The commercial meaning of electricity in South-East Europe has changed. For decades it was treated primarily as an input cost, volatile but manageable, important for margins but rarely decisive in strategic trade positioning. Under the EU’s Carbon Border Adjustment Mechanism, that logic no longer holds. Electricity has become part of the carbon content of traded goods, which means it now affects export competitiveness not only through the wholesale price paid by a steel mill, aluminium producer or fertiliser plant, but through the embedded emissions that must be reported and, from the definitive phase, financially absorbed at the border. CBAM entered its definitive regime on 1 January 2026 after the transitional phase that ran from 2023 to 2025, and the core sectors in scope remain iron and steel, aluminium, fertilisers, cement, hydrogen and electricity.
That shift is especially important in South-East Europe because the region still combines high industrial electricity intensity with power systems that are unevenly decarbonised. A Serbian steel exporter, a Balkan aluminium producer or a fertiliser supplier selling into the EU is no longer competing only on labour cost, logistics and raw materials. It is also competing on the carbon profile of every megawatt-hour consumed in production. The practical consequence is that electricity pricing, procurement structure and source attribution move from the treasury department into the export strategy of the business. The project-finance consequence is equally important: low-carbon electricity becomes a premium product that can support stronger PPAs, higher revenue stability and better debt terms for renewable assets.
The regulatory logic is explicit. The European Commission’s CBAM guidance and implementation material make clear that embedded emissions for relevant goods are not limited to direct process emissions. They also include, in defined cases and by methodology, indirect emissions associated with electricity consumed in production. In other words, the power used inside the plant is no longer a separate procurement issue sitting outside trade compliance; it is increasingly part of the carbon cost stack of the exported product itself. That is why the distinction between direct and indirect emissions has become commercially material for industrial producers across the Western Balkans and wider SEE region.
The first months of the definitive phase also reveal where the pressure is concentrated. In the European Commission’s January 2026 snapshot of initial CBAM declarations, iron and steel accounted for 98% of the reported volume, while fertilisers represented 1.2%, cement 0.5%, aluminium 0.3%, and electricity and hydrogen were still negligible in the early data capture. That distribution matters for South-East Europe because the region’s most exposed tradable industrial base still sits in steel, metals and fertiliser-adjacent value chains rather than in the narrower direct electricity-export category. For Serbia in particular, the implication is clear: the commercial impact of CBAM will be felt first and hardest through industrial electricity procurement inside steel and metals production, not through power exports as such.
Serbia is the clearest test case. HBIS Serbia, the operator of the Smederevo steel complex, is not a marginal exporter. The company’s latest corporate materials describe annual production capacity of 2.2 million tonnes, more than 5,000 employees, two blast furnaces and an integrated hot and cold rolling platform. In parallel, its public ESG and corporate materials show a strong focus on energy management, efficiency and long-duration power arrangements, including the company’s own 2025 communication that the plant would receive electricity under a 25-year contractual structure involving both EPS and renewable sources. That is not a cosmetic decarbonisation gesture. It is exactly the type of electricity-procurement repositioning that CBAM makes economically rational: reduce exposure to volatile wholesale prices, improve traceability, and lower the embedded carbon burden of exported steel.
Once the steel example is understood, the pricing implications become much more tangible. A large integrated steel plant can consume electricity at a scale where a €10/MWh difference in procurement cost or structured renewable supply premium translates into millions of euros per year. If an industrial consumer uses 1 TWh annually, every €1/MWhchange in the effective electricity price is worth €1 million on the cost base. At 2 TWh, that becomes €2 million per €1/MWh. In a CBAM environment, this no longer measures only commodity-cost exposure; it also measures the economic value of moving from generic grid power toward better-documented, lower-carbon electricity. A premium of €5–15/MWh for structured renewable supply can therefore still make sense if it reduces the carbon-adjusted export burden or strengthens customer acceptance in EU markets. That is why “CBAM-safe electricity” is emerging as a commercially meaningful concept rather than a policy slogan. The mechanism itself does not use that phrase, but the market increasingly does.
The effect is not limited to steel. Aluminium and fertilisers are also directly exposed. The Commission’s own sector list keeps both within the CBAM scope, and the methodology around direct and indirect emissions means electricity intensity matters materially for both. Aluminium is especially sensitive because electricity has always been central to the economics of the value chain. Fertilisers remain more directly gas-linked in process economics, but electricity still enters through plant operations, auxiliary systems and, in some pathways, process configuration. The strategic implication is that South-East Europe’s industrial base is being pushed toward a three-part electricity agenda simultaneously: lower carbon intensity, stronger documentation, and greater price certainty.
That is where the power market and industrial strategy converge. A merchant renewable asset in South-East Europe has traditionally been valued against wholesale prices shaped by Greek gas-to-power volatility, Romanian and Hungarian forward curves, Serbian coal baseload and regional congestion. Under CBAM, part of that merchant demand begins to convert into structured industrial demand. The buyer is no longer a utility or a generic trader alone. It is increasingly a steelmaker, metals processor or export manufacturer that wants electricity not merely as a cost hedge, but as part of a compliance and sales architecture. For developers, this creates a qualitatively different offtaker profile. For lenders, it creates a qualitatively different credit story.
The premium this can support is financially meaningful. In current South-East European conditions, industrial renewable PPAs are already being discussed and structured in broad ranges around €65–95/MWh depending on country, profile, firmness and credit quality. In a CBAM-driven context, the relevant comparison is not the cheapest available wholesale hour. It is the all-in cost of compliant supply versus non-compliant or poorly documented supply. If an industrial offtaker is willing to pay a €5–15/MWh premium for lower-carbon, traceable electricity, that premium feeds directly into project bankability. On a 100 MW solar project producing 140–160 GWh per year, a €10/MWh pricing uplift is worth roughly €1.4–1.6 million annually in incremental revenue. On a 200 MW wind project generating 600–700 GWh, the same uplift becomes €6–7 million per year. That scale is large enough to alter DSCR, debt sizing and sponsor returns.
Consider a stylised Serbian renewable project selling into a pure merchant environment. A 100 MW solar plant in a moderately constrained node with CAPEX of €70–85 million might, after capture discounts and curtailment, realise annual revenue of €8–11 million. Under merchant assumptions and sovereign-plus-project debt pricing, that may support leverage of only 55–65% and require minimum DSCR of 1.40x–1.50x. Replace part of that merchant exposure with a long-term industrial offtake linked to CBAM-sensitive demand and a €8–12/MWh premium, and the project’s revenue visibility improves enough that leverage can move toward 65–75%, with DSCR requirements easing toward 1.30x–1.40xin stronger structures. The project has not changed technology. The demand quality has changed.
This is where the Serbian industrial and power markets begin to reinforce each other. Serbia’s own official energy statistics show that end-user electricity consumption remains large, while industry continues to be central to the national consumption profile. At the same time, the country’s 2024 energy picture showed increased imports and tighter system conditions, underlining that not all industrial decarbonisation can be solved through generic grid supply. Large users need more certainty than the market can provide on a purely spot basis. CBAM therefore turns industrial electrification and renewable procurement into part of the same strategic problem.
The same logic is visible beyond Serbia. Across the Western Balkans and wider SEE space, exporters selling steel, metals, cement or fertiliser products into the EU increasingly need defendable carbon data, not only lower average emissions. This is why documentation and methodology matter as much as the physical power source. The 2025 CBAM simplification changes adopted in the EU reduced administrative burdens for many importers, including through a 50-tonne de minimis threshold for certain importers, but they did not remove the core carbon-pricing logic for the relevant industrial flows. The burden is therefore being rationalised, not reversed.
There is also an overlooked timing effect. Developers often think of CBAM as a demand-side theme that will support pricing later. In fact, it is already affecting procurement decisions now because industrial counterparties are redesigning contracts before they are forced into more expensive positions. That gives early renewable developers an advantage. A project reaching commercial structuring while industrial buyers are still building their electricity compliance architecture may secure a longer tenor, stronger covenants and better price escalation than a project arriving later into a more crowded market.
Storage enters this story because CBAM-sensitive offtakers rarely want intermittent electricity exposure without shaping or firming. A steel plant does not shut down because solar output drops. A metals processor does not want all of its renewable value delivered into the lowest-priced midday block. So the premium end of this market increasingly belongs to hybrid structures: wind plus balancing, solar plus BESS, or portfolios routed through traders that can sleeve and firm supply. For a 100 MW solar + 200 MWh BESS hybrid, the battery can recover part of the capture discount and create a flatter delivery profile, raising the effective value of power sold into a CBAM-driven industrial contract. That can add €8–20/MWh of realised value in high-volatility markets and turn a weak merchant solar case into a robust contracted industrial case.
Node-level pricing, congestion exposure, curtailment risk, balancing value and industrial load proximity all now influence whether a renewable project can become part of a CBAM-ready offtake structure. In that environment, the best route to market may not be the highest average power price. It may be the strongest combination of traceability, firmness and industrial relevance.
For investors, the wider conclusion is that CBAM is changing the demand composition of the SEE power market. It is converting part of industrial electricity procurement from generic commodity buying into creditworthy, compliance-driven contracting. That supports renewable revenue floors, particularly for assets that can demonstrate low-carbon supply and credible delivery. It also increases the value of projects located near large exporters or capable of serving them through structured offtake.
For industrial companies, the conclusion is equally stark. Electricity can no longer be optimised on price alone. It must increasingly be optimised on price, carbon content and provability. In a market where every €1/MWh matters at scale, and where every tonne of embedded emissions can affect trade economics, the cheapest power contract is not always the most competitive one.
That is the deeper effect of CBAM across South-East Europe. It does not simply add a border tax. It reorganises the value of electricity inside the region’s industrial system. It makes power origin more important, contract structure more strategic and renewable procurement more central to export competitiveness. In practical financial terms, it turns electricity from a pass-through cost into a measurable carbon asset.