utility fuel and carbon costs exceeds the incremental operating cost of ethanol production itself. As regulatory frameworks increasingly reward measured carbon- intensity reduction rather than technology choice, this utility displacement becomes directly monetisable. DBCOM captures this effect by extending
Region
Dominant
Annual potential
Key
High potential Integration
North America Corn stover, forestry residues
300+ (Mt/year)
Density variation challenge
Europe
Wheat straw, forestry
150-180
Labour cost
Medium
India/ASEAN
Rice & cereal residues 350-400
Seasonal spikes
Very high Medium
Africa
Bamboo, sorghum
100+ 200+
Logistics Transport
Latin America Cane trash, eucalyptus
High
Middle East
MSW fibres
30-50
Feedstock diversity
Growing
Regional biomass availability is derived from consolidated IEA Bioenergy and FAO assessments of recoverable agricultural, forestry and MSW based residue, reflecting technical rather than theoretical potential (IEA Bioenergy, 2024) (FAO, 2024).
Table 1 Global biomass supply landscape
from fragmented agricultural residues into reliable industrial feedstocks capable of supporting large-scale 2G ethanol deployment. Advances in mechanised harvesting, densification, digital aggregation platforms, and predictive residue mapping have transformed what was once a logistical bottleneck into a managed commodity. Agricultural residues are now secured through stable offtake contracts, enabling year-round availability at predictable costs across multiple regions. This maturity is reflected in global residue potential, where logistical constraints are increasingly outweighed by integration benefits. For DBCOM- integrated ethanol, reliable biomass supply is critical, enabling continuous lignin-derived steam generation and sustained refinery utility decarbonisation (see Table 1 ). Economic reality: why integration redefines cost competitiveness Once system boundaries are expanded beyond the biorefinery fence line, the economics of 2G ethanol change fundamentally. The decisive factor is not feedstock or enzyme cost, but the value created through refinery utility displacement and carbon monetisation. Refineries typically generate steam and power using fossil fuels, with utilities contributing roughly 10-25% of Scope 1 emissions and a significant share of operating cost. When lignin- derived steam from an integrated 2G ethanol plant displaces fossil-fired boilers, refinery fuel consumption declines, operational emissions fall, and carbon compliance exposure is reduced. In many cases, the combined value of avoided
carbon accounting beyond transport fuels to refinery utilities, converting decarbonisation from a compliance burden into a revenue- aligned outcome. Integration further lowers capital intensity: co-location avoids redundant boilers, cooling systems, water treatment, and transmission infrastructure, reducing Capex by approximately 8-12%. On a system basis, integrated 2G ethanol can therefore compete economically with 1G pathways despite higher standalone costs. Marginal abatement cost: moving 2G ethanol into the low-cost tier Marginal abatement cost (MAC) compares the cost of avoiding one tonne of CO₂ across decarbonisation options. MAC is context dependent and varies with region, energy prices, asset configuration, and integration level. The values shown are therefore indicative ranges used for relative comparison rather than precise project economics. High-impact refinery pathways such as green hydrogen and e-fuels typically exceed $150-400/t CO₂, while CCS occupies a mid- cost range. Under DBCOM, refinery-integrated 2G ethanol consistently falls into the low-cost tier. Standalone 2G ethanol delivers carbon abatement at roughly $70-110/t CO₂, while integrated deployment reduces this to $50-85/t CO₂ by capturing utility displacement benefits. This places 2G ethanol alongside the most cost-effective refinery decarbonisation options while offering immediate scalability, asset compatibility, and dual-boundary impact (see Figure 1 ).
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