Wind projects require particular treatment because their output profile differs from solar.
Wind generation is more likely during evening, winter and lower-solar periods when EU prices can be stronger. Solar projects face midday price cannibalisation and increasingly rely on storage, aggregation or shaped PPAs to preserve value. CBAM traceability therefore needs hourly operation without removing commercial differences between technologies.
Hydropower has different characteristics: reservoir plants can shift generation into higher-priced periods and provide balancing services, while run-of-river output remains linked to hydrological conditions. Albania benefits from a zero national default factor, but exporters in Montenegro, Bosnia and Herzegovina and Serbia operate within mixed systems. Those exporters require access to actual-emissions reporting to avoid being treated like lignite generation.
Verification responsibilities and data preparation requirements
Analysts at Virtu.Energy, described as a CBAM electricity-focused engineering platform, said cross-border trading and renewable exports remain business as usual operationally while each transaction must be supported by a credible CBAM evidence package. The package covers generation source, hourly production, contractual allocation, metering and delivery. The authorised CBAM declarant or EU importer remains legally responsible for declaration and eventual surrender of certificates.
In practice, however, importers would need substantial data sharing with exporters, traders and electricity producers because plant-level evidence cannot be created by a declarant if it was never collected or preserved by the generator. Supporting records must be capable of review by an EU-accredited verification body. Virtu.Energy analysts also said integrating pre-verification into PPAs, trading arrangements and plant data systems needs to start before incomplete contracts or missing hourly records make actual emissions unusable.
For new PPAs, CBAM provisions should define responsibility for data preparation, access to metering records, verification costs, correction of inconsistencies and liability if an evidence package is rejected. Existing contracts may require amendments because many were signed before definitive CBAM documentation requirements were established under the regime.
Whole-generation-mix approach and limits on zero-CBAM access
The proposed whole-generation-mix methodology would lower fallback exposure even where a generator cannot satisfy the full actual-emissions test. Its effect would vary by country, hydrological year and quality of national generation data used in calculations. The revision would not automatically guarantee zero-CBAM access for Western Balkan renewable electricity.
The changes are described as replacing several practically unworkable tests with rules closer to cross-border power market operations where trading structures differ from direct contracting assumptions. Developers integrating pre-verification early would be better positioned to protect EU offtake revenues while distinguishing wind, solar and hydropower output from carbon intensity associated with wider national systems.