Analysis developed by Virtu.Energy
Banks financing Southeast European manufacturers increasingly need to assess whether the borrower can preserve its EU export margin after electricity costs, embedded emissions and supplier-data requirements are included. A factory can maintain production, improve energy efficiency and still lose competitiveness if its EU customer faces a higher carbon liability or cannot substantiate the emissions attached to the goods.
For Serbia, Montenegro, Bosnia and Herzegovina, North Macedonia and Albania, the investment challenge extends beyond purchasing renewable electricity. Manufacturers need to understand their production route, the treatment of relevant precursors and the evidence that allows an EU importer to use their emissions data.
The economic exposure has several layers. Electricity determines part of the factory’s operating cost. Domestic carbon pricing may affect direct emissions and energy supply. CBAM applies to covered goods entering the EU, while buyers may impose broader environmental requirements through procurement contracts.
Those layers do not produce one universal surcharge. Their importance varies by product, technology and commercial arrangement. A steel producer using a blast furnace faces a different investment problem from an electric-arc-furnace mill, while an aluminium rolling business needs to assess purchased metal alongside its own conversion process.
The current CBAM scope covers specified goods in iron and steel, aluminium, cement, fertilisers, electricity and hydrogen, including selected precursors. Coverage is determined through the goods and their classification rather than simply the company’s industry label.
That is the starting point for a useful credit assessment. A bank should establish which products the borrower exports, their EU destinations, their tariff classifications and the proportion of revenue dependent on customers that import covered goods.
A manufacturer producing several product families may have materially different exposures within the same factory. Applying a single estimated carbon charge across its turnover can distort both the risk assessment and the investment response.
The distinction is particularly important for electricity consumed in production. Current definitive-period rules generally exclude purchased-electricity indirect emissions from the calculation for steel and aluminium goods listed in Annex II. Cement, fertilisers and agglomerated iron ore have relevant indirect-emissions coverage, with detailed rules governing precursor contributions.
A renewable PPA can therefore deliver substantial benefits without reducing every current CBAM liability. It may stabilise electricity costs, improve the product’s wider carbon footprint and satisfy customer requirements. Its direct effect on the CBAM calculation depends on the goods and emissions that the rules actually cover.
This distinction should guide investment priorities. A manufacturer should calculate the energy savings and carbon savings separately, then assess how each changes its EU selling position. Combining them into an undefined “green premium” makes it harder to determine whether the proposed capital expenditure can repay its cost.
Steel provides the clearest regional example. HBIS Serbia’s Smederevo production configuration includes blast furnaces and a converter shop, while Makstil in North Macedonia describes an electric-arc-furnace steel shop producing slabs for its plate mill. The different routes create different priorities for energy procurement, raw materials and direct-emissions reduction. These descriptions do not establish either company’s current verified emissions intensity.
For a blast-furnace operation, purchasing renewable electricity cannot eliminate emissions arising from coke-based ironmaking. The larger investment questions concern fuel and reductant use, process efficiency, the input mix and the feasibility of changing the production route.
An efficiency retrofit can still create value. Lower fuel consumption reduces operating costs and may reduce relevant emissions. However, the financial benefit should be compared with the plant’s expected operating life, maintenance requirements and the future competitiveness of its product.
For an electric-arc-furnace producer, electricity procurement takes a larger role in operating economics. Scrap quality, metallic yield, electrode consumption, fuel use and any purchased iron-bearing inputs remain relevant to the overall assessment.
A low direct-emissions profile does not protect the business from a power-price shock. An EAF mill may face a modest CBAM exposure for its own process yet experience substantial margin pressure when electricity prices rise or scrap becomes more expensive.
An illustrative calculation demonstrates the difference. Assume a plant uses 0.50 MWh of electricity per tonne of steel. A €30/MWh increase in its delivered electricity price adds €15 per tonne to production cost. At 300,000 tonnes of annual output, that is €4.5 million before any offsetting changes in production, efficiency or selling prices.
These are assumed operating values, not a forecast for a named producer. They show why a bank must examine electricity costs even where purchased-power emissions are excluded from the current CBAM calculation for the finished product.
Procurement can address some of that risk, but contract structure matters. A fixed-price PPA should be evaluated together with profile charges, balancing, network costs and replacement electricity. A low headline energy price does not establish a low delivered cost.
Industrial demand is also different from renewable generation. A continuous production process may need power when a solar plant produces little or nothing. A wind PPA can improve diversification while leaving substantial hourly shortfalls. The value of the arrangement depends on who covers those gaps and at what price.
Aluminium creates another distinction between the factory and its upstream supply chain. Impol Seval describes its Serbian production through casting, hot rolling and cold rolling. For this type of manufacturing, electricity and heat efficiency matter, but the purchased aluminium and relevant upstream production history also require assessment.
A processor buying primary metal is exposed to a different upstream profile from a business using qualifying scrap inputs. A change in the feedstock mix may improve competitiveness, but it must also meet product specifications and maintain yield.
The investment case therefore needs to include metallurgy and customer acceptance. A cheaper or lower-emission input can be commercially unsuitable if it increases rejects, requires additional processing or fails to meet the buyer’s requirements.
For aluminium producers, renewable electricity can be especially important to the wider product footprint and customer procurement. Yet a bank should not count an assumed reduction in current CBAM certificates unless the reduction is supported by the applicable emissions rules.
Direct emissions and relevant precursor emissions remain separate concerns. A rolling or remelting investment that improves electricity efficiency does not necessarily change the emissions attributed to purchased unwrought aluminium. Conversely, a better-documented metal supply can improve the buyer’s assessment even where the processor’s own electricity contract is unchanged.
Cement and fertilisers require a different allocation of capital. Their applicable electricity-related emissions mean renewable procurement can have a more direct role in reducing the relevant embedded-emissions calculation, provided the accounting conditions are met.
But the largest operational emissions may lie elsewhere. A cement investment needs to consider clinker content, kiln fuel, thermal efficiency and process emissions. A fertiliser investment needs to assess its feedstock and production chemistry alongside electricity consumption.
Electrification can improve a production route, but its value depends on the electricity price and the emissions treatment. Replacing fuel with electricity may reduce direct emissions while increasing exposure to power costs. The project needs to be assessed across both dimensions rather than promoted through the equipment’s technology label.
For banks, a practical approach is to calculate the cost of each measure per unit of output and per tonne of relevant emissions avoided. That allows comparisons among maintenance improvements, heat recovery, renewable procurement, process conversion and larger production-route changes.
The precursor chain adds a further source of commercial risk. A SEE manufacturer may purchase pig iron, DRI, slabs, billets or aluminium inputs from Türkiye or another third market and process them before export to the EU.
Regional processing does not automatically remove the relevant embedded emissions of those inputs. The accounting needs to follow the prescribed production boundaries and precursor rules, while customs origin is assessed through its own requirements.
For steel, the Commission’s guidance states that actual data for externally produced precursors need an appropriate verification report covering the relevant production period and accredited scope; otherwise, applicable default values are used. Relevant precursor indirect emissions can also enter the final calculation where the rules require them.
This makes procurement documentation part of the material’s value. Two suppliers can offer the same grade at similar prices while creating different downstream risks because one provides usable emissions evidence and the other does not.
The cheaper invoice may therefore produce the more expensive EU delivery. The manufacturer needs to compare the purchase price with the effect on the importer’s carbon calculation, verification costs and confidence in the supply chain.
Long-term supply contracts should address that issue before production begins. Useful terms would identify the producing installation, relevant production period, evidence required, update obligations and the treatment of missing or corrected information.
The same discipline is needed inside the factory. A reliable emissions calculation requires production quantities, fuel use, material inputs and allocation methods that reconcile with operational records.
A spreadsheet prepared at year-end cannot necessarily reconstruct missing measurements or distinguish products that shared equipment. The manufacturer needs a monitoring system designed around the actual production processes, with responsibility for data quality assigned to operations, procurement, finance and management.
The commercial purpose is straightforward: allow the EU buyer to connect imported quantities with a defensible emissions figure. A complete file should make that connection understandable rather than leave the importer to interpret disconnected energy bills, supplier declarations and production summaries.
Corporate carbon accounting can support the broader management system, but it should not be assumed to provide the required product calculation. A company-wide emissions total does not reveal how emissions should be attributed to each covered good.
That distinction also limits the use of marketing claims. “Low-carbon”, “renewable-powered” and similar descriptions can be commercially useful only when the buyer understands the boundary and supporting evidence. A broad product-footprint claim and a CBAM embedded-emissions calculation may cover different sources.
EU importers have a strong incentive to demand clarity because the declarant retains legal responsibility for its obligations, even when technical work is delegated to service providers. Contractual support from a manufacturer or consultant does not remove that responsibility.
The likely commercial consequence is more selective purchasing. An importer may favour a supplier with slightly higher material prices if its verified data reduce uncertainty and administrative costs. Another buyer may negotiate a larger discount where evidence is incomplete.
Those responses should be treated as commercial possibilities rather than uniform market behaviour. Their scale will depend on competition, product availability, the buyer’s own capabilities and the difference between actual and applicable default emissions.
The certificate price is another variable. At €82.32/tCO₂e, a difference of 0.50 tCO₂e per tonne of goods corresponds to €41.16 per tonne in gross carbon-price exposure before the relevant adjustments. For 100,000 tonnes, that amounts to €4.116 million.
The calculation is a sensitivity measure, not a final CBAM invoice. Industrial liability needs the appropriate free-allocation adjustment and any eligible carbon-price deduction. The Commission’s guidance sets out product- and precursor-related calculations for that adjustment; multiplying total emissions by a universal phase-in percentage can therefore misstate the exposure.
Nevertheless, the sensitivity is useful for financing decisions. It shows how an emissions-data problem can become material to customer negotiations and cash flow even when the manufacturer does not purchase the certificates itself.
Banks should therefore assess the borrower’s EU sales agreements. If the customer bears the formal liability, it may still seek compensation through lower prices, revised contract terms or reduced orders. The borrower’s exposure depends on bargaining power and the wording of the supply agreement.
Existing loans deserve particular attention. A facility approved before financial CBAM obligations may rely on export volumes and margins that are no longer secure. The review should examine customer concentration, contract renewal dates, emissions evidence and the capital needed to preserve competitiveness.
The objective is an actionable credit assessment. A factory with a manageable compliance gap may need investment in meters and records. Another may need a different precursor supplier. A third may face a production-route problem that cannot be solved through documentation.
Those responses require different financing instruments. A small equipment facility can support metering or efficiency improvements. Working capital can fund a better input mix or carbon-related contract settlement. A major process conversion needs longer-term finance, credible commissioning assumptions and sufficient equity.
The investment sequence matters. Financing a large renewable installation before understanding the factory’s covered emissions may leave the central export risk unresolved. Conversely, delaying basic monitoring work can prevent a manufacturer from demonstrating improvements it has already achieved.
Wider policy changes increase the need for preparation without justifying assumptions that proposals are law. The EU is considering expansion to additional steel- and aluminium-intensive downstream goods, anti-circumvention measures and changes to electricity attribution. The Commission has also published a study on indirect emissions and possible evolution of their coverage.
For manufacturers of components and fabricated products, the sensible response is to map material content, supplier installations and existing data gaps. Investment models should keep current obligations separate from a scenario in which the product enters a wider future scope.
The strongest industrial strategy combines competitive energy procurement, technically appropriate emissions reductions and a supply chain that can support the buyer’s declaration. Each element contributes differently, and none should be credited with benefits it cannot deliver.
SEE’s proximity to EU customers remains valuable, but proximity alone cannot protect a manufacturer’s delivered margin. The factory that can explain its production route, substantiate its inputs and finance the necessary improvements will have a stronger negotiating position than one offering a low price with an unresolved carbon file.
Analysis developed by Virtu.Energy