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

July 25th, 2014 No Comments   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

 

 

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 1 Comment   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 No Comments   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 5 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 »

Philippine Oil Pump Price Calculation Model and Oil Company Gross Margin – Annexes

September 13th, 2012 No Comments   Posted in Oil Pricing Formula

Philippine Oil Pump Price Calculation Model and Oil Company Gross Margin – Annexes

The last part of this 3-part series presents the results of applying the oil pump price calculation model into the 1974-June 2012 historical data on pump price, import costs, taxes and government imposts, logistical and transport costs, biofuels, and dealer margin. More »

Philippine Oil Pump Price Calculation Model and Oil Company Gross Margin – Analysis and Conclusions

September 12th, 2012 7 Comments   Posted in Oil Pricing Formula

Philippine Oil Pump Price Calculation Model and Oil Company Gross Margin – Analysis and Conclusions

 

Analysis and Conclusions

 

This chapter presents the evolution and derivation of the oil pump price formula. There is a need to develop an oil pump price formula simply because the oil companies never divulge their oil company gross margin which is the residual or price difference when we subtract from the actual pump price all the importation value adding activities such as supply cost or FOB/MOPS/Dubai, ocean freight and insurance, customs duty, BOC fee, import processing fee, customs doc stamps, bank charge, arrastre charge, wharfage charge, and excise tax or specific tax to arrive at the 12% VAT on all importation activities, and all local value adding activities such as oil company gross margin, transshipment, pipeline, depot operation, biofuels, hauler’s fee and dealer’s margin to arrive at the 12% VAT on local activities. More »

 Page 1 of 13  1  2  3  4  5 » ...  Last »