Municipal solid waste gasification with alcohol-to-jet upgrading produces low-carbon aviation fuel at fossil-competitive costs

Introduction

Aviation fuel consumption in the United States totals approximately 26 billion gallons per year, nearly all from fossil sources, and global demand is projected to exceed 230 billion gallons by 2050 (Energy Information Administration, 2023; Kumar and Rutherford, 2023; Mithal and Rutherford, 2023). The sector accounts for 2%–3.1% of global CO₂ emissions, with additional non-CO₂ warming effects from nitrogen oxides and contrail formation (Grewe et al., 2017). Reaching net-zero aviation emissions by 2050 under ICAO commitments requires a large-scale transition to sustainable aviation fuels (Bann et al., 2017; SAF Grand Challenge Roadmap Flight Plan for Sustainable, 2026; Van Dyk ana Saddler, 2024). Fuel costs currently represent 20%–30% of airline operating expenses, so economic viability is as binding a constraint as carbon performance (Dubey et al., 2024; Prussi et al., 2021).

Municipal solid waste presents a promising feedstock for SAF production, it combines high carbon content, established collection networks, tipping-fee revenue, and no competition with food or agricultural land. The United States generates over 250 million tonnes of MSW annually, and diverting waste from landfills avoids methane emissions that would otherwise accumulate over decades (Brandt et al., 2022; Brooks et al., 2016; Brown, 2015; Zhang et al., 2024). Gasification-based conversion of MSW to liquid fuels has been studied at pilot and commercial scales, with reported minimum selling prices of $0.85-$1.15 per liter and lifecycle GHG reductions of approximately 70% compared to petroleum jet fuel (Lee et al., 2022; Stratton et al., 2011; Suresh et al., 2018). Alcohol-to-jet pathways applied to biomass-derived syngas have shown similar economic performance at $1.00-$1.50 per liter, with emission reductions up to 85% under favorable process conditions (Geleynse et al., 2018; Han et al., 2017; Yang and Yao, 2025).

Most published assessments have evaluated individual process steps in isolation or have applied simplified yield assumptions for downstream sections. Few have built a fully integrated, mass- and energy-balanced simulation connecting gasification performance directly to co-product recovery and fuel yield within a single process model. System boundaries and financial assumptions vary considerably across the literature, making cross-study comparison unreliable (Beal et al., 2021; Lin et al., 2023).

Crucially, prior sensitivity analyses for MSW-to-fuel systems have examined only market and financial parameters, omitting process-level uncertainties specific to MSW: syngas H₂/CO ratio variability arising from heterogeneous feedstock composition; catalyst deactivation rates that govern ATJ upgrading economics; and MSW moisture and plastic content that directly affect both fuel yield and fossil carbon emissions. This study addresses all four gaps within a single unified BioSTEAM framework. The process flow diagram (Figure 1) and system boundary (Figure 2) were generated using draw. io (diagrams.net) and Microsoft Visio, respectively; results figures were produced in Python 3.10 using matplotlib; and the TEA discounted cash flow model was implemented within BioSTEAM v2.44.3.

This analysis evaluates a 2,000-tonne/day facility through gasification, mixed-alcohol synthesis, and ATJ conversion, with metals and propanol recovered as co-products. The objectives are: (i) to quantify MFSP under realistic feedstock and co-product scenarios; (ii) to determine cradle-to-gate GWP and identify its dominant contributors; (iii) to identify process and economic parameters with the greatest influence on cost and carbon performance; and (iv) to quantify combined parametric uncertainty through simultaneous 12-parameter Monte Carlo sampling, including process-level variables.

Materials and methods

Plant capacity and process configuration

The plant processes 2,000 tonnes per day of MSW at 25 wt% moisture. This scale aligns with the lower end of commercial waste-to-fuel capacity and reflects a realistic demonstration-to-commercial transition size. The process includes four main sections: front-end waste preparation (recyclable removal, shredding, and drying), gasification of the processed MSW fraction, syngas clean-up and conditioning, and catalytic upgrading through mixed alcohol synthesis and ATJ conversion. A heat recovery and steam generation system satisfies internal energy demands. Process modeling used BioSTEAM v2.44.3; stream compositions, temperatures, pressures, and flow rates from the simulation were used to size major equipment and determine energy requirements. The feedstock was characterized by proximate and ultimate analysis: C 27.4 wt%, H 3.9 wt%, O 32.1 wt%, N 0.8 wt%, S 0.2 wt%, ash 12.7 wt%, moisture 25 wt%, LHV 14.2 MJ/kg.

Pretreatment

The MSW enters the facility at 25 wt% moisture and undergoes mechanical size reduction. Non-combustible materials are removed through magnetic separation (ferrous metals), eddy-current separation (aluminum), trommel screening, and air classification, achieving recovery efficiencies of 95% for ferrous and 85% for non-ferrous streams, consistent with refuse-derived fuel systems. The organic-rich fraction is directed to a rotary drum dryer where co-current flow of hot flue gas from the char combustor reduces moisture to 10 wt% at 450 K over approximately 12 min.

Gasification

Dried MSW converts to syngas in an indirectly heated dual-bed fluidized-bed gasifier modeled on the Battelle/PNNL design. The gasifier operates at 1,598 K and 152 kPa, with circulating silica sand providing heat transfer between the gasification reactor and the char combustor. Steam serves as the fluidizing medium at a superficial velocity of 0.8 m s^-1. Primary pyrolysis occurs between 600–900 K, followed by secondary cracking and heterogeneous reactions up to 1,600 K. Char and ash (∼12 wt% of dry feed) are removed by high-efficiency cyclones and combusted with a slight excess of air to supply endothermic gasification reactions. Raw syngas composition leaving the reactor is approximately 42.5% CO, 22.1% H₂, 20.2% CO₂, 8.9% CH₄, with the remainder water and light hydrocarbons, giving a raw H₂/CO ratio of approximately 0.52 mol/mol. Key gasification reactions are listed in Table 1. Figure 1 shows the complete process flow diagram across all four sections.

TABLE 1. Overview of major chemical reactions in the gasification process [23].

Tar reforming and gas cleaning

Raw syngas pass through a bubbling fluidized-bed catalytic reformer at 1,123 K and 138 kPa containing Ni/MgO catalyst. Tar conversion exceeds 99% through thermal cracking and catalytic reforming; methane reforming proceeds concurrently at approximately 65% per-pass conversion. Downstream cooling generates medium-pressure steam for internal use. A venturi scrubber with recirculated water removes residual particulates, ammonia, and trace tar to below 0.01 g m^-3 particulate loading and greater than 99.9% ammonia removal. The cleaned syngas is compressed to 3.1 MPa and passed through a ZnO guard bed, reducing sulfur concentration to below 0.1 ppmv.

Steam reforming and gas conditioning

A tubular steam reformer achieves further methane conversion (92%) at 1,203 K and 2.8 MPa with a steam-to-carbon ratio of 3. Recovered heat from the reformer generates high-pressure steam at 10 MPa and 813 K. The water-gas shift reaction is moderated to achieve a target H₂/CO ratio of 1.2 mol/mol, which is the optimal feed ratio for MAS selectivity toward C₂-C₅ alcohols. Excess CO₂ is removed by a 40 wt% methyl diethanolamine absorption system, reducing CO₂ concentration from 20.2 mol% to below 7 mol%. The conditioned syngas is then compressed to 13.8 MPa for alcohol synthesis. Supplemental electrolytic hydrogen at $2.00/kg is added as required to maintain the H₂/CO target.

Mixed alcohol synthesis

Alcohol synthesis uses a fixed-bed reactor at 547 K (274 °C) and 13.8 MPa with a gas hourly space velocity of 2,980 h^-1. Per-pass CO conversion reaches 36.5%, with unreacted syngas recycled after cooling and condensation. Three distillation columns separate water, methanol, ethanol, and heavier alcohols. Methanol (99.5 wt% purity) is recycled to enhance ethanol formation through secondary reactions. Operating conditions and key reaction stoichiometries follow (Dutta et al., 2011) and are summarized in Table 2.

TABLE 2. Mixed alcohol synthesis reactor operating conditions and key reactions (Dutta et al., 2011).

Alcohol-to-jet upgrading

The mixed-alcohol stream converts to jet-range hydrocarbons through sequential dehydration, oligomerization, and hydrogenation. Ethanol dehydration uses γ-alumina catalyst at 623 K and 2.0 MPa, achieving 99.5% conversion to ethylene. Oligomerization of the olefin mixture at 473 K and 3.5 MPa over a zeolite catalyst produces C₈-C₁₆ olefins. Hydrogenation in a trickle-bed reactor at 523 K and 5.0 MPa with palladium on alumina catalyst saturates olefins to paraffins at greater than 99.9% conversion. The hydrocarbon mixture is fractionated to obtain a jet fuel cut in the 423–573 K boiling range. Overall jet fuel yield is 9.3 gallons per tonne of MSW (35.2 kg per tonne).

Techno-economic analysis

TEA used a discounted cash flow rate-of-return method following NREL guidelines [24]. All costs are in 2024 U.S. dollars. Equipment purchase costs were developed from vendor quotations for major units and scaled for auxiliary equipment using exponential correlations with exponents of 0.6–0.7 b y equipment type. Costs were adjusted to 2024 values using CEPCI = 820.5. Installed equipment costs were determined from the BioSTEAM process simulation; indirect costs including design and engineering, construction management, legal fees, and project contingency were calculated using the cost factor breakdown in Table 4, yielding a total capital multiplier of 3.73 times total acquired equipment cost. Variable costs and co-product credit assumptions are listed in Table 3.

TABLE 4. Direct and indirect cost factors for capital investment estimation [25].

TABLE 3. Operating cost and co-product credit assumptions for the MSW-to-SAF facility (2024 USD).

The project financing structure assumes 40% equity and 60% debt. Equity holders require a 10% internal rate of return; at a 21% corporate income tax rate, the 7.0% nominal debt interest rate corresponds to a 5.53% after-tax cost of debt. The resulting weighted-average cost of capital is WACC = 0.40 × 10% + 0.60 × 5.53% = 7.32%, which serves as the discount rate for all present net value calculations in the DCF model. The 7% debt rate reflects investment-grade project finance conditions for domestic infrastructure in 2024 (Cost Of Capital: 2025 Outlook, 2025; Ubando et al., 2022).

Annual fixed costs include labor for 60 full-time employees, structured as follows: 1 plant manager at $164,000/yr; 4 plant engineers at $78,000/yr each; 4 shift supervisors at $55,000/yr each; 24 shift operators at $44,700/yr each; 8 maintenance technicians at $47,000/yr each; 4 laboratory and quality control technicians at $42,000/yr each; 4 administrative staff at $38,000/yr each; and 2 environmental and safety officers at $65,000/yr each. Applying a 55% benefits and overhead multiplier yields a total annual labor cost of approximately $4.0 million. The simple average across all 60 roles is approximately $75,000/yr per FTE, consistent with the aggregate value reported in the original manuscript. Maintenance at 3% of total capital investment per year follows the NREL standard assumption for thermochemical biorefinery facilities (Ubando et al., 2022).

Catalyst replacement expenditures totaled $8.2 million per year: tar reformer catalyst at $12/kg (3-year lifetime), mixed alcohol synthesis catalyst at $45/kg (2-year lifetime), ethanol dehydration catalyst at $8/kg (5-year lifetime), oligomerization catalyst at $85/kg (1-year lifetime), and hydrogenation catalyst at $180/kg (3-year lifetime). Financial parameters are listed in Table 5.

TABLE 5. Financial assumptions for the discounted cash flow model.

Life cycle inventory analysis

The life cycle inventory was developed from mass and energy balance data from BioSTEAM, normalized to the functional unit of 1 MJ of synthetic jet fuel at the ex-refinery gate. Process-specific data for gasification, syngas reforming, alcohol synthesis, and ATJ upgrading were extracted from the steady-state simulation. Background data for utilities, chemicals, and transportation used the Ecoinvent v3.7 database in OpenLCA v2.3.1. Electricity consumption used the U.S. 2024 grid mix (38% natural gas, 16% coal, 19% nuclear, 27% renewables). MSW collection and transport assumed a 30 km diesel truck haul. LCI datasets are listed in Table 6.

TABLE 6. Ecoinvent v3.7 datasets used in the life cycle inventory (OpenLCA v2.3.1).

Life cycle assessment

Environmental impacts were assessed according to ISO 14040:2006 and ISO 14044:2006 using a cradle-to-gate system boundary that spans MSW collection through jet fuel production (Figure 2). The functional unit is 1 MJ of synthetic jet fuel at the ex-refinery gate. The system boundary explicitly includes: MSW collection and transport (30 km, diesel trucks); all on-site material and energy flows; infrastructure amortized over 30 years; and co-product credits for recovered metals, propanol, and exported electricity via system expansion. End-of-life combustion emissions are excluded (cradle-to-gate scope). Impact assessment used the IPCC 2021 method with a 100-year time horizon (1.0 kg CO₂-eq/kg CO₂, 27.9 kg CO₂-eq/kg CH₄, 273 kg CO₂-eq/kg N₂O).

Biogenic carbon in the organic MSW fraction was treated as carbon neutral following IPCC (2019) guidelines and the methodological conventions of the U.S. RFS2 and European RED II. This convention rests on the principle that CO₂ released from combustion of recently photosynthesized organic matter re-enters the short-cycle carbon pool on comparable timescales to its original sequestration, resulting in no net addition to atmospheric CO₂ over the 100-year GWP horizon. This assumption is widely accepted in lifecycle assessments of bioenergy systems (Capaz et al., 2021) and is specifically required by the RED II framework for advanced renewable fuels. Fossil carbon in plastic contaminants (∼8 wt% dry mass) does not meet the biogenic carbon criterion and is therefore counted in full at 10.8 g CO₂-eq/MJ in the baseline inventory.

The avoided landfill emission credit of 100 kg CO₂-eq per tonne of MSW diverted is consistent with EPA WARM v15 estimates for mixed MSW (96–133 kg CO₂-eq per tonne depending on composition) and with the IPCC AR5 methane GWP100 of 28 CO₂-eq/kg CH₄ used in earlier WARM calibrations. Application of the IPCC AR6 value (27.9 CO₂-eq/kg CH₄, used in the IPCC, 2021 impact method applied here) yields a numerically equivalent result. Sensitivity of GWP to plus or minus 20% variation in the landfill methane generation factor is plus or minus 1.0 g CO₂-eq/MJ, indicating that methodological uncertainty in this credit is not material. Electricity mix sensitivity was extended to include the 2024 U.S. regional grid averages for the Southwest (0.28 kg CO₂-eq/kWh, low renewable) and the Midwest (0.44 kg CO₂-eq/kWh, coal-heavy), in addition to the 100% renewable and 100% coal bounds reported in the sensitivity section.

Sensitivity analysis framework

Syngas H₂/CO ratio (plus or minus 30%, range 0.84–1.56 mol/mol from the 1.2 baseline). A 30% decrease in H₂/CO to 0.84 requires additional water-gas shift conversion, consuming approximately 15 MW extra thermal duty from natural gas, reducing CO conversion in MAS by approximately 12%, and decreasing jet fuel yield proportionally. From first principles: MFSP = $1.46/gal at low H₂/CO and $1.13/gal at high H₂/CO; GWP ranges from 33.0 to 35.1 g CO₂-eq/MJ.

Catalyst lifetime (plus or minus 50%, range 1.5–4.5 years vs. 3-year baseline). At 50% of design lifetime, annual MAS catalyst cost doubles from $8.2 million to $16.4 million; at 150% lifetime it falls to $5.47 million. Translating via 18.6 million gallons annual production: MFSP = $1.10/gal (optimistic) to $1.69/gal (pessimistic), a swing of $0.59/gal.

MSW moisture content (15–35 wt% versus the 25 wt% baseline). A 10 percentage-point moisture increase reduces dry-mass throughput by 13.3% at constant wet feed rate, cutting fuel yield by 11.8% and increasing specific drying energy. MFSP = $1.00/gal (15% moisture) to $1.59/gal (35% moisture); GWP = 32.6–35.6 g CO₂-eq/MJ.

MSW plastic fraction (4–15 wt% dry basis versus the 8 wt% baseline). Fossil carbon from plastics contributes 10.8 g CO₂-eq/MJ at 8 wt%, scaling proportionally. At 4 wt%: GWP = 28.3 g CO₂-eq/MJ. At 15 wt%: GWP = 43.1 g CO₂-eq/MJ. MFSP effect is negligible (plus or minus $0.05/gal) because plastics and organic fractions carry comparable calorific values.

Monte Carlo analysis

All 12 parameters were sampled simultaneously from uniform distributions using a linearized response-surface model calibrated to the Scenario 4 baseline (MFSP = $1.25/gal, GWP = 33.67 g CO₂-eq/MJ): MFSP = MFSP₀ + sum (sᵢ fᵢ), where sᵢ is the OAT-derived slope and fᵢ is the sampled fractional deviation. This linearization is standard practice for biorefinery uncertainty quantification (Humbird et al., 2002). Random seed 42; 1,000 iterations. Parameter ranges and OAT slopes are in Table 7.

TABLE 7. Twelve-parameter Monte Carlo configuration.

Results

Process model performance

The facility processes 2,000 tonnes of MSW per day and produces 70.4 Mg d^-1 of synthetic jet fuel (9.3 gallons, or 35.2 kg, per tonne of as-received waste). Ferrous metal recovery reaches 188 Mg d^-1 of iron from an 11.0 wt% Fe feed fraction (95% recovery efficiency), and aluminum recovery reaches 88 Mg d^-1 from a 4.6 wt% Al feed fraction (85% recovery). Mixed alcohols from the synthesis section comprise 10.7 Mg d^-1 ethanol, 22.3 Mg d^-1 n-propanol, and 10.7 Mg d^-1 n-butanol. Propanol (41.7 Mg d^-1 total C₃) is sold as a co-product; ethanol and butanol are recycled to the ATJ section. Approximately 85% of incoming MSW is diverted from landfill.

The facility energy balance is summarized in Table 8. Internal combustion of syngas and waste-heat recovery generates 62 MW gross electricity, of which 17 MW is consumed on-site, with 45 MW exported to the grid. Total thermal demand of 285 MW (drying, gasification, reforming, distillation, and ATJ upgrading) is met through char combustion and heat integration. Overall energy efficiency is 68%, defined as the ratio of chemical energy in liquid products to the sum of feedstock and supplemental natural gas energy inputs.

TABLE 8. Facility energy balance summary.

Capital investment

The installed equipment cost for the 2,000-tonne-per-day facility is $619.27 million (Figure 3). Multi-stage syngas compression and gas cleaning is the single largest cost item at $278.25 million (45% of total installed cost). The char combustor adds $105.19 million (17%) and the tar reformer with associated cyclones $95.35 million (15%). The gasifier and solids-handling equipment account for $89.41 million (14%). Downstream separation units contribute $94.53 million (CO separation), $46.15 million (methanol recovery), and $29.78 million (ethanol purification). The ATJ section adds approximately $87 million. Applying the indirect cost factors from Table 4 yields a total capital investment of $936 million, giving a capital charge of approximately $0.62 per gallon at 18.6 million annual gallons.

Minimum fuel-selling price

Four economic scenarios were evaluated (Figure 4). In Scenario 1 (no tipping fee, no co-product revenue), MFSP is $3.68 per gallon. Adding a $30 per tonne tipping-fee credit (Scenario 2) reduces MFSP to $2.77 per gallon. Including propanol revenue at $378 per tonne alongside the tipping-fee credit (Scenario 3) lowers MFSP to $2.20 per gallon. The most favorable case (Scenario 4), combining the tipping-fee credit with full metal and propanol recovery (aluminum at $2,205 per tonne, iron at $441 per tonne, propanol at $378 per tonne), produces an MFSP of $1.25 per gallon, within the 2019–2024 petroleum jet fuel average of $2.00-$3.50 per gallon. Return on investment and income tax dominate MFSP, contributing approximately $1.00 per gallon and $0.60 per gallon, respectively, in Scenario 1. Operations and maintenance add about $0.30 per gallon and utilities about $0.20 per gallon across scenarios.

Global warming potential

The cradle-to-gate GWP of MSW-derived SAF is 33.67 g CO₂-eq/MJ (Figure 5). Natural gas use is the largest contributor at 14.2 g CO₂-eq/MJ (42% of total), of which 7.8 g CO₂-eq/MJ arises from steam reforming and 6.4 g CO₂-eq/MJ from supplemental firing. Grid electricity contributes 4.1 g CO₂-eq/MJ (12%); sulfur removal and catalyst production add 3.5 g CO₂-eq/MJ (10%). Fossil carbon in plastic contaminants contributes 10.8 g CO₂-eq/MJ. Aluminum recovery provides a credit of −0.8 g CO₂-eq/MJ, iron −0.3 g CO₂-eq/MJ, and avoided landfill emissions −5.0 g CO₂-eq/MJ.

The net GWP of 33.67 g CO₂-eq/MJ represents a 63% reduction from the fossil jet fuel baseline of 89 g CO₂-eq/MJ. This value satisfies the CORSIA (Carbon Offsetting and Reduction Scheme for International Aviation) sustainability standard, which requires a minimum 10% lifecycle GHG reduction from the 2020 fossil baseline (CORSIA Eligible Fuels, 2026); the U.S. Renewable Fuel Standard 2 (RFS2) advanced biofuel threshold (<89 g CO2-eq/MJ); and the European Union Renewable Energy Directive II (RED II) limit for renewable aviation fuels (<94 g CO2-eq/MJ) under the current U.S. average electricity grid. With 100% renewable electricity, GWP falls to 25.1 g CO₂-eq/MJ (72% reduction), and with the U.S. Southwest regional grid (0.28 kg CO₂-eq/kWh) it falls to approximately 29.8 g CO₂-eq/MJ. Table 9 shows the twelve-parameter Monte Carlo results (1,000 iterations, seed = 42), including the mean, median, standard deviation, 5th percentile, 95th percentile, minimum, and maximum values for MFSP and GWP.

TABLE 9. Twelve-parameter Monte Carlo results (1,000 iterations, seed = 42).

GWP benchmarking against published pathways

Figure 6 places this result in the context of published SAF lifecycle assessments. The 33.67 g CO₂-eq/MJ value is consistent with the 32–36 g CO₂-eq/MJ range reported for MSW gasification followed by Fischer–Tropsch synthesis across multiple multi-pathway SAF reviews, including (Capaz et al., 2021; Morganti et al., 2024), who evaluated GHG mitigation costs and potentials across certified SAF pathways using harmonised lifecycle boundaries. For catalytic hydrothermolysis (CH) pathways from lipid feedstocks (Chen et al., 2023), report well-to-wake carbon intensities of 15.9–46.1 g CO₂-eq/MJ depending on feedstock burden, with oilseed-derived CH sitting in the 28–46 g CO₂-eq/MJ range (Beal et al., 2021). assessed nine alternative jet fuel production pathways for the US Department of Defense and report GHG emissions of 23–52 g CO₂-eq/MJ across fermentation-based and thermochemical conversion routes using various feedstocks including municipal solid waste; fermentation and ATJ upgrading pathways generally fall in the upper portion of this range owing to additional energy demands of the biological conversion step.

Plasma-assisted Fischer–Tropsch conversion of MSW produces substantially higher GHG intensities of 60–68 g CO₂-eq/MJ, owing to the electricity intensity of plasma gasification, as reviewed by (Amhamed et al., 2024). HEFA pathways from waste fats and oils achieve substantially lower GHG intensities of 16.8–21.4 g CO₂-eq/MJ for yellow grease and 25.7–37.5 g CO₂-eq/MJ for tallow (Seber et al., 2014), representing lifecycle GHG reductions of 63%–82% relative to the conventional fossil jet fuel baseline of 89 g CO₂-eq/MJ (“CORSIA Eligible Fuels, 2026”); these low values reflect feedstock displacement credits specific to lipid-based waste streams that do not apply to MSW feedstocks. Taken together, these comparisons confirm that the MSW gasification–MAS–ATJ pathway assessed in this study achieves a GHG intensity of 33.67 g CO₂-eq/MJ, representing approximately 62% reduction against the fossil baseline, consistent with the performance envelope of thermochemical MSW conversion pathways in the published literature.

Sensitivity analysis

Economic sensitivity

The IRR assumption is the strongest economic sensitivity: varying the target IRR from 8% to 12% changes MFSP from $0.89 to $3.61 per gallon (Figure 7). The unusually large IRR sensitivity directly reflects the optimistic baseline assumptions (full tipping fee + all co-product credits) of Scenario 4: when all revenue credits are active, capital service becomes the dominant remaining cost, amplifying the IRR effect. Aluminum price variation of plus or minus 20% ($1,764-$2,646 per tonne) shifts MFSP by plus or minus $0.42 per gallon. At the baseline aluminum price of $2,205 per tonne, the aluminum credit remains substantial yet conservative relative to optimistic assumptions used in some prior analyses. A plus or minus $10 per tonne change in net MSW tipping fee, consistent with reported increases in U.S. landfill gate fees (EREF Report Shows 10% Increase in U.S. Landfill Tipping Fees, 2022), produces plus or minus $0.30 per gallon in MFSP. Hydrogen price variation of plus or minus 20% ($1.60-$2.40 per kg) alters MFSP by plus or minus $0.22 per gallon. Capacity factor variation from 300 to 366 operating days per year shifts MFSP by plus or minus $0.35 per gallon.

The four process-level parameters contribute meaningfully to MFSP uncertainty. Catalyst lifetime (plus or minus 50%) yields a $0.59 per gallon swing ($1.10-$1.69/gal), equivalent to the tipping-fee uncertainty and larger than the hydrogen price sensitivity. These finding highlights catalyst procurement strategy as a significant project finance risk not captured in prior analyses of this pathway. MSW moisture content (15–35 wt%) also contributes a $0.59 per gallon swing ($1.00-$1.59/gal), underscoring the economic benefit of pre-drying or operating in drier climate regions. Syngas H₂/CO variability (plus or minus 30%) contributes a $0.33 per gallon swing, primarily through WGS natural gas demand and MAS yield effects. Plastic fraction has a negligible MFSP effect (plus or minus $0.05/gal).

Environmental sensitivity

Electricity consumption has the largest environmental sensitivity: replacing the U.S. average grid with 100% renewable electricity reduces GWP to 25.1 g CO₂-eq/MJ; a 100% coal grid raises it to 48.3 g CO₂-eq/MJ, a span of 23.2 g CO₂-eq/MJ (Figure 8). The Midwest regional grid (0.44 kg CO₂-eq/kWh) gives GWP of approximately 36.1 g CO₂-eq/MJ, and the Southwest regional grid (0.28 kg CO₂-eq/kWh) gives approximately 29.8 g CO₂-eq/MJ. Natural gas consumption variation of plus or minus 20% produces GWP values between 29.9 and 37.4 g CO₂-eq/MJ. Hydrogen consumption variation gives plus or minus 1.2 g CO₂-eq/MJ. Uncertainty in avoided landfill emissions (plus or minus 20% methane generation factor) introduces plus or minus 1.0 g CO₂-eq/MJ.

Among the parameters, MSW plastic fraction (4–15 wt%) ranks second overall in GWP sensitivity with a swing of 14.9 g CO₂-eq/MJ (28.3–43.1 g CO₂-eq/MJ). This is the largest identified GWP driver and is directly policy-relevant: source-separation programs diverting plastics to mechanical recycling rather than mixed-waste gasification could reduce SAF GWP by up to 14.9 g CO₂-eq/MJ relative to a high-plastic-fraction baseline. MSW moisture (15–35 wt%) contributes 3.0 g CO₂-eq/MJ via varying drying energy demand. Syngas H₂/CO (plus or minus 30%) contributes 2.1 g CO₂-eq/MJ through WGS natural gas consumption.

Monte Carlo uncertainty analysis

Figure 9 presents joint MFSP and GWP distributions from 1,000 simultaneous 12-parameter sampling iterations. Statistical results are summarised in Table 8.

The MFSP 90% confidence interval spans -$0.12 to $2.61/gal. Under simultaneously favorable conditions (high aluminum price, low IRR, high availability, dry low-plastic MSW, long catalyst lifetime) SAF could approach zero net cost. Under simultaneously adverse conditions, MFSP reaches $2.61/gal, still within the upper bound of historical fossil jet fuel pricing. The wide MFSP distribution (SD = $0.83/gal) reflects the dominant role of financial parameters (IRR, aluminum price) rather than process-level variability. The GWP 90% confidence interval of 28.4–42.8 g CO₂-eq/MJ falls below the fossil baseline (89 g CO₂-eq/MJ) for all 1,000 iterations, confirming robust climate benefits across the full uncertainty space. Figure 10 quantifies each parameter’s contribution to Monte Carlo variance via Pearson correlation: equity IRR and aluminum price dominate MFSP variance (|r| > 0.55); plastic fraction and grid electricity dominate GWP variance. The four process parameters collectively account for approximately 22% of MFSP variance and 52% of GWP variance.

Figure 11 decomposes gross GWP and positive cost contributions in descending order to identify the parameters where targeted intervention would yield the greatest reductions. On a gross-emission basis (40.6 g CO₂-eq MJ^-1), four unit operations account for 80% of total upstream GHG loading: natural gas consumption in steam reforming and auxiliary heating (14.2 g CO₂-eq MJ^-1, 35%), fossil carbon embedded in the plastic fraction of MSW (10.8 g CO₂-eq MJ^-1, 27%), grid-electricity draw for syngas compression (4.1 g CO₂-eq MJ^-1, 10%), and sulfur-removal catalyst production (3.5 g CO₂-eq MJ^-1, 9%). The remaining four sources collectively contribute approximately 8.0 g CO₂-eq MJ^-1. This distribution indicates that decarbonizing natural gas supply, for example, through renewable hydrogen or electrified reforming and reducing plastic-fraction combustion are the highest-leverage mitigation levers, consistent with the sensitivity results in Figure 8.

On the cost side (Figure 11b), three components account for 82% of gross positive expenditure: capital recovery (ROI and depreciation, $1.55 gal^-1, 48%), operations and maintenance ($0.60 gal^-1, 18%), and feedstock costs for hydrogen and catalysts ($0.51 gal^-1, 16%). Utilities and income tax jointly contribute the remaining 18%. The capital-intensive nature of the process reflects the high installed cost of syngas conditioning and compression ($278M; Figure 3), underscoring that economies of scale and improved catalyst lifetimes represent the most direct pathways to cost competitiveness with fossil jet fuel.

Discussion

The MFSP range of $1.25-$3.68 per gallon places the MSW-to-SAF pathway among the more economically competitive non-HEFA routes in the current literature. Fast pyrolysis oil upgrading and hydrothermal liquefaction pathways report MFSPs of $7.40-$8.34 and $6.80-$7.20 per gallon, respectively, normalized to 2024 USD. The cost differential arises mainly from the negative feedstock acquisition cost (tipping fee credit) and the value of recovered metals. The tipping-fee credit alone accounts for a $0.91 per gallon MFSP reduction between Scenario 1 and Scenario 2, larger than the effect of a 20% reduction in capital cost ($0.28 per gallon). The large influence of IRR and aluminum price on MFSP reflects the optimistic Scenario 4 baseline assumptions, under which capital service and metal recovery credits dominate; the sensitivity tornado (Figure 7) should be interpreted with this baseline in mind.

The durability of tipping-fee revenue over a 30-year project life warrants explicit consideration. Gate fees are set by municipal contracts typically 5–10 years in duration, and their continuation depends on landfill diversion policy, alternative waste treatment capacity, and regulatory requirements in the facility catchment area. Because the tipping-fee credit accounts for the largest single MFSP reduction in the model ($0.91/gal), project finance models for MSW-to-SAF facilities should include scenarios in which gate-fee revenue is partially or completely eliminated, particularly in jurisdictions where competing waste treatment infrastructure may depress gate fees over time.

The GWP of 33.67 g CO₂-eq/MJ satisfies CORSIA, RFS2, and RED II sustainability thresholds and is consistent with independently reported values for MSW gasification pathways (Morganti et al., 2024). The electricity sensitivity (23.2 g CO₂-eq/MJ GWP span between 100% renewable and 100% coal scenarios) confirms that grid decarbonization is the dominant lever for further GWP reduction, achievable without any change to the conversion process itself. This finding is particularly relevant for sitting decisions: facilities co-located with renewable generation or located in high-renewable grid regions will deliver substantially better lifecycle carbon performance. The natural gas sensitivity (plus or minus 20% corresponds to a 7.5 g CO₂-eq/MJ swing) points to steam reforming and supplemental firing as the main internal process levers, suggesting that electrification of heating duties or integration with low-carbon hydrogen would further reduce GWP below the 33.67 g CO₂-eq/MJ baseline.

Operational and market uncertainties

MSW composition varies by region and season; fluctuations in moisture, ash content, and plastics fraction influence syngas quality and fuel yield. The expanded Monte Carlo quantifies these effects: plastic fraction (4–15 wt%) produces a 14.9 g CO₂-eq/MJ GWP swing, and moisture (15–35 wt%) produces a $0.59/gal MFSP swing, both of which were not captured in the original analysis. Sites with higher plastic content generate more fossil-derived carbon emissions; pre-sorting to remove plastics for mechanical recycling offers a direct route to reducing GWP. Sites with lower MSW moisture (dry climates, summer operation) improve MFSP by reducing drying energy demand and increasing organic throughput.

Catalyst durability at commercial throughputs is an important uncertainty. The oligomerization catalyst requires annual replacement at $85 per kg, accounting for a disproportionate share of the $8.2 million annual catalyst budget. The expanded OAT analysis shows that catalyst lifetime variation of plus or minus 50% produces a $0.59/gal MFSP swing, comparable in magnitude to the tipping-fee sensitivity. This result was not captured in prior published TEAs of this pathway and should be a priority for experimental validation at pilot scale.

Hydrogen availability for ATJ hydrogenation ties process economics to supply chains that are themselves evolving. The plus or minus $0.22 per gallon MFSP sensitivity to a 20% hydrogen price swing is modest relative to IRR and aluminum effects, but hydrogen procurement logistics and long-term contract pricing remain practical uncertainties at commercial scale. Co-product market exposure also warrants attention: propanol revenues provide a meaningful MFSP reduction ($0.57 per gallon in Scenario 4) but depend on a relatively small global market; a 50% propanol price reduction would eliminate most of that benefit. Aluminum and iron credits are more reliable given manufacturing demand, though scrap metal prices are cyclical. Capacity factor variation (300–366 operating days) produces a $0.70 per gallon MFSP swing, larger than the capital cost sensitivity, confirming that feedstock supply reliability is as economically consequential as capital cost accuracy.

Regulatory treatment of MSW-based fuels remains inconsistent across standards. Landfill methane credits, biogenic carbon accounting, and co-product allocation rules differ between RFS2, RED II, and CORSIA, and changes to any of these could shift the pathway’s compliance position. The plus or minus 20% variation in landfill methane generation factors changes GWP by only plus or minus 1.0 g CO₂-eq/MJ, indicating that methodological uncertainty in the landfill credit is not material. Carbon treatment of fossil plastic contaminants (10.8 g CO₂-eq/MJ) carries greater regulatory significance. The Monte Carlo confirms that even at the 95th percentile of the uncertainty distribution, GWP remains at 42.8 g CO₂-eq/MJ, well below the 89 g CO₂-eq/MJ CORSIA threshold.

Conclusion

This study evaluated an integrated gasification and alcohol-to-jet pathway for producing SAF from 2,000 tonnes/day of MSW within a single BioSTEAM process model. The facility produces 9.3 gallons of SAF per tonne of waste along with recoverable aluminum, iron, and propanol. MFSP ranges from $1.25 per gallon with full tipping-fee and co-product credits to $3.68 per gallon without either, spanning the 2019–2024 petroleum jet fuel average. Cradle-to-gate GWP is 33.67 g CO₂-eq/MJ, a 63% reduction from conventional jet fuel, satisfying CORSIA, RFS2, and RED II thresholds.

Monte Carlo analysis yields a 90% confidence interval for MFSP of -$0.12 to $2.61/gal and for GWP of 28.4–42.8 g CO₂-eq/MJ. All 1,000 iterations satisfy the CORSIA climate threshold. The process parameters (syngas H₂/CO, catalyst lifetime, MSW moisture, plastic fraction) account for 22% of MFSP variance and 52% of GWP variance, establishing them as quantitatively important additions to sensitivity frameworks for MSW-to-fuel pathways.

Tipping-fee policy and co-product market access are more consequential for MFSP than process-level capital cost variation. Electricity decarbonization offers the most direct route to further GWP reduction: substituting 100% renewable electricity lowers GWP to 25.1 g CO₂-eq/MJ without changing conversion chemistry. Future work should address catalyst longevity at commercial throughputs, regional variation in MSW composition and plastic fraction, and the techno-economic and environmental effects of integrating carbon capture on the gasification or reforming units.

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Supplementary material

The Supplementary Material for this article can be found online at: https://www.frontiersin.org/articles/10.3389/ffuel.2026.1871799/full#supplementary-material

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Footnotes

Edited by: Ziyu Liu, Beihang University, China

Reviewed by: Kai Morganti, Santos Limited, Australia

Mohammad Heydari, Unitec Institute of Technology, New Zealand