Global aviation accounts for 2–3% of greenhouse gas emissions today, but without intervention, that share could surge toward 20% by mid-century as passenger vehicles electrify and road freight decarbonizes faster. Sustainable aviation fuel presents the most operationally compatible decarbonization pathway, yet factory-gate costs for electro-SAF remain pinned near $5.27 per kilogram in the European Union—more than six times the $0.77 wholesale kerosene benchmark. A comprehensive techno-economic analysis across multiple production pathways reveals why cost compression has stalled and which policy levers can break the impasse.
The HEFA Plateau and Feedstock Arithmetic
Hydroprocessed esters and fatty acids dominate current SAF output because the chemistry works and the infrastructure exists. HEFA production reached 5.5 billion liters in 2023 and doubled to 13 billion liters in 2024, driven by North American capacity expansions. Factory-gate costs cluster around $1.30 to $1.70 per kilogram across the EU, United States, and Brazil, with feedstock accounting for 40–45% of total expense. This feedstock dominance creates a structural ceiling: used cooking oil, tallow, and waste fats are geographically concentrated, face competing demand from road diesel markets, and cannot scale beyond existing collection networks without displacing food-sector lipids or triggering indirect land-use change.
Monte Carlo simulations using 10,000 draws and correlated cost uncertainties show HEFA’s neat premium averaging $0.61 per kilogram above fossil jet, roughly 80% more expensive. At a 50% blend ratio, the gap compresses to $0.31 per kilogram, equivalent to imposing a $130 per tonne CO₂ carbon price in the EU case. Airlines have absorbed fuel-cost volatility of two to three standard deviations historically through yield management, surcharges, and hedging, placing HEFA blends within operational tolerance. Yet this tolerance does not guarantee voluntary uptake: freight diesel applications, which operate on thinner margins and lag-indexed surcharge formulas, struggle to pass through even the smaller $0.23 per kilogram premium that renewable diesel commands over conventional diesel.
Fischer-Tropsch Capital Intensity and the Gasification Bottleneck
Fischer-Tropsch pathways convert lignocellulosic biomass or municipal solid waste into synthesis gas, then catalytically build paraffinic hydrocarbons. Cost decomposition reveals capital expenditure and site services—gasification trains, oxygen supply, gas cleanup, and Fischer-Tropsch reactors—absorb 30–36% of total outlay, while maintenance and utilities claim another 30–40%. Factory-gate costs range from $1.38 per kilogram in Brazil to $1.62 per kilogram in the EU, tracking regional differences in biomass logistics and industrial tariffs rather than feedstock pricing.
The pathway’s hydrogen intensity registers at just 0.005 kilograms per kilogram of fuel, as most hydrogen derives internally from water-gas shift reactions within the syngas loop. This low external hydrogen dependence insulates Fischer-Tropsch economics from green-hydrogen price swings, but the capital burden remains acute. A biomass-to-liquids rule-of-thumb estimates 5–6 tonnes of biomass per tonne of liquid fuel, contingent on gasifier efficiency and carbon losses. Industrial demonstrations, including UPM’s paper-pulp-forestry residue facility, confirm technical feasibility, yet project finance remains constrained by upfront installed costs and the need for proven gasification-cleanup trains. Sensitivity analysis shows that reducing installed capital by 20% through modularization would cut factory-gate costs more effectively than halving feedstock prices, underscoring the pathway’s engineering rather than commodity exposure.
Alcohol-to-Jet and the Ethanol Integration Mirage
Alcohol-to-jet platforms dehydrate bio-alcohols—ethanol or isobutanol—oligomerize the resulting olefins, then hydrogenate to jet-range paraffins. Factory-gate costs span $1.58 per kilogram in Brazil to $2.11 per kilogram in the EU, with feedstock again claiming 40–45% of the total. Brazil’s advantage reflects proximity to large-scale sugarcane ethanol infrastructure, yet even at the low end, ATJ blends require carbon-price equivalents near $127 per tonne CO₂ to reach parity with fossil kerosene.
Hydrogen demand sits at approximately 0.02 kilograms per kilogram of fuel for saturation and finishing steps, making ATJ moderately sensitive to hydrogen pricing but far less so than electro-SAF. The technology readiness level stands at 7–8, indicating pilot-to-demonstration scale, with some pathways capable of producing aromatic content that conventional HEFA and Fischer-Tropsch routes lack. Aromatics are mandatory for seal swell and density compliance under ASTM D7566 blending limits, positioning ATJ as a potential candidate for higher blend ratios or neat-fuel certification. However, cost structures mirror HEFA’s feedstock exposure, and scaling depends on mobilizing cellulosic or waste-derived alcohol streams rather than diverting food-grade ethanol—a constraint that limits geographic replication outside Brazil and the U.S. corn belt.
Electro-SAF’s Hydrogen Wall and the DAC Multiplier
Electro-SAF via reverse water-gas shift and Fischer-Tropsch synthesis consumes approximately 0.435 kilograms of hydrogen per kilogram of fuel, derived from stoichiometric requirements for a C₁₂ alkane. At EU baseline conditions—$5.60 per kilogram hydrogen and $300 per tonne CO₂ from direct air capture—factory-gate costs reach $5.27 per kilogram. Energy inputs (hydrogen plus electricity) account for 54–56% of total cost, while CO₂ supply claims 22–23%. Blending at 50% with fossil kerosene yields $3.02 per kilogram, a $2.25 per kilogram premium equivalent to $711 per tonne CO₂. Even an optimistic scenario—hydrogen falling to $1.00 per kilogram and DAC to $50 per tonne CO₂—leaves a residual gap requiring $240 per tonne CO₂ to close, well beyond plausible carbon-pricing trajectories.
Sensitivity analysis confirms that moving hydrogen prices from $2 to $10 per kilogram shifts electro-SAF costs by $3.50 per kilogram—a 66% swing relative to the EU factory-gate mean and 460% of the kerosene benchmark. By contrast, HEFA, ATJ, and Fischer-Tropsch move by tens of cents across the same hydrogen-price range. Carbon pricing at $200 per tonne CO₂ lifts fossil kerosene by $0.63 per kilogram but shifts bio-routes only marginally, narrowing but not eliminating gaps for HEFA and Fischer-Tropsch blends. For electro-SAF, carbon pricing alone cannot bridge the divide; structural reductions in electrolyzer capital costs, renewable power purchase agreement pricing, and CO₂ capture-transport infrastructure are prerequisites.
Policy Architecture and the Instrument-Mismatch Problem
Current mandates and credit systems treat alternative fuels as fungible, yet cost decomposition reveals distinct leverage points. HEFA and ATJ respond to feedstock mobilization (waste-lipid collection, certification, indexed offtake contracts) and policy instruments that stabilize realized spreads through credit floors or contracts-for-difference. Fischer-Tropsch economics hinge on capital availability (loan guarantees, accelerated depreciation) and utility-cost relief at industrial sites, mapping directly to the pathway’s CAPEX and maintenance-utilities bars. Electro-SAF requires input-side interventions: renewable power procurement matched to electrolyzer duty, production tax credits linked to delivered hydrogen costs, and CO₂ hub infrastructure funding.
ReFuelEU Aviation sets escalating SAF blend mandates across EU airports, beginning at modest levels and rising through 2050. Without complementary measures—airport-level credit trading with price collars, book-and-claim logistics to decouple scarce supply from distributed demand, and blend-ratio glidepaths aligned with airline budget envelopes—the regulation risks triggering compliance purchases at penalty rates rather than durable offtake. The U.S. Section 45V clean hydrogen production credit offers up to $3 per kilogram for qualifying electrolysis projects, directly addressing electro-SAF’s dominant cost driver, yet eligibility requirements around grid emissions intensity and temporal matching create bankability friction.
Brazil’s RenovaBio program trades decarbonization credits (CBIOs) representing one tonne of CO₂ avoided, establishing a market price signal. Lower modeled feedstock and utility costs in Brazil yield smaller parity gaps—$0.20 per kilogram for 50% HEFA blends, equivalent to $60 per tonne CO₂—suggesting that a CBIO price floor at this level could accelerate HEFA and Fischer-Tropsch deployment without the heavy fiscal outlays required in higher-cost jurisdictions. However, RenovaBio’s current structure lacks innovation-specific incentives, limiting its ability to catalyze advanced pathways or electro-fuels.
The Co-Processing Gambit and Refinery Conversion Economics
Integrating alternative-fuel feedstocks into existing petroleum refineries offers capital efficiency—Italian biorefinery conversions cut costs to one-fifth of greenfield equivalents by repurposing hydrotreaters and naphtha reformers. Co-processing triglycerides with gas oil at 5–20% ratios in conventional hydrodesulfurization units yields renewable diesel blends, with one Italian case achieving 7.7% emissions reductions (from 103.41 to 95.42 grams CO₂-equivalent per megajoule) at modest retrofit expense. Yet co-processing introduces operational complexities: oxygenated feedstocks increase hydrogen consumption, power demand, and heat input beyond baseline fossil-only operations, and the emissions accounting must isolate incremental demand attributable to the biogenic fraction—a measurement challenge that intensifies above 5% blend ratios.
Life-cycle assessments show that the emissions benefits of co-processing depend critically on feedstock type, hydrogen sourcing, and process configuration. HEFA from used cooking oil or tallow can deliver 34–65% GHG reductions relative to fossil kerosene when indirect land-use change is avoided, but displacing forests or natural shrublands nullifies savings entirely. Fischer-Tropsch from poplar, miscanthus, or municipal solid waste achieves 86–100% reductions in well-to-wake assessments, reflecting the pathway’s high biomass-carbon retention. ATJ from sugarcane or agricultural residues sits at 24–66 grams CO₂-equivalent per megajoule, intermediate between HEFA and Fischer-Tropsch. These ranges underscore that pathway selection cannot rest on cost alone—certification frameworks, feedstock sustainability criteria, and carbon-accounting methodologies shape both regulatory eligibility and bankability.
The Sequencing Imperative and Portfolio Logic
Expressing residual premiums as carbon-price equivalents clarifies the policy lift required for each pathway. HEFA and Fischer-Tropsch blends need $60–$130 per tonne CO₂ in most regions, achievable through combination instruments: blending credits with guardrails, indexed offtake agreements, and feedstock-mobilization support for HEFA; loan guarantees, utility-tariff relief, and reliability programs for Fischer-Tropsch. ATJ sits higher at $125–$210 per tonne CO₂, favoring deployment where alcohol supply chains confer site advantage rather than universal rollout. Electro-SAF’s $670–$710 per tonne CO₂ equivalent at 50% blend signals that parity via carbon pricing alone is politically and economically implausible; progress depends on cost-downs in clean hydrogen and CO₂ supply plus risk-sharing instruments that bridge remaining premiums.
Near-term strategy should prioritize HEFA and Fischer-Tropsch scaling, leveraging existing assets and co-processing where credible. Medium-term expansion of ATJ can exploit cellulosic and waste alcohol platforms, particularly in regions with established fermentation infrastructure. Electro-SAF deployment waits on structural improvements—electrolyzer capital costs, renewable power prices below $30 per megawatt-hour, and CO₂ capture-transport networks—that shift the pathway’s energy and carbon bars downward. This phased approach aligns instrument design with the largest cost components in each pathway’s decomposition, maximizing public-fund efficiency and minimizing displacement risk.
The aviation sector’s decarbonization timeline is compressed by fleet turnover cycles and infrastructure lock-in. Over 200,000 flights have used SAF blends, yet total production remains below 0.2% of global jet fuel consumption. Closing that gap requires a differentiated policy that recognizes feedstock constraints, capital intensity, and hydrogen dependence as distinct barriers rather than treating all alternative fuels as a monolithic category. Cost curves are stable, decompositions are robust, and sensitivity slopes are empirically grounded—the evidence base for targeted intervention is clear. What remains uncertain is whether regulatory architects will align instruments with pathway-specific cost drivers or continue applying uniform mandates that favor the lowest-cost option until feedstock scarcity stalls progress entirely.
