Summary of inputs and results for project finance models for various power generation technologies

September 14th, 2014 No Comments   Posted in cost of power generation

Summary of inputs and results for project finance models for various power generation technologies

I hope you had a wonderful time looking over the power generation technology summary that posted earlier.

I am providing below the summary to incorporate updates on the nuclear uranium PHWR technology:

GJ/kg    fuel $/kg    fab. $/kg    total $/kg    kWh/kg     Efficiency
3,900     365              400               765                 360,000    33.23%

I also updated the coal CFB and PC subcritical, supercritical and ultrasupercritical technologies.

I revised the structure of the models to allow 48 months of construction and 30 years of operation for coal, nuclear and ocean thermal technologies; the rest are 36 months of construction and 30 years of operation.

Since the models originate from one template, it would be most helpful in comparing alternative technologies, OEM or EPC supplier, capacity, efficiency or heat rate, construction lead time, operating period or economic life, overhaul schedule and capacity & heat rate degradation, fuel cost, and gov’t taxes and imposts.

Please refer also to attached price list of all my models and tool kits for energy and power applications.

TECHNOLOGY US$
Cost of Power Generation Technologies.xls $258
Levelized cost of electricity.xls $306
Latest Feed-in-Tariff Rates for Renewable Energy Technologies.doc $94
Wind Turbine Price List.xls $1,210
Power Plant Emission Data and Model:  
Solid Fuel, Liquid Fuel, Gaseous Fuel Properties $450
Power Plant Emission Calculation Model by mass.xls $752
Power Plant Emission Calculation Model by concentration.xls $900
CDM Feed-in-Tariff Models for Renewable Energy  
CDM Biomass Cogeneration Model.xls $1,800
CDM Biomass Direct Combustion Model.xls $1,800
CDM Biomass Gasification Model.xls $1,800
CDM Mini-Hydro Model.xls $1,800
CDM Ocean Thermal Model_10 MW.xls $1,800
CDM Ocean Thermal Model_50 MW.xls $1,800
CDM Solar PV Model.xls $1,800
CDM Wind Model.xls $1,800
ADVANCED Feed-in-Tariff Models for Renewable Energy  
ADV Biomass Cogeneration Model.xls $1,200
ADV Biomass Direct Combustion Model.xls $1,200
ADV Biomass Gasification Model.xls $1,200
ADV Mini-Hydro Model.xls $1,200
ADV Ocean Thermal Model_10 MW.xls $1,200
ADV Ocean Thermal Model_50 MW.xls $1,200
ADV Solar PV Model.xls $1,200
ADV Wind Model.xls $1,200
ADV Solar PV-Diesel Hybrid Model.xls $2,000
ADV Wind-Diesel Hybrid Model.xls $2,000
MTO Feed-in-Tariff Models for Renewable Energy  
MTO Fit_biomass cogeneration.xls $600
MTO Fit_biomass direct combustion.xls $600
MTO Fit_biomass gasification.xls $600
MTO Fit_Mini Hydro.xls $600
MTO Fit_ocean thermal_10 MW.xls $600
MTO Fit_ocean thermal_50 MW.xls $600
MTO Fit_solar PV.xls $600
MTO Fit_wind.xls $600
Simplified Feed-in-Tariff Models for Renewable Energy (Student Edition)  
Simplified Fit_biomass anaerobic digestion.xls $300
Simplified Fit_biomass cogeneration.xls $300
Simplified Fit_biomass gasification.xls $300
Simplified Fit_biomass direct combustion.xls $300
Simplified Fit_Mini Hydro.xls $300
Simplified Fit_ocean thermal_10 MW.xls $300
Simplified Fit_ocean thermal_50 MW.xls $300
Simplified Fit_solar PV.xls $300
Simplified Fit_wind.xls $300
Renewable Energy Resource Assessment Model  
Wind Energy Resource Assessment Tool_Anemometer Measurement $1,000
Wind Energy Resource Assessment Tool_3TIER Prediction $1,000
MTO Project Finance Models:  
proj_diesel genset power plant model.xls $300
proj_hybrid power plant model (diesel, biomass, mini-hydro, solar, wind).xls $1,300
proj_oil thermal power plant model.xls $1,000
proj_coal thermal power plant model (pulverized, CFB, IGCC).xls $2,000
proj_geothermal power plant model.xls $2,000
proj_simple cycle GT plant model.xls $1,500
proj_combined cycle GT plant model.xls $2,000
proj_nuclear power plant model.xls $3,000
LP Models for Optimal Load Dispatch  
Optimal Load Dispatch_Luzon_1.xls $1,558
Optimal Load Dispatch_Mindanao_1.xls $1,466
Optimal Load Dispatch_Visayas_1.xls $1,480
LP Model for Trigeneration.xls $1,306

Dear Friends,

I am happy to share with you the results of my continuing technical & research work on energy and power plant project finance modeling of various power generation technologies such as conventional, fossil, nuclear and renewable energy (biomass, WTE, mini-hydro, solar PV, wind and ocean thermal energy conversion or OTEC).

 Please refer to the attached summary and please let me know if you would be interested in securing a full-license to use the various models listed in the summary.

 The models are calibrated using US EIA, IEA and Paul Breeze and other internet sources of information to arrive at installed capacity, capacity factor, overnight $/kW capital cost (all-in cost), $/kW/year fixed O&M, $/MWh variable O&M, regulatory costs, fuel cost in native units, GHV of fuel, fuel-to-electricity conversion efficiency (thermal efficiency) or plant heat rate, construction period, economic life, cost of capital (% equity and IRR, % debt and loan interest), etc.

 Since these are best-practice or latest information, it would be helpful in benchmarking local power plants and its performance so that an economic and financial decision is made to retire, refurbish, or construct a new power plant to provide adequate capacity to meet increasing future demand and replace old plants.

 Hope to hear from you soon as to your interest in my complete line of project finance models.

 If you are interested, please order via email at:

energydataexpert@gmail.com

so I could provide you with my PayPal and bank/wire transfer details.

Once I received confirmation of payment, I will then email you the requested/ordered models.

Here is the sample summary:

Summary of Inputs and Results at 16.0% p.a. Equity IRR ( 30% equity and 70% debt )
Comparative Cost of Electricity (PhP/kWh): CP, months OP, years MW Net CF, % EPC, $/kW All in, $/kW $/kW/yr $/MWh TE, % HR, Btu/kWh FR, kWh/MT Fuel Cost & Units PhP/kWh Tariff
Biomass Gasification (27.09%, 4,000 Btu/lb) – 6.63 FIT 24 20 28.500 83.00% $2,628 $4,114 105.63 5.26 27.09% 12,598 700 1,297 PhP/MT 1.853 6.853
Biomass Cogeneration (26.00%, 4000 Btu/lb) – 6.63 FIT 24 20 34.000 83.00% $2,686 $4,114 105.63 5.26 26.00% 13,124 672 1,297 PhP/MT 1.930 7.000
Biomass Direct Combustion (28.00%, 4000 Btu/lb) – 6.63 FIT 24 20 8.300 83.00% $2,614 $4,114 105.63 5.26 28.00% 12,186 724 1,297 PhP/MT 1.792 6.817
Biomass IGCC (26.00%, 4000 Btu/lb) – 6.63 FIT 24 20 20.000 83.00% $2,670 $4,114 105.63 5.26 26.00% 13,124 672 1,297 PhP/MT 1.930 6.994
Biomass WTE (18.96%, 4000 Btu/lb) – 6.63 FIT 24 20 50.000 83.00% $5,428 $8,312 392.82 8.75 18.96% 17,996 490 1,297 PhP/MT 2.647 13.514
CFB Coal 50 mw (34.76%, 10,000 Btu/lb) 36 25 50.000 85.00% $1,846 $2,934 31.18 4.47 34.76% 9,816 2,246 3,740 PhP/MT 1.665 5.323
CFB Coal 135 mw (41.18%, 10,000 Btu/lb) 36 25 135.000 85.00% $2,134 $3,374 35.86 5.14 38.77% 8,800 2,505 3,740 PhP/MT 1.493 5.238
PC Coal 400 mw – subcritical (44.45%, 10,000 Btu/lb) 36 30 400.000 85.00% $2,068 $3,246 37.80 4.47 44.45% 7,677 2,872 3,740 PhP/MT 1.302 5.195
PC Coal 500 mw – supercritical (47.79%, 10,000 Btu/lb) 36 30 500.000 85.00% $2,068 $3,246 37.80 4.47 47.79% 7,139 3,088 3,740 PhP/MT 1.211 5.058
PC Coal 650 mw – ultrasupercritical (51.22%, 10,000 Btu/lb) 36 30 650.000 85.00% $2,068 $3,246 37.80 4.47 51.22% 6,662 3,309 3,740 PhP/MT 1.130 4.935
Diesel Oil Genset (32.00%, 19,200 Btu/lb) 24 20 50.000 40.00% $709 $1,100 4.00 30.00 32.00% 10,663 3,970 54,438 PhP/MT 13.713 23.194
Fuel Oil Genset (36.00%, 18,300 Btu/lb) 24 20 225.000 50.00% $853 $1,300 6.00 50.00 36.00% 9,478 4,257 36,066 PhP/MT 8.473 17.011
Fuel Oil Thermal (38.00%, 18,300 Btu/lb) 36 20 200.000 75.00% $991 $1,561 30.26 2.30 38.00% 8,979 4,493 36,066 PhP/MT 8.027 13.110
Geothermal (28.00%, 1,104 Btu/lb) 36 25 100.000 92.00% $3,973 $6,243 132.00 1.00 28.00% 12,186 200 562 PhP/MT 2.814 8.962
Large Hydro 36 30 500.000 52.00% $2,128 $2,936 14.13 1.00             3.618
Mini Hydro – 5.90 FIT 24 20 6.000 43.33% $2,199 $3,523 16.96 1.20             5.761
Solar PV Farm (1 mw) – 9.68 FIT (Chinese) 12 20 1.056 20.83% $1,842 $2,614 18.50 1.50             9.416
Solar PV Farm (25 mw) – 9.68 FIT 12 20 25.000 25.00% $2,122 $2,789 18.50 1.30             8.497
Wind Farm Onshore – 8.53 FIT 24 25 30.000 34.00% $1,627 $2,213 39.55 1.00             5.119
Wind Farm Offshore – 8.53 FIT 24 25 200.000 37.00% $4,761 $6,230 74.00 2.00             13.320
Ocean Thermal (10 mw) 48 30 16.000 60.00% $10,000 $14,170 85.02 5.58             19.193
Ocean Thermal (50 mw) 48 30 80.000 60.00% $8,000 $11,194 33.58 2.13             14.544
Nuclear Uranium PHWR (33.23%, 3,900 GJ/kg) 48 30 1,330.000 90.00% $2,275 $3,687 93.28 2.14 33.23% 10,268 360,000,000 33,660,000 PhP/MT 0.094 3.834
Natgas Thermal (45.00%, 22,129 Btu/lb) 36 25 200.000 60.00% $634 $1,000 30.00 5.00 38.00% 8,979 5,433 18,521 PhP/MT 3.409 6.510
Natgas Simple Cycle (38.00%, 22,129 Btu/lb) 36 25 70.000 30.00% $609 $973 7.34 15.45 31.45% 10,849 4,497 18,521 PhP/MT 4.119 8.918
Natgas Combined Cycle (53.07%, 22,129 Btu/lb) 36 25 500.000 87.00% $583 $917 13.17 3.60 53.07% 6,429 7,588 18,521 PhP/MT 2.441 4.186
CP – Construction period, months
OP – Operating period (Economic life), years
MW – Mega Watts installed capacity
Net CF – Net Capacity Factor (after plant own use and losses), % of installed capacity
EPC – Engineering Procurement Construction cost per kW
All in – All in Cost per kW (EPC + Owners Cost + Working Capital + Financing Cost)
$/kW/yr – Fixed O&M
$/MWh – Variable O&M (excluding fuel)
TE – Thermal Efficiency, % of GHV (Gross Heating Value)
HR – Heat Rate, Btu (GHV) / kWh (Gross Generation)
FR – Fuel Rate, kWh (Gross Generation) / MT
Fuel Cost in native units
PhP/kWh – Fuel Cost in PhP/kWh (from fuel cost in native units and Heat Rate)
Tariff – First Year Tariff, PhP/kWh (selling price needed to meet minimum equity IRR)
  

Fuel Properties and Gross Heating Value

Comparative Cost of Electricity (PhP/kWh): Gross Heating Value   Fuel Cost, in US$   Fuel Cost, in PhP   Density, Factor Fuel Technology
Biomass Gasification (27.09%, 4,000 Btu/lb) – 6.63 FIT 4,000 Btu/lb     1.297 PhP/kg 1000 kg/MT Biomass Gasification
Biomass Cogeneration (26.00%, 4000 Btu/lb) – 6.63 FIT 4,000 Btu/lb     1.297 PhP/kg 1000 kg/MT Biomass Cogeneration
Biomass Direct Combustion (28.00%, 4000 Btu/lb) – 6.63 FIT 4,000 Btu/lb     1.297 PhP/kg 1000 kg/MT Biomass Direct Combustion
Biomass IGCC (26.00%, 4000 Btu/lb) – 6.63 FIT 4,000 Btu/lb     1.297 PhP/kg 1000 kg/MT Biomass IGCC
Biomass WTE (18.96%, 4000 Btu/lb) – 6.63 FIT 4,000 Btu/lb     1.297 PhP/kg 1000 kg/MT Biomass WTE
CFB Coal 50 mw (34.76%, 10,000 Btu/lb) 10,000 Btu/lb 85.00 $/MT 3.740 PhP/kg 1000 kg/MT Coal CFB 50 mw
CFB Coal 135 mw (41.18%, 10,000 Btu/lb) 10,000 Btu/lb 85.00 $/MT 3.740 PhP/kg 1000 kg/MT Coal Coal CFB 135 mw
PC Coal 400 mw – subcritical (44.45%, 10,000 Btu/lb) 10,000 Btu/lb 85.00 $/MT 3.740 PhP/kg 1000 kg/MT Coal PC subcritical
PC Coal 500 mw – supercritical (47.79%, 10,000 Btu/lb) 10,000 Btu/lb 85.00 $/MT 3.740 PhP/kg 1000 kg/MT Coal PC supercritical
PC Coal 650 mw – ultrasupercritical (51.22%, 10,000 Btu/lb) 10,000 Btu/lb 85.00 $/MT 3.740 PhP/kg 1000 kg/MT Coal PC ultrasupercritical
Diesel Oil Genset (32.00%, 19,200 Btu/lb) 19,200 Btu/lb     46.000 PhP/L 0.845 kg/L Diesel Diesel Oil Genset
Fuel Oil Genset (36.00%, 18,300 Btu/lb) 18,300 Btu/lb     34.840 PhP/L 0.966 kg/L Bunker Fuel Oil Genset
Fuel Oil Thermal (38.00%, 18,300 Btu/lb) 18,300 Btu/lb     34.840 PhP/L 0.966 kg/L Bunker Fuel Oil Thermal
Geothermal (28.00%, 1,104 Btu/lb) 1,104 Btu/lb     5.248 $/GJ 5.537 $/mmBtu Geothermal Dual Flash
Large Hydro                 Water Large Hydro
Mini Hydro – 5.90 FIT                 Water Mini-hydro
Solar PV Farm (1 mw) – 9.68 FIT (Chinese)                 Solar Solar PV 1 mw
Solar PV Farm (25 mw) – 9.68 FIT                 Solar Solar PV 25 mw
Wind Farm Onshore – 8.53 FIT                 Wind Onshore Wind 30 mw
Wind Farm Offshore – 8.53 FIT                 Wind Offshore Wind 200 mw
Ocean Thermal (10 mw)                 Ocean OTEC 10 mw
Ocean Thermal (50 mw)                 Ocean OTEC 50 mw
Nuclear Uranium PHWR (33.23%, 3,900 GJ/kg) 1,676,708,808 Btu/lb 765000.00 $/MT 33660.000 PhP/kg 1000 kg/MT Uranium Nuclear PHWR
Natgas Thermal (45.00%, 22,129 Btu/lb) 22,129 Btu/lb     8.628 $/GJ 9.103 $/mmBtu Natgas Gas Thermal
Natgas Simple Cycle (38.00%, 22,129 Btu/lb) 22,129 Btu/lb     8.628 $/GJ 9.103 $/mmBtu Natgas Simple Cycle GT
Natgas Combined Cycle (53.07%, 22,129 Btu/lb) 22,129 Btu/lb     8.628 $/GJ 9.103 $/mmBtu Natgas Combined Cycle GT

 

Starting your Lending Investor Business – Use this package of services and softwares

July 25th, 2014 1 Comment   Posted in lending investors

Dear Friends,

 

To jump-start immediately your Lending Investor Business, please use this package of services and softwards to ensure you started on the right foot.

Here is the price list of our services and softwares.

We can discuss this further if you wish.

Best regards,

Marcial

—–

How to Start Your Own Lending Investor Business

Here are the costs for the WELC Management & Information System for Lending Investor Company:

1) Basic Business model (5-years simplified – Income statement and Balance Sheet) – excel file – US$ 400 (PhP 20,000)

2) Advanced Business model (60-months model – Income statement and Balance Sheet) – excel file – US$ 600 (PhP 30,000)

3) Loan processing system (new loan, re-loan, extension, etc) – excel file – US$ 500 (PhP 25,000)

4) General Ledger and Sub-Ledger Accounting System (with receivables, payables, income, balance, etc) – database program – US$ 1,000 (PhP 50,000)

5) Business plan (for SEC) – doc file – US$ 200 (PhP 10,000)

6) 1 week training (2 hours x 5 days = 10 hours) on the 3 systems (business model, loans processing and accounting system) – US $300 (PhP 15,000)

7) Assistance in registering your Lending Company – barangay, mayor’s office, DTI, SEC, BIR registrations – US$ 300 (PhP 15,000)

I hope you will find our services to your satisfaction, and hope to meet with you again and your equity partner.

For more information, you may contact our ofice staff for a private meeting to discuss your specific needs and budget requirements.

ofc tel/fax +63-2-9325530

 

Why the Philippines is Lacking in Power Supply Always

May 16th, 2014 No Comments   Posted in Energy Supply and Demand

Why the Philippines is Lacking in Power Supply Always

This paper will answer the question of “Why the Philippines is lacking in power supply always and have one of the highest power rates in the world.”

Firstly, the country has a poor mix of baseload capacity (must-run renewables such as solar PV, wind, mini-hydro, biomass; hydro for irrigation and water supply; geothermal; coal), limited mid-merit capacity (natural gas-fired open cycle gas turbine and combined cycle gas turbine), and expensive peak load capacity (stored hydro, diesel genset, oil-fired thermal, large hydro, oil-fired open cycle gas turbine).

Secondly, when power demand drops at night time or off-peak hours, the inflexible coal-fired power plants are forced to shut-down, leaving the grid with no recourse to run all the limited mid-merit plants with higher generation cost and cover the deficit with the very expensive oil-fired diesel gensets and oil-fired thermal power plants from the Wholesale Electricity Spot Market (WESM).

Thirdly, short-term and long-term supply planning is based on the assumption that installed and dependable capacity of generating units are available during the planning cycle, when in fact, during the 2-3 year cycle of severe drought “El Nino” and severe rainfall “La Nina”, the hydro power and water dams have very little water available to generate electricity, or when flooding occurs, the dams are constrained from releasing further any excess water to avoid aggravating further severe flooding at the downstream portion of the low lands.

Lastly, there is lack of capability to run least cost multi-period capacity expansion modelling tools  (e.g. linear programming models) based on the actual resource availability such as the limited capacity of hydro dams during prolonged drought periods. The LP model minimizes the net present value (NPV) of the cost of new power capacity investments, rehabilitation and overhauls of existing plants, fuel consumption, variable and fixed O&M, taxes and regulatory costs and other costs. The model will retire expensive and end-of-life power plants and replace them with newer and more efficient power plants, propose new capacities with the technology of higher efficiency and lower long run marginal cost (LRMC), optimize configuration (300 MW vs. 2 x 150 MW) – all of which will result in the lowest NPV and cheapest electricity tariff that will meet the power demand profile during off-peak and peak hours.

I then made assumptions on the actual % this dependable capacity is available during the scenario of severe El Nino summer drought where in large hydro power generation drops to 50% in Luzon and Visayas and 30% for Mindanao as is currently experienced now and historically.

My other assumptions during a severe drought (El Nino) include:

LUZON:

Coal = 90%

Oil Based (diesel, bunker oil) Diesel Gensets = 80%

Oil (bunker oil) Thermal = 60%

Oil Fired (diesel) Gas Turbine = 60%

Natural Gas fired Combined Cycle Gas Turbine = 90%

Geothermal = 70%

Large Hydro = 50%

Mini Hydro = 40%

RE (wind, solar, biomass) = 50%

VISAYAS:

Coal = 90%

Oil Based (diesel, bunker oil) Diesel Gensets = 80%

Oil Fired (diesel) Gas Turbine = 60%

Geothermal = 70%

Mini Hydro = 40%

RE (wind, solar, biomass) = 50%

MINDANAO:

Coal = 90%

Oil Based (diesel, bunker oil) Diesel Gensets = 80%

Geothermal = 70%

Large Hydro = 30% (based on current and historical experience)

Mini Hydro = 40%

RE (wind, solar, biomass) = 50%

Based on the above assumptions of resource availability, the following supply & demand balances for Luzon, Visayas and Mindanao grids clearly illustrates the power supply deficits of the 3 grids during severe drought that is not captured during the planning period by the government.

LUZON GRID

Most Likely Power Supply

2012

Installed

Dependable

Summer

Most Likely

COAL

3,879.0

3,664.0

3,297.6

PAGBILAO

764.0

764.0

90%

687.6

CALACA

600.0

450.0

90%

405.0

MASINLOC

630.0

630.0

90%

567.0

SUAL

1,294.0

1,294.0

90%

1,164.6

QUEZON POWER

511.0

460.0

90%

414.0

APEC

50.0

42.0

90%

37.8

UPPC

30.0

24.0

90%

21.6

OIL-BASED

0.0

0.0

0.0

Diesel

487.0

443.5

354.8

SUBIC DPP

116.0

112.0

80%

89.6

DURACOM

0.0

0.0

80%

0.0

CALIBU DPP

30.0

30.0

80%

24.0

PETERSVILLE DPP

9.3

6.0

80%

4.8

BAUANG DPP

235.2

205.0

80%

164.0

FCVC DPP

25.6

25.6

80%

20.5

TARLAC POWER

18.9

14.9

80%

11.9

TRANS ASIA POWER

52.0

50.0

80%

40.0

Oil Thermal

650.0

650.0

390.0

MALAYA

650.0

650.0

60%

390.0

Gas Turbine

620.0

540.0

324.0

HOPEWELL GT

0.0

0.0

60%

0.0

LIMAY CCGT

620.0

540.0

60%

324.0

NATURAL GAS

2,861.0

2,770.0

2,493.0

STA RITA

1,060.0

1,041.0

90%

936.9

ILIJAN

1,271.0

1,200.0

90%

1,080.0

SAN LORENZO

530.0

529.0

90%

476.1

GEOTHERMAL

751.5

586.9

410.8

MAKBAN

387.5

333.9

70%

233.8

BACMAN

130.0

45.0

70%

31.5

TIWI

234.0

207.9

70%

145.6

HYDROELECTRIC

2,439.7

2,123.8

1,059.9

Large Hydroelectric Plants

2,419.8

2,104.2

1,052.1

SAN ROQUE

411.0

411.0

50%

205.5

HEDCOR

33.8

15.4

50%

7.7

KALAYAAN PSPP

739.2

720.0

50%

360.0

MAGAT

360.0

360.0

50%

180.0

CALIRAYA

35.0

28.0

50%

14.0

BOTOCAN

22.8

22.4

50%

11.2

ANGAT

246.0

135.0

50%

67.5

PANTABANGAN-MASIWAY

132.0

132.0

50%

66.0

AMBUKLAO

105.0

105.0

50%

52.5

BINGA

100.0

100.0

50%

50.0

BAKUN

70.0

36.4

50%

18.2

CASECNAN (NIA)

165.0

39.0

50%

19.5

Small Hydroelectric Plants

19.9

19.7

7.9

CAWAYAN

0.4

0.4

40%

0.2

BUHI-BARIT

2.0

1.8

40%

0.7

NIA-BALIGATAN

6.0

6.0

40%

2.4

AGUA-GRANDE

4.5

4.5

40%

1.8

AMBURAYAN

0.2

0.2

40%

0.1

DAWARA

0.5

0.5

40%

0.2

BACHELOR

0.8

0.8

40%

0.3

PHILEX

0.5

0.5

40%

0.2

MAGAT A&B

2.5

2.5

40%

1.0

TUMAUINI

0.3

0.3

40%

0.1

BALUGBOG

0.7

0.7

40%

0.3

PALAPAQUIN

0.4

0.4

40%

0.2

INARIHAN

1.0

1.0

40%

0.4

YABO

0.2

0.2

40%

0.1

WIND

33.0

33.0

16.5

BANGUI WIND POWER

33.0

33.0

50%

16.5

BIOMASS

17.5

13.2

6.6

MONTALBAN LFG

9.3

5.4

50%

2.7

LAGUNA LFG

4.2

4.2

50%

2.1

LUCKY PPH

4.0

3.6

50%

1.8

TOTAL LUZON

11,738.6

10,824.4

8,353.2

 

Capacity, Peak Demand, Reserve Requirement

Power Development Plan Update, 2014-2020

4.47%

p.a. AAGR
Luzon Grid, in MW
Year (A) (B) ( C ) (D) (E= D x Reserve) (F = D + E) (G = A – F) (H)
Existing Capacity Committed Capacity Plant Retirement / Rehabilitation Peak Demand Forecast Reserve Margin Requirement Demand + Reserve Margin System Reserve Required Additional Capacity
2011 8,353 Bacman U1 (55 MW), Bacman U2 (30 MW), Bacman-Cawayan (20 MW), Ambuklao (105 MW), Subic (110 MW) 7,673 1,601 9,274 -920 0
2012 8,673 CIP 2 Diesel (21 MW), GF Biomass (13 MW), Bacman U3 (20 MW) Cawayan (25 MW) 7,995 1,614 9,609 -935 0
2013 8,752 GN Power (600 MW) 8,331 1,627 9,958 -1,206 0
2014 9,352 SLTEC (135 MW), SLPGC U1 (150 MW), EWC U1 (200 MW), PMPGC (100 MW), MGI (20 MW), AWOC (67.5 MW), SJCIPC (9.9 MW) 8,681 1,641 10,322 -970 0
2015 10,035 SLTEC (135 MW), SLPGC U2 (150 MW), EWC U2 (200 MW), IBEC (20 MW) 9,045 1,656 10,701 -666 300
2016 10,538 APC (82 MW), EWC U3 (200 MW) 9,479 1,673 11,152 -615 300
2017 10,820 9,934 1,691 11,626 -806 300
2018 10,820 10,411 1,710 12,122 -1,302 600
2019 10,820 10,911 1,730 12,641 -1,822 0
2020 10,820 11,435 1,751 13,186 -2,366 1,000
2021 10,820 11,983 1,773 13,757 -2,937 500
2022 10,820 12,559 1,796 14,355 -3,535 500
2023 10,820 13,161 1,820 14,982 -4,162 1,000
2024 10,820 13,793 1,846 15,639 -4,819 500
2025 10,820 14,455 1,872 16,328 -5,508 500
2026 10,820 15,149 1,900 17,049 -6,229 1,000
2027 10,820 15,876 1,929 17,805 -6,986 800
2028 10,820 16,638 1,960 18,598 -7,778 1,000
2029 10,820 17,437 1,991 19,428 -8,609 1,000
2030 10,820 18,274 2,025 20,299 -9,479 1,150
GDP elasticity Peak Demand
Note: Reserve Margin Requirement : 2014-15 7.00% 0.60 4.20% DOE
LFFR = 4 % of Peak Demand 2016-20 8.00% 0.60 4.80% DOE
Spinning = Largest single unit (647 MW) 2021-2030 8.00% 0.60 4.80% MTO
Back-up = Largest single unit (647 MW) Forced Outage Rate 6.60% DOE

 

Reserve Deficiency (Capacity less Peak Demand & Reserve Requirement)

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

Year

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

Existing Capacity

8,353

8,673

8,752

9,352

10,035

10,538

10,820

11,120

11,720

11,720

12,720

13,220

13,720

14,720

15,220

15,720

16,720

17,520

18,520

19,520

Committed + Rehabs – Retirements

320

79

600

682

503

282

0

0

0

0

0

0

0

0

0

0

0

0

0

0

Proposed Project
Indicative
Required Additional Cap

0

0

300

600

0

1,000

500

500

1,000

500

500

1,000

800

1,000

1,000

1,150

Total Capacity ( C )

8,673

8,752

9,352

10,035

10,538

10,820

11,120

11,720

11,720

12,720

13,220

13,720

14,720

15,220

15,720

16,720

17,520

18,520

19,520

20,670

Peak Demand ( P )

7,673

7,995

8,331

8,681

9,045

9,479

9,934

10,411

10,911

11,435

11,983

12,559

13,161

13,793

14,455

15,149

15,876

16,638

17,437

18,274

Reserved Margin Required ( R )

1,601

1,614

1,627

1,641

1,656

1,673

1,691

1,710

1,730

1,751

1,773

1,796

1,820

1,846

1,872

1,900

1,929

1,960

1,991

2,025

Peak Demand + Reserve Margin (P + R)

9,274

9,609

9,958

10,322

10,701

11,152

11,626

12,122

12,641

13,186

13,757

14,355

14,982

15,639

16,328

17,049

17,805

18,598

19,428

20,299

20.87%

20.19%

19.53%

18.91%

18.31%

17.65%

17.03%

16.43%

15.86%

15.32%

14.80%

14.30%

13.83%

13.38%

12.95%

12.54%

12.15%

11.78%

11.42%

11.08%

Reserve Deficiency ( C – P – R )

-600

-856

-606

-287

-163

-333

-506

-402

-922

-466

-537

-635

-262

-419

-608

-329

-286

-78

91

371

 

VISAYAS GRID

Most Likely Power Supply

2012

Installed

Dependable

Summer

Most Likely

Coal

805.6

776.8

699.1

TOLEDO POWER CORP. (Sangi Sta)

88.8

60.0

90%

54.0

CEBU TPP(Salcon)

106.8

106.8

90%

96.1

CEDC Coal

246.0

246.0

90%

221.4

PEDC Coal

164.0

164.0

90%

147.6

KEPCO Coal

200.0

200.0

90%

180.0

Diesel

560.4

434.3

347.4

PANAY POWER CORP.

94.9

87.0

80%

69.6

TOLEDO POWER CORP. (Carmen Sta)

45.8

37.4

80%

29.9

CEBU PRIVATE POWER

70.0

61.7

80%

49.4

EAST ASIA UTILITIES (MEPZA)

49.7

45.0

80%

36.0

PB 103

32.0

16.4

80%

13.1

PANAY DPP1

29.2

10.0

80%

8.0

PB 101

32.0

16.1

80%

12.9

PB 102

32.0

24.0

80%

19.2

BOHOL DPP

22.0

15.0

80%

12.0

12.5 MW BUNKER FUEL (GBPC)

12.6

11.3

80%

9.0

5 MW BUNKER FUEL (GBPC)

5.0

4.5

80%

3.6

GUIMARAS POWER

3.4

2.6

80%

2.1

PANAY DIESEL PP III

66.4

60.0

80%

48.0

CEBU DPP (Salcon)

43.4

36.0

80%

28.8

ENERVANTAGE DPP

22.0

7.3

80%

5.8

Gas Turbine 55.0 42.0 25.2
CEBU LAND-BASED GT

55.0

42.0

60%

25.2

Geothermal

923.3

745.0

521.5

PALINPINON GPP

192.4

189.0

70%

132.3

LEYTE GPP

112.5

75.0

70%

52.5

UNIFIED LEYTE

618.4

481.0

70%

336.7

NORTHERN NEGROS GPP

0.0

0.0

70%

0.0

Hydro

13.3

12.7

5.1

JANOPOL

5.2

5.0

40%

2.0

SEVILLA HEP

2.5

2.5

40%

1.0

AMLAN HEP

0.8

0.4

40%

0.1

LOBOC HEP

1.2

1.2

40%

0.5

MANTAYUPAN

0.5

0.5

40%

0.2

BASAK

0.5

0.5

40%

0.2

MATUTINAO

0.7

0.7

40%

0.3

TON-OK

1.1

1.1

40%

0.4

HENABIAN

0.8

0.8

40%

0.3

Biomass

44.3

26.0

13.0

SAN CARLOS

8.3

4.0

50%

2.0

FIRST FARMERS

21.0

10.0

50%

5.0

CASA

15.0

12.0

50%

6.0

TOTAL VISAYAS

2,401.9

2,036.8

1,611.3

 

Capacity, Peak Demand, Reserve Requirement

Power Development Plan Update, 2011-2030

4.55%

p.a. AAGR
Visayas Grid, in MW
Year (A) (B) ( C ) (D) (E= D x Reserve) (F = D + E) (G = A – F) (H)
Existing Capacity Committed Capacity Plant Retirement / Rehabilitation Peak Demand Forecast Reserve Margin Requirement Demand + Reserve Margin System Reserve Required Additional Capacity
2011 1,611 KEPCO Coal (200 MW) 1,553 262 1,815 -204 0
2012 1,811 1,662 266 1,929 -117 0
2013 1,811 1,778 271 2,050 -238 0
2014 1,811 TPC (82 MW), EDC (50 MW), SWECO (8 MW) 1,903 276 2,179 -368 0
2015 1,951 AESC (3.6 MW), SCBPI (16 MW) 2,036 281 2,318 -366 100
2016 1,971 PTCHC (2 x 135 MW) 2,199 288 2,487 -516 100
2017 2,241 2,375 295 2,670 -429 50
2018 2,241 2,565 303 2,867 -627 100
2019 2,241 2,770 311 3,081 -840 100
2020 2,241 2,992 320 3,311 -1,070 100
2021 2,241 3,231 329 3,560 -1,319 100
2022 2,241 3,489 340 3,829 -1,588 100
2023 2,241 3,769 351 4,119 -1,878 150
2024 2,241 4,070 363 4,433 -2,192 150
2025 2,241 4,396 376 4,772 -2,531 100
2026 2,241 4,747 390 5,137 -2,896 200
2027 2,241 5,127 405 5,532 -3,291 100
2028 2,241 5,537 421 5,959 -3,718 200
2029 2,241 5,980 439 6,420 -4,179 150
2030 2,241 6,459 458 6,917 -4,676 200
GDP elasticity Peak Demand
Note: Reserve Margin Requirement : 2014-15 7.00% 1.00 7.00% DOE
LFFR = 4 % of Peak Demand 2016-20 8.00% 1.00 8.00% DOE
Spinning = Largest single unit (100 MW) 2021-2030 8.00% 1.00 8.00% MTO
Back-up = Largest single unit (100 MW) Forced Outage Rate 7.00% DOE

 

Reserve Deficiency (Capacity less Peak Demand & Reserve Requirement)

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

Year

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

Existing Capacity

1,611

1,811

1,811

1,811

1,951

1,971

2,241

2,291

2,391

2,491

2,591

2,691

2,791

2,941

3,091

3,191

3,391

3,491

3,691

3,841

Committed + Rehabs – Retirements

200

0

0

140

20

270

0

0

0

0

0

0

0

0

0

0

0

0

0

0

Proposed Project
Indicative
Required Additional Cap

0

0

50

100

100

100

100

100

150

150

100

200

100

200

150

200

Total Capacity ( C )

1,811

1,811

1,811

1,951

1,971

2,241

2,291

2,391

2,491

2,591

2,691

2,791

2,941

3,091

3,191

3,391

3,491

3,691

3,841

4,041

Peak Demand ( P )

1,553

1,662

1,778

1,903

2,036

2,199

2,375

2,565

2,770

2,992

3,231

3,489

3,769

4,070

4,396

4,747

5,127

5,537

5,980

6,459

Reserved Margin Required ( R )

262

266

271

276

281

288

295

303

311

320

329

340

351

363

376

390

405

421

439

458

Peak Demand + Reserve Margin (P + R)

1,815

1,929

2,050

2,179

2,318

2,487

2,670

2,867

3,081

3,311

3,560

3,829

4,119

4,433

4,772

5,137

5,532

5,959

6,420

6,917

16.88%

16.03%

15.25%

14.51%

13.82%

13.10%

12.42%

11.80%

11.22%

10.69%

10.19%

9.73%

9.31%

8.91%

8.55%

8.21%

7.90%

7.61%

7.34%

7.10%

Reserve Deficiency ( C – P – R )

-4

-117

-238

-228

-347

-246

-379

-477

-590

-720

-869

-1,038

-1,178

-1,342

-1,581

-1,746

-2,041

-2,268

-2,579

-2,876

 

MINDANAO GRID

Most Likely Power Supply

2012

Installed

Dependable

Summer

Most Likely

MINDANAO
Diesel

621.8

468.9

375.1

MINDANAO ENERGY SYSTEM 1

18.9

18.0

80%

14.4

MINDANAO ENERGY SYSTEM 2

27.5

27.0

80%

21.6

COTABATO LIGHT 10.0 9.9 80%

7.9

BAJADA DPP

58.7

48.0

80%

38.4

SPPC

59.0

50.0

80%

40.0

PB 104

32.0

16.0

80%

12.8

TMI 2

100.0

100.0

80%

80.0

TMI 1

100.0

100.0

80%

80.0

WMPC

113.0

100.0

80%

80.0

ILIGAN DIESEL 1

62.7

0.0

80%

0.0

ILIGAN DIESEL 2

40.0

0.0

80%

0.0

Geothermal

108.5

102.0

71.4

MT APO

108.5

102.0

70%

71.4

Hydro

1,037.8

827.0

249.2

Large Hydroelectric Plants

1,024.7

816.0

244.8

AGUS 1

80.0

52.0

30%

15.6

AGUS 2

180.0

135.0

30%

40.5

AGUS 4

158.1

156.0

30%

46.8

AGUS 5

55.0

55.0

30%

16.5

AGUS 6

200.0

155.0

30%

46.5

AGUS 7

54.0

27.0

30%

8.1

PULANGI 4

255.0

200.0

30%

60.0

SIBULAN HEP

42.6

36.0

30%

10.8

Small Hydroelectric Plants

13.1

11.0

4.4

AGUSAN

1.6

1.6

40%

0.6

BUBUNAWAN

7.0

4.9

40%

2.0

TALOMO HEP

4.5

4.5

40%

1.8

Solar

1.0

1.0

0.5

SOLAR PV

1.0

1.0

50%

0.5

Coal Thermal

232.0

210.0

189.0

MINDANAO COAL

232.0

210.0

90%

189.0

Biomass

21.0

7.0

3.5

CRYSTAL SUGAR

21.0

7.0

50%

3.5

TOTAL MINDANAO

2,022.0

1,615.9

888.7

 

Capacity, Peak Demand, Reserve Requirement

Power Development Plan Update, 2011-2030

4.56%

p.a. AAGR
Mindanao Grid, in MW
Year (A) (B) ( C ) (D) (E= D x Reserve) (F = D + E) (G = A – F) (H)
Existing Capacity Committed Capacity Plant Retirement / Rehabilitation Peak Demand Forecast Reserve Margin Requirement Demand + Reserve Margin System Reserve Required Additional Capacity
2011 889 Minergy (27.5 MW), Cabulig Hydro (8 MW) 1,484 269 1,753 -865 100
2012 924 1,550 272 1,822 -898 50
2013 924 1,616 275 1,891 -966 100
2014 924 Conal P1 (100 MW), EDC (50 MW) 1,686 277 1,963 -1,039 0
2015 1,074 Conal P2 (100 MW), Therma (300 MW), SEC (200 MW) 1,755 280 2,036 -961 0
2016 1,674 FDCU (3 x 135 MW) 1,829 283 2,112 -438 0
2017 2,079 1,906 286 2,192 -113 300
2018 2,079 1,987 289 2,277 -197 100
2019 2,079 2,071 293 2,364 -285 100
2020 2,079 2,163 297 2,460 -381 100
2021 2,079 2,259 300 2,560 -480 100
2022 2,079 2,360 304 2,664 -585 200
2023 2,079 2,465 309 2,774 -694 0
2024 2,079 2,575 313 2,888 -809 100
2025 2,079 2,690 318 3,008 -929 100
2026 2,079 2,811 322 3,133 -1,054 100
2027 2,079 2,937 327 3,264 -1,185 100
2028 2,079 3,069 333 3,401 -1,322 200
2029 2,079 3,207 338 3,545 -1,466 100
2030 2,079 3,351 344 3,695 -1,616 100
GDP elasticity Peak Demand
Note: Reserve Margin Requirement : 2014-15 7.00% 0.80 5.60% DOE
LFFR = 4 % of Peak Demand 206 8.00% 1.60 12.80% DOE
Spinning = Largest single unit (105 MW) 2017-2020 8.00% 1.00 8.00% DOE
Back-up = Largest single unit (105 MW) Forced Outage Rate 7.00% DOE

 

Reserve Deficiency (Capacity less Peak Demand & Reserve Requirement)

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

Year

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

Existing Capacity

889

924

924

924

1,074

1,674

2,079

2,379

2,479

2,579

2,679

2,779

2,979

2,979

3,079

3,179

3,279

3,379

3,579

3,679

Committed + Rehabs – Retirements

36

0

0

150

600

405

0

0

0

0

0

0

0

0

0

0

0

0

0

0

Proposed Project
Indicative
Required Additional Cap

0

0

300

100

100

100

100

200

0

100

100

100

100

200

100

100

Total Capacity ( C )

924

924

924

1,074

1,674

2,079

2,379

2,479

2,579

2,679

2,779

2,979

2,979

3,079

3,179

3,279

3,379

3,579

3,679

3,779

Peak Demand ( P )

1,484

1,550

1,616

1,686

1,755

1,829

1,906

1,987

2,071

2,163

2,259

2,360

2,465

2,575

2,690

2,811

2,937

3,069

3,207

3,351

Reserved Margin Required ( R )

269

272

275

277

280

283

286

289

293

297

300

304

309

313

318

322

327

333

338

344

Peak Demand + Reserve Margin (P + R)

1,753

1,822

1,891

1,963

2,036

2,112

2,192

2,277

2,364

2,460

2,560

2,664

2,774

2,888

3,008

3,133

3,264

3,401

3,545

3,695

18.15%

17.55%

17.00%

16.46%

15.96%

15.48%

15.02%

14.57%

14.14%

13.71%

13.29%

12.90%

12.52%

12.15%

11.81%

11.47%

11.15%

10.84%

10.55%

10.27%

Reserve Deficiency ( C – P – R )

-829

-898

-966

-889

-361

-33

187

203

215

219

220

315

206

191

171

146

115

178

134

84

 

 

Coal-Fired Power Plant: How to Design and Calculate Plant Footprint, Fuel, Limestone, Hauling Trucks and Storage Areas for Coal and Ash

May 16th, 2014 No Comments   Posted in clean coal technologies

Coal-Fired Power Plant: How to Design and Calculate Plant Footprint, Fuel, Limestone, Hauling Trucks and Storage Areas for Coal and Ash

Yes, your favourite energy technology expert has prepared a simple but easy-to-use power plant model to augment your project finance model to calculate the following:

1) Coal quality and quantity of coal reserves (measured, indicative, inferred, total in-situ reserves)

2) Average specification of coal reserve (heating value, ash, volatile combustible matter, fixed carbon, sulfur, moisture)

3) Ultimate analysis of coal reserve (Carbon, Hydrogen, Nitrogen, Oxygen, Sulfur)

4) Testing for ROM coal (unwashed) and upgraded coal (washed)

5) Typical ash composition and ash fusion temperature

6) Coal consumption rate given fuel-to-power conversion efficiency and capacity factor

7) Limestone consumption rate requirement given its purity and reaction efficiency

8) Number of hauling trucks for transferring coal bottom ash to the permanent ash pond storage area given truck capacity, turn-around time, and operating hours

9) Coal stock yard area and dimensions (Depth, Length, Width) given coal rate, 37 days fuel supply and its bulk density

10) Temporary ash pond area and dimensions  (Depth, Length, Width) given coal rate, ash content and bottom ash portion, 60 days temporary storage, and its bulk density

11) Permanent ash pond area and dimensions  (Depth, Length, Width) given coal rate, ash content and bottom ash portion, 25 years permanent storage, and its bulk density

12) Make-up water Cooling Tower flow rate (10 deg Celsius Rise and 5% loss to the atmosphere in the Cooling Tower)

13) Once-thru Condenser cooling water flow rate (3 deg Celsius Rise)

14) Air-cooled Condenser flow rate (10 deg Celsius Rise)

15) Neutralization Pond Dimensions (for Demin plant and Boiler Feed Water blowdown wastes)

16) Sedimentation Pond or Siltation Basin Dimensions (for coal, limestone, ash and loose soil carried by rainfall to storm drain)

17) Power plant footprint with 20% allowance

18) Transmission Line Losses with 20% allowance (due to type of conductor, length, voltage, power factor and number of phases)

If you are interested in the Coal-Fired CFB Project Finance Model (15, 30, 50, 75, 100, 140 MW) and the Coal-Fired Power Plant Design Tool Kit, please confirm your order via email to this address:

energydataexpert@gmail.com

I will then email you the price in US$ and my bank account details so you could remit payment via bank or wire transfer.

If it is a special problem, I can also customize the project finance model and the coal-fired power plant design tool kit.

You may pay also thru PayPal.

Cheers,

Energy Technology Expert

—-

COAL QUALITY AND TONNAGE OF 10.334 MILLION MT coal reserves              
Resource Area  Coal Block No.    Measured   Indicated Total In-situ      
      Reserves   Reserves Reserves       
    BTU/lb   Tonnage  BTU/lb   Tonnage  Tonnage  BTU/lb      
PATULANGAN  164 7,217 1,061,494 6,163 2,786,727 3,848,221 6,454    
WALDO-DENTE  165 7,319 236,968 7,548 170,569 407,537 7,415    
WALDO-DENTE  166 7,319 693,636 7,548 1,118,038 1,811,674 7,460    
LAGUNTANG  204 7,520 1,761,556 7,135 1,644,528 3,406,084 7,334    
GEORGIA-LIBAS/ KABADYANGAN 205 / 206 7,314 631,867 7,591 228,806 860,673 7,388    
Total    7,374 4,385,521 6,787 5,948,668 10,334,189 7,036    
TOTAL RESOURCE     10,334,189 MT          
GHV of Resource AVERAGE   7,036 BTU/lb           
  MINIMUM   6,163 BTU/lb           
  MAXIMUM   7,591 BTU/lb           
                   
Average specifications of coal resource                
Heating Value BTU/lb 7,036 16,366 kJ / kg this coal reserve        
Ash % 27.94 3,909 kCal / kg          
Volatile Combustible Material (VCM) % 37.29 4,200 kCal / kg actual coal used        
Fixed Carbon (FC) % 21.25 7,560 Btu / lb          
Moisture % 13.52 10.00% % ash actual ash used        
Sulfur (S) % 1.26 1.26% % sulfur actual sulfur used        
                   
Testing for ROM coal (unwashed) and upgraded coal (washed)               
  ROM Coal Upgraded Coal              
Specifications (as-received basis) (air-dried)              
Heating Value, BTU/lb 6,670 8,500              
% Moisture 14.82 10.33              
% Fixed Carbon (FC) 23.98 28.85              
% Ash 24.33 15.77              
% Sulfur (S) 1.43 1.38              
% VCM 36.87 45.05              
HGI 47 40              
Ash Fusion, deg C:                  
     (a)  Oxidizing 1,446 1,363              
     (b)  Reducing 1,442 1,308              
                   
1.05506 kJ / Btu Btu / lb x 2.2046 lb/kg x 1.05506 kJ / Btu = kJ / kg          
4.1868 kJ / kCal kJ / kg x kCal / 4.1868 kJ = kCal / kg            
2.2046 lb / kg kCal / kg x kg / 2.2046 lb x 4.1868 kJ / kCal / 1.05506 kJ / Btu = Btu / lb        
                   
COAL REQUIREMENT AT VARIOUS PLANT CAPACITIES (2 x 50 MW)              
100 MW Conversion Factors              
1 h / h                
100 MWh / h                
    90.00% CFB Boiler Efficiency          
    40.00% Rankin Steam Turbine Efficiency          
    95.04% Generator Efficiency          
292 MWh / h 34.21% Overall Fuel to Electricity Efficiency          
292,275 kWh / h 1,000 kWh / MWh            
1,052,188,552 kJ / h 3,600 kJ / kWh            
997,278,403 BTU / h 1.05506 kJ / BTU 3412.12822 Btu / kWh        
131,914 lb / h 7,560 BTU / lb            
59,836 kg / h 2.2046 lb / kg            
60 MT / h 1,000 kg / MT            
1,436 MT / day 24 h / day            
    365 days per year            
    80.00% capacity factor            
419,330 MT / year 292 operating days per year          
                   
LIMESTONE REQUIREMENT (2 X 50 MW)                
CaCO3 + SO2 + 1/2 O2 –> CaSO4 + CO2                
Molecular Weights (kg / kgmol):                  
CaCO3   100.0892 40.08 12.011 15.9994        
SO2   64.0648 32.066 15.9994          
O2   31.9988   15.9994          
CaSO4   136.1436 40.08 32.066 15.9994        
CO2   44.0098 12.011 15.9994          
1000   kg coal              
1.26%   % Sulfur seam 1   100.00%          
    % Sulfur seam 2              
1.26%   % Sulfur average   100.00%          
12.60   kg Sufur              
32.066   kg / kgmol Sulfur              
0.39294   kg mol Sulfur              
0.39294   kg mol CaCO3 = CaSO4            
39.32901   kg CaCO3              
90.00%   % CaCO3 in limestone (purity) 500.00 PhP/MT limestone        
43.69890   kg CaCO3              
20.00%   conversion efficiency (1/5)            
218.49448   kg limestone              
0.21849 MT / MT coal actual kg limestone per kg coal            
0.16400   kg limestone per kg coal (JCI Study)            
0.29720   kg CaSO4 produced per kg coal            
1,436 MT / day Coal requirement              
314 MT / day Limestone requirement            
292   Days per year              
91,621 MT / year Limestone requirement            
                   
COAL HAULING TRUCKS REQUIREMENT (2 x 50 MW)                
100 MW Conversion Factors              
1 h / h                
100 MWh / h                
    90.00% CFB Boiler Efficiency          
    40.00% Rankin Steam Turbine Efficiency          
    95.04% Generator Efficiency          
292 MWh / h 34.21% Overall Fuel to Electricity Efficiency          
292,275 kWh / h 1,000 kWh / MWh            
1,052,188,552 kJ / h 3,600 kJ / kWh            
997,278,403 BTU / h 1.05506 kJ / BTU 3412.12822 Btu / kWh        
131,914 lb / h 7,560 BTU / lb            
59,836 kg / h 2.2046 lb / kg            
60 MT / h 1,000 kg / MT            
1,436 MT / day 24 h / day            
    8 h / day of truck transport          
8,616 MT / week 6 days / week of truck transport          
    48 h / week of truck transport          
    20 MT / h truck capacity (1 hour round trip)          
9.0 dump trucks 960 MT / week / dump truck          
                   
Coal Stock Yard with roof (2 x 50 MW)   100 MW          
1,436 MT / day coal   Coal requirement, “as received” basis          
    30 days of storage capacity          
    7 allowance for mine upsets or delivery upsets (1 week)        
    37 total days storage capacity          
53,134 MT in stock yard   total volume of stock yard          
44,800 cum stock yard 1.2 Assumed in-situ relative density, MT/cum          
    5 Maximum height of coal stock yard, m          
8,960 sqm floor area   Area of coal stock yard floor   2 x W^2 = V      
67 m wide   Width (W)     W^2 = V/2      
134 m long   Length (L = 2 x W)     W = sqrt(V/2) = (V/2)^(1/2)    
                   
Ash Pond with HDPE lining on sides and floor (2 x 50 MW) 100 MW          
1,436 MT / day coal   Coal requirement, “as received” basis   MT reserves      
    10.00% Ash content – Seam 1   10,334,189 100.00%    
      Ash content – Seam 2     0.00%    
144 MT / day ash 10.00% Ash content – Average   10,334,189 100.00%    
427 MT / day CaSO4 0.2972 CaSO4 produced, MT per MT coal          
570 MT / day total                
    5 days of storage capacity for ash          
    55 allowance for power plant upsets   95% 365 18 days
    60 total days storage capacity   90% 365 37 days
34,224 MT in ash pond   total volume of stock yard   85% 365 55 days
29,000 cum ash pond 1.2 Assumed bulk density of ash, MT/cum   80% 365 73 days
    5 Maximum depth of ash pond, m          
5,800 sqm floor area   Area of ash pond floor   2 x W^2 = V      
54 m wide   Width (W)     W^2 = V/2      
108 m long   Length (L = 2 x W)     W = sqrt(V/2) = (V/2)^(1/2)    
                   
Ash Pond Dimension & Capacity for 25 years operation                
  cap factor   MT/day MT/year          
40% 80.00% 365 57.44 16,773 bottom ash        
60%     86.16 25,160 fly ash        
100%     143.61 41,933 total ash        
                   
                   
                   
  years MT              
  25 419,330              
    1.2 MT/cum            
    349,442 cum            
    10 m deep            
    34,944 sqm 3.49 ha        
    132 m wide 0.132 km        
    264 m long 0.264 km        
                   
BOTTOM ASH HAULING TRUCKS REQUIREMENT (2 x 50 MW)              
100 MW Conversion Factors              
1 h / h                
100 MWh / h                
    90.00% CFB Boiler Efficiency          
    40.00% Rankin Steam Turbine Efficiency          
    95.04% Generator Efficiency          
292 MWh / h 34.21% Overall Fuel to Electricity Efficiency          
292,275 kWh / h 1,000 kWh / MWh            
1,052,188,552 kJ / h 3,600 kJ / kWh            
997,278,403 BTU / h 1.05506 kJ / BTU 3412.12822 Btu / kWh        
131,914 lb / h 7,560 BTU / lb            
59,836 kg / h 2.2046 lb / kg            
60 MT / h 1,000 kg / MT            
1,436 MT / day 24 h / day            
144 MT / day 10% coal ash            
57 MT / day 40% bottom ash in coal ash          
    8 h / day of truck transport          
345 MT / week 6 days / week of truck transport          
    48 h / week of truck transport          
    5 MT / h truck capacity (10 MT truck capacity, 2 hour round trip)        
2.0 dump trucks 240 MT / week / dump truck          
                   
Make-Up Water for Cooling Tower (10 deg Celsius Rise) – 2 x 50 MW              
100 MW Conversion Factors              
1 h / h                
100 MWh / h                
    90.00% CFB Boiler Efficiency   fuel to steam      
    40.00% Rankin Steam Turbine Efficiency   steam to drive shaft      
    95.04% Generator Efficiency   drive shaft to electricity    
292 MWh / h 34.21% Overall Fuel to Electricity Efficiency   fuel to electricity      
292,275 kWh / h 1,000 kWh / MWh            
1,052,188,552 kJ / h 3,600 kJ / kWh            
997,278,403 BTU / h 1.05506 kJ / BTU     Energy input from fuel    
897,550,563 BTU / h 90% CFB Boiler Efficiency   Energy to steam      
99,727,840 BTU / h 10% Heat Losses to Atmosphere   Energy to atmosphere & losses    
897,550,563 BTU / h         Energy input to steam turbine    
359,020,225 BTU / h 40% Rankin Steam Turbine Efficiency   Energy to drive shaft    
538,530,338 BTU / h 60% Heat Losses to Condenser   Energy to condenser / cooling tower    
359,020,225 BTU / h         Energy input to drive shaft    
341,212,822 BTU / h 95% Generator Efficiency   Energy to electricity      
17,807,403 BTU / h 5% Heat Losses to Generator   Energy to generator losses    
538,530,338 BTU / h         Energy input to condenser / cooling tower  
511,603,821 BTU / h 95% Heat transferred to cooling water   Energy to cooling water    
26,926,517 BTU / h 5% Heat Losses to Atmosphere   Energy to atmosphere & losses    
    10 Allowable temperature Rise, deg C     cum / h   cum / h
    1.8 deg F per deg C rise   MW Water Circulating CTW Losses Make-up
    18 Allowable temperature Rise, deg F   15 1,934 5.00% 97
    1 Specific heat of water, Btu / lb deg F   30 3,868 5.00% 193
28,422,434 lb / h 18.00 Allowable Btu / lb     50 6,446 5.00% 322
12,892,332 kg / h 2.2046 lb / kg     100 12,892 5.00% 645
12,892 cum / h 1,000 kg / cubic meter (kg / cum)   140 18,049 5.00% 902
645 cum / h 5.00% make-up water (cooling tower losses to atmosphere)        
0.1791 cum / sec make-up water              
                   
Once-Thru Cooling Water (3 deg Celsius Rise) – 2 x 50 MW              
100 MW Conversion Factors              
1 h / h                
100 MWh / h                
    90.00% CFB Boiler Efficiency   fuel to steam      
    40.00% Rankin Steam Turbine Efficiency   steam to drive shaft      
    95.04% Generator Efficiency   drive shaft to electricity    
292 MWh / h 34.21% Overall Fuel to Electricity Efficiency   fuel to electricity      
292,275 kWh / h 1,000 kWh / MWh            
1,052,188,552 kJ / h 3,600 kJ / kWh            
997,278,403 BTU / h 1.05506 kJ / BTU     Energy input from fuel    
897,550,563 BTU / h 90% CFB Boiler Efficiency   Energy to steam      
99,727,840 BTU / h 10% Heat Losses to Atmosphere   Energy to atmosphere & losses    
897,550,563 BTU / h         Energy input to steam turbine    
359,020,225 BTU / h 40% Rankin Steam Turbine Efficiency   Energy to drive shaft    
538,530,338 BTU / h 60% Heat Losses to Condenser   Energy to condenser / cooling tower    
359,020,225 BTU / h         Energy input to drive shaft    
341,212,822 BTU / h 95% Generator Efficiency   Energy to electricity      
17,807,403 BTU / h 5% Heat Losses to Generator   Energy to generator losses    
538,530,338 BTU / h         Energy input to condenser / cooling tower  
511,603,821 BTU / h 95% Heat transferred to cooling water   Energy to cooling water    
26,926,517 BTU / h 5% Heat Losses to Atmosphere   Energy to atmosphere & losses    
    3 Allowable temperature Rise, deg C     cum / h    
    1.8 deg F per deg C rise   MW Water Circulating    
    5.4 Allowable temperature Rise, deg F   15 6,446    
    1 Specific heat of water, Btu / lb deg F   30 12,892    
94,741,448 lb / h 5.40 Allowable Btu / lb     50 21,487    
42,974,439 kg / h 2.2046 lb / kg     100 42,974    
42,974 cum / h 1,000 kg / cubic meter (kg / cum)   140 60,164    
11.94 cum / sec once-thru water              
                   
Air Cooled Condenser (10 deg Celsius Rise) – 2 x 50 MW                
100 MW Conversion Factors              
1 h / h                
100 MWh / h                
    90.00% CFB Boiler Efficiency   fuel to steam      
    40.00% Rankin Steam Turbine Efficiency   steam to drive shaft      
    95.04% Generator Efficiency   drive shaft to electricity    
292 MWh / h 34.21% Overall Fuel to Electricity Efficiency   fuel to electricity      
292,275 kWh / h 1,000 kWh / MWh            
1,052,188,552 kJ / h 3,600 kJ / kWh            
997,278,403 BTU / h 1.05506 kJ / BTU     Energy input from fuel    
897,550,563 BTU / h 90% CFB Boiler Efficiency   Energy to steam      
99,727,840 BTU / h 10% Heat Losses to Atmosphere   Energy to atmosphere & losses    
897,550,563 BTU / h         Energy input to steam turbine    
359,020,225 BTU / h 40% Rankin Steam Turbine Efficiency   Energy to drive shaft    
538,530,338 BTU / h 60% Heat Losses to Condenser   Energy to condenser / cooling tower    
359,020,225 BTU / h         Energy input to drive shaft    
341,212,822 BTU / h 95% Generator Efficiency   Energy to electricity      
17,807,403 BTU / h 5% Heat Losses to Generator   Energy to generator losses    
538,530,338 BTU / h         Energy input to condenser / cooling tower  
511,603,821 BTU / h 95% Heat transferred to cooling water   Energy to cooling water    
26,926,517 BTU / h 5% Heat Losses to Atmosphere   Energy to atmosphere & losses    
    10 Allowable temperature Rise, deg C     000 cum / h    
    1.8 deg F per deg C rise   MW Air circulating    
    18 Allowable temperature Rise, deg F   15 7,148    
    0.240 Specific heat of air, Btu / lb deg F   30 14,297 1.005 kJ / kg-C
118,406,264 lb / h 4.32 Allowable Btu / lb     50 23,828 1.127 kg / cum
53,708,729 kg / h 2.2046 lb / kg     100 47,656    
47,656,370 cum / h 1.127 kg / cubic meter (kg / cum)   140 66,719    
13,238 cum / sec air              
                   
Neutralization Pond (Demin plant and Boiler Feed Water Blowdown wastes)            
                   
  Plant Size Depth, m Width, m Length, m Volume, cum R = L / W Cost, $    
0.2 600 10.0 30.0 80.0 24,000 2.67   V = Vo x (Q / Qo)^n
0 15 10.0 20.8 55.5 11,500 2.67   where n = 0.2  
0 30 10.0 22.2 59.2 13,200 2.67   R x W^2 x D = V
0 50 10.0 23.4 62.4 14,600 2.67   W^2 = V / (R x D)
1 100 10.0 25.1 66.9 16,800 2.67   W = sqrt(V / R / D) = (V / R / D)^(1/2)
0 140 10.0 25.9 69.1 17,900 2.67   L = R W  
USED 100 10.0 25.1 66.9 16,800 Used      
                   
Sedimentation Pond or Siltation Basin (coal, limestone, ash and loose soil carried by rainfall to storm drain)          
                   
  Plant Size Depth, m Width, m Length, m Volume, cum R = L / W Cost, $    
0.2 600 10.0 10.0 100.0 10,000 10.00   V = Vo x (Q / Qo)^n
0 15 10.0 6.9 69.0 4,800 10.00   where n = 0.2  
0 30 10.0 7.4 74.0 5,500 10.00   R x W^2 x D = V
0 50 10.0 7.8 78.0 6,100 10.00   W^2 = V / (R x D)
1 100 10.0 8.4 84.0 7,000 10.00   W = sqrt(V / R / D) = (V / R / D)^(1/2)
0 140 10.0 8.7 87.0 7,500 10.00   L = R W  
USED 100 10.0 8.4 84.0 7,000 Used      
                   
Power Plant Footprint (with 20% allowance)                
                   
0.737 120% Footprint              
MW Area, ha ha              
15 5 6.0              
30 8 9.6              
50 12 14.4 given at 50 MW            
70 15 18.0              
100 20 24.0 given at 100 MW            
140 26 31.2              
                   
Transmission Line Losses (due to type of conductor, length, voltage, power factor and number of phases)          
2 x 50 MW Site A – near River                
Line Voltage 69 kV   km 1.609        
Power 100,000 kW   mile 1        
Length (with 20% allowance) 12.00 km 10.00 feet 5280        
Power Factor 0.85 lag              
Total Line Current 984.399 A   resistivity of Al 20 17.002 ohm-cmil/ft    
Line Current/Circuit 328.133 A     25 17.345 ohm-cmil/ft    
No. of Circuit 3                
                   
Trnasmission Line                  
  Ampacity Resistance (ohms/mile)   Loss (3-phase)*        
ACSR (MCM) A 25 deg.C 50 deg.C 90 deg.C kW %      
336 530 0.278 0.306 0.351 6563.56 6.564%      
795 900 0.119 0.138 0.168 3141.08 3.141%      
                   
AAC (MCM) A 20 deg.C 25 deg.C 90 deg.C kW %      
336 495 0.267 0.273 0.343 6410.78 6.411%      
789 855 0.114 0.116 0.146 2730.07 2.730% USE LOWEST    
              ENERGY LOSS    
                   
Properties of Air http://www.engineeringtoolbox.com/air-properties-d_156.html            
Temperature Density Specific heat capacity Thermal conductivity Kinematic viscosity Expansion coefficient Prandtl’s number      
- t - - - - cp - - k - - ν - - b - - Pr -      
(oC) (kg/m3) (kJ/kg.K) (W/m.K) x 10-6(m2/s) x 10-3(1/K)        
-150 2.793 1.026 0.0116 3.08 8.21 0.76      
-100 1.98 1.009 0.016 5.95 5.82 0.74      
-50 1.534 1.005 0.0204 9.55 4.51 0.725      
0 1.293 1.005 0.0243 13.3 3.67 0.715      
20 1.205 1.005 0.0257 15.11 3.43 0.713      
40 1.127 1.005 0.0271 16.97 3.2 0.711      
60 1.067 1.009 0.0285 18.9 3 0.709      
80 1 1.009 0.0299 20.94 2.83 0.708      
100 0.946 1.009 0.0314 23.06 2.68 0.703      
120 0.898 1.013 0.0328 25.23 2.55 0.7      
140 0.854 1.013 0.0343 27.55 2.43 0.695      
160 0.815 1.017 0.0358 29.85 2.32 0.69      
180 0.779 1.022 0.0372 32.29 2.21 0.69      
200 0.746 1.026 0.0386 34.63 2.11 0.685      
250 0.675 1.034 0.0421 41.17 1.91 0.68      
300 0.616 1.047 0.0454 47.85 1.75 0.68      
350 0.566 1.055 0.0485 55.05 1.61 0.68      
400 0.524 1.068 0.0515 62.53 1.49 0.68      
                   
Mean Temperature (C) and Humidity (%) (SOURCE: IEER) 27.31 Mean Temp. 85.3 Ave Humidity      
          Records from:        
Location: Hinatuan, Surigao del Sur Synoptic Station (PAGASA 2000)     Source: PAGASA 2000      
                   
Month Rainfall Ave. (mm) Temperature (deg C) Humidity Wind Wind    
  Max. Min. Mean % Direction Speed (m/s)    
                   
Jan 728.20 29.7 22.5 26.1 88.0 NE 2.0    
Feb 516.30 29.8 22.4 26.1 88.0 NE 2.0    
Mar 446.70 30.5 22.7 26.6 86.0 NE 2.0    
Apr 322.30 31.6 23.2 27.4 85.0 E-W 2.0    
May 240.60 32.4 23.7 28.1 85.0 E-W 2.0    
Jun 262.60 32.3 23.5 27.9 85.0 W 2.0    
Jul 203.30 32.5 23.2 27.9 83.0 W 2.0    
Aug 180.60 32.9 23.3 28.1 82.0 W 2.0    
Sep 204.40 32.7 23.1 27.9 83.0 W 2.0    
Oct 261.20 32.3 23.2 27.8 84.0 W 2.0    
Nov 339.90 31.4 23.1 27.2 86.0 W 2.0    
Dec 539.1 30.4 22.8 26.6 88.0 W 2.0    
                   
Min 180.60 29.7 22.4 26.1 82.0   2.0    
Max 728.20 32.9 23.7 28.1 88.0   2.0    
Ave 353.77 31.5 23.1 27.3 85.3 W 2.0    
                   
Coal Characteristics of Design Coal   (SAMPLE DATA) 4,201 Btu / lb 7,560 Btu / lb used      
      0.40 % Sulfur 1.26 % Sulfur used      
                   
Characteristic   Unit “As Received” Basis “Moisture Free” Basis      
                   
Carbon   % wt. 26.10   58.00        
Hydrogen   % wt. 1.80   4.00        
Oxygen   % wt. 11.25   25.00        
Nitrogen   % wt. 0.23   0.51        
Sulfur   % wt. 0.36   0.80        
Chlorine   % wt. 0.04 0.40 0.09        
Ash   % wt. 5.22   11.60        
Moisture   % wt. 55.00            
Total   % wt. 100.00 Btu / lb 100.00 Btu / lb      
Gross Calorific Value   kcal / kg 2,334 4,201 5,187 9,336      
Net Calorific Value   kcal / kg 1,917 3,451 4,260 7,668      
Note: MFB = ARB x (100 / (100 – Moisture)              
                   
Coal Analysis Data by AL and Comparison with Data by PNC (SAMPLE DATA)            
                   
  Item Unit CC-260 BII 685 CC-235 BII 601 CC-232 BII-600  
      P2-028 P2-007 P2-006  
Analyzed at:     AL PNC AL PNC AL PNC  
Proximate Analysis                  
TM – Total Moisture   % 61.70   53.90   50.00    
IM – Inherent Moisture   % 21.10 11.76 20.60 12.43 9.20 11.86  
Ash (815 deg C)   % 5.30 20.67 8.40 10.10 49.60 16.80  
VM – Volatile Matter   % 53.50 38.54 54.20 41.78 32.80 37.97  
FC – Fixed Carbon   % 41.20 29.03 37.40 35.69 17.60 33.37  
Ultimate Analysis                  
Carbon   % 64.50            
Hydrogen   % 4.10            
Nitrogen   % 0.84            
Total Sulfur   % 0.36 0.69   0.58   0.25  
Combustible Sulfur   % 0.07            
Total Chlorine   % 0.04            
Volatile Chlorine   % 0.04            
Oxygen (by calculation)   % 25.15            
Gross Calorific Value   kJ /kg 26,960 7,655 25,510 9,100 11,620 8,168  
    kcal / kg 6,439   6,093   2,775    
    BTU / lb   4,253   5,056   4,538  
Net Calorific Value   kJ /kg 26,030            
    kcal / kg 6,217            
    BTU / lb              
PNC     51            
Remarks:   (1) AL – an authorized laboratory            
    (2) The data by PNC are “air dried” basis.          
                   
Coal Sample C-260 Ash Analysis Data   (SAMPLE DATA)            
                   
Composition   Analyzed Values   Compositions   Analyzed Values      
SiO2 wt. % 5.95   KO wt. % 0.08      
Al2O3 wt. % 8.95   P2O5 wt. % 0.04      
Fe2O3 wt. % 24.10   SO3 wt. % 13.90      
CaO wt. % 33.00   Cl ppm 0.04      
MgO wt. % 11.60   F   90.00      
Na2O wt. % 0.25              
Remarks: (1) The ash sample was collected after heating the coal sample to 815 deg C +/- 10 deg C.        
  (2) The fusion test of the ash sample CC-260 was carried out in accordance with          
        JIS M8801 and the following results have been obtained (refer to photographs).          
        Initial Deformation 1,320 deg C          
        Hemisphere Point 1,450 deg C and above          
        Flow Point   1,450 deg C and above          
                   
ENVIRONMENTAL STANDARDS (AIR, NOISE, WATER)                
Air Emission:                  
Clean Air Act of 1999                  
                   
NOx 260 mg/Nm3              
SOx 340 mg/Nm3 as SO2              
TSP 200 mg/Nm3              
Exhaust Noise Level:                  
Official Gazette Vol. 74, No. 23, 5 June 1978                
                   
Noise 90 dB measured at 10 meters distance            
Effluent Standards:                  
1990 Effluent Regulations                  
    Class D              
Temperature Rise 3 deg C              
pH 6 minimum              
  9 maximum              
COD 200 mg/L              
5-day 20C BOD 120 mg/L              
TSP 150 mg/L              
TDS 1,000 mg/L              

—-

 

Economics of a 135 MW (net) coal-fired Circulating Fluidized Bed (CFB) Thermal Power Plant

May 14th, 2014 No Comments   Posted in clean coal technologies

Economics of a 135 MW (net) coal-fired Circulating Fluidized Bed (CFB) Thermal Power Plant

Following is an annual construction model (3 years or 36 months) and a 25-year operating project finance model (30% equity, 70% debt) with a 16% p.a. equity IRR and coal cost of US$85 per tonne (metric ton or MT) with a gross heating value (GHV) of 10,000 Btu/lb,  36 months construction, 25 years commercial operation) using average annual drawdown (1/3 in year 1, 1/3 in year 2, 1/3 in year 3 construction drawdown). The CFB has an overall fuel to electricity thermal efficiency of 37.39% (92.5% boiler efficiency, 42.0% steam turbine efficiency and 96.25% mechanical clutch & electric generator efficiency). The results are as follows:

15 MW = 7.16 PhP/kWh

30 MW = 5.86

50 MW = 5.18

75 MW (2 units) = 4.75

100 MW (2 units) = 4.64

135 MW (1 unit) = 4.28

NOTE: 1 US$ = 44.0 PhP (US Dollar to Philippine Peso exchange rate)

As shown above, a minimum economic size of 75 MW (2 power island units) is necessary to be able to compete with a large 135 MW CFB currently being constructed by the major power players. By having 2 units, in the event of plant outage of one unit, there is still an operational half capacity that could provide energy sales and avoiding purchasing expensive replacement/backup power from the spot market to supply contractual requirements.

Order it now as it is capable of analysing 15, 30, 50, 70 (2 units) and 100 (2 units), and 135 (1 unit) megawatts of gross power output.

This model will allow you to optimize size, configuration, and equipment supplier to meet a particular power demand for both stand-alone, base load and mid-merit load operating regime.

Enhance your productivity by using this state-of-the-art power plant project finance model which has the following tabs (worksheets):

1) Cover sheet

2) Inputs & Assumptions

3) Manpower – complement and costs

4) Sensitivity Analysis – impact of -10%, 0% (base case) and +10% change in each parameter (tariff, capex, cost of fuel, O&M cost, plant capacity, thermal efficiency, capacity factor, debt interest rate, debt ratio)

5) Construction Period (could be annual drawdown or monthly drawdown)

6) Operating Period (up to 30 years commercial operation) – gross generation, station use and losses, net generation, land cost, fuel consumption and cost, O&M costs, evolution of balance sheet accounts

7) Financials – revenue, expenses (fuel, fixed O&M, variable O&M, taxes, regulatory and other costs), net income before tax (EBITDA), depreciation, interest, income tax, net income after tax, principal repayment, net cash flow, equity and project IRR, NPV and payback.

8) Asset Base Tariff – levelized tariff

====

Project Site Name & Location Coal 135 mw CFB
Renewable Energy Source Thermal
Hours per Year

8760

Timing
  Construction Period (from FC) (months) – maximum 36

36

  Operating Period (Yrs from COD)

25

  Yrs from base year CPI & Forex (2011) for FIT

4

  Yrs from base year CPI (2012) for CAPEX

1

  Yrs from base year CPI (2012) for OPEX

3

Construction Sources and Uses of Funds, $000
  Uses of Fund:
    Land

$142

    EPC (Equipment, Balance of Plant, Transport, Access Roads)

$167,726

    Transmission Line Interconnection Facility

$499

    Sub-Station Facility

$817

    Development & Other Costs

$25,695

    Construction Contingency

$7,806

    Value Added Tax

$14,878

    Financing Costs

$28,680

    Initial Working Capital

$18,704

  Total Uses of Fund

$264,947

  Sources of Fund:
    Debt

$185,463

    Equity

$79,484

  Total Sources of Fund

$264,947

  Construction Unit Costs (US$/kW):
    EPC Cost

$1,242

    Plant Cost (Excluding VAT, Financing, Working Capital)

$1,500

    All-in Project Cost

$1,963

Model Check:
Balance Sheet OK
Foreign Debt Amortization 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 2011
  Base year CPI for CAPEX 2012
  Base year CPI for OPEX 2012
Commercial Operating Date 2015

 

Technical and EPC Assumptions
Unit Capacity of Plant (MW/unit)

135.000

No. of Units (unit)

1.0

Gross Installed Capacity (MW)

135.00

Plant Availability Factor, %

94.00%

Guaranteed Efficiency Factor, %

98.00%

Allowance for losses & own use, %

0.14%

Net Capacity Factor after losses & own use, %

91.99%

Net Electrical Output (MWh in 1st Year)

1,087,882

Plant Degration, % p.a. (1-25 Yrs)

0.20%

% LC
Land cost ($000)

$136.36

100.0%

Equipment Cost ex BOP, Transport ($000/MW)

$965.00

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)

12.00

T/L Cost per km, 69 kV ($000/km)

$40.00

100.0%

Switchyard & Transformers ($000)

$786.00

100.0%

Access Roads ($000/km)

$182.00

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)

11.0%

100.0%

Contingency (% of Total Cost)

4.0%

50.0%

SET NPV (G28) TO ZERO BY VARYING FIT (F30) – ctrl +e

-0

Operating Assumptions Equity IRR
  Feed-in-Tariff (PhP/kWh)

4.28

16.0%

  Duration of FiT (Yrs)

20

Project IRR
  Tariff post FiT period (PhP/kWh)

7.00

13.1%

  FiT using Asset Base Methodology (PhP/kWh)

4.85

  Annual CER Volume (tCO2e/year) and $/tCO2e                -

$5.00

  O&M Cost ($000/unit/year)

$4,380.31

  Spare Parts, Tools & Equipment ($000/MW/yr)

$65.75

  O&M + Spares as % of EPC, T/L, S/S

7.84%

  Refurbishment Cost (% of EPC)

30%

  Timing of Refurbishment (Year from COD)

10

  G&A ($000/year)

$464.34

  Fuel Cost (switch for Thermal: 1=yes, 0=no)

1

    Average Fuel Cost (PhP/mt)

3,740

$85.00

    Fuel Rate (kWh/mt)

2,416

    Average Fuel Consumption (mt/year)

456,980

    Average Unit Cost of Fuel (PhP/kWh)

2.946

  Days Receivable & Payable

30

30

  VAT Recovery (70%)

0%

  Timing of VAT recovery (5 Yrs after COD)

0

 

Debt and Equity Assumptions
Local/Foreign Capital Mix:
  Local Capital

48.0%

  Foreign Capital

52.0%

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

70.00%

Total Local Debt ($000)

$47,821

Total Foreign Debt ($000)

$137,642

Total Debt Amount ($000)

$185,463

Equity:
  Equity Ratio

30.00%

  Equity Investment

$79,484

  Cost of Equity (Onshore Equity IRR) – Nominal

16.0%

  Cost of Equity (Onshore Equity IRR) – Real

11.5%

Press ctrl + d to converge CF, all-in cost, var & fix costs
WACC pre-tax

12.8%

WACC after-tax

9.0%

Tax Assumptions
  Income Tax Holiday (Yrs)

0

  Income Tax Rate % (after ITH)

30%

  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%

  Use Monthly Construction Drawdown (1 = monthly, 0 = annual)

0

 

Gross Heating Value

10,000

Btu/lb

2.2046

lb/kg

1000

kg/MT

22,046,000

Btu/MT
Efficiency, %

37.39%

of GHV
Plant Heat Rate

3600

kJ/kWh

1.05506

kJ/Btu

3,412

Btu/kWh

9,125

Btu/kWh
Fuel Rate

2,416

kWh/MT
Cost of Fuel

3,740

PhP/MT

2,416

kWh/MT
          1.548 PhP/kWh

====

Please confirm your order by email to:

energydataexpert@gmail.com

Then I will email you my bank details for the wire transfer/payment.

Once payment has been received, I will email you the excel model and the word file containing instructions on how to run the project finance model.

Cheers,

Your energy technology expert

 

HOW TO PLAN AND OPTIMIZE THE ENERGY, OIL, GAS, POWER AND TRANSMISSION INFRASTRUCTURE OF THE PHILIPPINES

HOW TO PLAN AND OPTIMIZE THE ENERGY, OIL, GAS, POWER AND TRANSMISSION INFRASTRUCTURE OF THE PHILIPPINES

My sincerest thanks to the readers, government officials, private investors, power developers, funding institution and non-government organizations that will respond positively to this conversation that I started recently as part of my functions as Senior Power Generation Engineer at SKM.

It is my fervent hope that this conversation will be continued as a result of your endorsement to the right parties and that timely coordination and meetings are done soonest as time is of the essence in having an integrated and optimized energy master plan for the country before year end 2013. More »

HOW TO MINIMIZE FLOODING IN CENTRAL LUZON AND THE MARIKINA VALLEY AND METRO MANILA

August 21st, 2013 3 Comments   Posted in Dam water release

HOW TO MINIMIZE FLOODING IN CENTRAL LUZON AND THE MARIKINA VALLEY AND METRO MANILA

The San Roque Dam was designed for a 50-year return flood frequency. Since Typhoon Ondoy and Peping were of the order to a 75-100 year flood, it is thus imperative to lower the dam rule curve by 4-5 meters which is the equivalent of 1 major storm. Please note that it took 6 typhoons to fill up the San Roque Dam to its operating level to provide both power and irrigation during summer. More »

The Boeing 787 is Doomed, Unless it Gets out of the Battery

July 13th, 2013 1 Comment   Posted in Green Plane

The Boeing 787 is Doomed, Unless it Gets out of the Battery

There is something fundamentally wrong with Boeing 787. It has too many batteries that needs to store a large amount of energy in a very small space called cell. More »

How to compute prices of gasoline and diesel

July 13th, 2013 No Comments   Posted in Oil Pricing Formula

BusinessWorld
http://www.bworldonline.com/content.php?section=Opinion&title=How-to-compute-prices-of-gasoline-and-diesel&id=73169
Thursday, July 11, 2013 | MANILA, PHILIPPINES

How to compute prices of gasoline and diesel

Strategic   Perspective René B. Azurin

SINCE PUMP prices of oil products are again rising, prompting the usual round of demonstrations against “overpricing,” I thought it would be useful to bring to everyone’s attention the pricing model developed by the Independent Oil Price Review Committee (IOPRC) which was tasked last year to study the reasonableness of retail prices of gasoline and diesel. More »

Why the Asiana Airline Boing 777 Crashed – No one cared about safety inside the plane and on the SF airport

July 10th, 2013 4 Comments   Posted in Flight Safety

Why the Asiana Airline Boing 777 Crashed – No one cared about safety inside the plane and on the SF airport

The plane crashed because the other pilots were busy drinking coffee while the pilot in training was playing at the yoke.

Seriously, it crashed because of a series of simple events that no one noticed was leading to a dangerous situation: More »

Expertise of Marcial Ocampo- now available for engagement (projects and consultancy or fixed employment)

June 19th, 2013 1 Comment   Posted in energy technology expert

Expertise of Marcial Ocampo – now available for engagement (projects and consultancy or fixed employment)

Conventional and Renewable Energy Statistics (historical, forecast)

Renewable Energy Supply/Demand and Tariff Studies

Renewable Energy Resource Assessment (wind, solar, mini-hydro) and Optimal Configuration Studies

Clean Coal and Conventional Coal Project Finance and Feasibility Studies

Electricity Supply/Demand and Tariff Studies (Luzon, Visayas, Mindanao, island grids) More »

Short-Term and Long-Term Solution to the Mindanao Power Crisis

March 29th, 2013 No Comments   Posted in optimal load dispatch

 Short-Term and Long-Term Solution to the Mindanao Power Crisis

Mindanao needs temporarily for the next 5 years turbo-charged high-efficiency diesel genset units (4 x 50mw) in a power barge configuration. While it may appear expensive on a per kwh basis, it is operated only when there is a power deficiency, and its cost will be due to capacity fees (to recover capital costs for its 5-year deployment), operating & maintenance fees (to recover manpower, spare parts and admin fees) and fuel costs (pass thru fuel conversion costs). More »

Face-saving Measures to End Sabah Stand-off Needed

March 9th, 2013 2 Comments   Posted in Sabah Claim

Face-saving Measures to End Sabah Stand-off Needed

The problem with Sultan Kiram is he is acting alone, then expects the Philippine gov’t to bail him out of this problem, holding everyone hostage, to make the face-saving measures.

At this point, the only viable face-saving activities are: More »

Gov’t to change renewable energy mix

February 26th, 2013 4 Comments   Posted in feed-in tariff

Gov’t to change renewable energy mix

Inquirer News, November 1st, 2012

The Department of Energy (DOE) is planning to reallocate the installation targets among the renewable energy sources in favor of the more expensive solar and wind power projects.

Energy Undersecretary Jose Layug Jr. assured the public, however, that such an action would not increase the feed-in-tariff (FIT) allowance—or the universal levy to be collected from all power consumers for the use of renewable energy facilities—beyond the estimate of 5 centavos per-kilowatt-hour (kWh). More »

How the Philippines Recovered and Stabilized its Economic and Fiscal Situation – master plan

January 18th, 2013 7 Comments   Posted in Philippine Master Plan

How the Philippines Recovered and Stabilized its Economic and Fiscal Situation – master plan

A power point presentation was prepared and here is the outline of that presentation. If you need a copy of the power pt presentation in pdf format, please email me your interest and I will email you arrangements and how to make the donation for sharing the information to your country.

energydataexpert@gmail.com

More »

How to Get Out of this Global Financial Meltdown – a suggested approach

January 18th, 2013 1 Comment   Posted in global financial meltdown

How to Get Out of this Global Financial Meltdown – a suggested approach

Oil Crisis, US Recession and Global Financial Meltdown

As early as 2007, signs of economic recession have been observed throughout the world.  By end December 2007, the international price of crude oil went past $100 per barrel.  Continued speculation in the world markets as well as increased demand pushed the price to its maximum of $147 per barrel by July 2008. More »

The Secret to Long Life

December 7th, 2012 No Comments   Posted in surviving cancer

The Secret to Long Life

I have a secret.
The secret to long life and good health. But it needs an important element. More »

Marcial Ocampo – the Energy Technology Expert (now available for projects and consultancy or fixed employment)

November 1st, 2012 6 Comments   Posted in energy technology expert

Marcial Ocampo – the Energy Technology Expert (now available for projects and consultancy or fixed employment)

Today, at 2pm on December 6, 2012, the Philippine Department of Energy (DOE) and the Energy Management Association of the Philippines (ENMAP now ENPAP) will confer on Marcial a SPECIAL RECOGNITION AWARD for his significant contributions to goals and achievements of the energy conservation (ENERCON) and energy efficiency initiatives of the government and private sector. The venue of the awards giving is the MERALCO Multi-Purpose Hall. Please be there my friends at the DOE, PNOC, PBR, PETRON, PETRONAS PHIL, DOST, FIRST GEN, UNDP, ADB and WB-IFC.

Marcial T. Ocampo is a Chemical Engineer and placed 2nd place during the 1973 Chemical Engineering Board Examination. Marcial also pursued advanced studies when he finished his M.S. Combustion and Energy from University of Leeds, UK. More »

Was Hurricane Sandy a conspiracy to re-elect President Obama?

November 1st, 2012 1 Comment   Posted in Global Warming

Was Hurricane Sandy a conspiracy to re-elect President Obama?

A computer program that can create a perfect storm? Not even the atomic bomb unleashed on Japan at the end of World War II made an impact on weather! Weather disturbance now is a result of global warming – higher temperature makes warmer atmospheric and surface water molecules causing water in the oceans to vaporize in greater amounts and when suddenly cooled, condenses, creates pressure differenials, and as the world’s atmosphere attempts to rebalance the pressures, the rush from high pressure to low pressure areas results in super typhoons of incredible wind speeds bringing with it saturated and moisture laden air giving us stupendous rainfall in a very short time – saturating the land and inundating low-lying areas that people have no time to evacuate. Global Warming is real and Americans must believe in it so it could be part of the solution – not believing in it – is a political problem of of American leaders. They could not convince their citizens because they are controlled by fossil-based companies of America. What a shame. America the great could not comprehend science, yet it sends man to the moon and hopes to reach Mars. But it could not solve problems here on earth. Greed of fossil-based America. Time to go Renewable. Invest so that the world, including America, will be a better place to leave. America must not drag the entire world to its foolishness. Reform America. The tipping point is near. A few more rise in temperature within this century, the polar ice will melt, the seas will rise, and half of mankind will sink into the oceans deprived of homes and sources of livelihood. And all because fossil-based and greedy corporations of America don’t believe in Global Warming, and their dog-leashed Americal Political Leaders can’t say otherwise, or their Presidential ambitions will go to waste for lack of political funding. How Sad. America is going to the Dogs.

 

Oil Pump Price Model – Excel Spreadsheet

September 14th, 2012 No Comments   Posted in Oil Pricing Formula

Oil Pump Price Model – Excel Spreadsheet

Calculation model for the following products:

  98 Octane – Super Premium
  95 Octane – Premium
  93 Octane – Unleaded
  87 Octane – Regular / Naphtha
  Avgas
  Kerosene
  Avturbo
  Low Sulfur Diesel
  Regular Diesel
  Low Sulfur Fuel Oil
  Bunker C Fuel Oil
  Lubricating Oils
  LPG – Cooking
  LPG – Power / Automotive

 

Click the link below to order, remit payment via PayPal, then download in one easy step. More »

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