Karandikars & Associates

Home About us Indian Indicators Global Indicators CTC Strategy Platform Conversion Factors Contact us

Areas of Expertise

Upstream Oil & Gas

Oil Refining

LNG

Power

Petro Chemicals

Green Chemicals


K&A Coal-to-Chemicals Platform: ATF/SAF (Fischer–Tropsch)

Demonstration disclosure:

This is a pre-feasibility screening-level model intended to illustrate relative sensitivities and typical magnitudes, not a bankable feasibility study. Key caveats:

  1. All capex and opex factors are typical publicly available estimates, not vendor-quoted figures — client needs to benchmark against current EPC quotations before use.
  2. The financial model is technology-agnostic. Accordingly, raw syngas composition and coal carbon content are treated as user inputs rather than being derived from a specific gasifier technology. The default syngas values are representative screening-level assumptions and are not intended to represent a guaranteed output from any particular gasification technology. Project-specific values should be established from the selected gasification technology, coal assay and vendor-guaranteed performance.
  3. Coal gasification is a non-catalytic thermal process; catalyst and chemical costs reflect only downstream shift, AGR, and synthesis duty.
  4. No escalation is applied to prices or costs denominated in US dollars over the plant life; these remain in flat real terms. Prices and costs denominated in Indian rupees change in accordance with the exchange-rate depreciation assumption used in the model.
  5. A range of gasifier module sizes is evaluated for screening purposes, with the lowest gasifier ISBL cost configuration identified as the default selection. The user may select an alternative configuration from the available options based on discussions with the selected technology licensor.

Hybrid Coal-Biomass gasification Pathway for ATF / SAF

Since Sustainable Aviation Fuel (SAF) is included as an eligible product under the Government of India's scheme for promotion of Coal/Lignite Gasification Projects, K&A has adopted a hybrid Coal–Biomass Co-gasification pathway as the ATF/SAF configuration. A biomass share of 25% represents a practical balance between renewable carbon contribution, biomass logistics and reuse of existing entrained-flow coal gasification technology. Users may evaluate biomass co-gasification between 5% and 50% to assess the impact on coal requirement, economics and project returns.

The Fischer–Tropsch synthesis section produces a common aviation turbine fuel stream. In the K&A model, the renewable (SAF) portion is accounted for in direct proportion to the biomass co-gasification percentage, while the balance is reported as conventional synthetic ATF. This accounting approach is intended for techno-economic evaluation of hybrid coal–biomass projects and should not be interpreted as regulatory certification under applicable SAF sustainability frameworks.

K&A Suggestion for Subscribers
We suggest that clients who subscribe to our Platform first run the model using the K&A Base Case assumptions and review and record the complete set of results before changing any inputs. The Base Case provides a consistent reference point for understanding the model, the interaction between key assumptions and the resulting technical and financial outcomes. Clients can then challenge, refine or replace individual assumptions based on their own project experience, site-specific information, technology licensor inputs and other feasibility-stage assessments.

User Inputs

The entire input section is available for free viewing. An active subscription is required to run the model and access calculated results, sensitivity analysis and the K&A Strategic Perspective.

  1. Enter your subscription password (provided upon registration).




  2. Select FT Liquids plant capacity (bbl/day)
    FT synthesis and downstream upgrading are capital-intensive processes, and commercial FT projects generally benefit significantly from scale. A 20,000 bbl/day (~1 MMTPA) FT liquids plant should therefore be regarded as a screening-scale reference rather than necessarily representing an economically optimal standalone project capacity. A capacity of around 50,000 bbl/day (~2.5 MMTPA) may provide a more appropriate reference point for a large-scale commercial FT project.
    For ease of reference and comparison, the default capacity in this model is set at 20,000 bbl/day. The model converts this capacity internally into tonnes of FT liquids for material-balance and financial calculations.




  3. FT Product Configuration
    This model considers a ATF/SAF-oriented FT configuration, producing primarily ATF, Naphtha and LPG. For screening purposes, the default product slate is assumed at 70% Kero boiling range, 20% Naphtha and 10% LPG. Actual product distribution depends on FT catalyst, reactor configuration, operating conditions and downstream upgrading strategy and should be validated with the selected technology licensor.

    1. ATF % in FT Output:




    2. Naphtha % in FT Output:




    3. LPG % in FT Output:




  4. Crude Oil Price ($/bbl):
    Crude oil is a globally traded commodity, with prices most commonly expressed in US$/bbl. This model does not attempt to address differences between crude grades, benchmark differentials or location-specific crude price adjustments. A representative long-term screening assumption of US$80/bbl is used as the default. Clients should replace this with their own long-term crude oil price outlook and applicable benchmark.




  5. Realized ATF Crack ($/bbl):
    ATF is a globally traded commodity, and its market economics are commonly assessed through its crack spread relative to crude oil. The model uses a US$15/bbl ATF crack as the default long-term screening assumption. Clients may replace this with their own market outlook, applicable benchmark and expected realization for the target market and offtake arrangement.

    The model uses 7.88 bbl per tonne of ATF to convert the calculated US$/bbl realization into US$/tonne.




  6. Realized SAF Premium over ATF (US$/tonne):
    Sustainable Aviation Fuel (SAF) is typically sold at a premium to conventional Aviation Turbine Fuel (ATF), reflecting higher production costs, regulatory mandates, sustainability attributes and limited global supply. Rather than entering an independent SAF selling price, this model derives the SAF price by adding a user-defined premium to the calculated ATF price, thereby maintaining a consistent relationship with crude oil and jet fuel markets
    The default screening assumption is US$800/tonne. Clients should replace this with their own long-term market outlook, expected offtake agreement or applicable policy support mechanism.




  7. Realized Naphtha Crack ($/bbl):
    Naphtha is a globally traded commodity, and its market economics are commonly assessed through its crack spread relative to crude oil. The model uses a US$5/bbl naphtha crack as the default long-term screening assumption. Clients may replace this with their own market outlook, applicable benchmark and expected realization for the target market and offtake arrangement.

    The model uses 9.0 bbl per tonne of Naphtha to convert the calculated US$/bbl realization into US$/tonne.




  8. Realized LPG Price (Derived from Naphtha price):
    LPG is a globally traded commodity, with prices commonly expressed in US$/tonne. LPG prices can vary significantly by season, region, product composition and benchmark. These factors are not modelled separately at the screening level. Instead, the model links the LPG price to the calculated Naphtha price on a US$/tonne basis, using 90% of the Naphtha price as the default relationship. Clients may replace this assumption with their own market outlook, applicable benchmark and expected realization for the target market and offtake arrangement.




  9. Biomass Co-firing in Total Gasifier Feed (%)
    Biomass co-firing determines the proportion of certified Sustainable Aviation Fuel (SAF) that can be produced under the proportional biomass accounting approach adopted in this model. It also influences biomass requirement, coal consumption, oxygen demand and overall project economics.
    The default screening assumption is 25% biomass co-firing. Commercial coal-biomass co-gasification projects typically evaluate biomass shares in the range of 5–50%. Lower values provide limited SAF production, while significantly higher biomass shares may introduce feedstock availability, handling and gasifier operating constraints.
    Accordingly, this model permits a user-defined biomass co-firing range of 5–50% Clients should modify the assumption within this range to reflect the intended feedstock strategy, biomass availability and the selected gasification technology.




  10. Delivered coal price at plant gate.
    Default assumption: US$35/t, equivalent to approximately ₹3,325/t at an exchange rate of ₹95/US$. The price is expressed in US$ to provide an internationally benchmarkable basis. This is also relevant in the Indian context, as import coal prices form part of the National Coal Index methodology for certain grades of non-coking coal.




  11. Raw syngas composition — H2 (vol%)
    Raw syngas composition is a critical model assumption and should be validated with the gasification technology licensor. H₂ and CO composition, coal carbon content, coal grade, oxygen consumption and gasifier operating conditions are interrelated and should therefore be assessed as an integrated set of assumptions.
    concentration in raw syngas. The default assumption is 35 vol%.




  12. Raw syngas composition — CO (vol%)
    CO concentration in raw syngas. The default assumption is 45 vol%.




  13. Raw syngas composition — CO2 (vol%)
    Default composition: CO2 15% and CH4 + Others 5%, giving a total raw syngas composition of 100%.




  14. Raw syngas composition — CH4 and other minor components (vol%)
    Model check: Individual syngas components must sum to 100%.




  15. Carbon content of coal (fraction, dry basis)
    Carbon content of coal (dry basis) is a principal driver of coal requirement. Indian non-coking coal is generally classified by GCV rather than directly by carbon content; the default assumption of 45% carbon represents a typical mid-grade non-coking coal.
    Carbon content should be assessed as part of the client's integrated coal-quality and gasification assessment, together with syngas composition and gasifier operating conditions. The default assumption should be modified to reflect the project-specific coal assay.




  16. Carbon conversion efficiency — accounts for unconverted carbon lost to slag/char
    Default assumption: 97%, based on published literature




  17. Total ash content in coal
    Ash does not directly affect the financial calculations in the current model; it is used to estimate annual ash generation and should be assessed as part of the overall coal assay and ash-handling requirements.




  18. Total moisture content in coal
    Moisture does not directly enter the financial calculations in the current model, but is an important coal-quality parameter and should be assessed as part of the overall coal assay.




  19. Total sulphur content in coal
    Used to estimate sulphur generation and potential sulphur recovery/revenue from the project. The default assumption is 0.5%, representative of Indian non-coking coal; Indian coals are generally characterized by relatively high ash and moisture content and comparatively low sulphur content. Users should modify the default based on the project-specific coal assay.




  20. Sulphur Price($/ton)
    Used to estimate revenue from sulphur sales. The default assumption is $80/t. Users should modify the default based on the project-specific realisation




  21. Delivered Biomass Price at Plant Gate (Rs/t, dry basis)
    Delivered biomass price at plant gate is a principal driver of SAF economics. The default assumption is US$ 80/ton or Rs 7,600/t at current exchange rate assumption (dry basis).




  22. Biomass Raw syngas composition — H2 (vol%)
    Biomass Raw syngas composition is a critical model assumption and should be validated with the gasification technology licensor. H2 and CO composition, carbon content in Biomass, Carbon Conversion Efficiency, oxygen consumption and gasifier operating conditions are interrelated and should therefore be assessed as an integrated set of assumptions.
    Representative H2 concentration in biomass raw syngas from the selected gasification technology. The default assumption is 28 vol%




  23. Biomass Raw syngas composition — CO (vol%)
    Representative CO concentration in raw syngas from the selected gasification technology. The default assumption is 48 vol%.




  24. Biomass Raw syngas composition — CO2 (vol%)
    Default composition: CO2 22% and CH4 + Others 2%, giving a total raw syngas composition of 100%.
    Representative CO2 concentration in biomass raw syngas. The default assumption is 22 vol%. Together with H2, CO and CH4 + Others, the total raw syngas composition must equal 100%




  25. Biomass Raw syngas composition — CH4 and other minor components (vol%)
    Model check: Individual syngas components must sum to 100%.




  26. Carbon content of Biomass(fraction, dry basis)
    Carbon content of Biomass (dry basis) is a principal driver of Biomass requirement. The default assumption is 37%
    Carbon content should be assessed as part of the client's integrated Biomass/coal-quality and gasification assessment, together with syngas composition and gasifier operating conditions. The default assumption should be modified to reflect the project-specific Biomass and coal assay.




  27. Biomass Carbon Conversion Efficiency (%)
    Carbon conversion efficiency accounts for carbon remaining in slag, ash and unconverted char. The default assumption is 97% and should be validated with the selected gasification technology.




  28. Government Coal Gasification Incentives
    Capital incentives offered by the Government of India are highly project-specific and depend on the applicable scheme, project eligibility, and milestone-based disbursement. The default model assumes a total capital incentive of Rs 2,000 crore, distributed equally as four annual instalments of ₹500 crore. Clients should modify both the year and amount of each instalment based on their assessment of the incentives likely to be available to the project.
    29. Instalment Year Amount (₹ Crore)
    Instalment 1
    Instalment 2
    Instalment 3
    Instalment 4

  29. Availability of a single gasifier unit
    Individual gasifier online availability accounts for periodic refractory relining and unplanned trips. Typical availability may range from 70%–85%, depending on coal characteristics, refractory life and operating conditions.
    Default: 75%. Final assumption should be established with the technology licensor and based on the Client's operating expectations.





  30. Reference Single Train Gasifier Capacity
    Single-train gasifier capacity is a major project-design decision. For high-ash coal, a 2,000–3,000 TPD range is used as the reference range in this model, with 2,500 TPD as the default. Capacity selection should be assessed together with gasification technology/licensor, coal characteristics, operating conditions, syngas composition and required plant scale.
    The reference capacity also provides the basis for scaling gasifier capital cost to the selected project capacity.




  31. Reference Gasifier ISBL Capital Cost
    Default assumption is US$100 million for a 2,500 TPD gasifier, equivalent to approximately US$40,000 per TPD of capacity. Actual cost should be assessed with the selected technology licensor and EPC contractor, including the applicable project scope and site conditions




  32. Oxygen Requirement (ton per ton of Coal)
    Specific oxygen requirement is a key gasifier operating parameter and directly affects ASU capacity and capital cost. The default assumption is 0.9 tonnes of O2 per tonne of coal. Actual consumption can vary materially with gasification technology, coal characteristics and operating conditions and should be validated with the selected licensor.




  33. Biomass Oxygen Consumption (t O2 / t Biomass)
    Oxygen consumption depends on biomass characteristics, gasifier design and operating conditions, and should be validated with the selected gasification technology licensor. The default assumption is 0.80 t O2 per tonne of dry biomass.




  34. Availability of a single ASU unit
    Accounts for planned maintenance and unplanned trips. Large-scale ASUs are a mature technology; the model uses a 95% default availability. The final assumption should be assessed with the selected ASU supplier and aligned with the overall plant operating philosophy.




  35. Reference ASU Capacity
    Reference ASU capacity is used for scaling ASU capital cost. The model uses 3,000 TPD of oxygen as the default reference capacity, broadly representative of a large-scale single-train ASU. Actual configuration and capacity should be determined from the project's oxygen requirement and selected supplier's design.




  36. Reference ASU ISBL Capital Cost
    Default assumption is US$90 million for a 3,000 TPD ASU, equivalent to approximately US$30,000 per TPD of oxygen capacity. Actual cost should be assessed with the selected ASU supplier and EPC contractor based on the required scope and project conditions.




  37. Reference Coal / Biomass Handling Capacity
    Coal handling capacity depends on FT plant scale, coal characteristics, technology and operating conditions. A reference range of 7,000–12,000 TPD is considered, with 10,000 TPD as the default reference capacity. This reference capacity is used as the basis for scaling coal-handling capital cost.




  38. Reference Coal / Biomass Handling Capital Cost The default reference capital cost is US$50 million for a 10,000 TPD coal-handling system, equivalent to approximately US$5,000 per TPD of capacity. This reference cost is used to scale coal-handling capital cost with capacity; actual cost should be assessed based on the required handling, storage, crushing, conveying and loading scope.




  39. Reference AGR Capacity
    Acid Gas Removal (AGR) capacity can be expressed in Nm³/hr, Nm³/day, tonnes/hr or TPD. Because syngas composition affects conversion between volume and mass, the model expresses the reference capacity in TPD for intuitive comparison. The model internally converts syngas composition and molecular weights to determine the corresponding kmoles/day and mass flow




  40. Reference AGR Capital Cost
    Our default capital cost for a 20,000 TPD shifted syngas AGR system is US$150 million, equivalent to approximately US$7,500 per daily tonne of raw syngas capacity
    Actual cost can vary materially with acid-gas composition, removal requirements, technology selection and project scope




  41. Reference Water Gas Shift Capacity
    Water Gas Shift (WGS) capacity is defined by the quantity of CO processed through the shift reaction, which converts CO to H₂ and CO₂. The required WGS capacity varies with the downstream product and the desired syngas composition. Capacity can be expressed in Nm³/hr, Nm³/day, tonnes/hr or TPD; the model expresses it as TPD of CO processed for intuitive comparison.
    Default reference capacity: 1,500 TPD of CO processed.




  42. Reference Water Gas Shift Capital Cost
    The default reference capital cost is US$30 million for a WGS system processing 1,500 TPD of CO, equivalent to approximately US$20,000 per daily tonne of CO processed. This reference cost is used to scale WGS capital cost with capacity; actual cost depends on conversion requirements, catalyst configuration, operating conditions and project scope.




  43. Reference FT Capacity
    FTe capacity of 20,000 b/d or approx 1 MMTPA is used as the default reference capacity in the model.




  44. Reference FT ISBL Capital Cost
    The default reference FT ISBL capital cost is US$600 million for the 20,000 b/d fuel oriented FT plant. Actual cost should be assessed with the selected technology licensor/EPC contractor and project-specific scope.




  45. OSBL (% of ISBL Capital Cost)
    Outside Battery Limits (OSBL) includes infrastructure and facilities outside the main process-unit boundaries. OSBL cost can vary materially with site conditions, existing infrastructure and project scope, and may range from approximately 25% to 100% of ISBL cost. The model uses 40% of ISBL as the default screening assumption




  46. EPC (% of ISBL+OSBL Capital Cost)
    Engineering, Procurement and Construction (EPC) costs can vary with project size, complexity and contracting strategy; the model uses 15% of combined ISBL + OSBL cost as the default screening assumption




  47. Owners' Cost (% of ISBL+OSBL+EPC Capital Cost)
    Owners' costs include project-specific costs incurred by the owner outside the ISBL, OSBL and EPC scope. The model uses 10% of combined ISBL + OSBL + EPC cost as the default screening assumption; actual requirements depend on project structure, ownership arrangements and scope allocation.




  48. Coal Handling Plant Scaling Exponent
    Capital cost exponent, or capital cost scaling factor, is commonly known as the Six-Tenths Rule. It is used to estimate the capital cost of a new plant or piece of equipment from the known cost and capacity of a different-sized unit, taking into account economies of scale.
    For most process equipment and industrial plants, scaling exponents generally fall in the range of 0.4–0.8, meaning that capital cost increases less than proportionately as plant capacity increases.
    Our default scaling factor is 0.6 for all plant and equipment categories. This is a widely used general-purpose assumption and is the basis for the commonly used term “Six-Tenths Rule.”




  49. AGR Plant Scaling Exponent (Default = 0.6)




  50. WGS Plant Scaling Exponent (Default = 0.6)




  51. FT Plant Scaling Exponent (Default = 0.6)




  52. Electricity Price
    Default assumption is US$70/MWh. Users should modify this to reflect the applicable project-specific electricity cost or power sourcing arrangement




  53. FT Plant Power Consumption
    Default assumption is 25 kWh per tonne of FT products produced. Actual consumption should be assessed against the selected technology and project configuration




  54. FT Catalyst Consumption
    Default assumption is US$5/t of FT products. Actual catalyst consumption and replacement cost should be assessed with the selected technology/licensor.




  55. Plant utilization in first year of operation
    Year 1 utilization is assumed at 80%, increasing to 90% in Year 2 and 100% under normal operating conditions from Year 3 onward. These assumptions are considered reasonable ramp-up assumptions in conjunction with the separately specified equipment availability




  56. Plant utilization in second year of operation
    Year 1 utilization is assumed at 80%, increasing to 90% in Year 2 and 100% under normal operating conditions from Year 3 onward. These assumptions are considered reasonable ramp-up assumptions in conjunction with the separately specified equipment availability




  57. Plant Normal utilization
    The model assumes 100% utilization from the third operating year onward, subject to the separately specified availability assumptions. Given the default 75% individual gasifier availability, the 80% / 90% / 100% utilization profile is intended as a ramp-up and operating-utilization assumption and is not intended to imply 100% physical equipment availability




  58. Project construction period
    Integrated gasification and downstream chemical projects are technically complex and involve multiple major process units and interfaces. The model uses 4 years as the default construction period, while allowing users to test construction periods from 2 to 7 years. The appropriate period should ultimately be established from the project execution schedule, technology/licensor requirements and EPC strategy




  59. Total operating life of the project.
    The total operating life assumed for the project after commercial operation. The model uses 25 years as the default for project financial evaluation




  60. Depreciation (in Years)
    The period over which the depreciable project investment is depreciated for financial modelling purposes. The model uses 20 years as the default.




  61. Annual fixed operating cost.
    Represents recurring fixed operating and maintenance costs that do not vary directly with production volume. The model assumes 2.5% of applicable project CAPEX per year as the default




  62. Project discount rate
    The discount rate used to calculate the present value of project cash flows and Project NPV. The model uses 10% as the default screening assumption. The appropriate rate should reflect the project's risk profile, financing structure, currency and investor return requirements and should be assessed by the Client for detailed investment evaluation.




  63. Equity discount rate
    The discount rate used exclusively to calculate the present value of post-tax equity cash flows and Equity NPV. This represents the shareholders' required rate of return. The model uses 14% as the default screening assumption, while the Project Discount Rate continues to be used for Project NPV. Clients may modify this assumption to reflect project-specific investor hurdle rates.




  64. Debt portion of project financing
    The percentage of project cost assumed to be financed through debt. The model uses 70% debt financing as the default, with the balance funded through equity




  65. Interest rate on US Dollar debt
    The annual interest rate assumed on US Dollar-denominated project debt. The default assumption is 7%.



  66. Rupee debt interest rate spread over US Dollar debt
    The additional interest rate assumed for Rupee-denominated debt relative to the US Dollar debt rate. The default spread is 3 percentage points.




  67. Working Capital as a percentage of Sales
    The default assumption is 10%.



  68. Interest rate on Working Capital
    The annual interest rate assumed on Working Capital. The default assumption is 6%.



  69. Rupee / US Dollar Exchange Rate for 1st Year
    The exchange rate assumed for Project Year 1, which is the first year of the construction period. The model uses ₹95/US$ as the default assumption.



  70. Annual Rupee Depreciation
    The assumed annual depreciation of the Rupee against the US Dollar over the project period. The model uses 3% per year as the default assumption, applied from the Year 1 exchange-rate base.



  71. Tenor of debt repayment
    The period over which project debt principal is repaid following commercial operation. The model assumes a 12-year repayment tenor as the default




  72. Corporate income tax rate
    The corporate income tax rate applied to taxable project/equity cash flows in the financial model. The default assumption is 25%.
    The model is intended for screening-level financial evaluation and does not optimise project-specific tax depreciation schedules, tax holidays, credits or other tax incentives. Clients should incorporate applicable tax provisions and project-specific incentives during detailed financial evaluation




  73. Sustaining Capital (pct of Project Cost)
    Annual capital expenditure assumed to maintain the plant and replace or refurbish equipment over its operating life. The model assumes 1.5% of project cost per year as the default





    74. Leading Global Technology Suppliers

    The following companies are among the leading global technology licensors for the product pathways covered by the K&A Coal-to-Chemicals Platform. Companies are listed in alphabetical order. The listing is indicative and does not constitute a recommendation, ranking or endorsement by Karandikars & Associates.

    ProductLeading Technology Suppliers
    GasificationAir Liquide Engineering & Construction (Lurgi), ECUST, Shell
    Syngas Gas Cleaning & Water Gas ShiftBASF, Johnson Matthey, Topsoe
    Acetic AcidBP Cativa, Celanese, Eastman
    AmmoniaCasale, KBR, Topsoe, thyssenkrupp Uhde
    Ammonium NitrateCasale, Incro, thyssenkrupp Uhde
    Ammonium SulphateCasale, Technip Energies, thyssenkrupp Uhde
    ChloromethanesKureha, Shin-Etsu, Tokuyama
    Dimethyl Ether (DME)Johnson Matthey, Topsoe
    Ethanol (Methanol Route)DICP, ECUST
    Fischer-Tropsch (FT)Johnson Matthey, Sasol, Shell, Topsoe
    FormaldehydeJohnson Matthey FORMOX, Mitsubishi Gas Chemical, Topsoe
    MethanolCasale, Johnson Matthey, Topsoe
    Methanol-to-Olefins (MTO)DICP, Honeywell UOP
    MMA (ALPHA Route)Lucite International
    MMA (C4 Route)Mitsubishi Chemical, Röhm
    MTBECDTECH (Lummus), Honeywell UOP
    Sustainable Aviation Fuel (SAF)Axens, Honeywell UOP, Johnson Matthey, Topsoe
    Synthetic Natural Gas (SNG)Honeywell UOP (TREMP), Johnson Matthey, Topsoe
    TAMECDTECH (Lummus), Honeywell UOP
    UreaCasale, Saipem, Stamicarbon, Toyo Engineering

    Disclaimer: Technology licensors listed above are trademarks of their respective owners. Karandikars & Associates is an independent techno-economic advisory platform and is not affiliated with or endorsed by any listed company.


K&A Coal-to-Chemicals Strategy Platform

Privacy Policy | Terms of Use
© 2026 Karandikars & Associates