EU CBAM implementation is forcing a more granular look at how “green” electricity is evidenced for trade compliance, not just how much power is consumed by heavy industry. In Serbia’s case, the challenge is quantified as an exporter green-electricity gap of 0.4–1.4 TWh per year that must be covered using traceable renewable attributes. The mechanism at the centre of the compliance question is the assignment and cancellation of Guarantees of Origin against consumption, rather than reliance on a residual electricity mix that remains dominated by fossil generation.
From CBAM exposure to a measurable “proof layer”
The gap figure is framed as a build programme with a proof layer, reflecting what CBAM-exposed exporters would need to secure beyond what can be allocated from the currently auctioned renewable pipeline. The accounting problem is sharpened by competing demand, supplier pooling, and the residual-mix default applied when attributes are missing. Serbia’s own residual-mix disclosure for 2024 underscores why “aspiration” alone does not close the compliance gap: brown coal and lignite account for 66.60%, with hydropower at 23.81%, natural gas at 5.02%, wind at 0.97%, and solar at 0.36%. In practical terms, closing the deficit requires additional projects whose output is contractually and administratively earmarked for exporters with attributes that can withstand audit and counterparty scrutiny.
Capacity factors translate TWh shortfalls into megawatts
Turning the exporter gap into project requirements depends on annual energy yield per installed megawatt, which varies with capacity factor assumptions. To keep calculations conservative and bank-case realistic for operating conditions, the conversion uses net capacity factor ranges rather than optimistic developer cases. A conservative onshore wind range of 30–35% implies that 1 MW of wind produces about 2.63–3.07 GWh per year, while a conservative utility solar range of 15–18% implies that 1 MW of solar produces about 1.31–1.58 GWh per year. With those yields, the compliance task becomes mechanical: how many MW must be built so that annual renewable MWh matches the missing 400–1,400 GWh.
Wind-only and solar-only closure scenarios
If Serbia attempted to close the full gap using wind alone, the required capacity is comparatively manageable because wind yields more annual energy per MW than solar under the stated assumptions. Covering the low end of 0.4 TWh per year means delivering 400 GWh annually; dividing by 2.63–3.07 GWh per MW per year implies roughly 130–152 MW of additional dedicated wind capacity. Covering the high end of 1.4 TWh per year means delivering 1,400 GWh annually; this implies roughly 456–532 MW of additional dedicated wind capacity. Expressed as project units using an approximated 150 MW greenfield wind park, this maps to about one park at the low end and roughly three to four parks at the high end, explicitly earmarked for exporter PPAs and GO allocation rather than absorbed into general supply portfolios.
Solar-only closure increases the megawatt requirement because annual yield per MW is lower in the conservative range used for planning. Delivering 400 GWh annually at 1.31–1.58 GWh per MW per year implies roughly 253–305 MW of solar, while delivering 1,400 GWh annually implies roughly 886–1,069 MW of solar. In project terms using 100 MW units, this translates to about three to five solar parks at the low end and about nine to eleven parks at the high end. The operational implication is that solar-only strategies multiply grid connection points, permitting sequences, and performance management variables, while also raising intraday profile risk unless projects are paired with firming or structured contracts that socialise profile exposure.
A blended portfolio anchored to exporter needs
In practice, an exporter-anchored solution is expected to be blended rather than resource-specific because exporters are buying more than MWh volume; they are buying a procurement structure that can hold up against balancing costs, congestion constraints, and counterparty scepticism about attribute integrity. A conservative planning split often used in coal-heavy systems seeking fast exporter decarbonisation targets roughly 60% of annual gap energy from wind and 40% from solar as a hedge against resource profile concentration and corridor dependence. Under this split for a 0.4 TWh gap, Serbia would procure about 240 GWh per year from wind and 160 GWh per year from solar, implying around 78–91 MW of wind and about 101–122 MW of solar based on the stated yields.
At the high end of a 1.4 TWh gap under the same split, wind procurement rises to about 840 GWh per year and solar to about 560 GWh per year, translating into roughly 274–319 MW of wind and about 354–427 MW of solar capacity needs within conservative capacity factor ranges. In project language this becomes approximately two wind parks of 150 MW each combined with approximately four solar parks of 100 MW each, with exact counts depending on realised performance buffers against low-wind years, curtailment risk, and commissioning slippage across multiple sites.
Investment envelopes tied to unit costs
Project counts can be linked to an implied CAPEX envelope using conservative planning cost ranges rather than single-point estimates that vary by site conditions and financing structures. For utility-scale solar, a conservative European emerging-market planning range is €0.55–€0.85 million per MW for all-in costs including typical development and owner costs plus standard connection works. For onshore wind, a conservative envelope is €1.10–€1.55 million per MW under similar planning logic.
Using these unit economics, a low-gap closure scenario illustrates how quickly total investment scales with resource choice: one 150 MW wind park implies CAPEX of €165–€233 million for a wind-only low-end approach; three 100 MW solar parks imply CAPEX of €165–€255 million for a solar-only low-end approach; a blended low-gap portfolio around 80–90 MW wind plus 100–120 MW solar implies combined CAPEX of approximately €143–€242 million before any node-specific reinforcement premium. At the high end, wind-only closure using three to four 150 MW parks implies €495–€932 million in CAPEX; solar-only closure using nine to eleven 100 MW parks implies €495–€935 million; and blended closure around 275–320 MW wind plus 350–430 MW solar implies approximately €496–€862 million before reinforcement premiums.
Grid deliverability and GO allocation are joint constraints
The compliance challenge is not only about building enough renewable capacity but also ensuring deliverability where contracted electricity can be absorbed without undermining delivered volumes through curtailment and congestion. The dominant exporter-driven demand centre identified for Serbia sits in the Belgrade–Danube basin due to concentration of major CBAM-exposed industrial load as well as likely concentration of supplier portfolios and industrial supply contracts under existing commercial structures.
This makes transmission reinforcement programmes directly relevant to CBAM attribute outcomes because they influence whether marginal renewable MWh contracted under PPAs remain deliverable in assumed volumes—and therefore generate the Guarantees of Origin needed to displace residual-mix electricity in exporters’ footprints. Serbia’s BeoGrid 2025 reinforcement programme has been described publicly as a major transmission upgrade enabling higher renewable integration and new high-voltage connections in that broader corridor serving Belgrade and Srem load basins.
Institutional design: earmarking attributes for exporters
A further constraint sits in institutional design rather than physical infrastructure: Serbia can build megawatts implied by the gap yet still fail if attribute allocation is not engineered for exporter use cases under CBAM evidence rules. The same EMS residual-mix disclosure that quantifies fossil-heavy defaults also quantifies GO market scale through cancellations in 2024 at 2,447,795 MWh. If CBAM-exposed exporters require an incremental additional GO-backed electricity volume equivalent to the stated gap range beyond what can realistically be allocated from existing and auctioned supply, then incremental demand will reshape market dynamics.
The key compliance condition described is that additional projects’ Guarantees of Origin must be contractually assigned to exporters and cancelled against their consumption rather than being absorbed into generic supplier claims through pooled allocation practices. This “earmarked for exporter PPAs/GOs” requirement functions as the mechanism converting renewable generation into defensible exporter footprints subject to audit scrutiny.
Broader implications for EU industry under CBAM-linked evidence
The Serbian case illustrates how CBAM-linked electricity evidence can turn power sector planning into a trade-compliance requirement for sectors such as cement, steel, aluminium, fertilisers, electricity-related supply chains, and hydrogen value chains where emissions accounting intersects with attribute-backed electricity procurement strategies. For importers relying on embedded emissions calculations supported by documented electricity attributes, gaps between contractual evidence capacity and residual-mix defaults can translate into compliance risk even when renewable generation exists elsewhere in the system.
For EU producers operating under ETS obligations alongside Green Deal decarbonisation pathways, these dynamics reinforce that carbon pricing exposure increasingly depends on verifiable operational data streams—especially where electricity attributes are used to substantiate lower-emissions claims in trade contexts governed by CBAM implementation phases rather than transitional reporting assumptions.