As CBAM compliance moves from planning to operational proof, the hardest part for importers and exporters is no longer the headline carbon accounting, but the traceability of the electricity attributes that underpin “low-carbon” claims. For coal-heavy power systems, the gap between what can be demonstrated and what is needed can translate directly into new renewable build requirements, contract design, and audit-ready documentation. In a Serbia-focused case study relevant to CBAM-exposed industrial trade, the scale of the electricity shortfall is quantified in annual TWh terms and then converted into megawatts, project counts, and investment envelopes.
The starting point is a quantified exporter green-electricity gap of 0.4–1.4 TWh per year. The figure represents the volume of electricity that CBAM-exposed exporters would need to cover with traceable renewable attributes—specifically Guarantees of Origin that can be assigned and cancelled against consumption—beyond what can realistically be allocated from an auctioned renewable pipeline once competing demand and supplier pooling are accounted for. The compliance challenge is sharpened by a “residual-mix default” mechanism that applies when attributes are missing, meaning unproven electricity does not disappear from the calculation.
Residual-mix reality makes “proof” unavoidable
Serbia’s own residual-mix disclosure for 2024 illustrates why aspiration alone cannot close an attribute deficit. The corrected residual mix remains dominated by brown coal and lignite at 66.60%, with hydropower at 23.81%, natural gas at 5.02%, wind at 0.97%, and solar at 0.36%. This baseline matters because it defines what happens when exporters cannot demonstrate renewable attributes for their contracted volumes.
In practical CBAM terms, closing the gap therefore requires additional projects whose output is contractually and administratively earmarked for exporters, with attributes that survive audit and counterparty scrutiny. The compliance risk is institutional as well as technical: even if generation exists in the market, GO allocation must be structured so that it is assignable to specific exporter consumption rather than diluted into generic supplier claims.
From TWh gaps to megawatts: capacity factors drive the math
Turning a TWh shortfall into procurement requirements depends on annual energy yield per installed megawatt, which in turn depends on capacity factor assumptions appropriate to local operating conditions. To keep calculations conservative and bank-case realistic, the conversion uses net capacity factor ranges rather than optimistic developer scenarios. A conservative onshore wind range of 30–35% implies that 1 MW of wind produces about 2.63–3.07 GWh per year.
For utility-scale solar, a conservative range of 15–18% implies that 1 MW of solar produces about 1.31–1.58 GWh per year. With these yields fixed, the problem becomes mechanical: how many megawatts must be built so that annual renewable MWh equals the missing 400–1,400 GWh represented by the exporter gap.
Wind-only and solar-only closures imply different project scales
If Serbia attempted to close the entire gap using wind alone, the capacity requirement would still be manageable because wind yields more annual energy per MW than solar under the stated assumptions. Closing 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. At the high end (1.4 TWh per year), delivering 1,400 GWh implies roughly 456–532 MW.
Expressed as project units using an approximation of a standard Serbian greenfield wind project as a 150 MW park, the wind-only envelope maps to about one to four such parks depending on whether a buffer is needed against low-wind years, curtailment, and commissioning slippage. If instead solar alone were used, the MW requirement rises because solar’s annual yield per MW is lower: closing 400 GWh annually implies roughly 253–305 MW of solar, while closing 1,400 GWh implies roughly 886–1,069 MW.
In project terms using 100 MW solar parks, that translates into about three to eleven parks across low-to-high gap closure scenarios. Solar-only solutions also increase exposure to intraday profile risk and price cannibalisation unless projects are paired with firming or structured through contracts that socialise profile risk—an important consideration for importers seeking stable attribute-backed volumes rather than intermittent delivery profiles.
A blended portfolio better matches deliverability constraints
Because exporters are buying more than MWh—they are buying a defensible footprint and a procurement structure that does not collapse under balancing costs, congestion, and counterparty scepticism—an exporter-anchored solution is expected to be blended rather than resource-specific ideology. The stated rationale for blending is diversification across resource profiles and transmission corridors so that GO-backed volumes remain deliverable across varying system conditions.
A conservative planning split used in coal-heavy systems aiming for fast exporter decarbonisation targets roughly 60% of annual gap energy from wind and 40% from solar. Under this split, closing a 0.4 TWh gap means procuring about 240 GWh per year from wind and 160 GWh per year from solar; translating those energy targets yields about 78–91 MW of wind and about 101–122 MW of solar. In project language this resembles one mid-size wind project combined with one solar park in roughly the 100 MW class.
At the high end (1.4 TWh) under the same split, targets become about 840 GWh per year wind and 560 GWh per year solar—translating to roughly 274–319 MW wind and about 354–427 MW solar. That corresponds to approximately two wind parks of 150 MW each combined with around four solar parks of 100 MW each, with exact counts depending on realised performance within conservative capacity factor ranges and on how much buffer is embedded against network constraints and multi-site build delays.
Investment envelopes: CAPEX ranges align across strategies
The compliance build programme also has an investment dimension relevant to EU ETS-linked industrial competitiveness discussions under the Green Deal framework. Because Serbia’s project costs vary by site, grid works, procurement cycle, and financing structure, CAPEX is quantified using conservative planning ranges rather than single-point estimates. For utility-scale solar, a conservative European emerging-market planning range is €0.55–€0.85 million per MW for all-in cost; for onshore wind it is €1.10–€1.55 million per MW.
Under these unit economics, a low-gap closure scenario can be read directly: one 150 MW wind park implies CAPEX of €165–€233 million; three 100 MW solar parks imply €165–€255 million; and a blended low-gap portfolio around 80–90 MW wind plus 100–120 MW solar implies roughly €143–€242 million before any node-specific reinforcement premium. At higher closure levels, wind-only (three to four 150 MW parks) implies €495–€932 million; solar-only (nine to eleven 100 MW parks) implies €495–€935 million.
A blended high-end closure around 275–320 MW wind plus 350–430 MW solar implies approximately €496–€862 million before reinforcement premiums, with differing execution risk profiles: fewer larger nodes for wind versus more sites and connections for solar.
Grid deliverability and GO allocation are inseparable
The regulatory relevance extends beyond generation volumes into deliverability mechanics that determine whether contracted renewable MWh remain usable after curtailment and congestion effects are realised in practice. In Serbia’s case analysis for exporter economics, transmission reinforcement programmes are framed as decisive because they influence whether marginal renewable MWh contracted under PPAs will be deliverable in assumed volumes—and therefore whether sufficient Guarantees of Origin can be generated to displace residual-mix electricity in exporter footprints.
The dominant exporter-driven demand centre is identified as the Belgrade–Danube basin due to concentration of large CBAM-exposed industrial load as well as likely concentration of supplier portfolios and industrial supply contracts. A first connection priority is therefore to anchor additional wind capacity in corridors designed to serve Belgrade and Srem load basins while stabilising transfer from wind-rich zones into those demand centres; Serbia’s BeoGrid 2025 reinforcement programme has been described publicly as enabling higher renewable integration through major transmission upgrades and new high-voltage connections in that broader corridor.
A second priority is deploying solar in ways that diversify nodal exposure rather than stacking every solution on a single wind corridor; because solar is modular it can often be placed where connection capacity exists or where incremental upgrades are cheaper than new long-distance evacuation lines. A third priority is institutional: even if megawatts are built to match gap arithmetic, closure fails if GO allocation is not designed for exporter use—supported by evidence that GO market scale already exists (2024 cancellations were quantified at 2,447,795 MWh) but must be reallocated through contract assignment rather than absorbed into pooled claims.
Sectors affected by CBAM face an attribute-proofing test
While this electricity attribute challenge is illustrated through Serbia-linked exporter needs for GO-backed power volumes, it sits inside CBAM’s broader compliance logic affecting sectors such as cement, steel, aluminium, fertilisers, electricity generation-related flows, and hydrogen supply chains where electricity inputs can materially shape reported embedded emissions claims under EU ETS-linked accounting approaches during CBAM implementation phases leading up to full application requirements.
The analytical synthesis from the quantified case is straightforward: residual-mix defaults make unproven electricity costly in compliance outcomes; capacity-factor assumptions convert an annual TWh shortfall into hundreds of megawatts; both resource choice (wind versus solar) and portfolio design (blended splits) change project counts but converge on similar investment order-of-magnitude envelopes; and finally grid deliverability plus exporter-specific GO assignment determine whether contractual expectations translate into audit-ready proof.