EU CBAM compliance is increasingly being translated into a practical question for industrial CFOs: how to secure verifiable low-carbon electricity attributes in time, at scale, and under real grid constraints. For exporters in sectors covered by the mechanism, the economics of “green” supply are not only about contracting costs, but also about whether eligible volumes survive curtailment and interconnection delays. The result is a shift from treating renewable PPAs as standalone instruments to building portfolio structures that can deliver firmed attributes to EU buyers.
CBAM’s sector map meets electricity intensity
In Serbia’s heavy industry, the compliance challenge can be structured around five CBAM-linked categories that touch major export flows: iron and steel, aluminium, fertilisers, cement, and electricity exports. Each segment has different electricity intensity and different exposure to EU buyer requirements, which affects how much value can realistically be captured through power procurement versus process change. That distinction matters for trade compliance because the buyer’s ability to report credible emissions reductions depends on the availability and deliverability of low-carbon attributes.
Steel procurement logic varies by production route. For integrated steel, electricity does not dominate direct emissions, but it still carries commercial weight because renewable procurement is increasingly used as a gating criterion by EU customers and because indirect emissions reductions are often an early step. In aluminium rolling and extrusion, electricity and heat inputs are more central both to unit costs and to the emissions narrative used in CBAM-related reporting.
How much green power is needed by 2028–2030
A financing-grade base case for Serbia’s industrial green power requirement by 2028–2030 points to 1.5–2.5 TWh per year of contracted renewable attributes delivered through credible structures. An upside scenario—driven by harder EU supplier requirements and pre-emptive procurement by exporters—raises the range to 3.0–4.0 TWh per year. The underlying assumption is targeted procurement aimed at reducing reportable indirect emissions and stabilising buyer confidence rather than instant full decarbonisation.
In a base case of 2.0 TWh per year, an indicative allocation across segments suggests roughly 0.6–0.8 TWh for steel and downstream metal fabrication tied to EU supply chains. Aluminium processors and metalworking clusters would account for 0.4–0.6 TWh, while fertiliser and chemicals producers with EU exposure would require 0.3–0.5 TWh. Cement and building materials with export orientation are estimated at 0.1–0.2 TWh, with 0.2–0.4 TWh directed to firmed or green-label electricity export tranches or support utilities and aggregators delivering green supply blocks to industry.
From TWh targets to MW build plans
Turning annual targets into generation capacity creates immediate system-stress trade-offs that affect curtailment risk and attribute delivery reliability. If 2.0 TWh per year were covered purely with solar, it would typically require about 1,200–1,400 MW of solar nameplate at a 17–19% capacity factor. Such a solar-heavy approach creates synchronized midday output that can collapse capture prices and force curtailment unless storage and exports expand alongside generation.
A wind-led approach for the same 2.0 TWh per year implies about 650–750 MW of onshore wind at a 32–38% capacity factor. The smaller MW footprint reflects higher capacity factor and produces output in a less synchronized pattern, which can reduce curtailment frequency and price cannibalization pressures compared with solar concentration.
A bankable supply stack: wind backbone plus selective solar
The most bankable structure described for manageable system stress combines wind as a stability backbone with solar deployed where nodes are strongest, supported by storage sized as insurance rather than decoration and backed by portfolio-level aggregation. A credible base-case platform delivering around 2.0 TWh per year is estimated at 400–500 MW wind plus 400–600 MW solar. It would also include 100–200 MW / 200–400 MWh of battery storage alongside an aggregator that firms delivery blocks.
This approach is positioned as a way to reduce the likelihood that industrial buyers pay for “green” PPAs while receiving unreliable attribute volumes due to congestion and curtailment events. In other words, compliance economics become tied to operational deliverability rather than contract strike prices alone.
CAPEX ranges and what grid reinforcement changes
Capital costs are presented as ranges that vary sharply with grid conditions rather than only technology choice. Utility-scale solar in Serbia under comparable South East Europe conditions is typically estimated at €0.55–0.90 million per MW, rising toward €0.95–1.10 million per MW where grid works are heavy. Onshore wind is estimated at €1.20–1.80 million per MW depending on civil works, access constraints, turbine class selection, and high-voltage distance.
Two-hour battery systems commonly land at €0.35–0.55 million per MWh fully installed. Under one mixed base case—450 MW wind, 500 MW solar, and 150 MW / 300 MWh batteries—the financing-grade all-in CAPEX envelope is estimated around €1.1–1.8 billion once owner costs, interconnection needs, and realistic contingencies are included.
Returns depend on contracting design—and curtailment breaks them
The investment profile differs depending on whether projects are built as merchant assets or as industrial procurement infrastructure under long-term arrangements that align settlement terms with attribute delivery expectations. Under CBAM pressure, the most investable structure is described as long-term contracts often spanning 10–15 years, allowing industrial buyers to treat power and attributes as stable inputs rather than volatile trading positions.
When cash flows are truly contracted and curtailment remains contained, wind and solar projects in the region are described as supporting unlevered returns in a 7–10% band. Wind is expected to show stronger resilience within that band because capture-price erosion tends to be slower with penetration and because its curtailment dynamics are more event-driven than structurally synchronized like solar at scale.
Curtailment sensitivity: lost eligible volume becomes direct value leakage
Curtailment risk is framed as where CBAM buyer-map modelling becomes a financial model rather than a policy memo. If the green supply platform delivers 2.0 TWh per year, each 1% of curtailment corresponds to 20 GWh of lost eligible volume; at an all-in green electricity value of €70–90/MWh this implies €1.4–1.8 million of annual value erosion per curtailment percentage point repeating every year.
The figures scale quickly: at 2% curtailment the platform leaks €2.8–3.6 million annually; at 5% it leaks €7.0–9.0 million; at 10% it leaks €14–18 million before accounting for second-order effects such as lower capture prices when remaining delivered volumes occur during saturated hours of renewable output.
Equity IRR compression under higher curtailment
For equity investors using an unlevered equity IRR target of 8–10%, the impact of curtailment is described as mechanical in contracted base cases once uncompensated losses rise above tolerances. Moving from 2% curtailment to 5% typically compresses IRR by roughly 60–120 basis points depending on debt sizing and whether curtailment is uncompensated.
A shift from 2% to 10% can compress IRR by about 150–250 basis points, potentially pushing projects below institutional hurdle rates unless contracted prices remain unusually strong or CAPEX remains unusually low. Wind-heavy portfolios are described as showing smaller IRR erosion for the same curtailment percentage because base capture prices are stronger and because curtailment tends to be more localized rather than structural.
Grid delays add another compliance risk layer
The most important stress test highlighted is grid-upgrade slip of 12–18 months, where portfolio programmes fail not through universal delay but through stranding specific tranches at delayed nodes while other capacity proceeds later or under different conditions. If planned capacity totalling 300 MW is delayed by 18 months, deferred generation could reach roughly 700–1,000 GWh depending on whether the portfolio is wind- or solar-heavy.
<pAt €70–90/MWh this translates into €49–90 million of postponed revenue and attribute delivery concentrated in early years when financing carry costs and contract milestones matter most for project viability under compliance-driven procurement structures.
Why aggregation becomes essential for delivered attributes
The analysis identifies balancing settlement costs as another hidden variable because industrial buyers care about delivered verifiable volumes rather than theoretical annual MWh output from generation assets alone. Constraints include connection-node saturation where industrial-scale solar clusters at strong substations; voltage and reactive-power management costs; ramping and reserve needs where solar-heavy procurement creates steep daily ramps requiring hydro dispatch, batteries or cross-border trades; and shaping plus imbalance plus replacement volumes during curtailment or outage periods.
These add-ons can quietly add several euros per MWh to effective delivered cost if portfolios are not aggregated and actively managed from day one using virtual balancing approaches that reduce forecast error and imbalance penalties while converting intermittent generation into deliverable procurement products.
Broader implications for CBAM-linked industry
The compliance message for importers, exporters, EU producers operating under the EU ETS framework is that CBAM-related competitiveness increasingly hinges on electricity attribute deliverability rather than only emissions accounting methodology or contract headline terms during early implementation planning periods leading up to definitive obligations.
For cement, steel, aluminium, fertilisers and electricity exporters—and for hydrogen-linked decarbonisation strategies that rely on credible low-carbon power—procurement design becomes part of regulatory risk management: it must withstand congestion-driven curtailment dynamics and interconnection timing uncertainty while maintaining stable attribute volumes demanded by EU buyers.