Serbia is entering 2026 with an energy-market challenge that looks like a cost problem but is increasingly shaping trade outcomes. The EU Carbon Border Adjustment Mechanism is moving from a reporting-only approach into a period when embedded emissions start to translate into a border cash cost. For exporters in CBAM-covered sectors, electricity procurement is therefore becoming part of trade compliance strategy, not just industrial input management.
CBAM expands the commercial meaning of embedded emissions
CBAM covers iron and steel, aluminium, cement, fertilisers and electricity in its initial scope, aligning closely with Serbia’s most energy-intensive export segments. Regional trade mapping indicates these CBAM-covered goods account for about 11.7% of Serbia’s total export value to the EU. Within that exposure, iron and steel contribute roughly 4.5%, electricity about 4.7%, aluminium around 2.0%, fertilisers near 0.5%, and cement approximately 0.1%. While these figures describe trade shares rather than profit shares, they point to where carbon-related costs and electricity-related emissions accounting can most directly affect unit economics.
Under the CBAM export frame, the key counterparties are not domestic consumers but EU-based industrial importers and OEM supply chains that must report and internalize embedded emissions. Supplier selection is expected to shift toward a straightforward criterion: whether exporters can evidence lower embedded emissions at scale using credible electricity attributes and stable delivery without unpredictable price changes. This creates a two-sided squeeze for non-EU producers—EU competitors benefit from ETS exposure alongside decarbonisation support and evolving low-carbon electricity mixes, while other non-EU suppliers may offer lower prices but still face CBAM-linked costs.
Electricity attributes move from procurement detail to competitiveness
For heavy industry in Serbia, “green electricity” is emerging as the fastest adjustable lever because it can be contracted ahead of deeper process technology changes. Steel, aluminium and fertilisers can reduce reported embedded emissions materially by shifting the electricity attribute stack, particularly where indirect emissions are counted or where customers treat electricity provenance as a gating factor in supplier decisions. This does not equate to full decarbonisation—blast furnace steel retains dominant direct emissions—but it can change the commercial conversation by reducing the “avoidable” portion of the footprint and supporting a credible transition pathway.
That shift also reframes investor questions around how much green electricity must be contracted or built to defend CBAM-exposed exports, and what that implies for capital expenditure, grid integration requirements and return profiles. In practice, the procurement challenge becomes tightly linked to how reliably renewable attributes can be delivered and accepted under EU buyer expectations.
What a bankable green power envelope could look like
A practical base case for industrial green power procurement in Serbia points to contracted demand of roughly 1.5–2.5 TWh per year by 2028–2030. The demand would be anchored by the largest CBAM-exposed electricity buyers across steel, aluminium and fertilisers, with additional volume potentially pulled in from cement and export-oriented fabrication as customer-driven emissions disclosure expands. An upside scenario—if EU buyers tighten supplier requirements and major exporters lock green supply early—could raise the envelope toward 3.0–4.0 TWh per year.
Supplying around 2.0 TWh per year with domestic renewables typically requires a portfolio sized by capacity factors: approximately 650–750 MW of wind at a 32–38% capacity factor or about 1,200–1,400 MW of solar at a 17–19% capacity factor. A system-credible approach is not solar-only; it is commonly framed as a mixed build of roughly 400–500 MW wind plus 400–600 MW solar supported by storage and firming contracts in the range of 100–200 MW paired with 200–400 MWh of storage. Such a combination is described as capable of delivering roughly 1.8–2.6 TWh while keeping curtailment and capture-price erosion within controllable limits.
CAPEX, returns and the compliance risk hidden in curtailment
Financing-grade delivered cost ranges for projects consistent with regional market conditions are used to estimate investment needs. Utility-scale solar is typically placed at €0.55–0.90 million per MW, rising toward €0.95–1.10 million per MW where grid works are heavier. Onshore wind is estimated at €1.20–1.80 million per MW depending on civil complexity and high-voltage distance, while two-hour battery systems often land at €0.35–0.55 million per MWh fully installed.
Under an illustrative mixed base case—450 MW wind plus 500 MW solar plus 150 MW / 300 MWh batteries—an all-in CAPEX envelope is described as landing around €1.1–1.8 billion once owner’s costs and interconnection are included. Scaling toward an upside configuration—700 MW wind plus 800 MW solar plus 200 MW / 400 MWh batteries—pushes the envelope toward €2.0–3.2 billion, with variation driven more by grid reinforcement intensity and site complexity than equipment alone.
Return assumptions depend on whether industrial offtake is bankable and whether renewable attributes are recognized in ways EU buyers accept. In Serbia’s context, the most investable structure for CBAM-facing industry is described as long-term PPAs with credible settlement—typically 10–15 years—structured either as physical delivery where feasible or as financial PPAs paired with guarantees of origin and balancing services. Under that structure, unlevered project IRRs for wind and solar are often placed in a 7–10% band for contracted cash flows.
Curtailment then becomes a compliance-adjacent economic risk because it can undermine both attribute volumes and cost predictability for buyers expecting fixed renewable attribute delivery under green PPAs. If curtailment reduces delivered eligible volume or triggers true-ups in markets used for compliance accounting, it creates cost volatility alongside compliance uncertainty. At portfolio scale, even “modest” curtailment can translate into significant value erosion: if a green supply platform delivers 2.0 TWh per year, each 1% curtailment equals about 20 GWh of lost eligible volume; at blended PPA values of €70–90/MWh this implies roughly €1.4–1.8 million per percentage point per year before penalties or renegotiation effects are considered.
System constraints determine whether green power remains deliverable
The market impact does not hinge only on renewable output volumes but on how those volumes interact with grid constraints that must be modeled explicitly for CBAM-relevant procurement strategies to hold up commercially. Connection-node saturation concentrates around stronger corridors and substations, making marginal capacity disproportionately expensive where upgrades lag or where nodes reach limits quickly. Voltage and reactive power management becomes an added cost at scale, while ramping and reserve needs increase when solar-heavy build-outs create steep daily ramps requiring fast flexibility.
Balancing and settlement further shape the effective cost paid by industrial buyers because their “true” green electricity cost includes not just PPA strike prices but also imbalance costs, shaping costs and any curtailment-driven replacement costs needed to maintain attribute delivery expectations.
Wind versus solar performance under curtailment pressures is also highlighted as structurally different: wind curtailment tends to be more event-driven and localized with less structural coincidence than solar, while higher capacity factors reduce the number of MW required per unit of energy delivered to meet attribute targets. Wind’s production profile can also be more stable across hours that do not align with universal solar peaks, which may improve the probability that industrial buyers receive usable attribute volumes matching their procurement strategy.
A portfolio approach faces its biggest test: grid upgrade timing
Aggregation and virtual balancing are presented as strategic tools because CBAM-facing industrial buyers do not only seek low prices; they need defensible emissions narratives with predictable cost outcomes tied to reliable attribute delivery. A portfolio-level aggregator can firm renewable output blocks, reduce forecast error, minimize imbalance exposure and use batteries alongside intraday repositioning to deliver higher “usable green volume” than standalone assets might achieve under real-world operational constraints.
The most investor-relevant stress test described for Serbia’s rollout concerns grid upgrades slipping by 12–18 months—a failure mode that can turn “green transition” investments into stranded capital expenditure if nodes cannot accept planned generation when needed for contract milestones or early-year debt service schedules.
If delayed grid capacity affects an industrial PPA platform planned around roughly 300 MW of wind and solar capacity over an additional period of up to 18 months, deferred generation could reach about 700–1,000 GWh depending on technology mix; at €70–90/MWh this equates to approximately €49–90 million in postponed revenue and attribute delivery concentrated early in project life cycles when contract milestones are most sensitive.
Broader compliance implications across ETS-linked industry
The policy relevance extends beyond Serbia’s domestic power sector because CBAM-linked reporting requirements connect embedded emissions accounting to EU buyer procurement decisions across cement, steel, aluminium, fertilisers and electricity supply chains operating under EU ETS conditions elsewhere in Europe’s carbon pricing architecture. For importers and exporters alike—including firms supplying hydrogen-related value chains where electricity intensity matters—the practical question becomes whether contractual structures can deliver credible emissions reductions at scale without introducing volatility that undermines compliance-ready documentation.
In this framework, green electricity becomes a survival variable for heavy-industry exporters entering the next stage of CBAM implementation: it must be procured in ways that remain system-realistic under grid constraints while still producing renewable attributes that EU counterparties can accept for embedded-emissions claims across product categories covered by CBAM’s initial scope.