Domestic renewable PPAs can protect operating margins, but they do not automatically reduce the EU carbon liability attached to Serbian exports.
The European Union’s Carbon Border Adjustment Mechanism entered its definitive phase on 1 January 2026, turning carbon reporting into a direct commercial issue for Serbia’s steel, aluminium, fertiliser and cement producers. The first two published CBAM certificate prices were €75.36 per tonne of CO₂ for the first quarter of 2026 and €75.28 for the second quarter, giving Serbian exporters and their EU customers a measurable carbon-price reference rather than an abstract future risk. European Commission CBAM certificate prices
The immediate challenge for Serbian companies is not simply to purchase more renewable electricity. It is to distinguish between three transactions that are often treated as though they were interchangeable. A Serbian factory consuming Serbian electricity is making a domestic power purchase. A Serbian factory exporting steel, aluminium, fertiliser or cement to the EU is participating in a product-CBAM transaction. A company physically delivering Serbian electricity across the EU customs border is participating in an electricity-as-a-good CBAM transaction. Ownership does not alter this classification: a German-, Chinese-, Slovenian- or Irish-owned factory operating in Serbia is still consuming electricity in Serbia.
That distinction changes the commercial value of a renewable PPA. For a Serbian manufacturer, a wind or solar contract can hedge electricity expenditure, reduce exposure to wholesale volatility and support corporate emissions targets. It does not, by itself, provide a blanket exemption from CBAM on products exported to the EU. For a trader physically importing Serbian electricity into Hungary, Romania, Croatia or Bulgaria, the electricity-specific rules apply directly, including the choice between a regulatory default factor and verified actual emissions.
The difference is particularly important for HBIS Group Serbia, the Chinese-owned operator of the Smederevo steelworks and the Šabac tinplate facility. The company has designed capacity of about 2.2mn tonnes of finished steel products a year and employs approximately 5,000 people, making it one of Serbia’s largest industrial employers and exporters.
A domestic wind PPA could give HBIS greater predictability over part of its electricity bill and improve the market-based emissions profile of purchased power. It would not remove the carbon cost associated with blast-furnace ironmaking, coke use and other direct production emissions embedded in steel sent to the EU. The steelworks needs a product-level CBAM system connecting installation emissions, production batches, electricity consumption, input materials and EU import declarations. Electricity procurement is one component of that system, not the complete answer.
The same principle applies differently at Impol Seval in Sevojno. The aluminium rolling company, controlled by Slovenia’s Impol Group, produced approximately 52,632 tonnes in 2024, an increase of 29.1 per cent from the previous year. Its exposure is not identical to that of a primary aluminium smelter because the plant processes aluminium into sheets, strips and other rolled products. Its CBAM position depends on product codes, imported or purchased aluminium inputs, upstream embedded emissions and the treatment of the Serbian processing stage.
For Impol Seval, renewable electricity can carry greater relative value than it does for an integrated blast-furnace steelworks because electricity is an important part of rolling, reheating, finishing and auxiliary consumption. Yet the company still has to trace the carbon intensity of slabs, ingots and recycled material entering the production chain. A Serbian PPA cannot erase upstream smelting emissions contained in imported aluminium feedstock. The group’s declared target to reduce emissions intensity by 58 per cent per tonne of aluminium by 2030, relative to 2021, therefore requires a combination of low-carbon inputs, recycling, process efficiency and renewable power rather than a certificate-led procurement strategy alone.
The financial stakes are equally visible at Elixir Group, Serbia’s principal phosphoric-acid and complex-fertiliser producer. Elixir Prahovo reports annual capacity of approximately 165,000 tonnes of phosphoric acid and 300,000 tonnes of NPK fertiliser. The group invested €179mn during 2025 as part of its Prahovo 2027 development programme, covering new phosphoric-acid capacity, crystalline fertilisers and energy recovery from waste.
Elixir also raised RSD4.1bn, equivalent to roughly €35mn, through a five-year green bond carrying a 6 per cent fixed annual coupon. The financing supported a new technical monoammonium-phosphate plant in Prahovo, while Scope assigned the group an issuer rating of BB/Stable. More than 70 per cent of production has historically been exported, creating a direct connection between carbon performance, export margins and debt-service capacity.
A renewable PPA can reduce electricity-price volatility at Prahovo and Šabac, but fertiliser CBAM calculations are shaped by more than purchased electricity. Feedstock, ammonia-related emissions, process heat and the exact fertiliser formulation can carry greater carbon weight. Elixir therefore needs product-specific verified data alongside its power-procurement records. The company’s €179mn investment cycle strengthens production capacity, but it also raises the amount of fixed capital whose returns depend on maintaining access to EU and global markets.
Serbia’s cement industry faces a similar split. Moravacem, part of Ireland-based CRH, operates the Popovac plant with annual capacity of approximately 1.35mn tonnes of cement and binders. Holcim Serbia operates the Beočin cement plant, while Titan Cementara Kosjerić remains another large producer.
Wind and solar contracts can stabilise electricity OPEX at these plants, but cement’s dominant emissions source is the chemical conversion of limestone into clinker, combined with thermal fuel consumption. The most important CBAM levers remain the clinker ratio, fuel mix, kiln efficiency, alternative fuels and carbon intensity of production. Renewable electricity supports the programme but cannot substitute for clinker decarbonisation.
The commercial logic changes when Serbian electricity itself is imported into the EU. The normal starting point is the applicable electricity default factor. Claiming plant-specific actual emissions is an exception requiring a complete evidence chain. The electricity must be covered by a qualifying PPA between the authorised CBAM declarant and the Serbian producer. The generator must be directly connected to the EU transmission system or the parties must demonstrate the required absence of physical congestion. The installation cannot emit more than 550g of fossil CO₂ per kWh. Generation and cross-border nominations must match for a period no longer than one hour, and the complete chain must be certified by an accredited verifier receiving at least monthly information. EU CBAM electricity criteria
A guarantee of origin does not satisfy these conditions. Neither does a corporate claim that the buyer consumes “100 per cent renewable electricity”. A conventional chain of back-to-back contracts among a Serbian generator, trader, supplier and EU industrial customer may also fail unless the contractual structure preserves the required relationship with the authorised CBAM declarant.
The cost difference is already material at the published second-quarter certificate price of €75.28 per tonne. A planning scenario using an electricity factor of 0.5–0.8 tonnes of CO₂ per MWh produces a CBAM cost of approximately €37.64–€60.22 per MWh. This is a sensitivity range rather than an estimate of Serbia’s official country default, but it illustrates the financial scale.
For an EU buyer importing 100GWh a year, failure to qualify for actual emissions could add €3.8mn–€6.0mn annually. A Serbian renewable offer priced at €55–70/MWh, combined with €10–20/MWh for cross-border capacity, losses, balancing and trading, could produce a delivered cost of about €66–93/MWh when plant-specific low emissions are accepted. The same transaction under full default-factor fallback could move towards €104–153/MWh, before taxes and buyer-specific charges. The value lies in verified eligibility, not in the renewable label.
The Serbian renewable pipeline is becoming large enough to support more industrial contracting. The first two auction rounds allocated close to 1.3GW of wind and solar capacity. The second round alone attracted 41 proposals and awarded support to projects totalling as much as 645MW, with bids reaching €50.9/MWh for solar and €53.6/MWh for wind. These auction prices provide useful cost discovery, although they should not be mistaken for corporate PPA offers available to every industrial consumer. EBRD review of Serbia’s second auction
The financing record is also improving. Enlight Renewable Energy’s 94.4MW Pupin wind farm carried a disclosed project cost of approximately €144mn, supported by about €91.4mn from the EBRD and Erste. Masdar and Taaleri Energia reached financial close on the 154MW Čibuk 2 project with €144mn of non-recourse debt from UniCredit and Erste. Čibuk 2 shares a grid connection with the existing 158MW Čibuk 1, reducing part of the infrastructure and connection risk.
Using recent Serbian and regional construction benchmarks, a mixed 1.3GW wind and solar portfolio represents an indicative investment envelope of around €1.4bn–€1.9bn. The working assumptions are €1.3mn–€1.6mn per MW for onshore wind and €0.55mn–€0.75mn per MW for utility solar, excluding exceptional grid reinforcements and long-duration storage.
A contracted Serbian wind project can support a base equity IRR of approximately 10–13 per cent, with an upside case of 13–15 per cent where output, market prices and balancing costs outperform. Solar can support approximately 9–12 per cent in the base case and 12–14 per cent in an upside case, but it is more exposed to falling midday capture prices as regional photovoltaic capacity expands.
Grid delays quickly weaken those returns. A 12–18 month connection delay can reduce wind equity IRR by around 2–3 percentage points, reflecting foregone generation, interest during construction and extended guarantees. Solar can lose 2.5–4 percentage points because the delayed project may enter a market with greater midday price cannibalisation than assumed at investment approval. Wind loses more absolute generation during curtailment because of its higher capacity factor, but it retains a broader production profile and stronger system value.
A 3 per cent wind-curtailment case can reduce equity IRR by roughly 0.4–0.8 percentage points. For solar, combined physical curtailment and capture-price deterioration of 5–8 per cent can cut equity returns by 0.8–1.8 percentage points. These sensitivities make grid location, nomination capability and connection rights as important as turbine or module selection.
Serbian industrial buyers should therefore contract wind and solar differently. HBIS, Elixir and cement producers operate substantial, relatively continuous loads, giving wind a better natural fit across seasons and hours. Solar can remain attractive for daytime demand at Impol Seval, food processors, logistics sites and other facilities with predictable daylight consumption. A fixed baseload product sold from a standalone solar plant requires explicit disclosure of where night-time replacement electricity comes from, how it is priced and which emissions factor applies.
Battery storage improves shaping and balancing, but it does not automatically preserve CBAM traceability. A battery charging partly from a renewable installation and partly from anonymous grid electricity needs separate metering and an accepted methodology before its discharged output can be attributed to the renewable generator.
Contracts should separate the PPA price from supplier sleeving, balancing, network charges, environmental attributes and CBAM-related costs. They should identify the exact generating installation, meter, delivery point and interval data. Cross-border structures need a formula allocating the cost of hours that lose actual-emissions eligibility. Data rights, audit access, verifier cooperation and change-in-law provisions are part of the purchased product rather than administrative appendices.
Serbian companies also need three separate but reconcilable ledgers: energy and financial settlement, guarantees of origin and other environmental attributes, and CBAM evidence. Combining them into a single “green electricity” record creates the exact weakness that EU importers, auditors and lenders are likely to challenge.
The first annual CBAM declaration for 2026 imports is due by 30 September 2027, while certificate purchases covering 2026 imports begin in February 2027. Serbian exporters are not always the formal certificate buyer, but the cost will be transmitted through lower netback prices, contractual indemnities, requests for verified installation data and working-capital negotiations with EU customers. The Commission expects the first accredited CBAM verifiers to emerge around September 2026, creating a potential capacity bottleneck for companies that leave verification until year-end. European Commission verification framework
HBIS Serbia, Impol Seval, Elixir Group, Moravacem, Holcim Serbia and Titan Cementara Kosjerić cannot approach this as a sustainability-reporting exercise detached from treasury and procurement. Electricity contracts now affect product margins, customer retention, financing headroom and the credibility of investment programmes. The competitive asset is no longer merely access to Serbian renewable generation. It is the ability to connect each purchased MWh to the correct factory, product, reporting period, contractual counterparty and EU declarant without confusing domestic electricity procurement with the carbon treatment of the exported product.