Coal-to-Chemicals Platform | Karandikars & Associates

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K&A Coal-to-Chemicals Platform: UCG IGCC

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:

All capex and opex factors are typical publicly available estimates, not vendor-quoted figures — client needs to benchmark against current EPC quotations before use.
In the financial model, raw syngas composition and coal carbon content are treated as user inputs. The default syngas values are representative screening-level assumptions. Project-specific values should be established from the pilot plant studies and vendor-guaranteed performance.
Coal gasification is a non-catalytic thermal process; catalyst and chemical costs reflect only downstream shift, AGR, and synthesis duty.
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.
The model is based on a standard UCG module producing 0.50 MMSCMD of raw syngas per module, together with its representative screening capital cost. The user may select an alternative UCG module capacity and cost from the available options based on discussions with the selected technology licensor.

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.

Enter your subscription password (provided upon registration).

Subscription Password:

Select the desired IGCC plant capacity.
Capacity selection should consider max single train capacities, economies of scale and total capital commitment. Our default value is 1,000 MW ( or 1 GW). The K&A Base Case adopts a commercially realistic 2×310 MW Gas Turbine and 380 MW Steam Turbine configuration representative of a large utility-scale IGCC power island

CCGT Capacity (MW):

Select GT Efficiency
Our default value is 36%

Gas Turbine Efficiency (%):

Select Plant Load Factor (PLF)
Our default value is 90%

IGCC Plant Load Factor (%):

Auxiliary Power Consumption
Default assumption is 3%. Actual consumption should be assessed against the selected technology and project configuration

Auxiliary Power Consumption:

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

Electricity Selling Price ($/MWh):

Underground unmineable coal price
Default assumption: US$20/t, equivalent to approximately ₹1,900/t at an exchange rate of ₹95/US$. 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.

Coal Price ($/t):

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

H2 (%):

Raw syngas composition — CO (vol%)
CO concentration in raw syngas. The default assumption is 30 vol%.

CO (%):

Raw syngas composition — CO2 (vol%)
Default composition: CO2 25% and CH4 + Others 10%, giving a total raw syngas composition of 100%.

CO2 (%):

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

CH4 + Others (%):

Carbon content of coal (fraction, dry basis)
Carbon content of the underground coal (dry basis) is a principal driver of coal requirement. Indian non-mineable coal is typically considered to be having carbon content of 70% and that is our default assumption
Carbon content should be assessed as part of the client's integrated coal-quality and syngas composition. The default assumption should be modified to reflect the project-specific coal assay.

Carbon Content of Coal:

Carbon conversion efficiency — accounts for conversion efficiency of UCG
Default assumption: 60%, based on published literature

Carbon Conversion Efficiency (%):

Government Coal Gasification Incentives
While provision has been made to capture potential Capital incentives that could be offered by the Government of India the default model does not assume any such incentives. Clients can modify both the year and amount of each instalment based on their assessment of the incentives likely to be available to the project.

Instalment	Year	Amount (₹ Crore)
Instalment 1
Instalment 2
Instalment 3
Instalment 4

Availability of a single UCG Module
Default: 100%. Final assumption should be established with the UCG technology licensor and based on the Client's operating expectations.

Individual Single Module Online Availability (%):

Reference Single UCG Module production Capacity
Single UCG Module syngas production capacity is a major project-design parameter. 0.5 MMSCMD per Module is used as the default.

Single UCG Module Capacity:

Reference single UCG Module Capital Cost
Default assumption is US$10 million per Module producing 0.5 MMSCMD raw syngas

Reference Single UCG Module Cost:

Average UCG Module life
Default assumption is 8 years Average UCG Module Life:
Oxygen Requirement (ton per ton of Coal)
Specific oxygen requirement is a key operating parameter and directly affects ASU capacity and capital cost. The default assumption is 0.50 tonnes of O2 per tonne of Coal. Actual consumption can vary materially with coal characteristics and operating conditions and should be validated with the selected licensor.

Oxygen Requirement (ton per ton of Coal):

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.

Individual ASU Online Availability (%):

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.

ASU Capacity:

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.

Reference ASU Cost:

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

Reference AGR Capacity:

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

Reference AGR Capital Cost:

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.

Water Gas Shift Capacity:

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.

Water Gas Shift Capital Cost:

Reference IGCC Capacity
Our Model uses 1,000 MW as default reference capacity for IGCC ISBL capital-cost scaling in the model.

IGCC Capacity:

Reference IGCC ISBL Capital Cost
The default reference IGCC ISBL capital cost is US$650 million for the 1,000 MW IGCC plant. AGR, gasification, ASU and coal handling are treated as separate ISBLs in the model. Actual cost should be assessed with the selected technology licensor/EPC contractor and project-specific scope.

Reference IGCC ISBL Cost:

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

OSBL (% of ISBL Capital Cost):

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

EPC (% of ISBL+OSBL Capital Cost):

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.

Owners' Cost (% of ISBL+OSBL+EPC Capital Cost):

AGR Plant Scaling Exponent (Default = 0.6)

AGR Plant Scaling Exponent:

WGS Plant Scaling Exponent (Default = 0.6)

AGR Plant Scaling Exponent:

IGCC Plant Scaling Exponent (Default = 0.6)

IGCC Plant Scaling Exponent:

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

Year 1 Utilization (%):

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

Year 2 Utilization (%):

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

Normal Utilization (%):

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

Construction Period (Years):

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

Plant Life (Years):

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.

Depreciation (Years):

UCG Sustaining CAPEX and Depreciation
UCG modules are assumed to have a shorter economic life than the main surface project assets and therefore require periodic replacement. The model treats these module replacements as sustaining CAPEX, capitalises them as fixed assets, and depreciates each replacement over the assumed UCG Module Depreciation Period. The annual sustaining CAPEX is derived from the assumed UCG module requirement and module life, rather than being treated as a simple operating expense. This recurring replacement requirement is incorporated into the project's cash flow, depreciation, financial statements and fixed-asset schedule.
The model uses 8 years as the default.

UCG Sustaining CAPEX Depreciation (Years):

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

Plant Fixed O&M (% of CAPEX):

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.

Discount Rate (%):

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.

Equity Discount Rate (%):

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

Debt (%):

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

US Dollar Debt Interest Rate (%):

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

Working Capital as a % of Sales:

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

Working Capital Interest Rate (%):

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.

Rupee Debt Interest Rate Spread (%):

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.

Rupee / US Dollar Exchange Rate for 1st Year:

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.

Annual Rupee Depreciation:

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

Debt Tenor (Years):

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

Tax Rate (%):

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

Sustaining Capital (%):

Leading Global Technology Suppliers

Product	Leading Technology Suppliers
Gasification	Air Liquide Engineering & Construction (Lurgi), ECUST, Shell
Syngas Gas Cleaning & Water Gas Shift	BASF, Johnson Matthey, Topsoe
Acetic Acid	BP Cativa, Celanese, Eastman
Ammonia	Casale, KBR, Topsoe, thyssenkrupp Uhde
Ammonium Nitrate	Casale, Incro, thyssenkrupp Uhde
Ammonium Sulphate	Casale, Technip Energies, thyssenkrupp Uhde
Chloromethanes	Kureha, Shin-Etsu, Tokuyama
Dimethyl Ether (DME)	Johnson Matthey, Topsoe
Ethanol (Methanol Route)	DICP, ECUST
Fischer-Tropsch (FT)	Johnson Matthey, Sasol, Shell, Topsoe
Formaldehyde	Johnson Matthey FORMOX, Mitsubishi Gas Chemical, Topsoe
Methanol	Casale, Johnson Matthey, Topsoe
Methanol-to-Olefins (MTO)	DICP, Honeywell UOP
MMA (ALPHA Route)	Lucite International
MMA (C4 Route)	Mitsubishi Chemical, Röhm
MTBE	CDTECH (Lummus), Honeywell UOP
Sustainable Aviation Fuel (SAF)	Axens, Honeywell UOP, Johnson Matthey, Topsoe
Synthetic Natural Gas (SNG)	Honeywell UOP (TREMP), Johnson Matthey, Topsoe
TAME	CDTECH (Lummus), Honeywell UOP
Urea	Casale, 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.

Karandikars & Associates

K&A Coal-to-Chemicals Platform: UCG IGCC

User Inputs

K&A Coal-to-Chemicals Strategy Platform