Proposed changes to the EU Carbon Border Adjustment Mechanism could give Western Balkan renewable generators a more practical route into European electricity markets, addressing rules that currently make it difficult for wind, solar and hydropower projects to prove that their exports carry low or zero embedded emissions.
The central problem is not the emissions produced by renewable assets. It is the evidentiary chain required to connect a specific generator with electricity imported into the EU through an interconnected market where power is traded, resold and physically mixed across several bidding zones.
Under the existing framework, importers generally face national default emission factors unless they satisfy cumulative conditions for the use of actual emissions. Those conditions were designed to establish a credible relationship between production and import, but they fit poorly with the commercial structure of European electricity trading.
A wind farm in Serbia, a solar plant in North Macedonia or a hydropower facility in Montenegro may sell electricity through an intermediary rather than directly to an EU importer. The power may cross several bidding-zone borders, while transmission capacity can be allocated through market coupling rather than through a separately nominated cross-border contract. Physical electricity flows also follow network conditions rather than the contractual path agreed between buyer and seller.
The result is that renewable electricity can inherit the default emissions of the exporting country’s wider power system. This is especially damaging in coal-dependent markets. Serbia’s current default factor of 1.041 tonnes of CO₂ per MWh produces an indicative CBAM liability of approximately €78.37/MWh at the Q2 2026 certificate price of €75.28/tCO₂. Bosnia and Herzegovina’s default factor of 1.148 tonnes generates a charge of about €86.42/MWh.
These costs can apply even when the electricity is contractually associated with a renewable plant, unless the importer can meet the conditions for reporting actual emissions. For project developers, that creates uncertainty over whether an EU-facing power-purchase agreement can deliver the expected price premium.
The proposed revision would recognise physical PPAs involving intermediaries, provided a verifiable contractual chain connects the generator, intermediary and EU importer. This is important because regional utilities and independent renewable producers frequently depend on licensed traders to manage balancing, scheduling and market access.
The reform would not turn financial or virtual PPAs into evidence of physical electricity delivery. The contract would still need to be linked to actual generation and cross-border supply. Hourly metering, nomination records, production data and contractual allocation would remain central to demonstrating that the electricity covered by the agreement was generated and delivered during the relevant period.
Guarantees of origin may contribute to the supporting documentation, but they are not automatically a substitute for the full CBAM evidence chain. Producers and traders must be able to connect the commercial agreement with measurable production, the applicable delivery period and the electricity presented for import into the EU.
The proposal would also remove the requirement to prove either a direct grid connection to the EU or the absence of physical congestion along the entire transmission route. The congestion condition has been particularly problematic because renewable generators cannot control the operational state of multiple interconnectors at the time of delivery.
Another amendment would confine firm capacity-nomination requirements to borders where capacity is allocated explicitly. Where market coupling allocates electricity and transmission capacity together, traders would no longer be expected to provide a separate nomination that the market design does not produce.
Taken together, the changes would make actual emissions technically usable rather than merely available in principle. They would also improve the economic distinction between a coal-fired export and electricity supplied under a traceable renewable contract.
That distinction is important for project finance. Western Balkan renewable developments are increasingly structured around long-term PPAs intended to stabilise revenue and support debt repayment. Where the target buyer is inside the EU, uncertainty over CBAM treatment can reduce the bankable offtake price, shorten the contract tenor or require a wider risk premium.
A 100 MW wind farm operating at a 35% capacity factor would produce around 307 GWh annually. Even a CBAM-risk discount of €10/MWh would reduce potential annual revenue by approximately €3.1 million. For a renewable project incorrectly exposed to a default cost exceeding €70/MWh, the nominal liability could be larger than the project’s operating margin and debt-service capacity.
Wind projects require particular treatment because their output profile, capacity factor and system value differ from solar. Wind generation is more likely to produce during evening, winter and lower-solar periods, when EU prices can be stronger. Solar projects face greater midday price cannibalisation and increasingly need storage, aggregation or shaped PPAs to preserve value. CBAM traceability therefore needs to operate at an hourly level without erasing the commercial differences between the technologies.
Hydropower has another set of 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 renewable exporters in Montenegro, Bosnia and Herzegovina and Serbia operate inside mixed systems and require access to actual-emissions reporting to avoid being treated like lignite generation.
Analysts at Virtu.Energy, a CBAM electricity-focused engineering platform, said cross-border trading and renewable exports remain business as usual operationally, but each commercial transaction must now be followed by a credible CBAM evidence package covering the generation source, hourly production, contractual allocation, metering and delivery.
The authorised CBAM declarant or EU importer remains legally responsible for the declaration and eventual surrender of certificates. In practice, however, the importer will have to share substantial data and documentation obligations with the exporter, trader and electricity producer. A declarant cannot independently create plant-level evidence that was never collected or preserved by the generator.
The supporting records must be capable of review by an EU-accredited verification body. Virtu.Energy analysts said integrating a pre-verification procedure into PPAs, trading arrangements and plant data systems is therefore no longer a task for the end of the reporting cycle. The process needs to begin now, before incomplete contracts or missing hourly records make the use of actual emissions impossible.
For new PPAs, CBAM provisions should define responsibility for data preparation, access to metering records, verification costs, correction of inconsistencies and liability where an evidence package is rejected. Existing contracts may require amendments because many were signed before the definitive CBAM regime created these documentation requirements.
The proposed whole-generation-mix methodology would lower fallback exposure even where a generator cannot satisfy the full actual-emissions test. Its effect will vary by country, hydrological year and the quality of national generation data.
The revision would not automatically guarantee zero-CBAM access for Western Balkan renewable electricity. It would, however, replace several practically unworkable tests with rules closer to the way cross-border power markets operate. Developers that integrate pre-verification early will be better placed to protect EU offtake revenues and distinguish their wind, solar and hydropower output from the carbon intensity of the wider national system.