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CDM Biomass Direct Combustion Model2.xls

June 25th, 2012 Posted in renewable energy

CDM Biomass Direct Combustion Model2.xls

In addition to the worksheets found in the ADV models of the regulator, 5 additional tabs or worksheets have been added (Capex, Opex, Revenues, Project IRR and Sensitivity) into the CDM model which is a financial evaluation without taxes (that distort the economic and technical performance) and debt (pure equity investment). For the RE project to benefit from CDM credits, the project IRR should not be more than 15% p.a.

Direct combustion of biomass system (furnace, boiler, steam turbine, generator) is carried out mostly in the countryside where biomass is abundant from agricultural activity such as paddy rice, corn fields, cotton fields, sugar cane fields, tree plantation and municipal solid waste (MSW). A 50-km radius of agricultural land can support around 6-12 MW of biomass power plant as in the case of India.

This advanced feed-in-tariff model for biomass direct combustion makes use of the basic assumptions of the country’s RE regulator for rated capacity (1 x 8.3 MW), capacity factor (80%), plant own use (10%), and 0.20% plant degradation rate.

It assumes equipment cost (FOB $/kW), ocean insurance and freight (4.5%), balance of plant (21%), G&A cost ($/year), O&M cost ($/kW/year), spare parts replacement cost ($/unit/year), substation and transmission line cost ($/km) and distance (km), access road cost ($/km) and distance (km), 15% project development cost, 12% VAT, 11% working capital and 4% contingency. VAT recovery is 70% on the 5th year. Days receivable and payable are 30 days.

Construction period is 24 months while operating period is 20 years. Cost of capital is 16% p.a. for 30% equity and 10% p.a. for 70% debt.

Exchange rate is 44.00 PhP/US$.

Incentives provided by the RE Law is applied such as the 7 years income tax holiday, after which a 10% income tax is applied. Property tax of 1.5% applied on 80% of book value. Local business tax is 1% of revenues while DOE 1-94 contribution is 0.01 PhP/kWh sold.

It also assumes an average biomass thermal efficiency of 27%, biomass fuel cost of 1,297 PhP/mt and gross heating value of 4,000 Btu/lb.

To order, pay and download this model, follow this link:

http://energydataexpert.com/product_info.php?cPath=19_37&products_id=176

The summary worksheet is shown below:

 

Project   Site Name & Location Direct Combustion
Renewable Energy Source Biomass
Hours per Year 8760
Timing
  Construction Period (from FC) (months) 24
  Operating Period (Yrs from COD) 20
  Yrs from base year CPI & Forex (2009)   for FIT 4
  Yrs from base year CPI (2011) for CAPEX 1
  Yrs from base year CPI (2011) for OPEX 3
Construction Sources and   Uses of Funds, $000
  Uses of Fund:
    EPC (Equipment, Balance of Plant,   Transport, Access Roads) $16,029
    Transmission Line Interconnection   Facility $42
    Sub-Station Facility $818
    Development & Other Costs $2,627
    Construction Contingency $782
    Value Added Tax $1,425
    Financing Costs $2,022
    Initial Working Capital $1,793
  Total Uses of Fund $25,536
  Sources of Fund:
    Debt $17,875
    Equity $7,661
  Total Sources of Fund $25,536
  Construction Unit Costs (US$/kW):
    EPC Cost $1,931
    Plant Cost (Excluding VAT, Financing,   Working Capital) $2,445
    All-in Project Cost $3,077
Model Check:
Balance Sheet   OK
Foreign Debt Amorization   OK
Local Debt Amortization   OK
Depreciation   OK
Sources and Uses of   Funds   OK
Debt-to-Equity Ratio   OK
Base Years
  Base year CPI & Forex for FiT 2009
  Base year CPI for CAPEX 2011
  Base year CPI for OPEX 2011
Commercial Operating Date 2013

 

Technical and EPC   Assumptions
Unit Capacity of Plant   (MW/unit) 8.300
No. of Units (unit) 1.0
Gross Installed Capacity   (MW) 8.30
Plant Availability Factor, % 84.23%
Guaranteed Efficiency   Factor, % 95.00%
Allowance for losses & own use, % 10.00%
Net Capacity Factor after   losses & own use, % 72.02%
Net Electrical Output (MWh   in 1st Year) 52,365
Plant Degration, % p.a.   (1-20 Yrs) 0.20%
            % LC
Equipment Cost ex BOP,   Transport ($000/MW) $1,500.00 11.4%
Insurance, Ocean Freight,   Local Transport 4.5% 100.0%
Balance of Plant (BOP), % of   Equipment Cost 21.0% 100.0%
Transmission Line Distance   (km) 1.00
T/L Cost per km, 69 kV   ($000/km) $40.00 100.0%
Switchyard &   Transformers ($000) $786.21 100.0%
Access Roads ($000/km) $181.82 100.0%
Distance of Access Road (km) 1.00
Dev’t & Other Costs   (land, permits, etc) (% of EPC) 15.0% 100.0%
VAT on importation (70%   recoverable) 12% 100.0%
Initial Working Capital (%   of EPC) 11.03% 100.0%
Contingency (% of Total   Cost) 4.0% 50.0%
SET NPV (F29) TO ZERO BY   VARYING FIT (F30)
Operating Assumptions – NPV 63,772    Equity IRR
  Feed-in-Tariff (PhP/kWh) – FIT 7.00 18.44%
  Duration of FiT (Yrs) 20    Project IRR
  Tariff post FiT period (PhP/kWh) 7.00 14.32%
  FiT using Asset Base Methodology (PhP/kWh) 8.13
  Annual CER Volume (tCO2e/year) and $/tCO2e                – $5.00
  O&M Cost ($000/unit/year) $1,150.00
  Spare Parts, Tools & Equipment   ($000/MW/yr) $1.00
  O&M + Spares as % of EPC, T/L, S/S 6.86%
  Refurbishment Cost (% of EPC) 30%
  Timing of Refurbishment (Year from COD) 10
  G&A ($000/year) $1
  Fuel Cost (switch for Biomass: 1=yes, 0=no) 1
    Average Fuel Cost (PhP/mt)       1,297.00
    Fuel Rate (kWh/mt)         700.00
    Average Fuel Consumption (mt/year)         83,961
    Average Unit Cost of Fuel (PhP/kWh)           3.137
  Days Receivable & Payable 30 30
  VAT Recovery 70%
  Timing of VAT recovery (Yrs after COD) 5
Gross   Heating Value 4,000  Btu/lb
2.2046  lb/kg
1000  kg/MT
8,818,400  Btu/MT
Efficiency,   % 27.09%  of GHV
Plant Heat   Rate 3600  kJ/kWh
1.05506  kJ/Btu
3,412  Btu/kWh
12,598  Btu/kWh
Fuel Rate 700  kWh/MT
Cost of Fuel       1,297.00  PhP/MT
700  kWh/MT
          1.853  PhP/kWh

 

Debt and Equity Assumptions
Local/Foreign Capital Mix:
  Local Capital 50.0%
  Foreign Capital 50.0%
Debt:
  Local & Foreign Upfront & Financing   Fees 2.00%
  Local & Foreign Commitment Fees 0.50%
  Local All-in Interest Rate excluding tax 10.00%
  Local Debt Payment Period (from end of GP)   (Yrs) 10
  Foreign All-in Interest Rate excluding tax 8.00%
  Foreign Debt Payment Period (from end of   GP) (Yrs) 10
  Local and Foreign Grace Period from COD   (months) 6
  Local and Foreign debt Service Reserve   (months) 6
  Debt Ratio 70%
  Total Local Debt ($000) – 30% $5,107
  Total Foreign Debt ($000) – 70% $12,768
    Total Debt Amount ($000) $17,875
Equity: 16%
  Equity Ratio 30%
  Equit Investment $7,661
  Cost of Equity (Onshore Equity IRR) –   Nominal 18.4%
  Cost of Equity (Onshore Equity IRR) – Real 13.9%
WACC pre-tax 12.1%
WACC after-tax 10.9%
Tax Assumptions
  Income Tax Holiday (Yrs) 7
  Income Tax Rate % (after ITH) 10%
  Property tax (from COD) 1.5%
  Property tax valuation rate (% of NBV) 80%
  Local Business Tax 1.0%
  Government Share (from COD) 0.0%
  ER 1-94 Contribution (PhP/kWh) 0.01
  Withholding Tax on Interest (Foreign   Currency) – WHT 10%
  Gross Receipts Tax on Interest (Local Currency) – GRT 5%
Economic Assumptions
  Base Foreign Exchange Rate (PhP/US$) – 2009 47.8125
  Forward Fixed Exchange Rate (2011) 44.0000
  Base Local CPI – 2009 160.00
  Annual Local CPI 4.0%
  Annual US CPI 2.0%
  Annual Peso Depreciation Rate 2.0%

 

Project IRR Pre tax (no escalation) – Equity –> 100.00%
Year (act) Year     CapEx
PhP(10^3)
    OpEx
PhP(10^3)
    TPC
PhP(10^3)
    Revenue
PhP(10^3)
    EBITDA
2011 0
2012 0        (1,053,204.67)        (1,053,204.67)        (1,053,204.67)
2013 1           (171,976.57)           (171,976.57)           418,919.47           246,942.90
2014 2           (175,533.85)           (175,533.85)           418,919.47           243,385.62
2015 3           (174,901.92)           (174,901.92)           418,919.47           244,017.55
2016 4           (174,270.00)           (174,270.00)           418,919.47           244,649.47
2017 5           (173,638.08)           (173,638.08)           418,919.47           245,281.39
2018 6           (173,006.15)           (173,006.15)           418,919.47           245,913.32
2019 7           (172,374.23)           (172,374.23)           418,919.47           246,545.24
2020 8           (171,742.31)           (171,742.31)           418,919.47           247,177.16
2021 9           (171,110.39)           (171,110.39)           418,919.47           247,809.08
2022 10           (170,478.46)           (170,478.46)           418,919.47           248,441.01
2023 11           (169,846.54)           (169,846.54)           418,919.47           249,072.93
2024 12           (169,214.62)           (169,214.62)           418,919.47           249,704.85
2025 13           (168,582.69)           (168,582.69)           418,919.47           250,336.78
2026 14           (167,950.77)           (167,950.77)           418,919.47           250,968.70
2027 15           (167,318.85)           (167,318.85)           418,919.47           251,600.62
2028 16           (166,686.93)           (166,686.93)           418,919.47           252,232.54
2029 17           (166,055.00)           (166,055.00)           418,919.47           252,864.47
2030 18           (165,423.08)           (165,423.08)           418,919.47           253,496.39
2031 19           (164,791.16)           (164,791.16)           418,919.47           254,128.31
2032 20           (164,159.24)           (164,159.24)           418,919.47           254,760.23
Totals        (1,053,204.67)        (3,399,060.84)        (4,452,265.52)        8,378,389.40        3,926,123.88
   IRR –> 22.99%

 

 

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