When the CBAM lens that has already reshaped thinking on green electricity is applied rigorously to natural gas, the conclusion is stark. Gas does not behave like a neutral transition fuel in a CBAM-constrained export economy. It behaves like a structural risk variable whose price volatility, emissions intensity, and perception by EU buyers increasingly determine whether Serbian industry retains margin or slowly loses competitiveness. Gas does not fail because it is unavailable. It fails because, under CBAM logic, it cannot deliver long-term certainty.
The core mistake in Serbia’s industrial energy debate is treating gas as a question of access and unit price. That framing belonged to a pre-CBAM world. Under CBAM, the relevant question is how much carbon-adjusted gas cost is embedded in each exported tonne, how volatile that exposure is over time, and how credible the exit pathway looks to EU procurement teams. Once electricity is partially decarbonised, gas becomes the dominant residual emissions signal—and buyers notice.
Gas enters CBAM exposure through three overlapping channels, and all three compound rather than offset each other. The first is direct emissions. In fertilisers, cement, chemicals, and parts of metals processing, gas combustion remains a primary source of reportable CO₂. Under CBAM, these emissions become visible at the border regardless of Serbia’s domestic carbon policy. The second channel is indirect cost transmission. Gas continues to set the marginal price of electricity across much of the region, meaning gas volatility feeds back into industrial power costs even when electricity procurement improves. The third channel is behavioural. EU buyers increasingly interpret gas-heavy production as transition-fragile. Even if formal CBAM charges are initially modest, suppliers whose cost base and emissions trajectory remain anchored to gas are scored as higher risk.
What makes gas especially problematic under CBAM is the non-linearity of its impact. A relatively small increase in gas price or gas intensity can trigger a disproportionate competitiveness penalty once buyers internalise future compliance risk. This is not because gas suddenly becomes unaffordable in absolute terms, but because it becomes unpredictable in carbon-adjusted terms. Under CBAM, unpredictability is punished faster than high average cost.
This is why the metric that matters is no longer gas price per megawatt-hour, but gas intensity per tonne of output, adjusted for emissions. Two Serbian producers paying the same price for gas can face radically different CBAM outcomes depending on how much gas is embedded in their product. In fertilisers, gas can represent 60–80% of variable production cost and the majority of direct emissions. In cement, gas may be secondary to process emissions but still materially increases the CBAM burden. In downstream metals processing, gas intensity varies widely, but once electricity is cleaned up, that variation becomes highly visible.
EU buyers prioritise what they see as “avoidable” emissions first. Electricity is the first lever. Gas is the next. A supplier that cleans its electricity footprint but leaves gas intensity untouched is not viewed as low-risk; it is viewed as halfway through a transition with uncertain completion. That perception alone is enough to affect pricing, contract duration, and volume allocation.
Gas price volatility amplifies this effect. Volatility functions as a hidden CBAM surcharge even before any formal carbon payment is made. A Serbian exporter operating with gas costs of €35–45/MWh in stable periods may face €60–80/MWh during stress. That swing feeds directly into unit costs and emissions intensity. Even if CBAM charges per tonne remain constant, the exporter’s delivered price becomes unstable relative to EU competitors who are increasingly insulated by electrification and renewable procurement. Buyers respond to that instability by discounting the supplier, shortening contracts, or reallocating volume.
Just as with electricity, variance matters as much as averages. A gas-heavy cost base with high volatility is treated as a supply risk. A stable but gradually declining gas footprint is treated as manageable. Under CBAM, predictability is a commercial asset.
The same aggregation logic that has proven decisive for electricity can be applied—partially—to gas. Aggregating industrial gas demand across sites and time blocks allows buyers to smooth procurement, reduce exposure to spot spikes, and lower effective costs by €5–10/MWh relative to unmanaged exposure. Storage optimisation and indexed contracts further reduce volatility. These tools matter, but they address only one dimension of the problem. They stabilise price. They do not reduce emissions.
This is where gas fundamentally loses the CBAM contest to electricity. Electricity decarbonisation converts a volatile, high-visibility emissions source into a lower-risk input that buyers can audit and reward immediately. Gas optimisation, even when executed well, leaves the emissions profile largely intact. From an investor and buyer perspective, this means gas can be managed, but it cannot be the foundation of a CBAM defence strategy.
The capital efficiency comparison is revealing. Deploying €1 billion into renewable electricity and aggregation can defend 2–3 TWh of green supply and materially improve buyer scoring across multiple export sectors. Deploying the same capital into gas infrastructure, hedging, or efficiency measures may stabilise costs temporarily, but it does not materially change CBAM exposure once electricity is cleaned up. This asymmetry explains why EU buyers increasingly view gas-heavy production as transitionally constrained rather than transitional.
As electricity decarbonisation advances, gas becomes the dominant residual risk. Exporters who solve electricity but leave gas untouched move from high risk to medium risk, but they do not become preferred suppliers. Their transition narrative stalls. Buyers accept them provisionally, but not strategically. Over time, that distinction translates into weaker bargaining power and thinner margins.
The sequencing implication is unavoidable. First, electricity must be cleaned to stabilise indirect emissions and restore buyer confidence. Second, gas intensity per tonne must decline through efficiency, electrification, and selective fuel switching. Third, residual gas use must be transparently ring-fenced within a credible transition pathway. Reversing this sequence fails, because gas optimisation without clean electricity does not change buyer behaviour, while clean electricity without gas reduction only postpones the next repricing.
A CBAM-credible gas strategy for Serbia therefore has a clear structure. It begins with explicit gas-intensity baselines by product, not generic fuel statistics. Buyers care about emissions per tonne, not national averages. It continues with price-and-variance control through aggregation and contract design, ensuring that gas volatility does not destabilise margins. It then prioritises electrification of marginal gas uses where green electricity is available, delivering a double benefit of lower emissions and lower CBAM visibility. Finally, it communicates a transparent residual gas pathway with defined milestones, because uncertainty is penalised more heavily than imperfection.
The strategic conclusion mirrors the lesson learned in electricity. Gas cannot be Serbia’s CBAM shield. It can only be a shrinking residual input within a broader transition architecture. Electricity determines whether Serbian exporters remain competitive in the near term. Gas determines whether that competitiveness is sustained or gradually eroded.
Under CBAM, gas is not a bridge unless it is visibly shortening.
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