Presentation by Takaya Watanabe – General Manager, Sustainability Energy & Environment Strategic Planning Dept., Mitsubishi Heavy Industries, Ltd. at Tokyo CCS Financial Model Workshop, 3 September 2012.

1. GCCSI Financial Model
Case Study
September 03, 2012
Presented by
© 2012 MITSUBISHI HEAVY INDUSTRIES, LTD. All Rights Reserved.
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2. Contents
Model Features
• Expected Users
• Commercial Relation Model
• Model Logic & Features
Project Case Study : IGCC + CCS Project
• Case Study (Assumption of a fictional project)
• Base Case Results (Model Outputs)
• Sensitivity Analysis (Model Outputs)
• Value & Request
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3. Model Features/Expected Users
The Model was developed to evaluate CCS Projects at a screening stage
The Expected Users are:
• Plant Owners (Utility company etc.)
• Project Developers
• Investors
• Lenders
• Policy Makers (Subsidies)
• Consultant/Think Tank
• EPC Contractor
• OEMs
This presentation is prepared by MHI as Project Developer/EPC Contractor/OEM
of Gasifier, Gas Turbine, Steam Turbine, CO2 Compressor.
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4. Model Features/Commercial Relation
Various type of
“Government Subsidies”
can be simulated
Payment to CO2
Transport & Storage
Provider is added to
Cost of Generation &
Capture Plant
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5. Model Features/Model Logic & Features
The model is set up to evaluate an integrated CCS Project including:
• Upto three (3) Power Generation and CO2 Capture Projects
• A Single CO2 Transport Project
• A Single CO2 Storage Project
The Model’s worksheets have been structured around four (4) categories as follows:
• Inputs : General Assumptions, Price Assumptions, Scenario Manager
• Calculations: WACC (Weighted Average Cost of Capital), Timing, Operating Cash Flow,
Capex, Depreciation, Transport & Storage Charges,
LCOE (Levelised Cost of Electricity), Government Subsidies
• Outputs
• Financial Statements: P/L Statement, Cashflow Statement, Balance Sheet,
Discounted Cashflow Valuation
• Summary: LCOE, Commercial Gaps, NPVs, Government Subsidies
• Charts: EBITDA, Source & Use of Funds, LCOE constrains, NPV Constituents
Commercial Gaps
• Others: Cover Sheet, Table of Contents, Information, Project Scheme, Macros etc.
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6. Model Features/Model Logic & Features
The Model can run a different scenario of User’s choice using “Scenario Manager”
The Model contains Sensitivity inputs for the following categories
• Capex
• Capex Subsidies
• O&M Costs
• Fuel Costs
• CO2 Cost
• CO2 Transportation Costs
• CO2 Storage Costs
• PPA Revenue
• Other Revenue (such as EOR Revenue
• Operating Subsidies
• WACC (Weighted Average Cost of Capital)
The Model can run the following Goal Seeking Macros:
• Goal Seeking Transport & Storage Charges (optimization to NPV = Zero)
• Goal Seeking Government Capex Subsidies (optimizing to NPV=Zero)
• Updating Sensitivities
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7. Case Study : Project Assumption
(Base Case)
General Assumption CCS Assumption
Project Scope: IGCC + CCS CO2 Transport CAPEX, OPEX
Commercial Operation starts in 2020 CO2 Storage CAPEX, OPEX
Business Model : SPC Scheme Etc. to calculate CO2 Transport & Storage Fee
w/ Equity 40%: Debt 60% (Sample of Input Sheet)
Revenue: Electricity Tariff @$ 50/MWh
No CO2 Revenue GCCSI CCS Model OK
Input - General
Assumptions
Power Generation & Capture Assumption SHEET CHECK OK
1General Assumptions Unit
Gross Generation Capacity: 1017MW
Timing
Plant Auxiliary Power: 218MW 1.1
Model start date Year 2012
Model periods Years
Fuel Consumption : 10.2 GJ/MWh Model end date Year
70
2,082
Fuel Cost: @$2.61/GJ 30-Jun-
Valuation date
date 11
CO2 Capture: 0.8 CO2- ton/Net MWh Mid-period cashflows
assumed
CO2 Cost: $30/CO2-ton Emission per Yr
Escalation
CAPEX: $ 3.0 Billion 1.2
Inflation Rate (CPI) % 2.5%
OPEX(Fixed): $ 3.9 Million /Yr Base Year of real revenue
inputs Year
2012
OPEX (Variable): $ 6.1/MWh per Year Base Year of real cost
inputs Year
2012
Price Escalation -
100.0%
Percentage of CPI %
Cost Escalation -
100.0%
Percentage of CPI %
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8. Base Case Result (Outputs)
•LCOE= Levelised Cost of Electricity = NPV of Project Costs/NPV of Total Generation= @$103.6/MWh
→ Project is not feasible with Market PPA Tariff (@$50/MWh)
• Commercial Gap = “LCOE” - “Levelised Electricity Price” = @$53.6/MWh
• Sample of “Built-in” chart for Model Outputs is shown below
CAPEX is the largest constituent $53.61/MWh
$103.6/MWh
Fuel Cost
$28.51/MWh is
$50.0/MWh
relatively low due
to low Coal Cost
Not
Considered
$53.6/MWh
The Model calculates Transportation Cost ($1.55/MWh)”
& Storage Cost ($7.24/MWh)
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9. Sensitivity Analysis (Outputs)
2Sensitivity Summary Unit
IGCC
LCOE changes
2.4
Base Case $ / MWh 109.63 109.63
Capex (+/- 10%) $ / MWh 5.62 (5.62)
O&M costs (+/- 10%) $ / MWh 0.65 (0.65)
Fuel costs (+/- 10%) $ / MWh 2.85 (2.85)
CO2 costs (+/- 10%) $ / MWh 0.29 (0.29)
WACC (high / low) $ / MWh 18.67 (15.91)
NPV changes
2.5
Base Case $ 000's (373,203.79) (373,203.79)
Capex (+/- 10%) $ 000's (230,049) 230,049
Capex Subsidies (+/- 10%) $ 000's (211,652) 211,652
O&M costs (+/- 10%) $ 000's (36,308) 36,308
Fuel costs (+/- 10%) $ 000's (158,453) 158,453
CO2 costs (+/- 10%) $ 000's (15,984) 15,984
Transport costs (+/-10%) $ 000's (8,624) 8,624
Storage costs (+/-10%) $ 000's (40,088) 40,088
Other revenue (+/-10%) $ 000's ‐ ‐
Operating subsidy (+/-10%) $ 000's ‐ ‐
EOR revenue (+/-10%) $ 000's ‐ ‐
Gov PPA revenue (+/-10%) $ 000's ‐ ‐
Market PPA revenue (+/-10%) $ 000's (277,856) 277,856
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10. WACC Assumption /Calculation
• The Model provides “Pre-Financing” Cashfow only.
• However, it provides “WACC” ( Weighted Average of Capital Cost) simulation.
• The following are the Assumption and Calculation of the Case Study Project.
WACC calculation IGCC
WACC Inputs Transport Storage Hub IGCC
2.1 Cost of commercial equity
Risk free rate 5.00%
10.1 Funding structure Beta - ungeared 0.75
Commercial equity 35.0% 20.0% 25.0% Debt / Equity 150.00%
Concessional equity 0.0% 40.0% 15.0% Regearing factor 2.05
Commercial debt 65.0% 20.0% 25.0% Beta - geared 1.54
Concessional debt 0.0% 10.0% 20.0% Market risk premium 6.00%
Government debt 0.0% 10.0% 15.0% Alpha 2.00%
Check OK OK OK Cost of commercial equity 16.23%
10.2 General valuation parameters 2.2 Commercial debt
Risk-free rate 5.00% 5.00% Risk free rate 5.00%
Market risk premium 6.00% 6.00% Margin above risk-free rate 3.50%
Liability Reserve -Interest Rate 5.0% Swap Margin 0.50%
Cost of commercial debt 9.00%
10.3 Commercial equity valuation parameters
Beta - ungeared 0.45 1.05 0.75 2.3 WACC
Alpha 0.0% 2.0% 2.0% WACC Nominal Post Tax - Calculated 8.80%
Sensitivity applied to base case 0.00%
10.4 Concessional equity valuation parameters WACC Nominal Post Tax 8.80%
Concessional equity rate (all in rate) 8.0% 10.0% 12.0%
Inflation Rate (CPI) 2.50%
10.5 Commercial debt valuation parameters WACC Real Post Tax 6.14%
Debt margin above swap 2.0% 3.0% 3.5%
Swap Margin 0.5% 0.5% 0.5% WACC Real Pre Tax - Applied 8.78%
10.6 Concessional debt valuation parameters
Concessional debt interest rate (all in rate) 6.0% 6.0% 6.0%
IRR of the Project is 8.80%p.a.
10.7 Government debt valuation parameters
(after Government Capital Cost Subsidy Macoro runs)
Government debt interest rate (all in rate) 5.0% 5.0% 5.0%
© 2012 MITSUBISHI HEAVY INDUSTRIES, LTD. All Rights Reserved. 10

11. “Value” and “Request”
• The Model is easy to operate and to simulate not only variation of essential
“Project Values” (CAPEX, OPEX, Revenue, Schedule, Plant Performance etc.)
but also various form of “Government Subsidies” (Feed-in-Tariff, Capital Cost
Subsidies, Operating Cost Subsidies and Tax Credit). This is a unique value of
GCCSI Financial Model.
• The Model is also useful to understand and evaluate the relation between
“Power Generation” and “CCS” in one cashflow model.
Request for Further Improvement
1.“Built-in Scenario of EOR (Enhanced Oil Recovery)”
The current model has EOR Revenue Selection Input but requires manual adjustment
for CCS related cost inputs. It would be ideal if the Model has a built-in function of
“CCS: EOR Ratio” (i.e.100%= No CCS but all the captured CO2 goes to EOR)
2. “Funding Cashflows”
The current Model is set for “Pre-Financing Cashflow” only. The built-in Option for
cashflow with various inputs of Debt terms (interest rate, repayment period), Debt
amortization and Equity distribution. Then, adding “ROE=Return of Equity” in Outputs
and Sensitivity sheets will be very much appreciated, especially, by Investors.
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12. © 2012 MITSUBISHI HEAVY INDUSTRIES, LTD. All Rights Reserved.
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13. Hand-out Material for Panel Discussion
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14. Feed-in-Tariff for Clean Coal Power Generation (1 of 2)
• In many countries, the Feed-in-Tariff (FIT) has been adopted as an incentive for
constructing Renewable Energy Plant
• If the main purpose of FIT is to reduce CO2 Emission, Why not “FIT for Clean Coal
Power Generation” ?
• In the Country X where the majority of Power is generated from Coal, “FIT for
Renewable” is established as follows:
Technology Power Tariff CO2 Emission Capacity (A) Annual (B) Annual (C) Incentive
Rate Utilization Reduction of Total per CO2
(CO2ton/MWh) Factor CO2 by 1000MW Incentive Reduction
Capacity Plant ($/Year) per Year
(CO2 ton/Year) ($/Ton)
Conventional @$55.30/MWh 0.99 90% Base Base Base
Coal Power (Market Tariff) (Base)
Generation
Renewable @$84.60/MWh zero 24% (2,081,376) 61.6 M$ $29.6/ton
(Wind) (FIT)
Renewable @$192.80/MWh zero 18% (1,561,032) 216.8 M$ $138.9/ton
(Solar-PV) (FIT)
Renewable @$258.20/MWh zero 23% (1,994,652) 408.8 M$ $204.9/ton
(Solar-CSP) (FIT)
(A) = CO2 Emission Rate x 1000MW x 24h x 365day x Capacity Utilization Factor
(B) = (FIT – Market Tariff) x 1000MW x 24h x 365day x Capacity Utilization Factor
(C) = (B) / (A)
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15. Feed-in-Tariff for Clean Coal Power Generation (2 of 2)
The same calculation for IGCC+CCS (90%) shows as follows:
Technology Power Tariff CO2 Emission Capacity (A) Annual (B) Annual (C) Incentive per
Rate Utilization Reduction of Total Annual CO2
(CO2ton/MWh) Factor CO2 by Incentive for Reduction for
1000MW Plant 1000MW 1000MW Plant
(CO2 ton/Year) Plant ($/Year) ($/Ton)
Conventional @$55.30/MWh 0.99 90% Base Base Base
Coal Power (Market Tariff) (Base)
Generation
IGCC + CCS X 0.089 90% (7,103,484) Y Z
Power Plant
With LCOE of “IGCC+90%CCS” = @$116.0/MWh by GCCSI Financial Model, X～Z can be evaluated as follows:
Technology X: Power Tariff Y: Annual Total Incentive for Z: Incentive per Annual CO2
1000MW Plant ($/Year) Reduction for 1000MW Plant ($/Ton)
Conventional Coal Power @$55.30/MWh Base Base
Generation (Market Tariff)
IGCC + CCS @$116.0/MWh 478.6 M$/Yr $67.4/Ton/Yr
Power Plant
If “Wind” FIT is applied @$84.60/MWh 61.6 M$ $29.6/ton
If “Solar-PV” FIT is applied @$192.80/MWh 216.8 M$ $138.9/ton
If “Solar-CSP” FIT is applied @$258.20/MWh 408.8 M$ $204.9/ton
Conclusion: In Country X,
1. FIT for “IGCC+CCS” is a valid option for “CO2 Reduction” Incentive.
2. FIT for IGCC + CCS should be higher than “Wind” but lower than “Solar”
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