Energy Technology Expert

How to Optimize Power Plant Design and Configuration (technology, capacity, efficiency, location) – see download file for input data

Optimizing the overall project concept during the plant feasibility study and detailed engineering study is a common problem faced by project developers and EPC contractors.  The question commonly asked by project owners from project developers and designers are:

(1) What engine/manufacturer should be considered (e.g. Siemens, Westinghouse, General Electric, Mitsubishi, Alstom, etc)?

(2) What is the minimum or optimal plant capacity given the range of power and energy demand (too low a capacity will not meet break even, too high a capacity will result in unutilized surplus capacity without corresponding benefits since it is demand limited)

(3) What is the maximum plant heat rate (or minimum thermal efficiency) given the type of fuel used (coal, oil, natural gas, nuclear, biomass, hydro, wind, solar) needed so that the utilization of expensive fuel given the cost of the technology will still result in an electricity tariff that is competitive without the need of subsidy?

(4) What is the optimum overhaul cycle (too frequent overhauls may not be justified by the overhaul cost and foregone energy and power sales, while long intervals between overhauls may result in deteriorating efficiency leading to higher fuel consumption, excessive down times leading to lower plant reliability and lower power and energy sales)?

(5) What is the optimum plant location considering the cost of the cooling system (once thru sea water, once thru lake water, river water cooling tower, deep well water cooling tower, radiator cooling) and cost of pumping energy, cost of the transmission system (type of T/L, length of wire, type of conductor) and the cost of lost energy, and delivered cost of the primary and backup fuels (piped natural gas and oils, delivery by barges or tank trucks)?

(6) What is the minimum level of non-refundable subsidy (no interest, no principal repayment) or maximum interest of debt (loan interest with principal repayment) needed to attain reasonable investor returns (as minimum equity DCR IRR).

(7) What is the minimum price of carbon emission reduction (CER) certificates (the model has an initial value of US$5.00 per metric ton of CO2 equivalent) so that including CDM will result in attaining minimum investor returns.

(8) In rural electrification, it is often required by the electricity regulator (ERC) that the project proponent has determined the “best new entrant” power generation technology in order that subsidies, if so required, are as minimum as possible.  This means the proponent has analyzed various power generation technologies suchs as diesel engines, renewable energy sources (biomass, mini-hydro, wind, solar, biogas) and hybrid combinations thereof with diesels for stable 24/7 electricity service.

(9) Lastly, when upon doing all possible ways of optimizing each system and determining the “best new entrant”, yet the resulting tariff is still higher than the average of the national or regional grid, then a feed-in tariff (FIT) mechanism is applied by the electricity regulator in order that the said renewable energy resource is able to operate efficiently and recover its costs and reasonable profit expected by any power investor. It has been concluded that without the FIT mechanism, renewable energy sources will never be able to compete and penetrate the grid since by its very nature (expensive, intermittent), it is generally more expensive than conventional fuels such as coal, oils, nuclear and large hydro.

Based on the author’s experience in conducting sensitivity analysis, the most significant variables affecting the economic returns of a project (as DCF IRR) are: electricity tariff at the given location/market, cost of delivered fuel, all-in project cost, plant heat rate (efficiency), O&M costs, degradation rates (capacity and heat rate), cost of capital (minimum hurdle rate for equity investments, cost of debt or bank loan), and equity structure (% equity, % subsidy, % debt).

As you have carefully guessed, the author has indeed developed a project finance model with built-in carbon emission reduction credit cash flows under the CDM of the Kyoto Protocol.

The user inputs will clearly show the extent of how the author has considered all the above variables into a robust and unified project finance model that allows sensitivity runs in order to determine what combination will result in the optimal design concept.  Optimal conditions are achieved when the DCF IRR is maximum, or the electricity tariff is minimum, or the all-in project cost is minimum, or the delivered fuel cost is minimum.

Thru a series of macros that vary each combination and pasting the results in a table for future comparison, the designer will be able to optimize the design concept in a breeze thru the click of the computer mouse!

For more information, you may write the author your specific concerns and needs:

Marcial T. Ocampo

email mars_ocampo@yahoo.com

energydataexpert@gmail.ocm

web   www.energytechnologyexpert.com

http://ph.linkedin.com/in/ocampomarcial

================= sample model inputs for optimizing power plant design and configuration

DATA INPUTS

Instructions for Running this Project Finance Model (by Marcial T. Ocampo)					1200 MW Simple Cycle GT (24 units x 50 MW each)
Enter the required data starting from the first step to the last step, then converge the model by pressing ctrl + d
0)	0	Include Carbon Emission Credits (CDM)					Blue cells are input fields for updating
							These cells are case switches
1)	2	Define the NPV and return IRR to be used (1-4).
	0	NPV-ROI	return on investment (100% equity, 0% debt) – project cost versus cash flow (need to set equity to 0%)
	1	NPV-ROE	return on equity (say 30% equity, 70% debt) – equity portion of project cost versus cash flow (default)
	0	NPV-FC	return on equity (say 30% equity, 70% debt) – equity portion of project cost versus dividends flow (no depreciation)
	0	NPV-FC discounted	return on equity (say 30% equity, 70% debt) – equity portion of project cost versus discounted dividends flow (depreciating currency)
2)	25	Define the operating period (25 to 30 years) for the CCGT.	This model is for 25 years but user may insert additional columns or delete columns to match period with project life.
	2009	Define the end of construction period (year 0).	It assumes everything has been constructed and finished at the end of this year (0) and will operate on following year (1).
3)		If you need to insert columns (increase operating period from 25 to say 30 years), place cursor at cell AA1
		in both Main and Reports worksheet, then highlight to the right the number of columns to add, then insert columns.
		Then copy the entire column range (AA10 .. AA615) in Main worksheet (the model sheet) up to the 2nd to the last column (say year 29)
		Then copy the entire column range (AA1 .. AA277) in Reports worksheet (the report sheet) up to the 2nd to the last column (say year 29)
		Be careful in copying the columns.  You must preserve the overhaul cycle for the overhaul and regular maintenance activities (rows 34 to 35) of Main worksheet.
4)		Define overhaul cycle and capacity degradation
	1.00%	Normal, % p.a.	normal degradation rate
	-4.00%	Overhaul, % p.a.	degradation recovered after overhaul
	5	Overhaul Cycle, yr	overhaul cycle
	80.00%	Recovery, %	fraction of normal degradation recovered during overhaul
	6										per unit
5)	1	Select engine model & manufacturer (1-6)	MW gross	own use(1)	MW net	Heat Rate, kJ / kWh	Efficiency, %	Cost, $/kW	Variable O&M	Fixed O&M	MW gross
24	1	Simple Gas Turbine Aero Derivative	1,200.000		1,200.000	9,474	38.00%	325	0.005	0.040	50.000
1	0	Recuperated GT	3.200		3.200	8,889	40.50%	400	0.005	0.040	3.200
1	0	CHAT 11 MW	11.000		11.000	8,090	44.50%	800	0.005	0.040	11.000
1	0	CHAT 300 MW	300.000		300.000	6,581	54.70%	375	0.005	0.040	300.000
1	0	Heavy Frame GT	200.000		200.000	10,286	35.00%	560	0.005	0.040	200.000
1	0	Other models, etc.	250.000		250.000	9286	38.77%	660	0.005	0.040	250.000
	Used	Simple Gas Turbine Aero Derivative	1,200.000	0.000	1,200.000	9,474	38.00%	325.00	0.00500	0.040
					(1) Own use is mainly condenser cooling pumping power
6)	1	Select plant location / method of cooling of condenser (1-5)	Length, m	Head, m	Temp rise, deg C	Flow, m3/hr	kW Power(2)	% of Gross Power	Cost, $(3)	cooling medium flow rate
	1	Once thru sea water	2,000.00	31.50	3.00	292,349	20,075.62	1.673%		sea water (m3/hr)
	0	Once thru lake water	400.00	15.00	3.00	292,349	9,559.82	0.797%		lake water (m3/hr)
	0	River water cooling tower	2,000.00	30.00	10.00	87,705	5,735.89	0.478%		river water (m3/hr)
	0	Deep well water cooling tower	1,000.00	60.00	10.00	87,705	11,471.78	0.956%		deep well (m3/hr)
	0	Radiator cooling			13.00	173,482	7,837.50	0.653%		ambient air (MT/hr)
	Used	Once thru sea water					20,075.62	1.673%	0
						(2) Power = 9.81 x (Q/3600) x H x 80%		(3) Cost estimate of piping, pump, treatment, etc.
7)		Once thru cooling (sea water, lake water)
		1,200.000	MWh / h	800.000	Heat to Boiler (2/3) since (1/3) goes to gas turbine
		2,105	MWh / h	38.0%	Overall Fuel to Electricity Efficiency			fuel to electricity
		2,105,263	kWh / h	1,000	kWh / MWh
		7,578,947,368	kJ / h	3,600	kJ / kWh
		7,183,427,832	BTU / h	1.05506	kJ / BTU			Energy input from fuel
		6,105,913,657	BTU / h	85%	Boiler Efficiency			Energy to steam
		1,077,514,175	BTU / h	15%	Heat Losses to Atmosphere			Energy to atmosphere & losses
		6,105,913,657	BTU / h					Energy input to steam turbine
		2,442,365,463	BTU / h	40%	Rankin Steam Turbine Efficiency			Energy to drive shaft
		3,663,548,194	BTU / h	60%	Heat Losses to Condenser			Energy to condenser / cooling tower
		2,442,365,463	BTU / h					Energy input to drive shaft
		2,369,582,972	BTU / h	97%	Mechanical Drive (99%) & Generator Efficiency (98%)			Energy to electricity
		72,782,491	BTU / h	3%	Heat Losses to Generator			Energy to generator losses
		3,663,548,194	BTU / h					Energy input to condenser / cooling tower
		3,480,370,785	BTU / h	95%	Heat transferred to cooling water			Energy to cooling water
		183,177,410	BTU / h	5%	Heat Losses to Atmosphere			Energy to atmosphere & losses
				3.0	Allowable temperature Rise, deg C			Water allowable temperature rise
				1.8	deg F per deg C rise
				5.4	Allowable temperature Rise, deg F
				1.00	Specific heat of lake water, Btu / lb deg F			Water specific heat
		644,513,108	lb / h	5.4	Allowable Btu / lb
		292,349,228	kg / h	2.2046	lb / kg
		292,349	cum / h	1,000	kg / cubic meter (kg / cum)			Cooling Water
8)		Water cooling tower (river water, deep well)
		1,200.000	MWh / h	800.000	Heat to Boiler (2/3) since (1/3) goes to gas turbine
		2,105	MWh / h	38.0%	Overall Fuel to Electricity Efficiency			fuel to electricity
		2,105,263	kWh / h	1,000	kWh / MWh
		7,578,947,368	kJ / h	3,600	kJ / kWh
		7,183,427,832	BTU / h	1.05506	kJ / BTU			Energy input from fuel
		6,105,913,657	BTU / h	85%	Boiler Efficiency			Energy to steam
		1,077,514,175	BTU / h	15%	Heat Losses to Atmosphere			Energy to atmosphere & losses
		6,105,913,657	BTU / h					Energy input to steam turbine
		2,442,365,463	BTU / h	40%	Rankin Steam Turbine Efficiency			Energy to drive shaft
		3,663,548,194	BTU / h	60%	Heat Losses to Condenser			Energy to condenser / cooling tower
		2,442,365,463	BTU / h					Energy input to drive shaft
		2,369,582,972	BTU / h	97%	Mechanical Drive (99%) & Generator Efficiency (98%)			Energy to electricity
		72,782,491	BTU / h	3%	Heat Losses to Generator			Energy to generator losses
		3,663,548,194	BTU / h					Energy input to condenser / cooling tower
		3,480,370,785	BTU / h	95%	Heat transferred to cooling water			Energy to cooling water
		183,177,410	BTU / h	5%	Heat Losses to Atmosphere			Energy to atmosphere & losses
				10.0	Allowable temperature Rise, deg C			Water allowable temperature rise
				1.8	deg F per deg C rise
				18	Allowable temperature Rise, deg F
				1.00	Specific heat of lake water, Btu / lb deg F			Water specific heat
		193,353,932	lb / h	18	Allowable Btu / lb
		87,704,768	kg / h	2.2046	lb / kg
		87,705	cum / h	1,000	kg / cubic meter (kg / cum)			Cooling Water
9)		Radiator cooling (ambient air)
		1,200.000	MWh / h	800.000	Heat to Boiler (2/3) since (1/3) goes to gas turbine
		2,105	MWh / h	38.0%	Overall Fuel to Electricity Efficiency			fuel to electricity
		2,105,263	kWh / h	1,000	kWh / MWh
		7,578,947,368	kJ / h	3,600	kJ / kWh
		7,183,427,832	BTU / h	1.05506	kJ / BTU			Energy input from fuel
		6,105,913,657	BTU / h	85%	Boiler Efficiency			Energy to steam
		1,077,514,175	BTU / h	15%	Heat Losses to Atmosphere			Energy to atmosphere & losses
		6,105,913,657	BTU / h					Energy input to steam turbine
		2,442,365,463	BTU / h	40%	Rankin Steam Turbine Efficiency			Energy to drive shaft
		3,663,548,194	BTU / h	60%	Heat Losses to Condenser			Energy to condenser / cooling tower
		2,442,365,463	BTU / h					Energy input to drive shaft
		2,369,582,972	BTU / h	97%	Mechanical Drive (99%) & Generator Efficiency (98%)			Energy to electricity
		72,782,491	BTU / h	3%	Heat Losses to Generator			Energy to generator losses
		3,663,548,194	BTU / h					Energy input to condenser / cooling tower
		3,480,370,785	BTU / h	95%	Heat transferred to cooling air			Energy to cooling water
		183,177,410	BTU / h	5%	Heat Losses to Atmosphere			Energy to atmosphere & losses
				13.0	Allowable temperature Rise, deg C (10 TO 16)			Allowable ambient air temperature rise
				1.8	deg F per deg C rise
				23.4	Allowable temperature Rise, deg F
				0.389	Specific heat of air, Btu / lb deg F = 7/18			Ambient Air specific heat
		382,458,328	lb / h	9.1	Allowable Btu / lb
		173,481,960	kg / h	2.2046	lb / kg
		173,482	MT / h	1,000	kg / MT			Cooling Ambient Air
10)		Define overhaul, maintenance, shutdown and outages
	28	Planned Overhaul, days (4 wks)
	14	Regular Maintenance, days (2 wks)
	0.10%	Economic S/D, % of CD
	0.50%	Deactivated S/D – External, % of CD
	5.00%	Forced Outage – Internal, % of CD
	95.00%	Load Factor, % of DC
11)		Define overhaul cycle and heat rate degradation
	1.00%	Normal, % p.a.	normal degradation rate
	-4.00%	Overhaul, % p.a.	degradation recovered after overhaul
	5	Overhaul Cycle, yr	overhaul cycle
	80.00%	Recovery, %	fraction of normal degradation recovered during overhaul
12)		Define transmission line (T/L) system and cost		Sea water	Lake water	River Water	Deep Well	Radiator	Selected
		Line Voltage	kV	230	230	230	230	230	230
		Power	kW	1,200,000	1,200,000	1,200,000	1,200,000	1,200,000	1,200,000
		Length	km	20.00	10.00	15.00	15.00	25.00	20.00	1.609	km / mile
		Power Factor	lag	0.85	0.85	0.85	0.85	0.85	0.85
		Cost per kilometer of T/L	$/km	$360,000	$396,000	$432,000	$432,000	$324,000	$360,000
	4	Conductor type (1-4)		Seaside City	Lakeside City	Riverside City	Riverside City	Inland City
		ACSR (MCM)		% T/L Loss	% T/L Loss	% T/L Loss	% T/L Loss	% T/L Loss	Selected
	1	ACSR (MCM) 336		11.814%	5.907%	8.861%	8.861%	14.768%	11.814%
	2	ACSR (MCM) 795		5.654%	2.827%	4.240%	4.240%	7.067%	5.654%
		AAC (MCM)							0.000%
	3	AAC (MCM) 336		11.539%	5.770%	8.655%	8.655%	14.424%	11.539%
	4	AAC (MCM) 789		4.914%	2.457%	3.686%	3.686%	6.143%	4.914%
	Used	AAC (MCM) 789		4.914%	2.457%	3.686%	3.686%	6.143%	4.914%
13)		Define other power losses
	1.00%	Step-up Transformer Loss (Switchyard), MWh
	0.00%	Other Losses (non-technical, pilferage), MWh
14)		Define fuel properties	GHV, Btu/lb	NHV, Btu/lb	GHV / NHV	kg / Liter	Btu/liter	Reference	$/MMBtu	PhP / liter 2009
	95.00%	Natural Gas (Malampaya Gas) – main fuel	22,129	20,249	1.093	2009	$GJ	8.628	9.10	418.11	PhP/GJ
	5.00%	Diesel Oil – backup fuel (gas pipeline downtime)	19,650	18,453	1.065	0.8448	36,597	46.44	16.92	30.00	PhP/liter
	4.00%	Low Sulfur Fuel Oil (LSFO – 1% S) – boiler fuel	18,400	17,449	1.055	0.9659	39,181	35.97	12.24	23.24	PhP/liter
	1.00%	Bunker Fuel Oil (BFO – 3% S) – boiler fuel	19,670	18,565	1.060	0.8916	38,664	34.84	12.01	22.51	PhP/liter
		Lube Oil				0.8500		232.00		149.87	PhP/liter
						2.2046	lb/kg		1.05506	kJ/Btu
15)		Lube Oil Consumption
	1.00%	Normal, % p.a.	normal degradation rate
	-4.00%	Overhaul, % p.a.	degradation recovered after overhaul
	5	Overhaul Cycle, yr	overhaul cycle
	80.00%	Recovery, %	fraction of normal degradation recovered during overhaul
	0.254	Ideal Lube Oil Consumption, g/kWh
16)	0	Escalate fuel, lubes, tariff and O&M costs? (1=yes, 0=no)	Used
	3.00%	Natural Gas (Malampaya Gas) – main fuel	0.00%
	3.50%	Diesel Oil – backup fuel (gas pipeline downtime)	0.00%
	2.50%	Low Sulfur Fuel Oil (LSFO – 1% S) – boiler fuel	0.00%
	2.00%	Bunker Fuel Oil (BFO – 3% S) – boiler fuel	0.00%
	5.00%	Lube Oil	0.00%
17)		Escalation rates for tariff and O&M costs	Used		(e.g. US)
	5.00%	Annual increase of the tariff, % p.a.	0.00%	Foreign (US)	US CPI	Local (RP)	RP CPI	% of operating income		Calculated	Paul Breeze
	3.25%	Purchase of chemical materials	0.00%	70.00%	2.50%	30.00%	5.00%	1.66%	variable O&M
	3.25%	Utilities (electricity, water)	0.00%	70.00%	2.50%	30.00%	5.00%	1.66%	variable O&M	0.00500	0.00500
	4.25%	Maintenance of the installation	0.00%	30.00%	2.50%	70.00%	5.00%	1.20%	fixed O&M
	4.25%	Personnel expense	0.00%	30.00%	2.50%	70.00%	5.00%	1.21%	fixed O&M
	4.25%	Land lease, rent	0.00%	30.00%	2.50%	70.00%	5.00%	1.20%	fixed O&M
	4.25%	Other services	0.00%	30.00%	2.50%	70.00%	5.00%	1.20%	fixed O&M	0.0400	0.0400
	5.00%	Taxes, Insurances, Benefits & Regulatory Costs	0.00%
18)		Define electricity sales & revenues	Factor	Adjustment
	70.00%	Electricity sales to DU, MWh	1.000	0.00%	discount price to direct customers (e.g. -10%)
	20.00%	Electricity sales to NPC, MWh	1.000	0.00%	reference price to national grid (e.g. 0%)
	10.00%	Electricity sales to WESM, MWh	1.000	0.00%	wholesale spot market price (e.g. +15%)
	100.00%	Total must add to 100%
19)		Define working capital for initial project cost (months)	$/year	Working Capital
	0	Total Fuel Costs	39,760,887	0	no working capital for natural gas fuel (could not be stored)
	1	Expenses from lube purchase	404,243	33,687
	1	Purchase of chemical materials	833,882	69,490
	1	Utilities (electricity, water)	833,882	69,490
	1	DOE 1-04 (0.01 PhP/kWh sold)	84,294	7,024	0.01	DOE 1-94 impost per kWh sold
	1	Maintenance of the installation	602,806	50,234	48.46	PhP/US$ exchange rate
	1	Personnel expense	607,830	50,652
	1	Land lease, rent	602,806	50,234
	1	Other services	602,806	50,234
		Total working capital	44,333,436	381,046
20)		Define corporate income tax rate and income tax holiday
	30%	Corporate income tax rate (% of taxable income)
	0	Income tax holiday (ITH), years
21)		Expenses not eligible for income tax deduction			sample data
	0.00%	Profit Sharing	of income after tax		5.00%
	0	Social Benefit Fund – Host Community	per month		10,000
22)		Calculation of Working Capital Needs (WCN)
	3.00	Cash needed for operations (+)	months of expenses
	1.00	Customers / Receivables (+)	months of revenue
	2.00	Stocks / Inventory (+)	months of fuel & chemicals
	1.00	Suppliers / Payables (-)	months of payables
23)		Estimate all-in capital cost				000 PhP
		Initial investment in land (US$/ha), 1 ha = 10,000 m2	100,000.00	10	ha	1,000
	325.00	Freight on Board = FOB USA = $/kW	15,749.50	1,200.000	MW	18,899,400
	5%	Ocean Freight = FRT = 5% x FOB	2%			377,988
	1%	Insurance = INS = 1% x FOB	1%			188,994
		Cargo, Insurance & Freight = CIF = FOB + FRT + INS				19,466,382
	12%	Value Added Tax = VAT = 12% x CIF	0%			–
	3%	Customs Duty = (CIF + VAT) x (% Duty) x (1 + % VAT)	0%			–
		Duty-Paid Landed Cost = DPLC = CIF + VAT + Duty				19,466,382
	3%	Local Freight Cost = LFC = 3% x CIF	1%			194,664
		Delivered Cost at Site = DCS = DPLC + LFC				19,661,046
	5%	Installation Cost = IC = 5% x FOB	2%			377,988
		Condenser Cooling System	0			–
		Transmission Line, PhP per km and km length	17,445,600	20.00	km	348,912
		Total EPC = DCS + IC+ CCS + T/L				20,387,946
	10%	Contingency (10%) = EPC x 10%	0%			–
	1%	Documentary Stamps (1%) = EPC x 1% = DS	0%			–
		Total Fixed Assets (EPC + Contingency + DS)				20,387,946
	10.00%	Depreciation term (years)	salvage	10.00%	733,966	25	20,388,946	000 US$	000 PhP	Developer/Modeler/Arranger Fees
	1.00%	Development costs (developer, modeler)		2.00%		407,779		$4,207	203,889	developer (1%) Robert Jimenez
	12.00%	Other Costs including taxes, contingencies		0.00%		-		$4,207	203,889	modeler (1%) Marcial Ocampo
		Carbon Emission Registration & Consultancy				-		$11,338	549,435	arranger (2%) Juan dela Cruz
		Initial investment in capitalized expenses				7,082,825	407,779	$19,753	957,214	Total developer/modeler/arranger
	10.00%	Amortization term (years)	salvage	10.00%	254,982	25
		Working Capital:
		Working capital (adjustments for DSCR = 1.1)		1.000		6,294,000
		Working capital (initial stocks – fuel) – 2 months				–
		Working capital (initial stocks – lubes) – 2 months				33,687
		Working capital (initial stocks – chemical materials) – 2 months				69,490
		Working capital (mobilization – utilities) – 2 months				69,490
		Working capital (mobilization – DOE 1-94) – 2 months				7,024
		Working capital (mobilization – maintenance) – 2 months				50,234
		Working capital (mobilization – personnel expense) – 2 months				50,652
		Working capital (pre-paid expense – advance rent) – 2 months				50,234
		Working capital (pre-paid expense – other services) – 2 months			6,675,046	50,234	27,471,771
		Interest During Construction:
	1.00%	Dev’t fees (loan arranger)		1.00%		274,718		Year -2	Year -1	Year 0	Construction period
	1.00%	Front end fees (loan arranger)		1.00%		274,718		33.0%	33.0%	34.0%	drawdown rate
	0.50%	Commitment fees (bank)		0.50%		138,732		9,065,684	9,065,684	9,340,402	annual drawdown
	12.00%	Interest During Construction (bank) – 36 months	3.00	6.00%		3,280,129	3,968,297	9,065,684	18,131,369	27,471,771	cumulative drawdown
	10.00%	Amortization term (years)	salvage	10.00%	142,859	25		92,030	46,702	0	fee on undrawn amount
	Capital	Total Investment (land, fixed, capitalized expenses, working capital)				31,440,068	31,440,068	543,941	1,087,882	1,648,306	interest on cumulative drawdown
				$/kW	541	648,784	US$
24)		Taxes, Insurances, Benefits & Regulatory Costs
		Real Property Tax – Land	1.60%	of land		NOTE: Differentiate between one time, cyclic (every 2 or 5 years) and recurring (annual)
		Real Property Tax – PPE	1.60%	of fixed assets		and vary the formula in the Main worksheet accordingly.
		Real Property Tax – Buildings	0.80%	of building		For simplicity in this model, they are assumed to be annual fees to be conservative.
		Land Lease & ROW	0.00	US$/MT coal
		Property Insurance – PPE	0.78%	of fixed assets
		Property Insurance – Building	0.78%	of building
		Business Interruption Insurance	0.56%	of previous year’s revenue
	of Capital	Special Education Fund – benefits to host community	1.00%	of land
	0.277%	SEC Registration & Fees	87,088.99	Securities & Exchange Commission (certificate of registration)
		BIR Registration & Fees	530.00	Bureau of Internal Revenue (registration of TIN, VAT)
	0.007%	DENR Permits & Fees	2,200.80	Department of Environment & Natural Resources (EIS, ECC)
		Discharge Fee (BOD, TSS) – DENR	0.00	water pollution discharge permit (4 wastes at 600 each)
	0.028%	EMB Permits & Fees	8,803.22	Environment Management Bureau (air quality)
		NWRB Permits & Fees	17,416.50	National Water Resources Board (water use permit)
		PNRI Permits & Fees	5,900.00	Philippine Nuclear Research Institute (radioactive material license)
		ERC Registration & Fess	1,500.00	Energy Regulatory Commission (certificate of compliance, authority to operate)
	0.015%	DOLE Permits & Fees	4,716.01	Department of Labor & Employment (permit to operate pressurized vessels)
		DTI Permits & Fees	0.00	Department of Trade & Industry (registration of business name, with SEC now for corporation)
	0.142%	LGU Registration & Fees	44,644.90	Local government units (barangay, municipal, provincial, regional)
	0.002%	NTC Registration & Fees	628.80	National Telecommunication Commission (radio station permit)
		BOC Registration & Fees	5,000.00	Bureau of Customs (accreditation and registration)
		PPA Registration & Fees	1,000.00	Philippine Port Authority (permit to operate shore line facilities)
		ATO Registration & Fees	13,050.00	Air Transportation Office (height clearance permit for smoke stack)
		PDEA Registration & Fees	3,000.00	Philippine Drug Enforcement Agency (essential chemicals commodity permit)
		BOI Registration & Fees	4,500.00	Board of Investment (certificate of registration)
		DOE Permits & Fees	800.00	Department of Energy (authority to import, certificate of registration)
		Local Business Taxes (1/2 of 1% of GR)	0.00%	of gross revenue
		National Franchise Taxes (1/2 of 1% of GR)	0.00%	of gross revenue
		Total Taxes, Insurances, Benefits & Regulatory Costs
25)		Cost of debt (loan interest)
	5.00%	Reference interest rate (Libor or other)	12	loan term
	1.00%	Spread	3.00	grace period (construction period)
	6.00%	Interest rate of debt	1	loan amortization method (1 = constant principal repayment, 0 = declining balance method)
26)		Capital Structure (equity & debt)
	15.00%	% to be financed by capital	30.00%	Equity IRR
	0.00%	% to be financed by non refundable subsidy	0.00%	Subsidy
	6.00%	% to be financed by debt	70.00%	Debt Interest
		Initial amount of capital	8.70%	WACC
27)		Debt Service Reserve Fund
	6	months of debt service
	4.00%	DSRF Income -interest on Foreign Currency Deposit
	7.50%	Withholding Tax on Foreign Currency Deposit
	0.30%	DSRF Expense – withholding tax
28)		Equity Structure (shareholder contribution)
	planned	Annual dividend payable	actual
	60.00%	Investor 1	89.12%
	20.00%	Investor 2	0.26%
	20.00%	Investor 3	10.62%
29)		Your done.  Now converge the model by pressing ctrl + d
30)		Press ctrl + g to optimize CCGT engine and plant location
31)		Press ctrl + r to update Summary Table
32)		Press ctrl + q to update Sensitivity Table
33)		Vary electricity tariff and see impact on NPV, IRR and payback.				Go to Main worksheet
		(impact of electricity tariff)				Update cell E5 (electricity tariff, $/kWh)
						View results for NPV, IRR and payback (cells F6..H9)
						Press ctrl + r to preserve Summary Table
34)		Determine capital cost given electricity tariff, fuel cost and O&M cost to meet IRR.				Go to Main worksheet
		(impact of capital cost) – maximum capital cost to meet minimum IRR				Update cell E5 (electricity tariff, $/kWh)
						Go to Sensitivity worksheet
						Use goal seek to determine capital cost to meet IRR:
						Set cell C16 (NPV) to zero by varying cell B9 (sensitivity factor for capital cost)
						Press ctrl + r to preserve Summary Table
35)		Determine main fuel cost (pipeline natgas) given electricity tariff, capital cost and O&M cost to meet IRR.				Go to Main worksheet
		(impact of main fuel cost) – maximum fuel cost to meet minimum IRR				Update cell E5 (electricity tariff, $/kWh)
						Go to Sensitivity worksheet
						Use goal seek to determine capital cost to meet IRR:
						Set cell C16 (NPV) to zero by varying cell B8 (sensitivity factor for main fuel cost)
						Press ctrl + r to preserve Summary Table
36)		Determine rated capacity given electricity tariff, capital cost and O&M cost to meet IRR.				Go to Main worksheet
		(impact of rated capacity) – minimum rated capacity to meet minimum IRR				Update cell E5 (electricity tariff, $/kWh)
						Go to Sensitivity worksheet
						Use goal seek to determine capital cost to meet IRR:
						Set cell C16 (NPV) to zero by varying cell B10 (sensitivity factor for rated capacity)
						Press ctrl + r to preserve Summary Table

Data inputs for simple cycle GT.doc (copyright 2009 by Marcial T. Ocampo)