Supply configuration creates the larger cost difference
The Midwest Fischer-Tropsch (FT) and methanol-to-jet (MTJ) designs cost $5,851.78/t and $5,879.03/t before support. The Texas FT design, with direct air capture (DAC) carbon and owned hybrid generation, costs $6,610.86/t. The larger cost difference in this comparison comes from the complete supply configuration.
Power and carbon arrangements change the cost structure substantially. The synthesis process must work with the hydrogen supply it actually receives. Financing then determines the selling price needed to meet the sponsor's return requirement.
Connect the physical project to its commercial requirement
Connect the design to the commercial decision
From inputs to saleable fuel
- Power, hydrogen and carbonElectricity supply, electrolysis and delivered CO₂Feedstock supply
- Buffer and conversionHydrogen availability, synthesis feed and pathwayProduct output
- Jet and coproductsJet, naphtha and LPG on an explicit allocation basisJet-attributed costs
What the project must earn
- Production economicsCapital, operating cost and modeled supportGross and net jet cost
- Commercial requirementDebt, tax, coproduct revenue and equity returnRequired jet selling price
Connect power, carbon and conversion choices to the revenue needed to meet the sponsor's return.
Connect power, hydrogen and carbon to the saleable product slate, then trace the investment and cash flows. Assessing a contract price also requires buyer evidence, including the value of meeting a mandate and the terms a buyer would accept.
Carbon and capital define the Texas cost structure
Fischer–Tropsch; direct-air-capture CO₂; hybrid renewables and battery; hourly matching.
What builds the production cost?
USD/t jet- Carbon feed
- Capital
- O&M
- Replacement
- Other costs
- Eligible statutory support
- Subtotal / total
Scroll across to see all cost components.
Production cost includes eligible statutory support. Required selling price also reflects financing and the sponsor's target return.
Capital contributes $3,579.38/t and carbon feed $1,878.88/t to the Texas case's gross cost. The design supplies electricity through owned renewable generation and battery assets, putting their cost into the investment budget. Purchased energy is zero.
Assess the synthesis quotation alongside the combined asset budget, generation performance and delivered-carbon terms. The full Excel workbook lets a team change those assumptions together with the pathway, power stack and plant scale, then follow their effects through the production chain.
Eligible statutory support reduces the Texas result to $5,819.51/t net cost. The separate selling-price calculation addresses the sponsor's revenue requirement under the financing assumptions.
The supply configuration deserves an early comparison
Solid negative bars show eligible statutory support. Filled markers show net production cost.
US designs with a qualifying 2027 construction start
USD/t jet- Net cost
Select a cost category to see its value in every design.
The designs assume qualifying 2027 construction starts and 2031 commercial operation. Filled negative bars deduct the levelized 45V support allocated to jet output. Midwest CO₂ is supplied at capture, conditioning and transport cost, with zero supplier opportunity premium. Figure 4 shows required selling prices under the same support assumptions.
Available conditional contracts also change financing assumptions or depend on unsettled terms. A numerical award comparison requires those terms to be matched.
Support assumptions
- All three US designs · eligible 45V hydrogen credit
The model assumes construction begins in 2027, commercial operation in 2031 and ten credit years, 2031–2040. Eligibility depends on the actual project meeting the construction, hydrogen-emissions and other requirements.
The scenarios assume the full modeled rate of $3.28/kg H₂, held flat in real 2026 USD, with prevailing-wage and apprenticeship requirements met. They assume qualifying hourly-matched electricity, incrementality and deliverability; the model’s hydrogen policy-view emissions are below the 0.45 kg CO₂e/kg H₂ full-rate threshold.
The model applies direct pay in 2031–2032, then a 0.92 monetization factor for transferred credits. The bars include that timing and discounting, with support allocated consistently to jet output under energy allocation.
Actual support payments depend on project eligibility. These cost comparisons include 45V alone; they exclude 45Z, competitive awards and buyer-compliance value.
- Carbon supply and implementation
Both Midwest designs assume cost-based access to fermentation CO₂. The workbook separately tests an illustrative $85/t CO₂ supplier opportunity premium.
Methanol was approved as an ASTM D7566 Annex 5 feedstock in July 2026. The proposed MTJ plant needs evidence for scale, yields, reliability and licensor guarantees.
- Potential contracts and buyer value
A numerical conditional case needs the same physical design and financing assumptions, with explicit price, volume, term and reference-price settlement. No such matched case is available for this edition.
Mandates and compliance benefits affect the buyer's economics. Producer cash support enters the required selling price, which reflects the sponsor's target return and financing assumptions.
The Midwest FT design has much smaller capital and carbon contributions: $1,523.52/t and $251.29/t. It carries $3,491.11/t of purchased energy. Both Midwest designs assume cost-based access to fermentation CO₂: capture, conditioning and transport, with zero supplier opportunity premium. An integrated owner or a cost-plus supply contract could support that assumption. An independent buyer would need a supply offer that establishes the delivered price and available volume.
The model adds $23/MWh to the earlier US new-build power purchase agreement (PPA) assumption, taking this case to $84/MWh. The adjustment represents assumed post-credit power economics; market pricing needs to be verified with suppliers. It raises the Midwest production cost materially. The Texas design owns its generation, so the adjustment leaves its costs unchanged.
The nearby MTJ case has a very similar gross cost. The revised power assumption narrows the advantage over Texas, but the difference between the two complete supply configurations remains much larger than the difference between the Midwest conversion routes. Compare feasible carbon and power arrangements early, before narrowing the discussion to conversion technology.
MTJ remains an emerging commercial configuration. Methanol became an approved feedstock under ASTM D7566 Annex 5 in July 2026, and process scale-up continues. Commercial selection needs evidence for the proposed plant's yields, reliability and licensor guarantees. Fraunhofer ISE describes the approval and development work.
For these designs with a qualifying 2027 construction start, the eligible 45V hydrogen credit contributes a levelized $791.35/t of jet in Texas, $969.25/t in Midwest FT and $983.21/t in Midwest MTJ. After those deductions, net costs are $5,819.51/t, $4,882.53/t and $4,895.82/t respectively. The same statutory rate produces different effects per tonne because the complete designs and allocation to jet output differ.
The Before support view holds the same designs and removes the incentive deduction, showing how much of each cost advantage depends on eligibility. Several assumptions change together across these complete designs. Isolating the effect of carbon source, power contract or location would require holding the others constant.
Follow hydrogen through to synthesis
Fischer–Tropsch; direct-air-capture CO₂; hybrid renewables and battery; hourly matching.
Hydrogen production and synthesis feed
kg H₂ per hour- Hydrogen produced
- Synthesis feed
- Hydrogen produced
- 2031.67 kg H₂ per hour
- Synthesis feed
- 3914.97 kg H₂ per hour
Hydrogen buffer at the end of each hour
kg H₂- Closing inventory
- Closing inventory
- 0.00 kg H₂
Hours 4009 to 4056 of the reference year show an operating example, with flow and inventory on their own scales. Annual performance requires the full year's operation.
The selected Texas interval shows variable hydrogen production, inventory building and draining, and some hours when synthesis is idle. The Midwest FT case also has idle hours. In the MTJ case, synthesis keeps running during this interval while feed tracks hydrogen production and closing inventory remains zero.
Storage serves different roles under these operating rules, equipment sizes and feed requirements. Assessing the MTJ project's buffer requirement needs a full-year view of those conditions.
The full workbook follows an 8,760-hour reference year through the power, hydrogen and buffer/feed blocks. Use that detail to examine when an upstream supply constraint reaches synthesis, and whether an additional asset would earn its place in the project.
For analysts: what the hourly chart includes
All three views use original reference-year hours 4009 to 4056. Hydrogen production and synthesis feed are kilograms in each hourly interval; closing buffer inventory is kilograms on a separate scale. The MTJ zero-inventory line shows the model's calculated output.
Annual utilization requires the full-year results. The workbook also includes electricity, curtailment and other operating balances outside this excerpt. Power/H₂ and buffer/feed calculations have hourly resolution; downstream synthesis and product economics use annual calculations.
Financing determines the required selling price
What must each project receive for its jet fuel?
USD/t jetQualifying 2027 construction starts and 2031 commercial operation. Required prices include eligible 45V support and coproduct revenues under the sponsor-return assumptions.
Eligible statutory producer support and coproduct revenues already enter the price solve. The price meets the assumed sponsor return under each design's financing terms.
The Midwest FT and MTJ designs have almost identical net costs: $4,882.53/t and $4,895.82/t. Their required selling prices are $5,598.30/t and $5,947.43/t. The contract must meet the revenue requirement of the financed project.
Net cost allocates discounted costs and support to jet output. Required price follows construction spending, debt service, tax, coproduct revenues and incentives through the sponsor's cash flows. It solves for the jet price that meets the assumed equity return. These cash-flow assumptions determine the difference between the two measures.
Figure 4 applies to the same qualifying 2027 construction starts, with commercial operation in 2031. Required prices include eligible 45V support under the stated hydrogen-emissions and other conditions. A project beginning construction in 2028 loses access to 45V, so its required price must be assessed without that credit. Compare the applicable result with a buyer offer or an explicitly justified buyer-value assumption, including who receives any compliance benefit.
Keep potential contracts outside the baseline
A competitive contract could change the project, but its effect depends on the terms. Price, supported volume, duration, reference-price settlement and the financing assumptions can move together. Treating the full potential as a simple reduction in production cost would hide those dependencies.
The comparison offers Before support and Eligible support views. Potential contract awards remain outside these selected US results, which include eligible statutory producer support. In a project-specific assessment, compare a clearly defined contract with a matched no-award case, and trace both through required price and cash flow before presenting a benefit. Assess mandates and buyer-compliance value through the customer proposition; producer cash receipts depend on the commercial terms.
Test the assumptions that could change the choice
Fischer–Tropsch; direct-air-capture CO₂; hybrid renewables and battery; hourly matching.
What moves the required selling price?
USD/t jetChanges from 7191.50 USD/t jet. Each assumption changes separately.
Left: lower cost or price. Right: higher cost or price. One-sided results retain their direction.
Each assumption is tested separately against this design’s required selling price. The bars show calculated responses; the selectivity test is one-sided.
Texas tests capital, carbon and conversion performance. Midwest designs test contracted power, capital and conversion performance.
In Texas, a 30% delivered-CO₂ cost shift moves required price by $739.50/t. In the Midwest, a 20% bought-power price shift moves it by $933.79/t for FT and $1,015.83/t for MTJ. Those power-price effects are more than twice the corresponding capex sensitivities of $412.64/t and $438.13/t. For these two designs, the power agreement deserves scrutiny before a tighter equipment estimate.
The workbook also includes an illustrative $85/t CO₂ supplier opportunity premium. This sensitivity tests how a competing outlet for biogenic carbon could affect the Midwest designs. A supply agreement should establish the premium, if any, that the project actually pays.
A ten-percentage-point reduction in jet selectivity raises required price by $1,012.22/t in Texas, $763.42/t in Midwest FT and $885.66/t in Midwest MTJ. Less jet output must carry the project’s economics when the product slate changes. Conversion performance and coproduct value therefore belong in the same commercial assessment as feedstock supply.
For analysts: model boundary, financing and commercial assumptions
Values are real 2026 USD/t jet with the selected energy-allocation convention. Jet, naphtha and LPG allocation and coproduct revenues need consistent treatment. Regional CO₂ costs can be declared stand-ins: verify availability, specification and delivered cost. Validate support, tax and carbon-accounting assumptions against the project's certification and eligibility requirements.
The sensitivity chart measures changes in required selling price. Texas covers capital, carbon and one-sided selectivity tests. The Midwest views cover PPA price, capital and one-sided selectivity tests. Shifts differ in size; selectivity is one-sided. The ranking reflects the effect of those specified changes, with no probabilities assigned. The price solve uses linear sponsor tax with immediate loss use; the separate lender view carries losses forward without an 80% limitation. Working capital, decommissioning and salvage are excluded.
Test the project you could actually deliver
The e-SAF Excel model provides editable inputs, the complete operating year and seventeen sensitivity drivers. It includes 17 prepared designs plus CUSTOM. Compare pathways and allocation choices, then follow your assumptions into required price, project cash flows, equity returns and debt coverage through support changes. Technical and quick-start guides accompany the documented input sources.
Bring the carbon terms, power arrangement, conversion evidence and financing assumptions that your team needs to defend. CovalentIQ can help shape the alternatives and identify the commercial evidence still needed from suppliers, partners and buyers.
Explore the e-SAF model or discuss your project.
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